EDGAR 10-K Filing

Company CIK: 1276187
Filing Year: 2024
Filename: 1276187_10-K_2024_0001276187-24-000024.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS
Overview
Energy Transfer LP is a Delaware limited partnership with common units publicly traded on the NYSE under the ticker symbol “ET.”
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “Energy Transfer” mean Energy Transfer LP and its consolidated subsidiaries, which include Sunoco LP and USAC.
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.
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. 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. Energy Transfer distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.
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.
The following chart summarizes our organizational structure as of February 9, 2024. For simplicity, certain entities and ownership interests have not been depicted.
Significant Achievements in 2023
Strategic Transactions
•In November, the Partnership completed its acquisition of Crestwood, which owns gathering and processing assets located in the Williston, Delaware and Powder River basins.
•In May, the Partnership acquired Lotus Midstream, which owns an integrated crude midstream platform located in the Permian Basin.
Organic Growth Projects
•In August, the Partnership’s eighth fractionator was placed in service at the Mont Belvieu NGL Complex, which brings fractionation capacity at Mont Belvieu to approximately 1.15 MMBbls/d.
•In June, the Partnership’s 200 MMcf/d Bear cryogenic processing plant was placed in service in the Permian Basin.
Segment Overview
See Note 16 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional financial information about our segments.
Intrastate Transportation and Storage Segment
Intrastate natural gas transportation pipelines receive natural gas from other mainline transportation pipelines, storage facilities and gathering systems, and deliver the natural gas to industrial end-users, storage facilities, utilities, power generators and other third-party pipelines. Through our intrastate transportation and storage segment, we own and operate (through wholly owned subsidiaries or through joint venture interests) approximately 12,200 miles of intrastate natural gas transportation pipelines with approximately 24 Bcf/d of transportation capacity, three natural gas storage facilities located in Texas and two natural gas storage facilities located in Oklahoma.
Energy Transfer operates one of the largest intrastate pipeline systems in the United States, which provides energy logistics to major trading hubs and industrial consumption areas throughout the country. In Texas, our intrastate transportation and storage segment provides transportation of natural gas to major markets from various prolific natural gas producing areas in Texas and Louisiana (Permian Basin and Barnett, Haynesville and Eagle Ford shales) through our Oasis Pipeline, ETC Katy Pipeline, Lobo Pipeline, RIGS and Pelico Pipeline as well as our two natural gas pipeline and storage systems: ET Fuel and HPL. 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.
Our intrastate transportation and storage segment’s results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay a fee even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline or (iv) a combination of the three, generally payable monthly.
We also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and marketing companies. Generally, we purchase natural gas from either the market (including purchases from our marketing operations) or from producers at the wellhead. To the extent the natural gas comes from producers, it is primarily purchased at a discount to a specified market price and typically resold to customers based on an index price. In addition, our intrastate transportation and storage segment generates revenues from fees charged for storing customers’ working natural gas in our storage facilities and from managing natural gas for our own account.
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. Through our interstate transportation and storage segment, we directly own and operate approximately 20,090 miles of interstate natural gas
pipelines with approximately 20.1 Bcf/d of transportation capacity and another approximately 7,085 miles and 12.3 Bcf/d of transportation capacity through joint venture interests.
Our vast interstate natural gas network spans the United States from Florida to California and Texas to Michigan, offering a comprehensive array of pipeline and storage services. Our pipelines have the capability to transport natural gas from nearly all Lower 48 onshore and offshore supply basins to customers in the Gulf Coast, Southeast, Southwest, Midwest and Northeast United States as well as Canada. Through numerous interconnections with other pipelines, our interstate systems can access virtually any supply or market in the country. As discussed further herein, our interstate transportation and storage segment’s operations are regulated by the FERC, which has broad regulatory authority over the business and operations of interstate natural gas pipelines.
Lake Charles LNG, our wholly owned subsidiary, owns an LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground storage capacity and the regasification facility has a send-out capacity of 1.8 Bcf/d. 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. The project would utilize existing dock and storage facilities owned by Lake Charles LNG located on the Lake Charles site. Lake Charles LNG Export entered into a prior development agreement with Shell in March 2019; however, Shell withdrew from the project in March 2020 due to adverse market factors affecting Shell’s business following the onset of the COVID-19 pandemic. 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 agreements allow either party to terminate the agreement if Lake Charles LNG Export has not satisfied specified conditions by a specified date. One of those conditions relates to Lake Charles LNG Export making a “final investment decision” to proceed with the construction of the liquefaction facility. To date, the specified dates for satisfying these conditions have been extended by mutual agreement of the parties to the agreements. We have also signed nonbinding letter agreements with several customers for LNG offtake, and we are in discussions with several parties for potential long-term LNG offtake and potential equity investments in the project.
The results from our interstate transportation and storage segment are primarily derived from the fees we earn from natural gas transportation and storage services.
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. Gathering systems generally consist of a network of small diameter pipelines and, if necessary, compression systems, that collect natural gas from points near producing wells and transports it to larger pipelines for further transportation.
Treating plants remove carbon dioxide and hydrogen sulfide from natural gas that is higher in carbon dioxide, hydrogen sulfide or certain other contaminants, to ensure that it meets pipeline quality specifications. Natural gas processing involves the separation of natural gas into pipeline quality natural gas, or residue gas, and a mixed NGL stream. Some natural gas produced by a well does not meet the pipeline quality specifications established by downstream pipelines or is not suitable for commercial use and must be processed to remove the mixed NGL stream. In addition, some natural gas can be processed to take advantage of favorable margins for NGLs extracted from the gas stream.
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. 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. Many of our midstream assets are integrated with our intrastate transportation and storage assets as well as our NGL assets.
Our midstream segment’s results are derived primarily from margins we earn from natural gas volumes that are gathered, transported, purchased and sold through our pipeline systems and the natural gas and NGL volumes processed at our processing and treating facilities.
NGL and Refined Products Transportation and Services Segment
Our NGL and refined products operations transport, store and execute acquisition and marketing activities utilizing a complementary network of pipelines, storage and blending facilities as well as strategic offtake locations that provide access to multiple markets.
Our NGL and refined products transportation and services segment includes:
•approximately 5,700 miles of NGL pipelines;
•our Nederland Terminal and connecting pipelines which provide transportation of ethane, propane, butane and natural gasoline from our Mont Belvieu NGL Complex to our Nederland Terminal where these products can be exported;
•our Marcus Hook Terminal which includes fractionation, storage and exporting assets. 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.
Our NGL pipelines primarily transport NGLs from the Permian Basin, the Barnett and Eagle Ford shales to Mont Belvieu, Texas. In the Northeast, our NGL pipelines transport from the Marcellus and Utica shales to our Marcus Hook Terminal, to customer facilities in Marysville, Michigan and to delivery points on the Canadian border.
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. Our refined product marketing terminals are located primarily in the Northeast, Midwest and Southwest United States, with approximately 8 MMBbls of refined products storage capacity. Our refined products operations utilize our integrated pipeline and terminalling assets, as well as acquisition and marketing activities, to service refined products markets in several regions throughout the United States. The mix of products delivered through our refined products pipelines varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. The products transported in these pipelines include multiple grades of gasoline and middle distillates, such as heating oil, diesel and jet fuel. Rates for shipments on these product pipelines are regulated by the FERC and other state regulatory agencies, as applicable.
Revenues in this segment are principally generated from fees charged to customers under dedicated contracts or take-or-pay contracts. Under a dedicated contract, the customer agrees to deliver the total output from particular processing plants that are connected to the NGL pipeline. Take-or-pay contracts have minimum throughput commitments requiring the customer to pay regardless of whether a fixed volume is transported. Fees are market-based, negotiated with customers and competitive with regional regulated pipelines and fractionators. Storage revenues are derived from base storage and throughput fees. This segment also derives revenues from fee-based export activities, the marketing of NGLs as well as processing and fractionating refinery off-gas.
Crude Oil Transportation and Services Segment
Our crude oil operations provide transportation (via pipeline and trucking), terminalling as well as acquisition and marketing services to crude oil markets throughout the Southwest, Midwest and Northeast United States. 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. This segment includes equity ownership interests in seven crude oil pipeline systems: the Bakken Pipeline, Bayou Bridge Pipeline, White Cliffs Pipeline, Maurepas Pipeline, the Permian Express pipelines, Enable South Central Pipeline and the Wink to Webster Pipeline. 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 acquisition and marketing activities utilize our pipeline and terminal assets,
our proprietary fleet of crude oil tractor trailers and truck unloading facilities, as well as third-party assets to service crude oil markets principally in the Midcontinent United States.
Revenues throughout our crude oil pipeline systems are generated from tariffs paid by shippers utilizing our transportation services. These tariffs are filed with the FERC and other state regulatory agencies, as applicable.
Our crude oil acquisition and marketing activities include the gathering, purchasing, marketing and selling of crude oil. Specifically, the crude oil acquisition and marketing activities include:
•purchasing crude oil at both the wellhead from producers and in bulk from aggregators at major pipeline interconnections and trading locations;
•storing inventory during contango market conditions (when the price of crude oil for future delivery is higher than current prices);
•buying and selling crude oil of different grades at different locations in order to maximize value;
•transporting crude oil using our pipelines, terminals and trucks or, when necessary or cost effective, pipelines, terminals or trucks owned and operated by third parties; and
•marketing crude oil to major integrated oil companies, independent refiners and resellers through various types of sale and exchange transactions.
Investment in Sunoco LP
Sunoco LP is primarily engaged in the distribution of motor fuels to independent dealers, distributors, and other commercial customers and the distribution of motor fuels to end-user customers at retail sites operated by commission agents. Additionally, it receives rental income through the leasing or subleasing of real estate used in the retail distribution of motor fuel. Sunoco LP also operates 75 retail stores located in Hawaii and New Jersey.
Sunoco LP is a distributor of motor fuels and other petroleum products which Sunoco LP supplies to third-party dealers and distributors, to independent operators of commission agent locations and other commercial consumers of motor fuel. Also included in the wholesale operations are transmix processing plants and refined products terminals. Transmix is the mixture of various refined products (primarily gasoline and diesel) created in the supply chain (primarily in pipelines and terminals) when various products interface with each other. Transmix processing plants separate this mixture and return it to salable products of gasoline and diesel.
Sunoco LP is the exclusive wholesale supplier of the Sunoco-branded and EcoMaxx-branded motor fuels, supplying an extensive distribution network of approximately 5,534 company and third-party operated locations throughout the United States and Puerto Rico. In addition to distributing motor fuels, Sunoco LP also distributes other petroleum products such as propane and lubricating oil, and Sunoco LP receives rental income from real estate that it leases or subleases.
Investment in USAC
USAC provides natural gas compression services throughout the United States, including the Utica, Marcellus, Permian Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville, Niobrara and Fayetteville shales. USAC provides compression services to its customers primarily in connection with infrastructure applications, including both allowing for the processing and transportation of natural gas through the domestic pipeline system and enhancing crude oil production through artificial lift processes. As such, USAC’s compression services play a critical role in the production, processing and transportation of both natural gas and crude oil. As of December 31, 2023, USAC had 3.8 million horsepower in its fleet.
USAC operates a modern fleet of compression units, with an average age of approximately 11 years. USAC’s standard new-build compression units are generally configured for multiple compression stages allowing USAC to operate its units across a broad range of operating conditions. As part of USAC’s services, it engineers, designs, operates, services and repairs its compression units and maintains related support inventory and equipment.
USAC provides compression services to its customers under fixed-fee contracts with initial contract terms typically between six months to five years, depending on the application and location of the compression unit. USAC typically continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay a monthly fee even during periods of limited or disrupted throughput, which enhances the stability and predictability of its cash flows. 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.
USAC’s assets and operations are all located and conducted in the United States.
All Other Segment
Our “All Other” segment includes:
•our gas marketing activities, which optimize basis pricing differentials by purchasing and transporting natural gas, primarily on company owned pipelines, and selling that gas primarily to industrial end-users or to other marketers;
•our commodity marketing company, which focuses primarily on wholesale power trading activities;
•our natural gas compression equipment business, which has operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas;
•our wholly owned subsidiary, Dual Drive Technologies, Ltd., which provides compression services to customers engaged in the transportation of natural gas, including our other segments; and
•subsidiaries involved in the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities.
Asset Overview
The following descriptions include summaries of significant assets within the Partnership’s reportable segments. Amounts, such as capacities, volumes and miles included in the following descriptions are approximate and are based on information currently available; such amounts are subject to change based on future events or additional information.
The map below depicts the major assets of our core businesses, excluding the assets of Sunoco LP, USAC and the businesses in our all other segment. 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.
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
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 ET Fuel System has bi-directional capabilities and has many interconnections with pipelines providing direct access to power plants and other intrastate and interstate pipelines. It is strategically located near high-growth production areas and provides access to the three major natural gas trading centers in Texas: the Waha Hub near Pecos, Texas, the Maypearl Hub in Central Texas and the Carthage Hub in East Texas.
The ET Fuel System also includes our Bethel natural gas storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 300 MMcf/d and an injection capacity of 75 MMcf/d, and our Bryson natural gas storage facility, with a working capacity of 5.2 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d.
In addition, the ET Fuel System is integrated with our Godley processing plant which gives us the ability to bypass the plant when processing margins are unfavorable by blending the untreated natural gas from our gas gathering system known as the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.
•The Oasis Pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capabilities with approximately 1.3 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis Pipeline connects to the Waha and Katy market hubs and has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.
The Oasis Pipeline is integrated with our gathering system known as the Southeast Texas System and is an important component to maximizing our Southeast Texas System’s profitability. The Oasis Pipeline enhances the Southeast Texas System by (i) providing access for natural gas gathered on the Southeast Texas System to third-party supply and market points and interconnecting pipelines and (ii) allowing us to bypass our processing plants and treating facilities on the Southeast Texas System when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.
•The HPL System is an extensive network of intrastate natural gas pipelines, the underground Bammel storage reservoir and related transportation assets. 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 HPL System is well situated to gather and transport gas in many of the major gas producing areas in Texas including a strong presence in the key Houston Ship Channel and Katy Hub markets, allowing us to play an important role in the Texas natural gas markets. The HPL System also offers its shippers off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel, Carthage and Agua Dulce as well as our Bammel storage facility.
The Bammel storage facility has a total working gas capacity of approximately 52.5 Bcf, a peak withdrawal rate of 1.3 Bcf/d and a peak injection rate of 0.6 Bcf/d. The Bammel storage facility is located near the Houston Ship Channel market area and the Katy Hub, and is ideally suited to provide a physical backup for on-system and off-system customers. As of December 31, 2023, we had approximately 17.2 Bcf committed under fee-based arrangements with third parties and approximately 37.0 Bcf stored in the facility for our own account.
•The ETC Katy Pipeline connects three treating facilities, one of which we own, with our gathering system known as Southeast Texas System. The ETC Katy Pipeline serves producers in East and North Central Texas and provides access to the Katy Hub. 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. OIT is a web-like configuration with multidirectional flow capabilities between numerous receipt points and delivery points. 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. 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.
•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. The Partnership owns a 16% membership interest in and operates Comanche Trail Pipeline.
•Trans-Pecos Pipeline is a 143-mile intrastate pipeline that delivers natural gas from the Waha Hub near Pecos, Texas to the United States/Mexico border near Presidio, Texas. The Partnership owns a 16% membership interest in and operates Trans-Pecos Pipeline.
•The Red Bluff Express Pipeline is an approximately 120-mile intrastate pipeline that runs through the heart of the Delaware Basin and connects certain of our plants as well as third-party plants to the Waha Oasis Header. The Partnership owns a 70% membership interest in and operates Red Bluff Express Pipeline.
•Other intrastate natural gas pipelines include our 630-mile Pelico Pipeline in northern Louisiana and our 167-mile Lobo Pipeline in South Texas.
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 -
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.
The following information describes our principal interstate transportation and storage assets:
•FGT extends from South Texas through the Gulf Coast region of the United States to South Florida. FGT is the principal transporter of natural gas to the Florida energy market, delivering approximately 60% of the natural gas consumed in the state. In addition, FGT’s numerous intrastate and interstate pipeline interconnections with major interstate and intrastate natural gas pipelines provide access to diverse natural gas supply sources. FGT’s customers include electric utilities, independent power producers, industrial end-users and local distribution companies. FGT is owned by Citrus, a 50/50 joint venture with Kinder Morgan, Inc.
•Transwestern Pipeline transports natural gas supply from the Permian Basin, the San Juan Basin and the Anadarko Basin. The system has bi-directional capabilities and can access Texas and Midcontinent natural gas market hubs as well as major western markets in Arizona, Nevada and California. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.
•Panhandle Eastern Pipe Line’s transmission system consists of four large diameter mainline pipelines with bi-directional capabilities, extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan. 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. Trunkline has one natural gas storage field located in Louisiana.
•Tiger is a bi-directional system that extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, interconnecting with multiple interstate pipelines.
•Fayetteville Express Pipeline originates near Conway County, Arkansas and continues eastward to Panola County, Mississippi with multiple pipeline interconnections along the route. 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. The Midcontinent Express Pipeline is owned by a 50/50 joint venture with Kinder Morgan, Inc., the operator of the system.
•EGT provides natural gas transportation and storage services to customers in Oklahoma, Texas, Arkansas, Louisiana, Missouri and Kansas. EGT has two underground storage facilities in Oklahoma and one underground natural gas storage facility in Louisiana. Through numerous pipeline interconnections along the system and at the Perryville Hub, EGT customers have access to Midwest and Northeast markets as well as most of the major natural gas consuming markets east of the Mississippi River.
•MRT provides natural gas transportation and storage services in Texas, Arkansas, Louisiana, Missouri and Illinois. MRT has underground natural gas storage facilities in Louisiana and Illinois. MRT receives natural gas from a variety of interstate and intrastate pipelines through its interconnections and delivers natural gas primarily to the St. Louis market.
•SESH, a 50/50 joint venture with Enbridge Inc., provides transportation services in Louisiana, Mississippi and Alabama. SESH transports natural gas from the Perryville Hub in Louisiana to its endpoint in Mobile County, Alabama. SESH has 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.
Regasification Facility
Lake Charles LNG, our wholly owned subsidiary, owns an LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground LNG storage capacity and the regasification facility has a send out capacity of 1.8 Bcf/d. 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. The project would utilize existing dock and storage facilities owned by Lake Charles LNG located on the Lake Charles site. Lake Charles LNG Export entered into a prior development agreement with Shell in March 2019; however, Shell withdrew from the project in March 2020 due to adverse market factors affecting Shell’s business following the onset of the COVID-19 pandemic. 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. The construction of the liquefaction facility has been approved by FERC. In addition, Lake Charles LNG Export received its wetlands permits from the USACE to perform wetlands mitigation work and to perform modification and dredging work for the temporary and permanent dock facilities at the Lake Charles LNG facilities.
The export of LNG produced by any liquefaction facility in the United States requires export authorization from the DOE. The NGA requires the DOE to approve applications for LNG exports unless such approval would be “inconsistent with the public interest.” In March 2013, Lake Charles LNG Export obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”). 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. 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. 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. The Biden administration stated that these studies were necessary to enable the DOE to make determinations related to the statutory “public interest” standard. The DOE has stated that these studies will take several months to complete, after which a draft policy statement will be made available for public comment prior to finalizing the policy statement. This process is not expected to be completed prior to the U.S. Presidential election in November 2024.
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. The agreements allow either party to terminate the agreement if Lake Charles LNG Export has not satisfied specified conditions by a specified date. One of those conditions relates to Lake Charles LNG Export making a “final investment decision” to proceed with the construction of the liquefaction facility. To date, the specified dates for satisfying these conditions have been extended by mutual agreement of the parties to the agreements. We have also signed nonbinding letter agreements with several customers for LNG offtake, and we are in discussions with several parties for potential long-term LNG offtake and potential equity investments in the project.
During 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.
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.
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. This system also includes three natural gas processing plants (La Grange, Alamo and Brookeland) with
an aggregate capacity of 510 MMcf/d. These plants process the rich gas that flows through our gathering system to produce residue gas and NGLs. 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.
The assets in our Eagle Ford System consist of 30-inch and 42-inch natural gas gathering pipelines originating in Dimmitt County, Texas, and extending to both our King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. These assets also include four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with an aggregate capacity of 1.9 Bcf/d. Our Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to our intrastate transportation pipeline systems for deliveries of residue gas and are also connected with our NGL pipelines.
•We own a 60% interest in Edwards Lime Gathering, LLC, which operates natural gas gathering, compression and treating facilities as well as an oil pipeline and oil stabilization facility in South Texas.
Ark-La-Tex:
•Our Ark-La-Tex assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including our Tiger pipeline. Our northern Louisiana assets include the Bistineau, Creedence, Tristate, Logansport, Magnolia, Olympia, Amoruso, and Lumberjack systems, which collectively include 11 natural gas treating facilities, with aggregate capacity of 3.1 Bcf/d.
The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in northwest Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, a residue gas pipeline that provides market access for natural gas from our processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region, and an NGL pipeline that connects to a third party that provides access to the Mont Belvieu market for NGLs produced from our processing plants. Collectively, the six natural gas processing facilities (Dubach, Lincoln, Rosewood, Mt. Olive, Sligo and Waskom) have an aggregate capacity of 0.9 Bcf/d.
Through the gathering and processing systems described above and their interconnections with our intrastate transportation pipelines, we offer producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.
North Central Texas:
•The North Central Texas System is an integrated system located in four counties in North Central Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford shales. Our North Central Texas assets include our Godley plant, which processes rich gas produced from the Barnett Shale and STACK play, with an aggregate capacity of 700 MMcf/d. The Godley plant is integrated with the ET Fuel System.
Permian Basin:
•The Permian Basin Gathering System offers wellhead-to-market services to producers in 11 counties in West Texas and two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of our system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that we gather and process, including several major interstate and intrastate pipelines serving California, the Midcontinent and Texas natural gas markets. The NGL market outlets includes our NGL pipeline system. The Permian Basin Gathering System includes 13 processing facilities (Waha, Red Bluff, Halley, Keystone, Tippet, Panther, Rebel, Grey Wolf, Bear, Arrowhead, Carlsbad, Orla I and Orla II) with an aggregate processing capacity of 3.2 Bcf/d and one natural gas conditioning facility with an aggregate capacity of 200 MMcf/d.
•In addition, we own a 50% membership interest in Mi Vida JV LLC, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. We operate the plant and related facilities on behalf of the joint venture. We also own a 50% equity interest in Crestwood Permian Basin LLC, a joint venture which owns the Nautilus natural gas gathering system in West Texas. We operate the gathering system on behalf of the joint venture.
Midcontinent:
•The Midcontinent Systems are located in three large natural gas producing regions in the United States: the Hugoton Basin in southwest Kansas, the Anadarko Basin in the Texas Panhandle and Oklahoma, including the STACK and SCOOP plays, and the Arkoma Basin in eastern Oklahoma and Arkansas. These mature basins have continued to provide generally long-lived, predictable production volumes. Our Midcontinent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Midcontinent Systems include 17 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, 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. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.
•We own the Hugoton Gathering System that has 1,900 miles of pipeline extending across parts of southwest Kansas and northwest Oklahoma. This system is operated by a third party.
•We own a 50% membership interest in Atoka Midstream LLC, which owns a natural gas gathering system in Oklahoma.
Williston Basin:
•We own and operate the Arrow and Rough Rider systems which include natural gas gathering systems and processing facilities (Bear Den and Wild Basin). 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.
Powder River Basin:
•We own and operate the Jackalope rich natural gas gathering system, the Continental Express high-pressure pipeline and the Bucking Horse gas processing facility in Converse County, Wyoming. The Bucking Horse gas processing facility has an aggregate processing capacity of 345 MMcf/d.
Eastern:
•The Eastern region assets are located in eleven counties in Pennsylvania, four counties in Ohio and three counties in West Virginia, which gather natural gas from the Marcellus and Utica shales. Our Eastern region assets include approximately 600 miles of natural gas gathering pipelines, natural gas trunklines and fresh-water pipelines, nine gathering and processing systems and the 200 MMcf/d Revolution processing plant, which feeds into our Mariner East and Rover pipeline systems.
•We also own a 51% membership interest in Aqua - ETC Water Solutions LLC, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.
•We own a 75% membership interest in ORS. 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.
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
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. Nolan Pipeline 500 - -
Refined Products Terminals:
Eagle Point - - 6,700
Marcus Hook Terminal - - 930
Marcus Hook Tank Farm - - 1,900
Marketing Terminals - - 7,700
J.C. Nolan Terminal - - 130
(1)The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.
(2)Additionally, the ET Geismar Olefins off-gas processing facility has inlet volume capacity of 54 MMcf/d.
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 ethane pipeline is part of the Orbit Gulf Coast joint venture, as described below.
•The White Cliffs NGL pipeline, in which we have 51% ownership interest, transports mixed NGLs produced in the DJ Basin to Cushing, Oklahoma where it interconnects with the Southern Hills Pipeline to move NGLs to Mont Belvieu, Texas and has a throughput capacity of approximately 90 MBbls/d.
•Other NGL pipelines include the 127-mile Justice pipeline, 63-mile Blue Ridge pipeline, the 45-mile Freedom pipeline, the 20-mile Spirit pipeline and a 50% interest in the 87 mile Liberty pipeline. Through our recent acquisition of Crestwood, we also own an undivided interest in 80 MBbls/d of capacity in a segment of the EPIC Y-Grade Pipeline, LP (EPIC) pipeline from Orla, Texas to Benedum, Texas.
•Our Mont Belvieu NGL Complex is an integrated liquids storage and fractionation facility. The storage facility has approximately 60 MMBbls of salt dome capacity providing 100% fee-based cash flows. The storage facility has access to multiple NGL and refined products pipelines, the Houston Ship Channel trading hub, numerous chemical plants, refineries and fractionators.
The fractionation facility includes eight fractionators, which process NGLs delivered from several sources, including our Gulf Coast NGL Express, West Texas Gateway and Justice pipelines.
•Our Spindletop storage facilities, located in Beaumont, Texas, have 8 MMBbls of salt dome capacity.
•Acquired in 2023, Crestwood’s NGL storage assets include 13 LPG terminals which offer 10 MMBbls of storage capacity located in Pennsylvania, South Carolina, Mississippi, Michigan, New York and Indiana, with receipts and deliveries that are supported by both rail cars and third-party pipelines.
Other Crestwood assets include a fleet of rail and rolling stock with approximately 1.6 MMBbls/d of NGL pipeline, terminal and transportation capacity, which also includes rail-to-truck terminals located in Michigan, Indiana, Ohio, New Hampshire, Pennsylvania, New Jersey, New York, Rhode Island, North Carolina, South Carolina and Mississippi.
•ET Geismar Olefins consists of a refinery off-gas processing unit and an o-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting complex located along the Mississippi River refinery corridor in southern Louisiana. The off-gas processing unit cryogenically processes refinery off-gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components. 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. It also includes a 180 MBbls/d ethane refrigeration facility and a 1.2 MMBbls storage facility at our Nederland Terminal.
•The Marcus Hook Terminal includes fractionation, terminalling and storage assets with a capacity of approximately 2 MMBbls of NGL storage capacity in underground caverns, 4 MMBbls of above-ground NGL refrigerated storage and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 MMBbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGL storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Terminal serves as an offtake outlet for our Mariner East Pipeline System.
The Marcus Hook Terminal also has a tank farm with total refined products storage capacity of approximately 2 MMBbls. The terminal receives and delivers refined products via pipeline and primarily provides terminalling services to support movements on our refined products pipelines.
•The Inkster Terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 860 MBbls of NGLs. We use the Inkster Terminal’s storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in western Ohio. 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. 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 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. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.
•The Eagle Point Terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 7 MMBbls and provides customers with access to the facility via ship, barge, rail and pipeline. The terminal can deliver via ship, barge, rail, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
•The J.C. 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.
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
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.
Our crude oil operations consist of an integrated set of pipeline, terminalling, trucking and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets. 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. Our crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. Our crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.
•Bakken Pipeline. The Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a 1,915-mile pipeline that transports domestically produced crude oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including our crude terminal in Nederland, Texas. The Bakken Pipeline has a capacity of up to 750 MBbls/d. The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the Midwest and Gulf Coast regions.
The Dakota Access Pipeline consists of approximately 1,170 miles of 12, 20, 24 and 30-inch diameter pipeline traversing North Dakota, South Dakota, Iowa and Illinois. Crude oil transported on the Dakota Access Pipeline originates at six terminal locations in the North Dakota counties of Mountrail, Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the Energy Transfer Crude Oil Pipeline for delivery to the Gulf Coast or can be transported via other pipelines to refining markets throughout the Midwest.
The Energy Transfer Crude Oil Pipeline consists of approximately 745 miles of mostly 30-inch diameter pipeline from Patoka, Illinois to Nederland, Texas, where the crude oil can be refined or further transported to additional refining markets.
•Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between Energy Transfer and a subsidiary of Phillips 66, in which we have a 60% ownership interest and serve as the operator of the pipeline. The Bayou Bridge Pipeline consists of a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, and a 24-inch pipeline from Lake Charles, Louisiana to St. James, Louisiana. Bayou Bridge Pipeline has a capacity of approximately 480 MBbls/d of light and heavy crude oil from different sources to the St. James crude oil hub, which is home to important refineries located in the Gulf Coast region.
•West Texas Gulf Pipeline. West Texas Gulf Pipeline is a 26-inch and 20-inch pipeline system that transports barrels from Colorado City, Texas to Longview, Texas for delivery onto Mid Valley Pipeline and additional delivery points along the Gulf Coast via joint tariff.
•Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include the Permian Express 1, Permian Express 2, Permian Express 3, Permian Express 4, Permian Longview and Louisiana Access, Longview to Louisiana and Nederland Access pipelines. These pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the Permian Basin, with origins in multiple locations in West Texas.
•White Cliffs Pipeline. White Cliffs Pipeline owns a 12-inch common carrier, crude oil pipeline, with a throughput capacity of 100 MBbls/d, that transports crude oil from Platteville, Colorado to Cushing, Oklahoma.
•Maurepas Pipeline. The Maurepas Pipeline consists of three pipelines, with an aggregate throughput capacity of 460 MBbls/d, which service refineries in the Gulf Coast region.
•Mid Valley Pipeline. The Mid Valley Pipeline originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United States.
•Cushing Pipeline. The Cushing Pipeline, acquired as a part of the 2023 Lotus Midstream transaction, consists of two 16-inch crude oil pipelines, providing service from the Permian Basin to Cushing, Oklahoma and to third-party systems in North Texas.
•Wink to Webster Pipeline. The Wink to Webster Pipeline is capable of transporting approximately 1,000 MBbl/d from origin points at Wink and Midland in the Permian Basin for delivery to multiple Houston area locations. Our 5% ownership interest in the Wink to Webster Pipeline was obtained in the 2023 acquisition of Lotus Midstream.
•Crude Gathering and Water Gathering and Disposal. We own integrated crude oil and water gathering systems across multiple basins in the United States.
▪Permian Basin: Our Permian Basin gathering assets in West Texas and eastern New Mexico encompass multiple systems in highly active areas of both the Delaware and Midland basins, with the ability to deliver virtually all gathered crude to major market hubs, including Midland, Wink and Crane, as well as our own long-haul pipelines that provide service to the Gulf Coast and Cushing. Our Permian Basin operations also consist of produced water gathering and disposal services in the Delaware Basin which were acquired in the Crestwood transaction in the fourth quarter of 2023.
▪Williston Basin: Our Williston Basin gathering assets in North Dakota and eastern Montana include several systems, acquired through the Enable and Crestwood acquisitions, built for gathering and transporting crude production from the wellhead to long-haul pipelines, including our Bakken Pipeline. Additionally, we have multiple water gathering systems in the Williston Basin that transport produced water to wholly owned and third-party disposal wells.
▪Midcontinent: Our Midcontinent gathering assets in Oklahoma and Kansas primarily transport wellhead and truck-delivered volumes to several local refineries as well as to Cushing, Oklahoma. A portion of these operations are conducted through Enable South Central Pipeline, a joint venture with a subsidiary of CVR Energy, Inc., which is operated by us and in which we own a 60% membership interest.
Crude Oil Terminals
•Nederland, TX. The Nederland Terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores and distributes crude oil, NGLs, feedstocks, petrochemicals and bunker oils (used for fueling ships and other marine vessels). The terminal currently has a total storage capacity of approximately 30 MMBbls in more than 80 above ground storage tanks with individual capacities of up to 660 MBbls.
The Nederland Terminal can receive crude oil at three of its six ship docks and three of its four barge berths. The three ship docks are capable of receiving over 2 MMBbls/d of crude oil. In addition to our crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 395 MMBbls. The terminal also has crude oil rail unloading facilities, including steam availability for heating heavy oils prior to loading.
The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has three ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 MMBbls/d of crude oil to our crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland Terminal generates crude oil revenues primarily by providing term or spot storage services and throughput capabilities to a number of customers.
•Midland, TX. We have two terminals in Midland, Texas, one of which includes approximately 1 MMBbls of crude oil storage and a combined 20 lanes of truck loading and unloading; the terminal provides access to the Permian Express pipelines. The second terminal, obtained in the 2023 acquisition of Lotus Midstream, offers 2 MMBbls of crude oil storage capacity and additional supply and demand connectivity.
•Marcus Hook, PA. The Marcus Hook Terminal can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total active crude oil storage capacity of approximately 1 MMBbls.
•Houston, TX. The Houston Terminal consists of storage tanks located on the Houston Ship Channel with an aggregate storage capacity of 18.2 MMBbls used to store, blend and transport refinery products and refinery feedstocks via pipeline, barge, rail, truck and ship. 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.
•Cushing, OK. The Cushing Terminal has approximately 9.5 MMBbls of crude oil storage. The storage terminal has inbound connections with the White Cliffs Pipeline from Platteville, Colorado, the Great Salt Plains Pipeline from Cherokee, Oklahoma, the Cimarron Pipeline from Boyer, Kansas and two-way connections with all of the other major storage terminals in Cushing. The Cushing Terminal also includes truck unloading facilities.
•Patoka, IL. The Patoka Terminal is a tank farm owned by the PEP joint venture and is located in Marion County, Illinois. The facility includes 234 acres of owned land and provides for approximately 1.9 MMBbls of crude oil storage.
•Price River Terminal. The Price River Terminal is a rail terminal joint venture in Carbon County, Utah, capable of transloading local waxy crude production as well as other bulk materials. The terminal has 200 MBbls of heated storage and more than 60 MBbls/d of rail loading capacity.
•Colt Hub. 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.
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.
Investment in Sunoco LP
Sunoco LP’s fuel distribution and marketing operations are conducted by the following consolidated subsidiaries:
• Sunoco, LLC (“Sunoco LLC”), a Delaware limited liability company, primarily distributes motor fuel in more than 40 states throughout the United States. Sunoco LLC also processes transmix and distributes refined product through its terminals in over 15 states.
•Sunoco Retail LLC (“Sunoco Retail”), a Pennsylvania limited liability company, owns and operates retail stores that sell motor fuel and merchandise primarily in New Jersey. Sunoco Retail also leases owned sites to commission agents who sell motor fuels to the motoring public on Sunoco Retail's behalf for a commission.
•Aloha Petroleum LLC, a Delaware limited liability company, distributes motor fuel and operates terminal facilities on the Hawaiian Islands.
•Aloha Petroleum, Ltd. (“Aloha”), a Hawaii corporation, owns and operates retail stores on the Hawaiian Islands and leases owned sites to commission agents who sell motor fuels to the motoring public on Aloha's behalf for a commission.
•Peerless Oil & Chemicals, Inc. (“Peerless”), a Delaware corporation, is a terminal operator that distributes fuel products to over 100 locations primarily within Puerto Rico.
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.
Sunoco LP’s operations also include retail operations in Hawaii and New Jersey, credit card services and franchise royalties.
Investment in USAC
The following details the assets of USAC:
USAC’s modern, standardized compression unit fleet is powered primarily by the Caterpillar, Inc.’s 3400, 3500 and 3600 engine classes, which range from 401 to 5,000 horsepower per unit. These larger horsepower units, which USAC defines as 400 horsepower per unit or greater, represented 87.0% of its total fleet horsepower as of December 31, 2023. The remainder of its
fleet consists of smaller horsepower units ranging from 40 horsepower to 399 horsepower that are primarily used in gas lift applications.
The following table provides a summary of USAC’s compression units by horsepower as of December 31, 2023:
Unit Horsepower Fleet Horsepower Number of Units Horsepower on Order (1)
Number of Units on Order (1)
Total Horsepower Number of Units Percent of Fleet Horsepower Percent of Units
Small horsepower
<400 499,752 2,946 - - 499,752 2,946 13.0 % 54.6 %
Large horsepower
>400 and <1,000 416,983 715 - - 416,983 715 10.9 % 13.2 %
>1,000 2,858,925 1,714 52,500 21 2,911,425 1,735 76.1 % 32.2 %
Total large horsepower 3,275,908 2,429 52,500 21 3,328,408 2,450 87.0 % 45.4 %
Total horsepower 3,775,660 5,375 52,500 21 3,828,160 5,396 100.0 % 100.0 %
(1)As of December 31, 2023, USAC had 21 large horsepower units, consisting of 52,500 horsepower, on order for expected delivery during 2024.
All Other
The following details the significant assets in the “All Other” segment.
Compression
We own Dual Drive Technologies, Ltd, which provides compression services to customers engaged in the transportation of natural gas, including our other segments.
Natural Resources Operations
Our Natural Resources operations primarily involve the management and leasing of coal properties and the subsequent collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage fees. 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.
Business Strategy
We believe we have engaged, and will continue to engage, in a well-balanced plan for growth through strategic acquisitions, internally generated expansion, measures aimed at increasing the profitability of our existing assets and executing cost control measures where appropriate to manage our operations.
We intend to continue to operate as a diversified, growth-oriented limited partnership. We believe that by pursuing independent operating and growth strategies we will be best positioned to achieve our objectives. We balance our desire for growth with our goal of preserving a strong balance sheet, ample liquidity and investment grade credit metrics.
Following is a summary of the business strategies of our core businesses:
Growth through acquisitions. We intend to continue to make strategic acquisitions that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of our existing assets while supporting our investment grade credit ratings.
Engage in construction and expansion opportunities. We intend to leverage our existing infrastructure and customer relationships by constructing and expanding systems to meet new or increased demand for midstream and transportation services.
Increase cash flow from fee-based businesses. 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 profitability of our existing asset base by adding new volumes under long-term producer commitments, undertaking additional initiatives to enhance utilization and reducing costs by improving operations.
Competition
Natural Gas
The business of providing natural gas gathering, compression, treating, transportation, storage and marketing services is highly competitive. Since pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of our transportation and storage segment are other pipelines. Pipelines typically compete with each other based on location, capacity, price and reliability.
We face competition with respect to retaining and obtaining significant natural gas supplies under terms favorable to us for the gathering, treating and marketing portions of our business. Our competitors include major integrated oil and gas companies, interstate and intrastate pipelines and other companies that gather, compress, treat, process, transport and market natural gas. Many of our competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours.
In marketing natural gas, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil and gas companies, and local and national natural gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with our marketing operations.
NGL
In markets served by our NGL pipelines, we face competition with other pipeline companies, including those affiliated with major oil, petrochemical and natural gas companies, and barge, rail and truck fleet operations. In general, our NGL pipelines compete with these entities in terms of transportation fees, reliability and quality of customer service. We face competition with other storage facilities based on fees charged and the ability to receive and distribute the customer’s products. We compete with a number of NGL fractionators in Texas and Louisiana. Competition for such services is primarily based on the fractionation fee charged.
Crude Oil and Refined Products
In markets served by our crude oil and refined products pipelines, we face competition from other pipelines as well as rail and truck transportation. Generally, pipelines are the safest, lowest cost method for long-haul, overland movement of products and crude oil. Therefore, the most significant competitors for large volume shipments in the areas served by our pipelines are other pipelines. In addition, pipeline operations face competition from rail and trucks that deliver products in a number of areas that our pipeline operations serve. While their costs may not be competitive for longer hauls or large volume shipments, rail and trucks compete effectively for incremental and marginal volume in many areas served by our pipelines.
With respect to competition from other pipelines, the primary competitive factors consist of transportation charges, access to crude oil supply and market demand. Competitive factors in crude oil purchasing and marketing include price and contract flexibility, quantity and quality of services, and accessibility to end markets.
Our refined product terminals compete with other independent terminals with respect to price, versatility and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.
Wholesale Fuel Distribution and Retail Marketing
In our wholesale fuel distribution business, we compete primarily with other independent motor fuel distributors. The markets for distribution of wholesale motor fuel and the large and growing convenience store industry are highly competitive and fragmented, which results in narrow margins. We have numerous competitors, some of which may have significantly greater resources and name recognition than we do. Significant competitive factors include the availability of major brands, customer service, price, range of services offered and quality of service, among others. We rely on our ability to provide value-added and reliable service and to control our operating costs in order to maintain our margins and competitive position.
In our retail business, we face strong competition in the market for the sale of retail gasoline and merchandise. Our competitors include service stations of large integrated oil companies, independent gasoline service stations, convenience stores, fast food stores, supermarkets, drugstores, dollar stores, club stores and other similar retail outlets, some of which are well-recognized national or regional retail systems. The number of competitors varies depending on the geographical area. 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. We compete by pricing gasoline competitively, combining our retail gasoline business with convenience stores that provide a wide variety of products, and using advertising and promotional campaigns.
Credit Risk and Customers
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
Our natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. In addition to oil and gas producers, the Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
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. For FERC regulatory purposes, “transportation” includes natural gas pipeline transmission (forwardhauls and backhauls), storage and other services. FGT, Transwestern, Panhandle, Trunkline, Tiger, Fayetteville Express, Rover, Sea Robin, Midcontinent Express, EGT, MRT, SESH, Stingray, Gulf Run and Southwest Gas transport natural gas in interstate commerce and thus each qualifies as a “natural-gas company” under the NGA subject to the FERC’s regulatory jurisdiction. We also hold certain natural gas storage facilities that are subject to the FERC’s regulatory oversight under the NGA.
The FERC’s NGA authority includes the power to:
•approve the siting, construction and operation of new facilities;
•review and approve transportation rates;
•determine the types of services our regulated assets are permitted to perform;
•regulate the terms and conditions associated with these services;
•permit the extension or abandonment of services and facilities;
•require the maintenance of accounts and records; and
•authorize the acquisition and disposition of facilities.
Under the NGA, interstate natural gas companies must charge rates that are just and reasonable. In addition, the NGA prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
The maximum rates to be charged by NGA-jurisdictional natural gas companies and their terms and conditions for service are required to be on file with the FERC. Most natural gas companies are authorized to offer discounts from their FERC-approved maximum just and reasonable rates when competition warrants such discounts. 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 must make offers of rate discounts and negotiated rates on a basis that is not unduly discriminatory. 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. We cannot guarantee that the FERC will allow us to charge rates that fully recover our costs or continue to pursue its approach of pro-competitive policies.
Pursuant to the FERC’s rules promulgated under the Energy Policy Act of 2005 (the “EPAct of 2005”), it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of electric energy or natural gas or the purchase or sale of transmission or transportation services subject to FERC jurisdiction: (i) to defraud using any device, scheme or artifice; (ii) to make any untrue statement of material fact or omit a material fact; or (iii) to engage in any act, practice or course of business that operates or would operate as a fraud or deceit. The Commodity Futures Trading Commission (“CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act (“CEA”). In addition, the Federal Trade Commission has the authority under the Federal Trade Commission Act of 1914 and the Energy Independence and Security Act of 2007 to regulate wholesale petroleum markets. With regard to our physical purchases and sales of natural gas, NGLs or other energy commodities; our transportation of these energy commodities; and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by the FERC, the CFTC and/or the Federal Trade Commission. These agencies hold substantial enforcement authority, including the ability to assess or seek civil penalties of up to approximately $1.5 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
Failure to comply with the NGA, the EPAct of 2005, the CEA and the other federal laws and regulations governing our operations and business activities can result in the imposition of administrative, civil and criminal remedies.
Regulation of Intrastate Natural Gas and NGL Pipelines. Intrastate transportation of natural gas and NGLs is largely regulated by the state in which such transportation takes place. To the extent that our intrastate natural gas transportation systems transport natural gas in interstate commerce, the rates and terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the NGPA. The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. The rates and terms and conditions of some transportation and storage services provided on our pipeline systems of Enable Oklahoma Intrastate Transmission, LLC, Oasis Pipeline, LP, Houston Pipe Line Company LP, ETC Katy Pipeline, LLC, Energy Transfer Fuel, LP, , Lobo Pipeline Company, LLC, Pelico Pipeline, LLC, Regency Intrastate Gas LP, Red Bluff Express Pipeline, LLC, Trans-Pecos Pipeline, LLC and Comanche Trail Pipeline, LLC are subject to FERC regulation pursuant to Section 311 of the NGPA. 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. Should the FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our business may be adversely affected. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies.
Our intrastate natural gas operations are also subject to regulation by various agencies in Texas, principally the TRRC. Our intrastate pipeline and storage operations in Texas are also subject to the Texas Utilities Code, as implemented by the TRRC. Generally, the TRRC is vested with authority to ensure that rates, operations and services of gas utilities, including intrastate pipelines, are just and reasonable and not discriminatory. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a customer or TRRC complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies.
Our NGL pipelines and operations are subject to state statutes and regulations which could impose additional environmental, safety and operational requirements relating to the design, siting, installation, testing, construction, operation, replacement and management of NGL transportation systems. In some jurisdictions, state public utility commission oversight may include the possibility of fines, penalties and delays in construction related to these regulations. 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. Since we do not control the entire transportation path of all NGLs shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
Regulation of Sales of Natural Gas and NGLs. The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The price at which we sell NGLs is not subject to federal or state regulation.
To the extent that we enter into transportation contracts with natural gas pipelines that are subject to FERC regulation, we are subject to FERC requirements related to the use of such capacity. Any failure on our part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties.
Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC frequently proposes and implements new rules and regulations affecting those segments of the natural gas industry. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of the FERC’s regulatory changes may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action in a manner that is materially different from other natural gas marketers with whom we compete.
Regulation of Gathering Pipelines. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We own a number of natural gas pipelines in Texas, Louisiana and West Virginia that we believe meet the traditional tests the FERC uses to establish a pipeline’s status as a gathering pipeline not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation and varying interpretations, so the classification and regulation of our gathering facilities could be subject to change based on future determinations by the FERC, the courts and Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.
In Texas, our gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for our intrastate pipeline facilities. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities.
Historically, apart from pipeline safety, Louisiana has not acted to exercise this jurisdiction respecting gathering facilities. In Louisiana, our Chalkley System is regulated as an intrastate transporter, and the Louisiana Office of Conservation has determined that our Whiskey Bay System is a gathering system.
We are subject to state ratable take and common purchaser statutes in all of the states in which we operate. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting the right of an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination allegations. Our gathering operations could be adversely affected should they be subject in the future to the application of additional or different state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Regulation of Interstate Crude Oil, NGL and Products Pipelines. Interstate common carrier pipeline operations are subject to rate regulation by the FERC under the ICA, the EPAct of 1992, and related rules and orders. The ICA requires that tariff rates for petroleum pipelines be “just and reasonable” and not unduly discriminatory and that such rates and terms and conditions of service be filed with the FERC. 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. If the FERC finds that the new or changed rate is unlawful, it may require the carrier to pay refunds for the period that the rate was in effect. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.
The FERC generally has not investigated interstate rates on its own initiative when those rates, like those we charge, have not been the subject of a protest or a complaint by a shipper. However, the FERC could investigate our rates at the urging of a third party if the third party is either a current shipper or has a substantial economic interest in the tariff rate level. Although no assurance can be given that the tariff rates charged by us ultimately will be upheld if challenged, management believes that the tariff rates now in effect for our pipelines are within the maximum rates allowed under current FERC policies and precedents.
For many locations served by our product and crude pipelines, we are able to establish negotiated rates. Otherwise, we are permitted to charge cost-based rates, or in many cases, grandfathered rates based on historical charges or settlements with our customers. To the extent we rely on cost-of-service ratemaking to establish or support our rates, the issue of the proper allowance for federal and state income taxes could arise. In July 2016, the United States Court of Appeals for the District of Columbia Circuit issued an opinion in United Airlines, Inc., et al. v. FERC, finding that the FERC had failed to demonstrate that permitting an interstate petroleum products pipeline organized as a master limited partnership, or MLP, to include an income tax allowance in the cost of service underlying its rates, in addition to the discounted cash flow return on equity, would not result in the pipeline partnership owners double recovering their income taxes. The court vacated the FERC’s order and remanded to the FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance.
In March 2018, the FERC issued a Revised Policy Statement on Treatment of Income Taxes in which the FERC found that an impermissible double recovery results from granting an MLP pipeline both an income tax allowance and a return on equity pursuant to the FERC’s discounted cash flow methodology. The FERC revised its previous policy, stating that it would no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC stated it will address the application of the United Airlines decision to non-MLP partnership forms as those issues arise in subsequent proceedings. In July 2018, the FERC dismissed requests for rehearing and clarification of the March 2018 Revised Policy Statement, but provided further guidance, clarifying that a pass-through entity will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double recovery of investors’ income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding FERC’s March 2018 Revised Policy Statement, as clarified and revised on rehearing. In light of the rehearing order’s clarification regarding individual entities’ ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impacts the FERC’s policy on the treatment of income taxes may have on the rates an interstate pipeline held in a tax-pass-through entity can charge for the FERC regulated transportation services are unknown at this time. Please see “Item 1A. Risk Factors - Regulatory Matters.”
Effective January 2018, the 2017 Tax Cuts and Jobs Act changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. With the lower tax rate, and as discussed immediately above, the maximum tariff rates allowed by the FERC under its rate base methodology may be impacted by a lower income tax allowance component. Many of our interstate pipelines, such as Tiger, Midcontinent Express and Fayetteville Express, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines, and the rate base methodology does not apply directly to these contracts. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. In addition, several of these pipelines are covered by approved settlements, pursuant to which rate filings will be made in the future. As such, the timing and impact to these systems of any tax-related policy change is unknown at this time and varies based on the circumstances of each pipeline.
The EPAct of 1992 required the FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, the FERC adopted an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. The FERC’s indexing methodology is subject to review every five years.
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. Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG minus 0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period July 1, 2022 through June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the January 20 order with FERC, which was denied by FERC on May 6, 2022. Certain parties have appealed the January 20 and May 6 orders. Such appeals remain pending at the D.C. Circuit. The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates. A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling.
In November 2017, the FERC responded to a petition for declaratory order and issued an order that may have significant impacts on the way a marketer of crude oil or petroleum products that is affiliated with an interstate pipeline can price its services if those services include transportation on an affiliate’s interstate pipeline. In particular, the FERC’s November 2017 order prohibits buy/sell arrangements by a marketing affiliate if: (i) the transportation differential applicable to its affiliate’s interstate pipeline transportation service is at a discount to the affiliated pipeline’s filed rate for that service; and (ii) the pipeline affiliate subsidizes the loss. Several parties have requested that the FERC clarify its November 2017 order or, in the alternative, grant rehearing of the November 2017 order. On December 15, 2022, the FERC provided further clarification of its November 2017 order but denied requests for rehearing.
Finally, on December 15, 2022, the FERC issued a Proposed Policy Statement on Oil Pipeline Affiliate Committed Service, which addresses whether a contract for committed transportation service complies with the Interstate Commerce Act where the only shipper to obtain the committed service is an affiliate of the regulated entity. If adopted, the proposed policy statement would create a rebuttable presumption that affiliate contracts are unduly discriminatory and not just and reasonable in certain circumstances and require a pipeline to produce additional evidentiary support for affiliate contracts rates and terms. This follows a trend of increased scrutiny by FERC on affiliated contracts across all industries regulated by the FERC. Initial comments on the proposed policy statement were due on February 13, 2023. The FERC has taken no further action on the proposed policy statement since that time.
Regulation of Intrastate Crude Oil, NGL and Products Pipelines. Some of our crude oil, NGL and products pipelines are subject to regulation by the TRRC, the Pennsylvania Public Utility Commission and the Oklahoma Corporation Commission. The operations of our joint venture interests are also subject to regulation in the states in which they operate. The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions generally have not initiated an investigation of rates or practices of petroleum pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although management cannot be certain that our intrastate rates ultimately would be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.
In addition, as noted above, the rates, terms and conditions for shipments of crude oil, NGLs or products on our pipelines could be subject to regulation by the FERC under the ICA and the EPAct of 1992 if the crude oil, NGLs or products are transported in interstate or foreign commerce whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all crude oil, NGLs or products shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
Regulation of LNG Liquefaction Facilities and LNG Exports. The design, construction, operation, maintenance and expansion of our liquefaction facilities and the import or export of LNG are highly regulated activities subject to the jurisdiction of the FERC pursuant to the NGA. In contrast to pipeline regulation, the FERC does not require LNG terminal owners to provide open-access services at cost-based or regulated rates.
In order to site, construct and operate our LNG terminal, we received and are required to maintain authorizations from the FERC under Section 3 of the NGA as well as other material governmental and regulatory approvals and permits. 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. 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. Our FERC authorizations require us to comply with certain ongoing conditions and reporting obligations and to maintain other regulatory agency approvals throughout the life of our facilities. For example, throughout the life of our LNG terminal, we are subject to regular reporting requirements to the FERC, PHMSA, and applicable federal and state regulatory agencies regarding the operation and maintenance of our facilities. To date, we have been able to obtain and maintain required approvals as needed, and the need for these approvals and reporting obligations have not materially affected our construction or operations.
The export of LNG produced by any liquefaction facility in the United States requires export authorization from the DOE. The NGA requires the DOE to approve applications for LNG exports unless such approval would be “inconsistent with the public interest.” In March 2013, Lake Charles LNG Export obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”). FTA countries currently recognized by the DOE for exports of LNG include Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea and Singapore. 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. 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. 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. The Biden administration stated that these studies were necessary to enable the DOE to make determinations related to the statutory “public interest” standard. The DOE has stated that these studies will take several months to complete, after which a draft policy statement will be made available for public comment prior to finalizing the policy statement. This process is not expected to be completed prior to the U.S. Presidential election in November 2024.
Regulation of Pipeline Safety. Our pipeline operations are subject to regulation by the DOT, through PHMSA, pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA, as amended, govern the design, installation, testing, construction, operation, replacement and management of natural gas as well as crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas, which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources and unusually sensitive ecological areas. Failure to comply with the pipeline safety laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory, remedial or corrective action obligations, the occurrence of delays in permitting or the performance of projects, or the issuance of injunctions limiting or prohibiting some or all of our operations in the affected area.
The HLPSA and NGPSA have been amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016. The 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. The 2011 Pipeline Safety Act doubled the maximum administrative fines for safety violations from $0.1 million to $0.2 million for a single violation and from $1 million to $2 million for a related series of violations, but provided that these maximum penalty caps do not apply to certain civil enforcement actions. In May 2021, PHMSA issued a final rule increasing those maximum civil penalties to approximately $0.2 million per day, with a maximum of approximately $2 million for a series of violations, to account for inflation. Upon reauthorization of PHMSA, Congress often directs the agency to complete certain rulemakings. 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, in November 2021, PHMSA issued a final rule significantly expanding reporting and safety requirements of operators of gas gathering pipelines. 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. Additionally, in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas from related pipeline facilities. PHMSA, together with state regulators, are expected to commence and complete inspection of these plans in 2022.
In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. The states in which we conduct operations typically have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines. Under such state regulatory programs, states have the authority to conduct pipeline inspections, to investigate accidents and to oversee compliance and enforcement, safety programs and record maintenance and reporting. Congress, PHMSA and individual states may pass or implement additional safety requirements that could result in increased compliance costs for us and other companies in our industry. For example, federal construction, maintenance and inspection standards under the NGPSA that apply to pipelines in relatively populated areas may not apply to gathering lines running through rural regions. However, in October 2019, PHMSA published two further final rules, in addition to the November 2021 rule discussed above, that create or expand reporting, inspection, maintenance, and other pipeline safety obligations, including, among other things, extending pipeline integrity assessments to pipelines in certain locations, including newly-defined “Moderate Consequence Areas” (“MCAs”). Specifically, PHMSA issued a final rule imposing numerous requirements on onshore gas transmission pipelines relating to maximum allowable operating pressure (“MAOP”), reconfirmation and exceedance reporting, the integrity assessment of additional pipeline mileage found in MCAs, non-High Consequence Area (“HCAs”), and Class 3 and Class 4 areas by 2023, and the consideration of seismicity as a risk factor in integrity management. Establishing MAOP through reliance on historical pipeline design, construction, inspection, testing, and other records requires that such records be traceable, verifiable, and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing (including hydrotesting) or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. Failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipelines. PHMSA’s second final rule, published in October 2019, applicable to hazardous liquid transmission and gathering pipelines, significantly extended and expanded the reach of certain integrity management requirements, use of in-line inspection tools by 2039 (unless the pipeline cannot be modified to permit such use), increased annual, accident, and safety-related conditional reporting requirements, and expanded use of leak detection systems beyond HCAs. The integrity-related requirements and other provisions of the 2011 Pipeline Safety Act, the 2016 Pipeline Safety Act, and the PIPES Act of 2020, as well as any implementation of PHMSA rules thereunder, could require us to pursue additional capital projects or conduct integrity or maintenance programs on an accelerated basis and incur increased operating costs that could have a material adverse effect on our results of operations and financial condition.
In another example of how future legal requirements could result in increased compliance costs, notwithstanding the applicability of the federal OSHA’s Process Safety Management (“PSM”) regulations and the EPA’s Risk Management Planning (“RMP”) requirements at regulated facilities, PHMSA and one or more state regulators, including the TRRC, have in recent years, expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities, in order to assess compliance of such equipment and pipelines with hazardous liquid pipeline safety requirements. 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.
Environmental Matters
General. Our operation of processing plants, pipelines and associated facilities, including compression, in connection with the gathering, processing, storage and transmission of natural gas and the storage and transportation of NGLs, crude oil and refined products is subject to stringent U.S. federal, tribal, state and local laws and regulations, including those governing, among other things, air emissions, wastewater discharges, the use, management and disposal of hazardous and nonhazardous materials and wastes, and the cleanup of contamination. Similar or more stringent laws also exist in Canada. Noncompliance with such laws and regulations, or incidents resulting in environmental releases, could cause us to incur substantial costs, penalties, fines and criminal sanctions, third-party claims for personal injury or property damage, capital expenditures to retrofit or upgrade our facilities and programs, or curtailment or cancellation of permits on operations. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall cost of doing business, including our cost of planning, permitting, constructing and operating our plants, pipelines and other facilities. 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. Historically, our environmental compliance costs have not had a material adverse effect on our business, results of operations or financial condition; however, there can be no assurance that such costs will not be material in the future. For example, we cannot be certain that identification of presently unidentified conditions, more rigorous enforcement by regulatory agencies, enactment of more stringent environmental laws and regulations or unanticipated events will not arise in the future and give rise to environmental liabilities that could have a material adverse effect on our business, financial condition or results of operations.
Uncertainty about the future course of regulation continues to exist following the change in U.S. presidential administrations in January 2021. Upon taking office, the Biden Administration issued an executive order directing all federal agencies to review and take action to address any federal regulations promulgated during the prior administration that may be inconsistent with the current administration’s policies. As a result, several regulatory developments have occurred, but it remains unclear the degree to which this will continue. The executive order also established an Interagency Working Group on the Social Cost of Greenhouse Gases (“Working Group”), which is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” During 2021, the Working Group published interim estimates of the social costs of carbon, methane, and nitrous oxide and sought public comment on these estimates. The Working Group has not yet published its final recommendations. Further regulation of air emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand for oil and natural gas and, in turn, have a material adverse effect on our business, financial condition or results of operations.
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. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of hazardous substances and waste materials and may require investigatory and remedial actions at sites where such material has been released or disposed. For example, the Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of a “hazardous substance” into the environment. These persons include the owner and operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substance that has been released into the environment. Under CERCLA, these persons may be subject to strict, joint and several liability, without regard to fault, for, among other things, the costs of investigating and remediating the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA and comparable state law also authorize the federal EPA, its state counterparts, and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we generate wastes that may fall within that definition or that may be subject to other waste disposal laws and regulations. We may be responsible under CERCLA or state laws for all or part of the costs required to clean up sites at which such substances or wastes have been disposed.
We also generate both hazardous and nonhazardous wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, as amended, (“RCRA”) and comparable state statutes. We are not currently required to comply with a substantial portion of the RCRA hazardous waste requirements at many of our facilities because the minimal quantities of hazardous wastes generated there make us subject to less stringent non-hazardous management standards. From time to time, the EPA has considered or third parties have petitioned the agency on the adoption of stricter handling, storage and disposal standards for nonhazardous wastes, including certain wastes associated with the exploration, development and production of crude oil and natural gas. For example, in 2016, the EPA entered into an agreement with several environmental groups to analyze certain Subtitle D criteria regulations pertaining to oil and gas wastes and, if necessary, revise them. In response to the decree, in April 2019, the EPA signed a determination that revision of the regulations is not necessary at this time. It is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements, or that the full complement of RCRA standards could be applied to facilities that generate lesser amounts of hazardous waste. 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.
We currently own or lease sites that have been used over the years by prior owners and lessees and by us for various activities related to gathering, processing, storage and transmission of natural gas, NGLs, crude oil and refined products. Waste disposal practices within the oil and gas industry have improved over the years with the passage and implementation of various
environmental laws and regulations. Nevertheless, some hydrocarbons and wastes have been disposed of or otherwise released on or under various sites during the operating history of those facilities that are now owned or leased by us. Notwithstanding the possibility that these releases may have occurred during the ownership or operation of these assets by others, these sites may be subject to CERCLA, RCRA and comparable state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or contamination (including soil and groundwater contamination) or to prevent the migration of contamination.
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.
The Partnership is subject to extensive and frequently changing federal, tribal, state and local laws and regulations, including those relating to the discharge of materials into the environment or that otherwise relate to the protection of the environment, waste management and the characteristics and composition of fuels. 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 legacy sites that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that are no longer operated by ETC Sunoco, closed and/or sold refineries and other formerly owned sites. We have established a wholly owned captive insurance company for these legacy sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company. 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. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.
Under various environmental laws, including the RCRA, the Partnership has initiated corrective remedial action at certain of its facilities, formerly owned facilities and at certain third-party sites. At the Partnership’s major manufacturing facilities, we have typically assumed continued industrial use and a containment/remediation strategy focused on eliminating unacceptable risks to human health or the environment. The remediation accruals for these sites reflect that strategy. Accruals include amounts designed to prevent or mitigate off-site migration and to contain the impact on the facility property, as well as to address known, discrete areas requiring remediation within the plants. Remedial activities include, for example, closure of RCRA waste management units, recovery of hydrocarbons, handling of impacted soil, mitigation of surface water impacts and prevention or mitigation of off-site migration. A change in this approach as a result of changing the intended use of a property or a sale to a third party could result in a comparatively higher cost remediation strategy in the future.
In general, a remediation site or issue is typically evaluated on an individual basis based upon information available for the site or issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (for example, service station sites) in determining the amount of probable loss accrual to be recorded. The estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance allows us the minimum amount of the range to accrue. 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.
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. 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. If changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could materially and adversely impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to time, significant charges against income for environmental remediation may occur. And while management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position, it can provide no assurance.
Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by PCBs, and the costs of this work are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2025 is $3 million, which is included in the total environmental accruals mentioned above. Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007. Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCB contamination. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by customers and former customers. Such future costs are not expected to have a material impact on our financial position, results of operations or cash flows, but management can provide no assurance.
Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities, such as our processing plants and compression facilities, expected to produce air emissions or to result in the increase of existing air emissions, that we obtain and strictly comply with air permits containing various emissions and operational limitations, or that we utilize specific emission control technologies to limit emissions. We will incur capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. In addition, our processing plants, pipelines and compression facilities are subject to increasingly stringent regulations, including regulations that require the installation of control technology or the implementation of work practices to control hazardous air pollutants. Moreover, the Clean Air Act requires an operating permit for major sources of emissions and this requirement applies to some of our facilities. Historically, our costs for compliance with existing Clean Air Act and comparable state law requirements have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future. The EPA and state agencies are often considering, proposing or finalizing new regulations that could impact our existing operations and the costs and timing of new infrastructure development. For example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA completed attainment/non-attainment designations in 2018, and states with moderate or high non-attainment areas must submit state implementation plans to the EPA by October 2021. By law, the EPA must review each NAAQS every five years. In December 2020, the EPA announced that it was retaining without revision the 2015 NAAQS for ozone. However, the Biden Administration has announced plans to formally review this decision and consider instituting a more stringent standard. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to our customers’ operations. 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. The Federal Water Pollution Control Act of 1972, as amended, (“Clean Water Act”) and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including hydrocarbon-bearing wastes, into state waters and waters of the United States. Pursuant to the Clean Water Act and similar state laws, a National Pollutant Discharge Elimination System, or state permit, or both, must be obtained to discharge pollutants into federal and state waters. In addition, the Clean Water Act and comparable state laws require that individual permits or coverage under general permits be obtained by subject facilities for discharges of storm water runoff. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. 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 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. EPA, which used the “continuous surface connection” test to determine whether wetlands qualify as WOTUS. The Sackett decision invalidated certain parts of the January 2023 rule and significantly narrowed its scope, resulting in a revised rule being issued in September 2023; however, the September 2023 rule did not define the term “continuous surface connection.” Due to the injunction, implementation of the rule currently varies by state, and it remains unclear how broadly the agencies will interpret the term “continuous surface connection.” As a result of these developments,
the scope of jurisdiction under the Clean Water Act is uncertain at this time, but to the extent any rule expands the scope of the Clean Water Act’s jurisdiction, our operations as well as our exploration and production customers’ drilling programs could incur increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.
Additionally, for over 35 years, the USACE has authorized construction, maintenance, and repair of pipelines under a streamlined Nationwide Permit (“NWP”) program. From time to time, environmental groups have challenged the NWP program, and, in April 2020, the U.S. District Court for the District of Montana determined that NWP 12 failed to comply with consultation requirements under the federal Endangered Species Act. The district court vacated NWP 12 and enjoined the issuance of new authorizations for oil and gas pipeline projects under the permit. In January 2021, the EPA and USACE issued a final rule reissuing and restricting NWP 12 to oil and gas pipelines and creating a new nationwide permit to authorize certain dredge and fill activities associated with utility lines conveying other substances such as brine, potable water, wastewater, and other substances excluding oil, natural gas, products derived from oil or natural gas, and electricity. The Biden Administration was asked to examine the final rule. Additionally, an October 2021 decision by the District Court for the Northern District of California resulted in the vacatur of a 2020 rule revising the Clean Water Act Section 401 certification process, following which, in November 2021, USACE announced that it has temporarily suspended finalization of certain permitting decisions, including under NWP 12, that rely on a Section 401 certification or waiver under the 2020 rule. This vacatur was subsequently stayed by the U.S. Supreme Court in April 2022, and the EPA published a final rule to update and replace the relevant regulations in September 2023. We could face significant delays and financial costs if we must obtain individual permit coverage from USACE for our projects as a result of any future actions.
Spills. Our operations can result in the discharge of regulated substances, including NGLs, crude oil or other products. The Clean Water Act, as amended by the federal Oil Pollution Act of 1990, as amended, (“OPA”), and comparable state laws impose restrictions and strict controls regarding the discharge of regulated substances into state waters or waters of the United States. The Clean Water Act and comparable state laws can impose substantial administrative, civil and criminal penalties for non-compliance including spills and other non-authorized discharges. The OPA subjects owners of covered facilities to strict joint and potentially unlimited liability for removal costs and other consequences of a release of oil, where the release is into navigable waters, along shorelines or in the exclusive economic zone of the United States. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require that containment dikes and similar structures be installed to help prevent the impact on navigable waters in the event of a release of oil. PHMSA, the EPA, or various state regulatory agencies, has approved our oil spill emergency response plans that are to be used in the event of a spill incident.
In addition, some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Our management believes that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our results of operations, financial position or expected cash flows.
Endangered Species. The Endangered Species Act, as amended, restricts activities that may affect endangered or threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may operate in areas that are currently designated as a habitat for endangered or threatened species or where the discovery of previously unidentified endangered species, or the designation of additional species as endangered or threatened may occur in which event such one or more developments could cause us to incur additional costs, to develop habitat conservation plans, to become subject to expansion or operating restrictions, or bans in the affected areas. Moreover, such designation of previously unprotected species as threatened or endangered in areas where our oil and natural gas exploration and production customers operate could cause our customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of operations, which could reduce demand for our services.
Climate Change. Climate change continues to attract considerable public, governmental and scientific attention. 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 greenhouse gases (“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. 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, and, in the United States, President Biden has announced that he intends to pursue substantial reductions in GHG emissions, particularly from the oil and gas sector. For example, on January 27, 2021, President Biden signed an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, an increase in the production of offshore wind energy, and an increased emphasis on climate-related risks across government agencies and economic sectors. 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. 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. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines.
Federal agencies also have begun directly regulating GHG emissions, such as methane, from oil and natural gas operations. 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 volatile organic compound (“VOC”) emissions. These Subpart OOOOa standards expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. In September 2020, the EPA removed natural gas transmission and storage operations from this sector and rescinded the methane-specific requirements of the rule for production and processing facilities. However, Congress passed, and President Biden signed into law, a revocation of the 2020 rulemaking, effectively reinstating the 2016 standards. 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 the 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 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. The December 2023 rule also establishes a “super-emitter” response program that would allow third parties to make reports to the EPA of large methane emission events, triggering certain investigation and repair requirements. Fines and penalties for violations of these rules could be substantial. GHG emission standards, including methane emissions imposed on the oil and gas sector, could result in increased costs to our operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. Several states have also adopted, or are considering adopting, regulations related to GHG emissions, some of which are more stringent than those implemented by the federal government.
At the international level, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France in signing the “Paris Agreement,” a treaty that requires member countries to submit individually-determined, non-binding emission reduction goals every five years beginning in 2020. Although the United States withdrew from the Paris Agreement under the Trump administration, President Biden recommitted the United States in February 2021, and, in April 2021, announced a new, more rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. The international community gathered again in Glasgow in November 2021 at the 26th Conference of the Parties (“COP26”) during which multiple announcements were made, including a call for parties to eliminate fossil fuel subsidies, amongst other measures. Relatedly, the United States and European Union jointly announced at COP26 the launch of the Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. In December 2023, at the 28th Conference of the Parties (“COP28”), the parties signed onto an agreement to transition away from fossil fuels in energy systems and increase renewable energy capacity, although no timeline for doing so was set.
President Biden’s January 2021 climate change executive order directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs. The executive order also directed the federal government to identify “fossil fuel subsidies” to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. As noted above, a separate executive order issued in January 2021 established a Working Group that is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” During 2021, the Working Group published interim estimates of the social costs of carbon, methane, and nitrous oxide and sought public comment on these estimates. The Working Group has not yet published its final recommendations. However, in September 2023, President Biden issued an executive order directing agencies to consider the Working Group’s social cost of a project’s greenhouse gases when conducting environmental reviews of major federal actions.
The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Litigation risks are also increasing, as several oil and gas companies have been sued for allegedly causing climate-related damages due to their production and sale of fossil fuel products or for allegedly being aware of the impacts of climate change for some time but failing to adequately disclose such risks to their investors or customers. Various investors are becoming increasingly concerned about the potential effects of climate change and may elect in the future to shift some or all of their investments into other sectors. 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. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero by 2050. Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding for fossil fuel energy companies. In late 2020, the Federal Reserve joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. More recently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Such efforts could make it more difficult to secure funding for exploration and production or midstream activities and could also increase the cost of obtaining financings and/or negatively affect terms of financings.
Finally, climatic events in the areas in which we operate, whether from climate change or otherwise, can cause disruptions and, in some cases, delays in, or suspension of, our services. These events, including but not limited to drought, winter storms, wildfire, extreme temperatures or flooding, may become more intense or more frequent as a result of climate change and could have an adverse effect on our continued operations. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities or our customers’ facilities from powerful winds or rising waters, or increased costs for, or difficulty obtaining, insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our NGLs and natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we transport, and thus demand for our services. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our products could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.
We recognize the need to decrease emissions and integrate alternative energy sources into our operations, and we actively pursue economically beneficial opportunities to reduce our environmental footprint throughout our operations. Protecting public health and the environment is the primary initiative of our environmental management teams, both in the construction and operation of our assets. These teams have worked to reduce our emissions and minimize our environmental impact. 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.
Powering our assets through renewable energy sources is an established part of our operations where it is economically viable to do so. We have reduced our carbon footprint by using a diversified mix of energy sources, including solar and wind power to generate electrical power. 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.
In February 2021, we announced the formation of our alternative energy group. This group is tasked with increasing our efforts to support renewable energy projects such as solar and/or wind farms, either as a power purchaser, or in a partnership with third party developers, when they make economic sense. This group is also focused on developing alternative energy projects aimed at reducing the environmental footprint throughout our operations, including a variety of projects related to carbon capture, utilization and sequestration of CO2.
While our environmental management initiatives have not materially impacted our capital expenditures or results of operations, we recognize that the non-financial impacts of these initiatives are of interest to our investors and other stakeholders. 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. For additional information on our environmental management initiatives, including our efforts to curb GHG emissions and to integrate alternative energy sources, please see our Corporate Responsibility Report available on our website at http://www.energytransfer.com/corporate-responsibility. Information contained on our website is not part of this report.
Employee Health and Safety. We are subject to the requirements of the federal OSHA and comparable state laws that regulate the protection of the health and safety of workers. In addition, the Occupational Safety and Health Administration’s hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. Historically, our costs for OSHA required activities, including general industry standards, recordkeeping requirements, and monitoring of occupational exposure to regulated substances, have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.
Natural Resource Reviews. The National Environmental Policy Act (“NEPA”) provides for an environmental impact assessment process in connection with certain projects that involve federal lands or require approvals by federal agencies. The NEPA process implicates a number of other environmental laws and regulations, including the Endangered Species Act, Migratory Bird Treaty Act, Rivers and Harbors Act, Clean Water Act, Bald and Golden Eagle Protection Act, Fish and Wildlife Coordination Act, Marine Mammal Protection Act and National Historic Preservation Act, often requiring coordination with numerous governmental authorities. The NEPA review process can be lengthy and subjective, resulting in delays in obtaining federal approvals for projects. Our projects that are subject to the NEPA can include pipeline construction and pipeline integrity projects that involve federal lands or require approvals by federal agencies. In July 2020, the Council on Environmental Quality (“CEQ”) issued final revisions to NEPA regulations that seek to conform the scope of direct, indirect, and cumulative impact analyses for proposed projects subject to NEPA with existing case law. However, in October 2021, the CEQ published a proposed rule to restore, in general, NEPA regulations that were in effect before being modified by the 2020 revisions. This rule was finalized in April 2022, and CEQ issued additional proposed revisions to NEPA regulations in July 2023. More stringent environmental impact analyses under or third-party challenges with respect to the sufficiency of any environmental impact statement or assessment prepared pursuant to NEPA could adversely impact such projects in the form of delays or increased compliance and mitigations costs.
Indigenous Protections. Part of our operations cross land that has historically been apportioned to various Native American/First Nations tribes (“Indigenous Peoples”), who may exercise significant jurisdiction and sovereignty over their lands. Indigenous Peoples may also have certain treaty rights and rights to consultation on projects that may affect such lands. 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. Although the court’s ruling indicates that it is limited to criminal law, as applied within the Muscogee (Creek) Nation reservation, the ruling may have significant potential implications for civil law, both in the Muscogee (Creek) Nation reservation and other reservations that may similarly be found to not have been disestablished. State courts in Oklahoma have applied the analysis in McGirt in ruling that the Cherokee, Chickasaw, Seminole, and Choctaw reservations likewise had not been disestablished.
On October 1, 2020, the EPA granted approval to the State of Oklahoma under Section 10211(a) of the Safe, Accountable, Flexible, Efficient Transportation Equity Act of 2005 (the “SAFETE Act”) to administer all of the State’s existing EPA-approved regulatory programs to Indian Country within the state except: Indian allotments to which Indians titles have not been extinguished; lands that are held in trust by the United States on behalf of any Indian or Tribe; lands that are owned in fee by any Tribe where title was acquired through a treaty with the United States to which such tribe is a party and that have never been allotted to any citizen or member of such Tribe. The approval extends the State’s authority for existing EPA-approved regulatory programs to all lands within the State to which the State applied such programs prior to the U.S. Supreme Court’s ruling in McGirt. However, several Tribes expressed dissatisfaction with the consultation process performed in relation to this approval, and, in December 2021, the EPA proposed to withdraw and reconsider the October 2020 decision. Additionally, the SAFETE Act provides that any Tribe in Oklahoma may seek “Treatment as a State” by the EPA, and it is possible that one or more of the Tribes in Oklahoma may seek such an approval from the EPA. At this time, we cannot predict how these jurisdictional issues may ultimately be resolved.
Human Capital Management
As of December 31, 2023, Energy Transfer and its consolidated subsidiaries employed an aggregate of 13,786 employees, 1,422 of which are represented by labor unions. We believe that our relations with our employees are good.
Our employees are our greatest asset, and we seek to attract and retain top talent by fostering a culture that is guided by our core values and that respects all people and cultures, promotes safety, and focuses on the protection of public health and being a good steward of the environment.
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. We recognize that people are our most valued resource, and we are committed to hiring and investing in employees who strive for excellence and live by our core values: working safely, corporate stewardship, ethics and integrity, entrepreneurial mindset, our people, excellence and results, and social responsibility. We value our employees for what they bring to our organization by embracing those from all backgrounds, cultures, and experiences. We also believe that the keys to our successes have been the cultivation of an atmosphere of inclusion and respect within our family of partnerships and sustaining organizations that promote diversity and provide support across all communities in which we do business. These are the principles upon which we build and strengthen relationships among our people, our stakeholders, and those within the communities in which we do business.
Respecting All People and All Cultures. We believe strict adherence to our Code of Business Conduct and Ethics is not only right, but is in the best interest of the Partnership, its Unitholders, its customers, and the industry in general. In all applicable instances, the policies of the Partnership require that the business of the Partnership be conducted in a lawful and ethical manner. Every employee acting on behalf of the Partnership must adhere to these policies. Please refer to “Item 10. Directors, Executive Officers and Corporate Governance” for additional information on our Code of Business Conduct and Ethics.
Commitment to Public Health, Safety and the Environment. Protecting public health and being a good steward of the environment is an important initiative for our environmental management teams, both in the construction and operation of our assets. These teams consist of environmental engineers, scientists and geologists who seek to responsibly and efficiently reduce emissions associated with our operations, be a good steward of the land, water and air in the areas where we operate, and remain in compliance with all applicable regulations. Our environmental, health and safety department’s more than 200 environmental and safety professionals provide environmental and safety training to our field representatives. This group also assists others throughout the organization by identifying continuous training for personnel, including training that is required by applicable laws, regulations, standards, and permit conditions. It is our policy to communicate our safety standards and expectations to all employees and contractors with the expectation that each individual has the obligation to make safety the highest priority. Our safety culture aims to promote an open environment for discovering, resolving, and sharing safety challenges. We strive to eliminate unwanted safety events through a comprehensive process that promotes leadership, employee involvement, communication, personal responsibility to comply with standard operating procedures and regulatory requirements, effective risk reduction processes, maintaining clean facilities, contractor safety, and personal wellness. Energy Transfer’s goal is operational excellence, which means an injury- and incident-free workplace. To achieve this, we strive to hire and maintain the most qualified and dedicated workforce in the industry and make safety and safety accountability part of our daily operations. We believe that the OSHA Total Reportable Incident Rate (“TRIR”) is a key performance indicator that we use to evaluate our safety programs. TRIR can provide companies with a look at their safety record performance for the year by calculating the number of recordable injury and illness incidents per 200,000 hours worked. Our TRIR was 0.77 for 2023, out of approximately 18.9 million hours worked during the year, compared to a TRIR of 1.01 for 2022. We believe the Partnership’s low TRIR speaks to the Partnership’s investment in and focus on safety and environmental compliance as well as the reliability of our assets.
For additional information on our Human Capital Management initiatives, please see our Corporate Responsibility Report available on our website at http://www.energytransfer.com/corporate-responsibility. Please note that the preceding internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found and/or provided at such internet address or contained on our website in general is intended or deemed to be incorporated by reference in this report.
SEC Reporting
We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the SEC. From time to time, we may also file registration statements and related documents pertaining to equity or debt offerings. The SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
We provide electronic access, free of charge, to our periodic and current reports, and amendments to these reports, on our internet website located at http://www.energytransfer.com. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with the SEC. Information contained on our website is not part of this report.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
The following is a summary of important risk factors that are specific to our business, industry and partnership structure that could materially impact our future performance and results of operations. These risk factors should be reviewed when considering an investment in our securities. These are not all the risks we face. Other factors that we face in the ordinary course of business that are currently considered immaterial or that are currently unknown to us may impact our future operations.
Risk Factor Summary
Risks Related to the Partnership’s Business
Results of Operations and Financial Condition. 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.
Indebtedness. Our business, results of operations, cash flows and financial condition, as well as our ability to make distributions, could be impacted by the following:
•our debt level and debt agreements, or increases in interest rates;
•the credit and risk profile of our general partner and its owners; and
•a downgrade of our credit ratings.
Capital Projects and Future Growth. 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.
Regulatory Matters. 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.
Risks Relating to Our Partnership Structure
Cash Distributions to Unitholders. Our cash distributions could be impacted by the following:
•our general partner’s absolute discretion in issuing an unlimited number of limited partner interests or other classes of equity without the consent of our Unitholders;
•cash distributions are not guaranteed and may fluctuate with our performance and other external factors;
•limitations on available cash that are imposed by our distribution policy;
•our general partner’s absolute discretion in determining the level of cash reserves; and
•unitholders’ potential liability to repay distributions.
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. Risks that are unique to our subsidiaries and/or our relationship to our subsidiaries could reduce our subsidiaries’ cash available for distributions to us, including:
•the potential issuance of additional common units by Sunoco LP or USAC;
•a significant decrease in demand for or the price of motor fuel in the areas Sunoco LP serves;
•disruptions in Sunoco LP’s operations due to dangers inherent in motor fuel transportation;
•seasonal industry trends, which may cause Sunoco LP’s operating costs to fluctuate;
•adverse publicity for Sunoco LP resulting from negative events or developments;
•increased costs to retain necessary land use, which could disrupt Sunoco LP’s operations; and
•federal, state and local laws and regulations that govern the industries in which our subsidiaries operate.
Risks Related to Conflicts of Interest. Our stakeholders could be impacted by conflicts of interest, including:
•our general partner may favor its own interests to the detriment of our Unitholders;
•fiduciary duties owed to Sunoco LP, USAC and their respective unitholders by their general partners; and
•potential conflicts of interest faced by directors and officers in managing our business.
Tax Risks. Our stakeholders could be impacted by tax risks, including:
•our tax treatment depends on our status as a partnership for federal income tax purposes, and not being subject to a material amount of entity-level taxation;
•our cash available for distribution to Unitholders may be substantially reduced if we become subject to entity-level taxation as a result of the IRS treating us as a corporation or legislative, judicial or administrative changes, and may also be reduced by any audit adjustments if imposed directly on the partnership;
•even if Unitholders do not receive any cash distributions from us, Unitholders will be required to pay taxes on their share of our taxable income;
•a Unitholder’s share of our taxable income may be increased as a result of the IRS successfully contesting any of the federal income tax positions we take;
•tax-exempt entities and non-U.S. 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.
Risk Factor Discussion
The following discussion provides additional information regarding each of our risk factors listed above. In addition, Sunoco LP and USAC file Annual Reports on Form 10-K that include risk factors that can be reviewed for further information.
Risk Relating to the Partnership’s Business
Results of Operations and Financial Condition
Our cash flow depends primarily on the cash distributions we receive from our subsidiaries, as well as our partnership interests in Sunoco LP and USAC, including the IDRs in Sunoco LP and, therefore, our cash flow is dependent upon the ability of our subsidiaries, Sunoco LP and USAC to make distributions in respect of those partnership interests.
We do not have any significant assets other than our interests in our subsidiaries. As a result, our cash flow depends on the performance of our subsidiaries, including Sunoco LP and USAC, and their ability to make cash distributions, which is dependent on the results of operations, cash flows and financial condition of our subsidiaries, including Sunoco LP and USAC.
The amount of cash that our subsidiaries distribute to us each quarter depends upon the amount of cash generated from our subsidiaries’ operations, which will fluctuate from quarter to quarter and will depend upon, among other things:
•the amount of natural gas, NGLs, crude oil and refined products transported through our subsidiaries’ pipelines;
•the level of throughput in processing and treating operations;
•the fees charged and the margins realized by our subsidiaries, including Sunoco LP and USAC, for their services;
•the price of natural gas, NGLs, crude oil and refined products;
•the relationship between natural gas, NGL and crude oil prices;
•the weather in their respective operating areas;
•the level of competition from other midstream, transportation and storage and retail marketing companies and other energy providers;
•the level of their respective operating costs and maintenance and integrity capital expenditures;
•the tax profile on any blocker entities treated as corporations for federal income tax purposes that are owned by any of our subsidiaries;
•prevailing economic conditions; and
•the level and results of their respective derivative activities.
In addition, the actual amount of cash that 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 they 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;
•debt service requirements;
•fluctuations in working capital needs;
•their ability to borrow under their respective revolving credit facilities;
•their ability to access capital markets;
•restrictions on distributions contained in their respective debt agreements; and
•the amount, if any, of cash reserves established by the board of directors and their respective general partners in their discretion for the proper conduct of their respective businesses.
Energy Transfer does not have any control over many of these factors, including the level of cash reserves established by the board of directors. 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.
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. As a result, our subsidiaries may declare and/or pay cash distributions during periods when they record net losses.
Income from our midstream, transportation, terminalling and storage operations is exposed to risks due to fluctuations in the demand for and price of natural gas, NGLs, crude oil and refined products that are beyond our control.
The prices for natural gas, NGLs, crude oil and refined products reflect market demand that fluctuates with changes in global and United States economic conditions and other factors, including:
•the level of domestic natural gas, NGL, refined products and oil production;
•the level of natural gas, NGL, refined products and oil imports and exports, including liquefied natural gas;
•actions taken by natural gas and oil producing nations;
•instability or other events affecting natural gas and oil producing nations;
•the impact of weather, geopolitical events such as the armed conflict in Ukraine and political instability in the Middle East, public health crises, and other events of nature on the demand for natural gas, NGLs, refined products and oil;
•the availability of storage, terminal and transportation systems, and refining, processing and treating facilities;
•the price, availability and marketing of competitive fuels;
•supply chain disruptions and inflation;
•the demand for electricity;
•activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas and related products;
•rising interest rates and slowing economic growth;
•the cost of capital needed to maintain or increase production levels and to construct and expand facilities;
•the impact of energy conservation and fuel efficiency efforts; and
•the extent of governmental regulations, taxation, fees and duties.
In the past, the prices of natural gas, NGLs, refined products and oil have been extremely volatile, and we expect this volatility to continue.
Any loss of business from existing customers or our inability to attract new customers due to a decline in demand for natural gas, NGLs, refined products or oil could have a material adverse effect on our revenues and results of operations. In addition, significant price fluctuations for natural gas, NGL, refined products and oil commodities could materially affect our profitability.
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. A sustained increase in inflation may continue to increase our costs for labor, services, and materials, which, in turn, could cause our operating costs and capital expenditures to increase. Further, our producer suppliers and customers face inflationary pressures and resulting impacts, such as the tight labor market, availability of drilling and hydraulic fracturing equipment, and supply chain disruptions, which could increase the cost of production which in turn may limit the level of drilling activity in the regions in which we operate. Our throughput volumes may be impacted if producers are constrained. The rate and scope of these various inflationary factors may increase our operating costs and capital expenditures materially, which may not be readily recoverable in the prices of our services and may have an adverse effect on our results of operations and financial condition.
Additionally, the Federal Reserve and other central banks have implemented policies in an effort to curb inflationary pressure on the costs of goods and services across the U.S., including the significant increases in prevailing interest rates that occurred during 2022 and 2023 as a result of the 525 aggregate basis point increase in the federal funds rate, and the associated macroeconomic impact on slowdown in economic growth could negatively impact our business. While the Federal Reserve indicated in December 2023 that it may reduce benchmark interest rates in 2024, the continuation of rates at the current level could have the effects of raising the cost of capital and depressing economic growth, either of which-or the combination thereof-could hurt the financial and operating results of our business.
An impairment of goodwill and intangible assets could reduce our earnings.
As of December 31, 2023, our consolidated balance sheet reflected $4.02 billion of goodwill and $6.24 billion of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization.
We depend on certain key producers for our supply of natural gas and the loss of any of these key producers could adversely affect our financial results.
Certain producers who are connected to our systems represent a material source of our supply of natural gas. We are not the only option available to these producers for disposition of the natural gas they produce. To the extent that these and other producers may reduce the volumes of natural gas that they supply us, we would be adversely affected unless we were able to acquire comparable supplies of natural gas from other producers.
Our intrastate transportation and storage and interstate transportation and storage operations depend on key customers to transport natural gas through our pipelines and the pipelines of our joint ventures.
During 2023, two customers accounted for approximately 36% of our intrastate transportation and storage revenues. During 2023, four customers collectively accounted for 30% of our interstate transportation and storage revenues.
Certain of our joint ventures also depend on key customers. Citrus has long-term agreements with its top two customers which accounted for 52% of its 2023 revenue. For the Trans-Pecos and Comanche Trail pipelines, a single customer is the primary shipper.
The failure of the major shippers on our and our joint ventures’ intrastate and interstate transportation and storage pipelines to fulfill their contractual obligations could have a material adverse effect on our cash flow and results of operations if we or our joint ventures were unable to replace these customers under arrangements that provide similar economic benefits as these existing contracts.
We may be unable to retain or replace existing midstream, transportation, terminalling and storage customers or volumes due to declining demand or increased competition in crude oil, refined products, natural gas and NGL markets, which would reduce our revenues and limit our future profitability.
The retention or replacement of existing customers and the volume of services that we provide at rates sufficient to maintain or increase current revenues and cash flows depends on a number of factors beyond our control, including the price of and demand for crude oil, refined products, natural gas and NGLs in the markets we serve and competition from other service providers.
A significant portion of our sales of natural gas are to industrial customers and utilities. As a consequence of the volatility of natural gas prices and increased competition in the industry and other factors, industrial customers, utilities and other gas customers are increasingly reluctant to enter into long-term purchase contracts. Many customers purchase natural gas from more than one supplier and have the ability to change suppliers at any time. Some of these customers also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are many companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in natural gas sales markets primarily on the basis of price.
We also receive a substantial portion of our revenues by providing natural gas gathering, processing, treating, transportation and storage services. While a substantial portion of our services are sold under long-term contracts for reserved service, we also provide service on an unreserved or short-term basis. Demand for our services may be substantially reduced due to changing market prices. Declining prices may result in lower rates of natural gas production resulting in less use of services, while rising prices may diminish consumer demand and also limit the use of services. In addition, our competitors may attract our customers’ business. If demand declines or competition increases, we may not be able to sustain existing levels of unreserved service or renew or extend long-term contracts as they expire or we may reduce our rates to meet competitive pressures.
Revenue from our NGL transportation systems and refined products storage is also exposed to risks due to fluctuations in demand for transportation and storage service as a result of unfavorable commodity prices, competition from nearby pipelines, and other factors. We receive substantially all of our transportation revenues through dedicated contracts under which the customer agrees to deliver the total output from particular processing plants that are connected only to our transportation
system. Reduction in demand for natural gas or NGLs due to unfavorable prices or other factors, however, may result lower rates of production under dedicated contracts and lower demand for our services. In addition, our refined products storage revenues are primarily derived from fixed capacity arrangements between us and our customers, a portion of our revenue is derived from fungible storage and throughput arrangements, under which our revenue is more dependent upon demand for storage from our customers.
The volume of crude oil and refined products transported through our crude oil and refined products pipelines and terminal facilities depends on the availability of attractively priced crude oil and refined products in the areas serviced by our assets. A period of sustained price reductions for crude oil or refined products could lead to a decline in drilling activity, production and refining of crude oil or import levels in these areas. A period of sustained increases in the price of crude oil or refined products supplied from or delivered to any of these areas could materially reduce demand for crude oil or refined products in these areas. In either case, the volumes of crude oil or refined products transported in our crude oil and refined products pipelines and terminal facilities could decline.
The loss of existing customers by our midstream, transportation, terminalling and storage facilities or a reduction in the volume of the services our customers purchase from us, or our inability to attract new customers and service volumes would negatively affect our revenues, be detrimental to our growth, and adversely affect our results of operations.
We and our subsidiaries, including Sunoco LP and USAC, are exposed to the credit risk of our customers and derivative counterparties, and an increase in the nonpayment and nonperformance by our customers or derivative counterparties could reduce our ability to make distributions to our Unitholders.
We, Sunoco LP and USAC are subject to risks of loss resulting from nonpayment or nonperformance by our, Sunoco LP’s and USAC’s customers. Commodity price volatility and/or the tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by our customers. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our risk management policies and procedures are not properly followed. Any material nonpayment or nonperformance by our customers or our derivative counterparties could reduce our ability to make distributions to our Unitholders. Any substantial increase in the nonpayment and nonperformance by our customers could have a material effect on our, Sunoco LP’s and USAC’s results of operations and operating cash flows.
Severe market disruptions could cause some of our counterparties to file for bankruptcy protection, in which case our existing contracts with those counterparties may be rejected by the bankruptcy court. Following the request of one of our FERC-regulated natural gas pipelines, the FERC commenced a proceeding to determine whether the public interest requires abrogation or modification of a firm transportation agreement with one of our shippers. By order dated November 9, 2020, FERC held that the record did not support a finding that the public interest presently required abrogation or modification of the subject firm transportation agreement. The shipper subsequently filed for bankruptcy. Thereafter, on July 19, 2022, the Fifth Circuit Court of Appeals rejected FERC’s jurisdictional basis for its earlier public interest decision, vacated the November 9, 2020 order and a settlement has been reached regarding the agreement in the underlying bankruptcy proceeding. We will attempt to remarket the subject capacity and, depending on the availability of alternatives to our services, any resulting contracts may have terms that are less favorable to us than the former shipper’s contract.
The profitability of certain activities in our natural gas gathering, processing, transportation and storage operations are largely dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs.
For a portion of the natural gas gathered on our systems, we purchase natural gas from producers at the wellhead and then gather and deliver the natural gas to pipelines where we typically resell the natural gas under various arrangements, including sales at index prices. Generally, the gross margins we realize under these arrangements decrease in periods of low natural gas prices.
We also enter into percent-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements pursuant to which we agree to gather and process natural gas received from the producers.
Under percent-of-proceeds arrangements, we generally sell the residue gas and NGLs at market prices and remit to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, we deliver an agreed upon percentage of the residue gas and NGL volumes to the producer and sell the volumes we keep to third parties at market prices. Under these arrangements, our revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have an adverse effect on our revenues and results of operations.
Under keep-whole arrangements, we generally sell the NGLs produced from our gathering and processing operations at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, our gross margins generally decrease when the price of natural gas increases relative to the price of NGLs.
When we process the gas for a fee under processing fee agreements, we may guarantee recoveries to the producer. If recoveries are less than those guaranteed to the producer, we may suffer a loss by having to supply liquids or its cash equivalent to keep the producer whole.
We also receive fees and retain gas in kind from our natural gas transportation and storage customers. Our fuel retention fees and the value of gas that we retain in kind are directly affected by changes in natural gas prices. Decreases in natural gas prices tend to decrease our fuel retention fees and the value of retained gas.
In addition, we receive revenue from our off-gas processing and fractionating system in south Louisiana primarily through customer agreements that are a combination of keep-whole and percent-of-proceeds arrangements, as well as from transportation and fractionation fees. Consequently, a large portion of our off-gas processing and fractionation revenue is exposed to risks due to fluctuations in commodity prices. In addition, a decline in NGL prices could cause a decrease in demand for our off-gas processing and fractionation services and could have an adverse effect on our results of operations.
Our midstream facilities and transportation pipelines provide services related to natural gas wells that experience production declines over time, which we may not be able to replace with natural gas production from newly drilled wells in the same natural gas basins or in other new natural gas producing areas.
In order to maintain or increase throughput levels on our gathering systems and transportation pipeline systems and asset utilization rates at our treating and processing plants, we must continually contract for new natural gas supplies and natural gas transportation services.
A substantial portion of our assets, including our gathering systems and our processing and treating plants, are connected to natural gas reserves and wells that experience declining production over time. Our gas transportation pipelines are also dependent upon natural gas production in areas served by our gathering systems or in areas served by other gathering systems or transportation pipelines that connect with our transportation pipelines. We may not be able to obtain additional contracts for natural gas supplies for our natural gas gathering systems, and we may be unable to maintain or increase the levels of natural gas throughput on our transportation pipelines. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and production of natural gas near our gathering systems or in areas that provide access to our transportation pipelines or markets to which our systems connect. We have no control over the level of drilling activity in our areas of operation, the amount of reserves underlying the wells and the rate at which production from a well will decline. In addition, we have no control over producers or their production and contracting decisions.
While a substantial portion of our services are provided under long-term contracts for reserved service, we also provide service on an unreserved basis. The reserves available through the supply basins connected to our gathering, processing, treating, transportation and storage facilities may decline and may not be replaced by other sources of supply. A decrease in development or production activity could cause a decrease in the volume of unreserved services we provide and a decrease in the number and volume of our contracts for reserved transportation service over the long run, which in each case would adversely affect our revenues and results of operations.
If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations and cash flows could be materially and adversely affected.
Our revenues depend on our customers’ ability to use our pipelines and third-party pipelines over which we have no control.
Our natural gas transportation, storage and NGL businesses depend, in part, on our customers’ ability to obtain access to pipelines to deliver gas to us and receive gas from us. Many of these pipelines are owned by parties not affiliated with us. Any interruption of service on our pipelines or third-party pipelines due to testing, line repair, reduced operating pressures, or other causes or adverse change in terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport natural gas to and from our pipelines and facilities and a corresponding material adverse effect on our transportation and storage revenues. In addition, the rates charged by interconnected pipelines for transportation to and from our facilities affect the utilization and value of our storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on our storage revenues.
Shippers using our oil pipelines and terminals are also dependent upon our pipelines and connections to third-party pipelines to receive and deliver crude oil and products. Any interruptions or reduction in the capabilities of these pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volume over interconnecting oil pipelines, the allocations of pipeline capacity to our existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes transported in its pipelines or through our terminals. Allocation reductions of this nature are not infrequent and are beyond our control. Any such interruptions or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could have a material adverse effect on our results of operations, financial position, or cash flows.
The inability to continue to access lands owned by third parties could adversely affect our ability to operate and our financial results.
Our ability to operate our pipeline systems on certain lands owned by third parties will depend on our success in maintaining existing rights-of-way and obtaining new rights-of-way on those lands. We are parties to rights-of-way agreements, permits and licenses authorizing land use with numerous parties, including, private land owners, governmental entities, Native American tribes, rail carriers, public utilities and others. 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. We cannot provide any assurance that we will be able to maintain access to existing rights-of-way upon the expiration of the current grants, that all of the rights-of-way will be obtained in a timely fashion or that we will acquire new rights-of-way as needed.
Further, whether we have the power of eminent domain for our pipelines varies from state to state, depending upon the type of pipeline and the laws of the particular state and the ownership of the land to which we seek access. When we exercise eminent down rights or negotiate private agreements cases, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located. For example, following a decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operators. Any loss of rights with respect to our real property, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to Unitholders.
Our storage operations are influenced by the overall forward market for crude oil and other products we store, and certain market conditions may adversely affect our financial and operating results.
Our storage operations are influenced by the overall forward market for crude oil and other products we store. A contango market (meaning that the price of crude oil or other products for future delivery is higher than the current price) is associated with greater demand for storage capacity, because a party can simultaneously purchase crude oil or other products at current prices for storage and sell at higher prices for future delivery. A backwardated market (meaning that the price of crude oil or other products for future delivery is lower than the current price) is associated with lower demand for storage capacity because a party can capture a premium for prompt delivery of crude oil or other products rather than storing it for future sale. A prolonged backwardated market, or other adverse market conditions, could have an adverse impact on its ability to negotiate favorable prices under new or renewing storage contracts, which could have an adverse impact on our storage revenues. As a result, the overall forward market for crude oil or other products may have an adverse effect on our financial condition or results of operations.
Competition for water resources or limitations on water usage for hydraulic fracturing could disrupt crude oil and natural gas production from shale formations.
Hydraulic fracturing is the process of creating or expanding cracks by pumping water, sand and chemicals under high pressure into an underground formation in order to increase the productivity of crude oil and natural gas wells. Water used in the process is generally fresh water, recycled produced water or salt water. There is competition for fresh water from municipalities, farmers, ranchers and industrial users. In addition, the available supply of fresh water can also be reduced directly by drought. Prolonged drought conditions increase the intensity of competition for fresh water. Limitations on oil and gas producers’ access to fresh water may restrict their ability to use hydraulic fracturing and could reduce new production. Such disruptions could potentially have a material adverse impact on our financial condition or results of operations.
A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow.
Some of our operations involve risks of personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow. For example, natural gas pipeline and other facilities operate at high pressures. Virtually all of our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.
If one or more facilities that are owned by us, or that deliver natural gas or other products to us, are damaged by severe weather or any other disaster, accident, catastrophe or event, our operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply our facilities or other stoppages arising from factors beyond our control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to Unitholders.
As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.
Terrorist attacks aimed at our facilities could adversely affect our business, results of operations, cash flows and financial condition.
The United States government has issued warnings that energy assets, including our nation’s pipeline infrastructure, may be the future target of terrorist organizations. Some of our facilities are subject to standards and procedures required by the Chemical Facility Anti-Terrorism Standards. We believe we are in compliance with all material requirements; however, such compliance may not prevent a terrorist attack from causing material damage to our facilities or pipelines. Any such terrorist attack on our facilities or pipelines, those of our customers, or in some cases, those of other pipelines could have a material adverse effect on our business, financial condition and results of operations.
Our business could be affected adversely by union disputes and strikes or work stoppages by unionized employees.
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. Any work stoppage could, depending on the affected operations and the length of the work stoppage, have a material adverse effect on our business, financial position, results of operations or cash flows.
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.
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. In addition, in the ordinary course of our business, we collect, process, transmit and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, as well as personally identifiable information, in our data centers and on our networks. We also engage third parties, such as service providers and vendors, who provide a broad array of software, technologies, tools, and other products, services and functions (e.g., human resources, finance, data transmission, communications, risk, compliance, among others) that enable us to conduct, monitor and/or protect our business, operations, systems and data assets.
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. These events can result from malfeasance by external parties, such as hackers, or due to human error or malfeasance by our or our service providers’ employees and contractors (e.g., due to social engineering or phishing attacks). In addition, work-from-home arrangements may present additional operational and cybersecurity risks to our information technology infrastructure and physical assets.
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. 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. We may be unable to anticipate, detect or prevent future attacks, particularly as the methodologies used by attackers change frequently or are not recognized until launched, and we may be unable to investigate or remediate incidents because attackers are increasingly using techniques and tools designed to circumvent controls, to avoid detection, and to remove or obfuscate forensic evidence.
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. A successful cyber attack or other security incident could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. 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. 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. Any losses, costs or liabilities may not be covered by, or may exceed the coverage limits of, any or all of our applicable insurance policies.
Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.
Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. If a key system was to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. Our systems could be damaged or interrupted by a security breach, fire, flood, power loss, telecommunications failure or similar event. We have a formal disaster recovery plan in place, but this plan may not entirely prevent delays or other complications that could arise from an information systems failure. Our business interruption insurance may not compensate us adequately for losses that may occur.
Product liability claims and litigation could adversely affect our business and results of operations.
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.
Along with other refiners, manufacturers and sellers of gasoline, ETC Sunoco is a defendant in numerous lawsuits that allege MTBE contamination in groundwater. Plaintiffs, who include water purveyors and municipalities responsible for supplying drinking water and private well owners, are seeking compensatory damages (and in some cases injunctive relief, punitive damages and attorneys’ fees) for claims relating to the alleged manufacture and distribution of a defective product (MTBE-containing gasoline) that contaminates groundwater, and general allegations of product liability, nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. There has been insufficient information developed about the plaintiffs’ legal theories or the facts that would be relevant to an analysis of the ultimate liability to ETC Sunoco. An adverse determination of liability related to these allegations or other product liability claims against ETC Sunoco could have a material adverse effect on our business or results of operations.
We do not control, and therefore may not be able to cause or prevent certain actions by, certain of our joint ventures.
Certain of our operations are conducted through joint ventures, some of which have their own governing boards. With respect to our joint ventures, we share ownership and management responsibilities with partners that may not share our goals and objectives. Consequently, it may be difficult or impossible for us to cause the joint venture entity to take actions that we believe would be in their or the joint venture’s best interests. Likewise, we may be unable to prevent actions of the joint venture. Differences in views among joint venture partners may result in delayed decisions or failures to agree on major matters, such as large expenditures or contractual commitments, the construction or acquisition of assets or borrowing money, among others. Delay or failure to agree may prevent action with respect to such matters, even though such action may serve our best interest or that of the joint venture. Accordingly, delayed decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our business and operations.
The use of derivative financial instruments could result in material financial losses by us.
From time to time, we and/or our subsidiaries have sought to reduce our exposure to fluctuations in commodity prices and interest rates by using derivative financial instruments and other risk management mechanisms and by our trading, marketing and/or system optimization activities. To the extent that we hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor.
The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. 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. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.
In addition, our derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to our physical or financial positions or hedging policies and procedures are not followed.
Increasing levels of congestion in the Houston Ship Channel could result in a diversion of business to less busy ports.
Our Gulf Coast facilities are strategically situated on prime real estate located in the Houston Ship Channel, which is in close proximity to both supply sources and demand sources. In recent years, the success of the Port of Houston has led to an increase in vessel traffic driven in part by the growing overseas demand for U.S. crude, gasoline, liquefied natural gas and petrochemicals and in part by the Port of Houston’s recent decision to accept large container vessels, which can restrict the flow of other cargo. 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.
The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on our financial results.
Certain of our subsidiaries provide pension plan and other postretirement healthcare benefits to certain of their employees. The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension and other postretirement fund values, changing demographics and fluctuating actuarial assumptions that may have a material adverse effect on the Partnership’s future consolidated financial results. While certain of the costs incurred in providing such pension and other postretirement healthcare benefits are recovered through the rates charged by the Partnership’s regulated businesses, the Partnership’s subsidiaries may not recover all of the costs and those rates are generally not immediately responsive to current market conditions or funding requirements. Additionally, if the current cost recovery mechanisms are changed or eliminated, the impact of these benefits on operating results could significantly increase.
Mergers among customers and competitors could result in lower volumes being shipped on our pipelines or products stored in or distributed through our terminals, or reduced crude oil marketing margins or volumes.
Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing systems instead of our systems in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers and could experience difficulty in replacing those lost volumes and revenues, which could materially and adversely affect our results of operations, financial position, or cash flows.
Fraudulent activity or misuse of proprietary data involving our outsourcing partners could expose us to additional liability.
We utilize both affiliated entities and third parties in the processing of our information and data. Breaches of security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information, or sensitive or confidential data about us or our customers, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose us to a risk of loss, or misuse of this information, result in litigation and potential liability, lead to reputational damage, increase our compliance costs, or otherwise harm our business.
Our trucking fleet operations are subject to the Federal Motor Carrier Safety Regulations which are enacted, reviewed and amended by the Federal Motor Carrier Safety Administration (“FMCSA”). Our fleet currently has a “satisfactory” safety
rating; however, if our safety rating were downgraded to “unsatisfactory,” our business and results of operations could be adversely affected.
All federally regulated carriers’ safety ratings are measured through a program implemented by the FMCSA known as the Compliance Safety Accountability (“CSA”) program. The CSA program measures a carrier’s safety performance based on violations observed during roadside inspections as opposed to compliance audits performed by the FMCSA. The quantity and severity of any violations are compared to a peer group of companies of comparable size and annual mileage. If a company rises above a threshold established by the FMCSA, it is subject to action from the FMCSA. There is a progressive intervention strategy that begins with a company providing the FMCSA with an acceptable plan of corrective action that the company will implement. If the issues are not corrected, the intervention escalates to on-site compliance audits and ultimately an “unsatisfactory” rating and the revocation of its operating authority by the FMCSA could have an adverse effect on our business, results of operations and financial condition.
Indebtedness
Our debt level and debt agreements may limit our ability to make distributions to Unitholders and may limit our future financial and operating flexibility.
As of December 31, 2023, we had approximately $52.39 billion of consolidated debt, excluding the debt of our unconsolidated joint ventures. Our level of indebtedness affects our operations in several ways, including, among other things:
•a significant portion of our and our subsidiaries’ cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions;
•covenants contained in our and our subsidiaries’ existing debt agreements require us and them, as applicable, to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;
•our and our subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;
•we may be at a competitive disadvantage relative to similar companies that have less debt;
•we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level; and
•failure by us or our subsidiaries to comply with the various restrictive covenants of our respective debt agreements could negatively impact our ability to incur additional debt, including our ability to utilize the available capacity under our revolving credit facility, and our ability to pay our distributions.
The debt level and debt agreements of our subsidiaries, including Sunoco LP and USAC, may limit the distributions we receive from these subsidiaries, as well as our future financial and operating flexibility.
Our subsidiaries’ levels of indebtedness affect their operations in several ways, including, among other things:
•a significant portion of our subsidiaries’ cash flows from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions to us;
•covenants contained in our subsidiaries’ existing debt agreements require the respective subsidiaries, as applicable, to meet financial tests that may adversely affect their flexibility in planning for and reacting to changes in their respective businesses;
•our subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;
•our subsidiaries may be at a competitive disadvantage relative to similar companies that have less debt;
•our subsidiaries may be more vulnerable to adverse economic and industry conditions as a result of their debt levels;
•failure by our subsidiaries to comply with the various restrictive covenants of the respective debt agreements could negatively impact the respective subsidiaries’ ability to incur additional debt, including their ability to utilize the available capacity under their revolving credit facilities, and to pay distributions to us and their unitholders.
As a result of Sunoco LP’s previously announced acquisition of NuStar, which is expected to close in the second quarter of 2024, Sunoco LP expects to assume NuStar’s debt and issue additional debt, aggregating approximately $4.2 billion. This additional debt may accelerate any of the risks discussed above.
We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service our debt or to repay debt at maturity.
Unlike a corporation, our Partnership Agreement requires us to distribute, on a quarterly basis, 100% of our Available Cash (as defined in our Partnership Agreement) to our Unitholders of record and our general partner. Available Cash is generally all of our cash on hand as of the end of a quarter, adjusted for cash distributions and net changes to reserves. Our general partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves or the reserves of our operating subsidiaries in amounts it determines in its reasonable discretion to be necessary or appropriate:
•to provide for the proper conduct of our business and the businesses of our operating subsidiaries (including reserves for future capital expenditures and for our anticipated future credit needs);
•to provide funds for distributions to our Unitholders and our general partner for any one or more of the next four calendar quarters; or
•to comply with applicable law or any of our loan or other agreements.
Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.
In addition to our exposure to commodity prices, we have significant exposure to changes in interest rates, including the significant increases in prevailing interest rates as a result of changes in federal monetary and fiscal policy. 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.
An increase in interest rates could impact demand for our storage capacity.
There is a financing cost for a storage capacity user to own crude oil while it is stored. That financing cost is impacted by the cost of capital or interest rate incurred by the storage user, in addition to the commodity cost of the crude oil in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing crude oil for future sale. As a result, a significant increase in interest rates could adversely affect the demand for our storage capacity independent of other market factors.
An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular for yield-based equity investments such as our Common Units. Any such reduction in demand for our Common Units resulting from other more attractive investment opportunities may cause the trading price of our Common Units to decline.
A downgrade of our credit ratings could impact our and our subsidiaries’ liquidity, access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.
A downgrade of our credit ratings may increase our and our subsidiaries’ cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our and our subsidiaries’ ability to access capital markets could also be limited by a downgrade of our credit ratings and other disruptions. Such disruptions could include:
•economic downturns;
•deteriorating capital market conditions;
•declining market prices for crude oil, natural gas, NGLs and other commodities;
•terrorist attacks or threatened attacks on our facilities or those of other energy companies; and
•the overall health of the energy industry, including the bankruptcy or insolvency of other companies.
Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the rating agencies, and we cannot assure you that we will maintain our current credit ratings.
Capital Projects and Future Growth
If we and our subsidiaries do not make acquisitions on economically acceptable terms, our future growth could be limited.
Our results of operations and our ability to grow and to make distributions to Unitholders will depend in part on our ability to make acquisitions that are accretive to our distributable cash flow per unit.
We may be unable to make accretive acquisitions for any of the following reasons, among others:
•because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
•because we are unable to raise financing for such acquisitions on economically acceptable terms;
•because of recent heightened antitrust focus in the energy industry creating potential risk, expense and delays in connection with prospective acquisitions and consolidations; or
•because we are outbid by competitors, particularly as a trend of consolidation within the energy industry continues, some of which are substantially larger than us and have greater financial resources and lower costs of capital then we do.
Furthermore, even if we consummate acquisitions that we believe will be accretive, those acquisitions may in fact adversely affect our results of operations or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that we may:
•fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;
•decrease our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
•significantly increase our interest expense or financial leverage if we incur additional debt to finance acquisitions;
•encounter difficulties operating in new geographic areas or new lines of business;
•incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which we are not indemnified or for which the indemnity is inadequate;
•be unable to hire, train or retrain qualified personnel to manage and operate our growing business and assets;
•less effectively manage our historical assets, due to the diversion of management’s attention from other business concerns; or
•incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.
If we consummate future acquisitions, our capitalization and results of operations may change significantly. As we determine the application of our funds and other resources, Unitholders will not have an opportunity to evaluate the economic, financial and other relevant information that we will consider.
Capital projects may require significant amounts of debt and equity financing, which may not be available to us on acceptable terms, or at all.
We may fund our growth capital expenditures, including any new pipeline construction projects and improvements or repairs to existing facilities that we may undertake, with proceeds from sales of our debt and equity securities and borrowings under our revolving credit facility; however, we cannot be certain that we will be able to issue our debt and equity securities on terms satisfactory to us, or at all. If we are required to seek alternative financing, the terms of which may not be attractive to us, or to revise or cancel our expansion plans.
A significant increase in our indebtedness that is proportionately greater than our issuance of equity could negatively impact our and our subsidiaries’ credit ratings or our ability to remain in compliance with the financial covenants under our revolving credit agreement, which could have a material adverse effect on our financial condition, results of operations and cash flows.
The Inflation Reduction Act of 2022 could decrease demand for crude oil and natural gas and could impose new costs on our operations.
In August 2022, President Biden signed the IRA 2022, which contains hundreds of billions in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. In addition, the IRA 2022 imposes the first-ever federal fee on the emission of GHGs through a methane emissions charge. 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. 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. In addition, the multiple incentives offered for various clean energy industries referenced above could decrease demand for crude oil and natural gas, increase our compliance and operating costs and consequently adversely affect our business.
If we do not continue to construct new pipelines, our future growth could be limited.
Our results of operations and ability to grow and to increase distributable cash flow per unit will depend, in part, on our ability to construct pipelines that are accretive to our distributable cash flow. 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.
Furthermore, even if we construct a pipeline that we believe will be accretive, the pipeline may in fact adversely affect our results of operations or results from those projected prior to commencement of construction and other factors.
Expanding our business by constructing new pipelines and related facilities subjects us to risks.
One of the ways that we have grown our business is through the construction of additions to our existing gathering, compression, treating, processing and transportation systems. The construction of new pipelines and related facilities (or the improvement and repair of existing facilities) involves numerous regulatory, environmental, political and legal uncertainties beyond our control and requires the expenditure of significant amounts of capital that we will be required to finance through borrowings, the issuance of additional equity or from operating cash flow. If we undertake these projects, they may not be completed on schedule, at all, or at the budgeted cost. A variety of factors outside our control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third-party contractors, may result in increased costs or delays in construction. For example, in recent years, pipeline projects by many companies have been subject to several challenges by environmental groups, such as challenges to agency reviews under the NEPA and to the USACE NWP program. Any changes to the USACE NWP program that exclude our projects from coverage could require us to reroute pipeline projects, or seek individual permits that involve longer permitting timelines, leading to construction delays. For more information on the NWP program, see our regulatory disclosure titled “Clean Water Act.” Separately, cost overruns or delays in completing a project could have a material adverse effect on our results of operations and cash flows. Moreover, our revenues may not increase immediately following the completion of a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, but we may not materially increase our revenues until long after the project’s completion. In addition, the success of a pipeline construction project will likely depend upon the level of oil and natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas proposed to be serviced by the project as well as our ability to obtain commitments from producers in the area to utilize the newly constructed pipelines. In this regard, we may construct facilities to capture anticipated future growth in oil or natural gas production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve our expected investment return, which could adversely affect our results of operations and financial condition.
The liquefaction project is dependent upon securing long-term contractual arrangements for the offtake of LNG on terms sufficient to support the financial viability of the project.
Lake Charles LNG Export, our wholly owned subsidiary, is in the process of developing a liquefaction project at the site of our existing regasification facility in Lake Charles, Louisiana. The project would utilize existing dock and storage facilities owned by us located on the Lake Charles site. The parties’ determination as to the feasibility of the project will be particularly dependent upon the prospects for securing long-term contractual arrangements for the offtake of LNG which in turn will be dependent upon supply and demand factors affecting the price of LNG in foreign markets. The financial viability of the project will also be dependent upon a number of other factors, including the expected cost to construct the liquefaction facility, the terms and conditions of the financing for the construction of the liquefaction facility, the cost of the natural gas supply, the costs to transport natural gas to the liquefaction facility, the costs to operate the liquefaction facility and the costs to transport LNG from the liquefaction facility to customers in foreign markets (particularly Europe and Asia). 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.
The construction of the liquefaction project remains subject to further approvals and some approvals may be subject to further conditions, review and/or revocation.
In December 2015, the FERC authorized Lake Charles LNG Export to site, construct and operate the liquefaction project subject to various condition, including a condition requiring all phases of the liquefaction project to be completed and in-service within five years of the date of the FERC authorization order. The order also requires the modifications to our Trunkline pipeline facilities that connect to our Lake Charles facility and additionally requires execution of a transportation contract for natural gas supply to the liquefaction facility prior to the initiation of construction of the liquefaction facility. In December 2019, the FERC granted an extension of time until and including December 16, 2025, to complete construction of the liquefaction project and pipeline facilities modifications and place the facilities into service. 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. The NGA requires the DOE to approve applications for LNG exports unless such approval would be “inconsistent with the public interest.” In March 2013, Lake Charles LNG Export obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”). 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. Lake Charles LNG Export applied for an extension of the deadline to commerce 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.
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. The Biden administration stated that these studies were necessary to enable the DOE to make determinations related to the statutory “public interest” standard. The DOE has stated that these studies will take several months to complete, after which a draft policy statement will be made available for public comment prior to finalizing the policy statement. This process is not expected to be completed prior to the U.S. Presidential election in November 2024.
Based on this action by the Biden administration, there is uncertainty as to the ultimate determinations by the DOE with respect to whether the export of LNG from a specific liquefaction facility, such as the proposed Lake Charles LNG facility, will be considered “not inconsistent with the public interest,” the applicable standard for approval under the NGA. Accordingly, there can be no assurance as to whether Lake Charles LNG Export will receive approval of its application for a Non-FTA Authorization.
Integration of assets acquired in past acquisitions or future acquisitions with our existing business will be a complex and time-consuming process. A failure to successfully integrate the acquired assets with our existing business in a timely manner may have a material adverse effect on our business, financial condition, results of operations or cash available for distribution to Unitholders.
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.
If any of these risks or other unanticipated liabilities or costs were to materialize, then desired benefits from past acquisitions and future acquisitions resulting in a negative impact to our future results of operations. In addition, acquired assets may perform at levels below the forecasts used to evaluate their acquisition, due to factors beyond our control. 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. Even if performed, a detailed review of assets and businesses may not reveal existing or potential problems and may not provide sufficient familiarity with such business or assets to fully assess their deficiencies and potential. Inspections may not be performed on every asset, and environmental problems, may not be observable even when an inspection is undertaken.
We are affected by competition from other midstream, transportation, terminalling and storage companies.
We experience competition in all of our business segments. With respect to our midstream operations, we compete for both natural gas supplies and customers for our services. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas.
Our natural gas and NGL transportation pipelines and storage facilities compete with other interstate and intrastate pipeline companies and storage providers in the transportation and storage of natural gas and NGLs. The principal elements of competition among pipelines are rates, terms of service, access to sources of supply and the flexibility and reliability of service. Natural gas and NGLs also compete with other forms of energy, including electricity, coal, fuel oils and renewable or alternative energy. Competition among fuels and energy supplies is primarily based on price; however, non-price factors, including governmental regulation, environmental impacts, efficiency, ease of use and handling, and the availability of subsidies and tax benefits also affects competitive outcomes.
In markets served by our NGL pipelines, we compete with other pipeline companies and barge, rail and truck fleet operations. We also face competition with other storage and fractionation facilities based on fees charged and the ability to receive, distribute and/or fractionate the customer’s products.
Our crude oil and refined petroleum products pipelines face significant competition from other pipelines for large volume shipments. These operations also face competition from trucks for incremental and marginal volumes in the areas we serve. Further, our crude and refined product terminals compete with terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.
We, Sunoco LP and USAC may not be able to fully execute our growth strategy if we encounter increased competition for qualified assets.
Our strategy contemplates growth through the development and acquisition of a wide range of midstream, transportation, storage and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively and diversify our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding the acquisition of additional assets and businesses, stand-alone development projects or other transactions that we believe will present opportunities to realize synergies and increase our cash flow.
Consistent with our strategy, we may, from time to time, engage in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve our participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. We cannot give assurance that our acquisition efforts will be successful or that any acquisition will be completed on terms considered favorable to us.
In addition, we may experience increased competition for the assets we purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in us losing to other bidders more often or acquiring assets at higher prices, both of which would limit our ability to fully execute our growth strategy. Inability to execute our growth strategy may materially adversely impact our results of operations.
We compete with other businesses in our market with respect to attracting and retaining qualified employees.
Our continued success depends on our ability to attract and retain qualified personnel in all areas of our business. We compete with other businesses in our market with respect to attracting and retaining qualified employees. A tight labor market, increased overtime and a higher full-time employee ratio may cause labor costs to increase. A shortage of qualified employees may require us to enhance wage and benefits packages in order to compete effectively in the hiring and retention of such employees or to hire more expensive temporary employees. No assurance can be given that our labor costs will not increase, or that such increases can be recovered through increased prices charged to customers. We are especially vulnerable to labor shortages in oil and gas drilling areas when energy prices drive higher exploration and production activity.
Regulatory Matters
Increased regulation of hydraulic fracturing or produced water disposal could result in reductions or delays in crude oil and natural gas production in our areas of operation, which could adversely impact our business and results of operations.
The hydraulic fracturing process has come under considerable scrutiny from sections of the public as well as environmental and other groups asserting that chemicals used in the hydraulic fracturing process could adversely affect drinking water supplies and may have other detrimental impacts on public health, safety, welfare and the environment. In addition, the water disposal process has come under scrutiny from sections of the public as well as environmental and other groups asserting that the operation of certain water disposal wells has caused increased seismic activity. Additionally, several candidates for political office in both state and federal government have announced intentions to impose greater restrictions on hydraulic fracturing or produced water disposal. For example, on January 27, 2021, the Biden Administration issued an executive order temporarily suspending the issuance of new authorizations, and suspending the issuance of new leases pending completion of a review of current practices, for oil and gas development on federal lands and waters (but not tribal lands that the federal government merely holds in trust). The suspension of these federal leasing activities prompted legal action by several states against the Biden Administration, resulting in issuance of a nationwide preliminary injunction by a federal district judge in Louisiana in June 2021, followed by a permanent injunction in August 2022, effectively halting implementation of the leasing suspension. Relatedly, the Department of the Interior (“DOI”) released its report on federal gas leasing and permitting practices in November 2021, referencing a number of recommendations and an overarching intent to modernize the federal oil and gas leasing program, including by adjusting royalty and bonding rates, prioritizing leasing in areas with known resource potential, and avoiding leasing that conflicts with recreation, wildlife habitat, conservation, and historical and cultural resources. 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. Implementation of many of the recommendations in the DOI report will require Congressional action and we cannot predict the extent to which the recommendations may be implemented now or in the future, but restrictions on federal oil and gas activities have the potential to result in increased costs on us and our customers, decrease demand for our services on federal lands, and adversely impact our business. Separately, in November 2022, the BLM proposed a rule that would limit flaring from well sites on federal lands, as well as allow the delay or denial of permits if the BLM finds that an operator’s methane waste minimization plan is insufficient. 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. Some local communities have adopted, or are considering adopting, additional restrictions for oil and gas activities, such as requiring even greater setbacks. While the final impacts of these developments cannot be predicted, the adoption of new laws or regulations imposing additional permitting, disclosures, restrictions or costs related to hydraulic fracturing or produced water disposal or prohibiting hydraulic fracturing in proximity to areas considered to be environmentally sensitive could make drilling certain wells impossible or less economically attractive. As a result, the volume of crude oil and natural gas we gather, transport and store for our customers could be substantially reduced which could have an adverse effect on our financial condition or results of operations.
Legal or regulatory actions related to the Dakota Access Pipeline could cause an interruption to current or future operations, which could have an adverse effect on our business and results of operations.
On July 27, 2016, the Standing Rock Sioux Tribe and other Native American tribes (the “Tribes”) filed a lawsuit in the United States District Court for the District of Columbia (“District Court”) challenging permits issued by the USACE permitting Dakota Access to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE allowing the pipeline to cross land owned by the USACE adjacent to the Missouri River. As a result of this litigation, the District Court vacated the easement, ordered USACE to prepare an Environmental Impact Statement (“EIS”), and order the pipeline shutdown and drained of oil. Dakota Access and USACE appealed this decision and moved for a
stay of the District Court’s orders. On August 5, 2020, the Court of Appeals granted a stay of the portion of the District Court order that required Dakota Access to shut the pipeline down and empty it of oil, but the Court of Appeals denied a stay of the easement vacatur. The August 5, 2020 order also stated that the Court of Appeals expected the USACE to clarify its position with respect to whether USACE intends to allow the continued operation of the pipeline notwithstanding the vacatur of the easement and that the District Court may consider additional relief, if necessary. Following this order, the Tribes filed a motion with the District Court seeking an injunction to prevent the continued operation of the pipeline. On January 26, 2021, the Court of Appeals affirmed the District Court’s order requiring an EIS and its order vacating the easement. 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. Dakota Access filed for rehearing en banc on April 12, 2021, which the Court of Appeals denied. On September 20, 2021, Dakota Access filed a petition with the U.S. Supreme Court to hear the case. Oppositions were filed by the Solicitor General and plaintiffs, and Dakota Access has filed its reply.
The District Court scheduled a status conference for February 10, 2021 to discuss the impact of the Court of Appeals’ ruling on the pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed in light of the Court of Appeals’ recent vacatur ruling. USACE filed a motion for a continuance of the status conference until April 9, 2021, and this motion was approved by the District Court on February 9, 2021. Dakota Access and the Tribes filed their supplemental declarations on April 19, 2021 and April 26, 2021, respectively. On April 26, 2021, the District Court requested that USACE advise it by May 3, 2021 as to USACE’s current position, if it has one, with respect to the motion. On May 3, 2021, USACE advised the District Court that it had not changed its position with respect to its opposition to the Tribes’ motion for injunction. The USACE also advised the District Court that it expected that the EIS will be completed by March 2022. On May 21, 2021 the District Court denied the plaintiffs’ request for an injunction. The District Court further directed the parties to file a joint status report by June 11, 2021 concerning potential next steps in the litigation. On June 22, 2021, the District Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. On January 20, 2022, the Standing Rock Sioux Tribe withdrew as a cooperating agency on the draft EIS, prompting the USACE to temporarily pause on the draft EIS. On September 8, 2023, the USACE published the Draft EIS. Comments to the Draft EIS were due on December 13, 2023. The USACE anticipates that a Final EIS and Record of Decision would be issued in 2024. For further information, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this annual report.
Our interstate natural gas pipelines are subject to laws, regulations and policies governing the rates they are allowed to charge for their services, which may prevent us from fully recovering our costs.
Laws, regulations and policies governing interstate natural gas pipeline rates could affect the ability of our interstate pipelines to establish rates, to charge rates that would cover future increases in its costs, or to continue to collect rates that cover current costs.
We are required to file with the FERC tariff rates (also known as recourse rates) that shippers may pay for interstate natural gas transportation services. We may also agree to discount these rates on a not unduly discriminatory basis or negotiate rates with shippers who elect not to pay the recourse rates. 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 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. 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.
The costs of our interstate pipeline operations may increase, and we may not be able to recover all of those costs due to FERC regulation of our rates. If we propose to change our tariff rates, our proposed rates may be challenged by the FERC or third parties, and the FERC may deny, modify or limit our proposed changes if we are unable to persuade the FERC that changes would result in just and reasonable rates that are not unduly discriminatory. We also may be limited by the terms of rate case settlement agreements or negotiated rate agreements with individual customers from seeking future rate increases, or we may be constrained by competitive factors from charging our tariff rates.
To the extent our costs increase in an amount greater than our revenues increase, or there is a lag between our cost increases and our ability to file for and obtain rate increases, our operating results would be negatively affected. Even if a rate increase is permitted by the FERC to become effective, the rate increase may not be adequate. We cannot guarantee that our interstate pipelines will be able to recover all of our costs through existing or future rates.
The ability of interstate pipelines held in tax-pass-through entities, like us, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before the FERC and the courts for a number of years. Effective January 2018, the 2017 Tax Cuts and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity (“ROE”) calculated using the discounted cash flow methodology. On July 18, 2018, the FERC clarified that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’ income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding FERC’s decision denying a separate master limited partnership recovery of an income tax allowance and its decision not to require the master limited partnership to refund accumulated deferred income tax balances. In light of the rehearing order’s clarification regarding individual entities’ ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impacts that FERC’s policy on the treatment of income taxes may have on the rates an interstate pipeline held in a tax-pass-through entity can charge for the FERC regulated transportation services are unknown at this time.
Even without application of FERC’s recent rate making-related policy statements and rulemakings, under the NGA, FERC or our shippers may challenge the cost-of-service rates we charge. 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 rate. 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. Many of our interstate pipelines, such as Tiger, Midcontinent Express and Fayetteville Express, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. The revenues we receive from natural gas transportation services we provide pursuant to cost-of-service based rates may decrease in the future as a result of changes to FERC policies, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost-of-service rates, if any, will depend on a detailed review of all of a pipeline’s cost-of-service components and the outcomes of any challenges to our rates by the FERC or our shippers.
By an order issued on January 16, 2019, the FERC initiated a review of Panhandle’s then existing rates pursuant to Section 5 of the NGA to determine whether the rates charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the NGA. The NGA Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021, and on December 16, 2022, the FERC issued its order on the initial decision. On January 17, 2023, Panhandle and the Michigan Public Service Commission each filed a request for rehearing of FERC’s order on the initial decision, which were denied by operation of law as of February 17, 2023. On March 23, 2023, Panhandle appealed these orders to the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”), and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the Court of Appeals consolidated Panhandle’s and Michigan Public Service Commission’s appeals and stayed the consolidated appeal proceeding while the FERC further considered the requests for rehearing of its December 16, 2022 order. On September 25, 2023, the FERC issued its order addressing arguments raised on rehearing and compliance, which denied our requests for rehearing. Panhandle has timely filed its Petition for Review with the Court of Appeals regarding the September 25, 2023 order. On October 25, 2023, Panhandle filed a limited request for rehearing of the September 25 order addressing arguments raised on rehearing and compliance, which was subsequently denied by operation of law on November 27, 2023. On November 30, 2023, Panhandle submitted a refund report regarding the consolidated rate proceedings, which has been protested by several parties. On January 5, 2024, the FERC issued a second order addressing arguments raised on rehearing in which it modified certain discussion from its September 25, 2023 order and sustained its prior conclusions. Panhandle has timely filed its Petition for Review with the Court of Appeals regarding the January 5, 2024 order.
On July 1, 2022, Transwestern filed a rate case pursuant to Section 4 of the NGA. By order dated September 9, 2022, a procedural schedule was adopted in this proceeding, setting the commencement of the hearing for June 22, 2023 with an initial decision anticipated by November 15, 2023. By a subsequent order dated February 14, 2023, the procedural schedule was suspended based on representations that the participants have reached an agreement in principle to resolve all issues in this
proceeding and a settlement is being prepared for filing at FERC. A settlement was filed with the FERC on April 5, 2023, and approved by order dated June 30, 2023.
On December 1, 2022, Sea Robin filed a general rate proceeding under Section 4 of the NGA reflecting a general rate increase for gathering and transportation services. A hearing in the proceeding is scheduled for October 24, 2023 with an initial decision anticipated by March 19, 2024. The parties have reached a settlement in the case, and the settlement was filed with the FERC on December 29, 2023.
Our interstate natural gas pipelines are subject to laws, regulations and policies governing terms and conditions of service, which could adversely affect our business and results of operations.
In addition to rate oversight, the FERC’s regulatory authority extends to many other aspects of the business and operations of our interstate natural gas pipelines, including:
•terms and conditions of service;
•the types of services interstate pipelines may or must offer their customers;
•siting and construction of new facilities;
•acquisition, extension or abandonment of services or facilities;
•reporting and information posting requirements;
•accounts and records; and
•relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.
Compliance with these requirements can be costly and burdensome. In addition, we cannot guarantee that the FERC will authorize tariff changes and other activities we might propose and to undertake in a timely manner and free from potentially burdensome conditions. Future changes to laws, regulations, policies and interpretations thereof may impair our access to capital markets or may impair the ability of our interstate pipelines to compete for business, may impair their ability to recover costs or may increase the cost and burden of operation.
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. On February 18, 2021, the FERC issued another NOI (“2021 NOI”), reopening its review of the 1999 Policy Statement. Comments on the 2021 NOI were due on May 26, 2021. In September 2021, FERC issued a Notice of Technical Conference on Greenhouse Gas Mitigation related to natural gas infrastructure projects authorized under Sections 3 and 7 of the NGA. A technical conference was held on November 19, 2021, and post-technical conference comments were submitted to the FERC on January 7, 2022. 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 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. Comments on the 2022 Policy Statements were due on April 25, 2022, and reply comments were due on May 25, 2022. 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 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.
Transportation provided on our common carrier interstate crude oil, NGL and refined products pipelines is subject to rate regulation by the FERC, which requires that tariff rates for transportation on these oil pipelines be just and reasonable and not unduly discriminatory. If we propose new or changed rates, the FERC or interested persons may challenge those rates and the FERC is authorized to suspend the effectiveness of such rates for up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the proposed rate is unjust or unreasonable, it is authorized to require the carrier to refund revenues in excess of the prior tariff during the term of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon
an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.
The primary ratemaking methodology used by the FERC to authorize increases in the tariff rates of petroleum pipelines is price indexing. The FERC’s ratemaking methodologies may limit our ability to set rates based on our costs or may delay the use of rates that reflect increased costs. On March 25, 2020, the FERC issued a Notice of Inquiry seeking comment on a proposal to change the preliminary screen for complaints against oil pipeline index rate increases to a “Percentage Comparison Test” consistent with the preliminary screen used by the FERC for protests against oil pipeline index rate increases. The FERC also requested comment on whether the appropriate threshold for the screen is a 10% or more differential between a proposed index rate increase and the annual percentage change in cost of service reported by the pipeline. Initial comments were due June 16, 2020, and reply comments were due July 16, 2020.
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. Specifically, the policy statement adopted the proposal in the FERC’s earlier Notice of Inquiry issued on March 25, 2020 to eliminate the “Substantially Exacerbate Test” as the preliminary screen applied to complaints against index rate increases and instead adopt the proposal to apply the “Percentage Comparison Test” as the preliminary screen for both protests and complaints against index rate increases. At this time, we cannot determine the effect of a change in the FERC’s preliminary screen for complaints against index rates changes, however, a revised screen would result in a threshold aligned with the existing threshold for protests against index rate increases. Any complaint or protest raised by a shipper could materially and adversely affect our financial condition, results of operations or cash flows.
On June 18, 2020, FERC issued a NOI requesting comments on a proposed oil pipeline index for the five-year period commencing July 1, 2021 and ending June 30, 2026, and requested comments on whether and how the index should reflect the Revised Policy Statement and FERC’s treatment of accumulated deferred income taxes as well as FERC’s revised ROE methodology.
On December 17, 2020, FERC issued an order establishing a new index of PPI-FG plus 0.78%. The FERC received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG minus 0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period July 1, 2022 to June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the January 20 order with FERC, which was denied by FERC on May 6, 2022. Certain parties have appealed the January 20 and May 6 orders. Such appeals remain pending at the D.C. Circuit.
Under the Energy Policy Act of 1992 (the “Energy Policy Act”), certain interstate pipeline rates were deemed just and reasonable or “grandfathered.” Revenues are derived from such grandfathered rates on most of our FERC-regulated pipelines. A person challenging a grandfathered rate must, as a threshold matter, establish a substantial change since the date of enactment of the Energy Policy Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. If the FERC were to find a substantial change in circumstances, then the existing rates could be subject to detailed review and there is a risk that some rates could be found to be in excess of levels justified by the pipeline’s costs. In such event, the FERC could order us to reduce pipeline rates prospectively and to pay refunds to shippers.
If the FERC’s petroleum pipeline ratemaking methodologies procedures changes, the new methodology or procedures could adversely affect our business and results of operations.
State regulatory measures could adversely affect the business and operations of our midstream and intrastate pipeline and storage assets.
Our midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects our business and the market for our products. The rates, terms and conditions of service for the interstate services we provide in our intrastate gas pipelines and gas storage are subject to FERC regulation under Section 311 of the NGPA. Our pipeline systems of Enable Oklahoma Intrastate Transmission, LLC, Oasis Pipeline, LP, Houston Pipe Line Company LP, ETC Katy Pipeline, LLC, Energy Transfer Fuel, LP, Lobo Pipeline Company, LLC, Pelico Pipeline, LLC, Regency Intrastate Gas LP, Red Bluff Express Pipeline, LLC, Trans-Pecos Pipeline, LLC and Comanche Trail Pipeline, LLC provide such services. 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. 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. All of the states in which we operate midstream assets, intrastate pipelines or intrastate storage facilities have adopted some form of complaint-based regulation, which allow producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to the fairness of rates and terms of access. The states in which we operate have ratable take statutes, which generally require gathering pipelines to take, without undue discrimination, production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Should a complaint be filed in any of these states or should regulation become more active, our business may be adversely affected.
Our intrastate transportation operations located in Texas are also subject to regulation as gas utilities by the TRRC. Texas gas utilities must publish the rates they charge for transportation and storage services in tariffs filed with the TRRC, although such rates are deemed just and reasonable under Texas law unless challenged in a complaint.
We are subject to other forms of state regulation, including requirements to obtain operating permits, reporting requirements, and safety rules (see description of federal and state pipeline safety regulation below). Violations of state laws, regulations, orders and permit conditions can result in the modification, cancellation or suspension of a permit, civil penalties and other relief.
Certain of our assets may become subject to regulation.
The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines under the NGA has been the subject of extensive litigation and may be determined by the FERC on a case-by-case basis, although the FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of our gathering facilities could change based on future determinations by the FERC, the courts or Congress. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.
Intrastate transportation of NGLs is largely regulated by the state in which such transportation takes place. Energy Transfer GC NGL’s pipeline transports NGLs within the state of Texas and is subject to regulation by the TRRC. This NGLs transportation system offers services pursuant to an intrastate transportation tariff on file with the TRRC. In 2013, Energy Transfer GC NGL’s pipeline also commenced the interstate transportation of NGLs, which is subject to the FERC’s jurisdiction under the Interstate Commerce Act (“ICA”) and the Energy Policy Act. Both intrastate and interstate NGL transportation services must be provided in a manner that is just, reasonable, and non-discriminatory. The tariff rates established for interstate services were based on a negotiated agreement; however, if the FERC’s ratemaking methodologies were imposed, they may, among other things, delay the use of rates that reflect increased costs and subject us to potentially burdensome and expensive operational, reporting and other requirements. In addition, the rates, terms and conditions for shipments of crude oil, petroleum products and NGLs on our pipelines are subject to regulation by the FERC if the NGLs are transported in interstate or foreign commerce, whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all crude oil, petroleum products and NGLs on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
In addition, if any of our pipelines were found to have provided services or otherwise operated in violation of the NGA, NGPA, or ICA, this could result in the imposition of administrative and criminal remedies and civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC. Any of the foregoing could adversely affect revenues and cash flow related to these assets.
We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.
Pursuant to authority under the NGPSA and HLPSA, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for natural gas transmission and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas (“HCAs”) which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources, and unusually sensitive ecological areas. These regulations require operators of covered pipelines to:
•perform ongoing assessments of pipeline integrity;
•identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
•improve data collection, integration and analysis;
•repair and remediate the pipeline as necessary; and
•implement preventive and mitigating actions.
In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. Any changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. For example, in October 2019, PHMSA published the first of three regulations relating to new or more stringent requirements for certain natural gas lines and gathering lines, that had originally been proposed in 2016 as part of PHMSA’s “Gas Megarule.” The rulemaking imposed numerous requirements on onshore gas transmission pipelines relating to MAOP, reconfirmation and exceedance reporting, the integrity assessment of additional pipeline mileage found in MCAs, non-HCAs, Class 3 and Class 4 areas by 2023, and the consideration of seismicity as a risk factor in integrity management. PHMSA’s second final rule, applicable to hazardous liquid transmission and gathering pipelines, significantly extended and expanded the reach of certain integrity management requirements, use of in-line inspection tools by 2039 (unless the pipeline cannot be modified to permit such use), increased annual, accident, and safety-related conditional reporting requirements, and expanded use of leak detection systems beyond HCAs. The third final rule was published in August 2022, which adjusted the repair criteria for pipelines in HCAs, created new criteria for pipelines in non-HCAs, and strengthened integrity management assessment requirements, among other items. The changes adopted by these rulemakings could have a material adverse effect on our results of operations and costs of transportation services.
Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.
The NGPSA and HLPSA were amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). Among other things, the 2011 Pipeline Safety Act increased the penalties for safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm that the material strength of certain pipelines are above 30% of specified minimum yield strength, and operator verification of records confirming the MAOP of certain interstate natural gas transmission pipelines. In March 2022, PHMSA issued a final rule increasing the maximum administrative fines for safety violations were increased to account for inflation, with maximum civil penalties set at $239,142 per day, with a maximum of $2,391,412 for a series of violations. Upon reauthorization of PHMSA, Congress often directs the agency to complete certain rulemakings. 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. Additionally, in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas from related pipeline facilities. The safety enhancement requirements and other provisions of Congressional mandates to PHMSA, as well as any implementation of PHMSA rules thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto, could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial condition.
Our business involves the generation, handling and disposal of hazardous substances, hydrocarbons and wastes which activities are subject to environmental and worker health and safety laws and regulations that may cause us to incur significant costs and liabilities.
Our business is subject to stringent federal, tribal, state, and local laws and regulations governing the discharge of materials into the environment, worker health and safety and protection of the environment. These laws and regulations may require the acquisition of permits for the construction and operation of our pipelines, plants and facilities, result in capital expenditures to manage, limit or prevent emissions, discharges or releases of various materials from our pipelines, plants and facilities, impose specific health and safety standards addressing worker protection, and impose substantial liabilities for pollution resulting from our construction and operations activities. Several governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate
difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations and permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of investigatory remedial and corrective action obligations, suspension and debarment from federal contracting opportunities, the occurrence of delays in permitting and completion of projects, and the issuance of injunctive relief. For example, following a state grand jury investigation and the filing of charges alleging criminal misconduct involving the construction and related activities of the Mariner East 2 pipeline (“Mariner 2”), in August 2022 we entered into a plea of no contest with the Pennsylvania Attorney General’s Office that requires us to pay fines to the Commonwealth, pay for independent evaluations of potential water quality impacts to residential water supplies and compensate any affected homeowners, and to also pay $10 million to support water quality improvement projects. Any additional requirements from the PADEP regarding Mariner 2 or other of our pipeline projects may result in delays in the completion of these projects. Subsequently, the EPA issued a Notice of Proposed Debarment (“NPD”) on October 28, 2022, arising from SPLP’s and ETC Northeast Pipeline, LLC’s nolo contendere plea agreements and convictions for violations of Pennsylvania’s Clean Streams Law related to the Revolution and Mariner 2 pipelines. The following entities were proposed for debarment: (1) SPLP (pleading entity); (2) ETC Northeast Pipeline, LLC (pleading entity); (3) Energy Transfer LP; (4) SemGroup LLC; and (5) LE GP, LLC. The NPD presently prevents the named entities from pursuing or renewing Federal government contracts or Federal financial assistance agreements. While we are engaging with the EPA to attempt to resolve the matter, at this time there can be no assurance that the EPA will not finalize a debarment applicable to the named entities for a set period of time, or expand the debarment to other Energy Transfer affiliates. Currently, none of the entities named in the NPD are party to any Federal government contracts or Federal financial assistance agreements.
Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or released, even under circumstances where the substances, hydrocarbons or wastes have been released by a predecessor operator. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property and natural resource damage allegedly caused by noise, odor or the release of hazardous substances, hydrocarbons or wastes into the environment.
We may incur substantial environmental costs and liabilities because of the underlying risk arising out of our operations. Although we have established financial reserves for our estimated environmental remediation liabilities, additional contamination or conditions may be discovered, resulting in increased remediation costs, liabilities or natural resource damages that could substantially increase our costs for site remediation projects. Accordingly, we cannot assure you that our current reserves are adequate to cover all future liabilities, even for currently known contamination.
Uncertainty about the future course of regulation continues to exist following the change in U.S. presidential administrations in January 2021. Upon taking office, the Biden Administration issued an executive order directing all federal agencies to review and take action to address any federal regulations promulgated during the prior administration that may be inconsistent with the current administration’s policies. As a result, several regulatory developments have occurred, but it remains unclear the degree to which this will continue . The executive order also established a Working Group that is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” During 2021, the Working Group published interim estimates of the social costs of carbon, methane, and nitrous oxide and sought public comment on these estimates. The Working Group’s interim estimate of the social cost of carbon has been subject to litigation in 2022, but is in use while litigation is pending. The EPA has also separately developed its own proposal for a social cost of carbon, which is significantly higher than that proposed by the Working Group. The EPA’s proposal is currently undergoing independent peer review and is not yet in use by the agency. Further regulation of air emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand for oil and natural gas and, in turn, have a material adverse effect on our business, financial condition or results of operations.
Changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, emission standards, or storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. For example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards, and the EPA finalized its attainment/non-attainment designations in 2018, though these are subject to change. In December 2020, the EPA announced that it was retaining without revision the 2015 NAAQS for ozone. However, the Biden Administration has announced plans to formally review this decision and consider instituting a more stringent standard. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to our customers’ operations. Compliance with this final rule or any other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines or new restrictions or prohibitions with respect to permits or projects, and significantly increase our capital expenditures and operating costs, which could adversely impact our business. Historically, we have been able to satisfy the 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.
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. The Clean Water Act also requires us to maintain spill prevention control and countermeasure plans at our terminal facilities with above-ground storage tanks and pipelines. In addition, OPA requires that most fuel transport and storage companies maintain and update various oil spill prevention and oil spill contingency plans. Facilities that are adjacent to water require the engagement of Federally Certified Oil Spill Response Organizations to be available to respond to a spill on water from above-ground storage tanks or pipelines.
Transportation and storage of refined products over and adjacent to water involves risk and potentially subjects us to strict, joint, and potentially unlimited liability for removal costs and other consequences of an oil spill where the spill is into navigable waters, along shorelines or in the exclusive economic zone of the United States.
In the event of an oil spill into navigable waters, substantial liabilities could be imposed upon us. The Clean Water Act imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters, with the potential of substantial liability for the violation of permits or permitting requirements.
Terminal operations and associated facilities are subject to the Clean Air Act as well as comparable state and local statutes. Under these laws, permits may be required before construction can commence on a new source of potentially significant air emissions, and operating permits may be required for sources that are already constructed. If regulations become more stringent, additional emission control technologies.
Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the services we provide.
Climate change continues to attract considerable public, governmental and scientific attention. 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. 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, and, in the United States, President Biden has announced that he intends to pursue substantial reductions in GHG emissions, particularly from the oil and gas sector. For example, on January 27, 2021, President Biden signed an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, an increase in the production of offshore wind energy, and an increased emphasis on climate-related risks across government agencies and economic sectors. In August 2022, the IRA 2022 was signed into law, which appropriates significant federal funding for renewable energy initiatives and amends the federal Clean Air Act to impose a first-time fee on the emission of methane from sources required to report their GHG emissions to the EPA. 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. Calculation of the fee is based on certain thresholds established in the IRA 2022.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. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission
Federal agencies also have begun directly regulating GHG emissions, such as methane, from oil and natural gas operations. 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. These Subpart OOOOa standards expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. In September 2020, the EPA finalized amendments to Subpart OOOOa that rescind the methane limits for new,
reconstructed and modified oil and natural gas production sources while leaving in place the general emission limits for VOCs. In addition, the rulemaking removes from the oil and natural gas category the natural gas transmission and storage segment. However, Congress passed, and President Biden signed into law, a revocation of the 2020 rulemaking, effectively reinstating the 2016 standards. 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. The December 2023 rule also revises requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys, establishes a “super-emitter” response program to timely mitigate emissions events, triggering certain response and repair requirements, and provides additional options for the use of advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions. Fines and penalties for violations of these rules can be substantial. Several states have also adopted, or are considering, adopting, regulations related to GHG emissions, some of which are more stringent than those implemented by the federal government. Methane emission standards imposed on the oil and gas sector could result in increased costs to our operations or those of our customers as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business.
At the international level, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France in signing the “Paris Agreement,” a treaty that requires member countries to submit individually-determined, non-binding GHG emission reduction goals every five years beginning in 2020. Although the United States withdrew from the Agreement under the Trump administration, President Biden recommitted the United States in February 2021, and, in April 2021, announced a new, more rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. The international community gathered again in Glasgow in November 2021 at COP26 during which multiple announcements were made, including a call for parties to eliminate fossil fuel subsidies, amongst other measures. Relatedly, the United States and European Union jointly announced at COP26 the launch of the Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. At the 27th Conference of the Parties in Sharm El-Sheik in November 2022, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase-out of fossil fuel subsidies. The United States also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. In December 2023, at COP28, parties signed onto an agreement to transition away from fossil fuels in energy systems and increase renewable energy capacity so as to achieve net zero by 2050, although no timeline for doing so was set. Although no timeline to phase out or phase down all fossil fuels has been made, there can be no guarantees that countries will not seek to implement a timeline in the future.
President Biden’s January 2021 climate change executive order also directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs. This pause was subsequently subject to a permanent injunction in August 2022, effectively halting implementation of the leasing suspension with respect to those leases canceled or postponed prior to March 24, 2021. The executive order also directed the federal government to identify “fossil fuel subsidies” to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. As noted above, a separate executive order issued in January 2021 established a Working Group that is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” During 2021, the Working Group published interim estimates of the social costs of carbon, methane, and nitrous oxide and sought public comment on these estimates. The Working Group’s interim estimate of the social cost of carbon, $51 per ton, has been subject to litigation in 2022, but is in use while litigation is pending. It is difficult to predict how these measures may impact our business; however, any new restrictions on oil and gas permitting or leasing on federal lands could discourage new oil and gas development by our customers, which could have an adverse effect on our business.
The adoption, strengthening and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Litigation risks are also increasing, as several oil and gas companies have been sued for allegedly causing climate-related damages due to their production and sale of fossil fuel products or for allegedly being aware of the impacts of climate change for some time but failing to adequately disclose such risks to their investors or customers.
There are also increasing financing risks for fossil fuel energy companies, as various investors become increasingly concerned about the potential effects of climate change and may elect in the future to shift some or all of their investments into other sectors. 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. For example, at COP26, the GFANZ announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero by 2050. Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding for fossil fuel energy companies. In late 2020, the Federal Reserve announced that it has joined NGFS, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. In November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. In September 2022, the Federal Reserve announced that six of the United States’ largest banks will participate in a pilot climate scenario analysis exercise, which launched in early 2023, to enhance the ability of firms and supervisors to measure and manage climate-related financial risk. While we cannot predict what polices may result from these developments, such efforts could make it more difficult for exploration and production companies and midstream companies, like us, to secure funding as well as negatively affect the cost of, and terms for, financings to fund growth projects or other aspects of our business. Additionally, in March 2022 the SEC released a proposed rule requiring climate disclosures, which is expected to be finalized in 2024. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.
Climatic events in the areas in which we operate, whether from climate change or otherwise, can cause disruptions, and in some cases, delays in, or suspension of, our services. These event, including but not limited to drought, winter storms, wildfire, extreme temperatures or flooding, may become more intense or more frequent as a result of climate change and could have an adverse effect on our continued operations. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities or our customers’ facilities from powerful winds or rising waters. We may experience increased insurance costs, or difficulty obtaining adequate insurance coverage, for our assets in areas subject to more frequent severe weather. We may not be able to recoup these increased costs through the rates we charge our customers. Extreme weather events could cause damage to property or facilities that could exceed our insurance coverage and our business, financial condition and results of operations could be adversely affected.
Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our NGLs and natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we transport, and thus demand for our services. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our products could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.
A climate-related decrease in demand for crude oil, natural gas and other hydrocarbon products could negatively affect our business.
Supply and demand for crude oil, natural gas and other hydrocarbon products we handle is dependent upon a variety of factors, many of which are beyond our control. These factors include, among others, the potential adoption of new government regulations, including those related to fuel conservation measures and climate change regulations, technological advances in fuel economy and energy generation devices. For example, legislative, regulatory or executive actions intended to reduce emissions of GHGs could increase the cost of consuming crude oil, natural gas and other hydrocarbon products, thereby potentially causing a reduction in the demand for such products. A broader transition to alternative fuels or energy sources, whether resulting from potential new government regulation, carbon taxes, governmental incentives and funding such as those provided in the IRA 2022, or consumer preferences could result in decreased demand for hydrocarbon products like crude oil, natural gas and NGLs that we handle. Any decrease in demand for these products could consequently reduce demand for our services and could have a negative effect on our business.
Increased attention to ESG matters and conservation measures may adversely impact our business.
Increasing attention to, and societal expectations on companies to address, climate change and other environmental and social impacts, investor and societal expectations regarding voluntary ESG disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for fossil fuels and consequently demand for our midstream services, reduced profits, increased risk of investigations and litigation, and negative impacts on the value of our assets and access to capital. Increasing attention to climate change and environmental conservation, for example, may result in reduced demand for
oil and natural gas products and additional governmental investigations and private litigation against us or our customers. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to climate change or asserted damage to the environment, or to other mitigating factors. While we may participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations and products, we cannot guarantee that such participation or certification will have the intended results on our ESG profile. Moreover, while we are pursuing various low-carbon opportunities such as renewable power generation, renewable fuels, and carbon capture and storage projects through our alternative energy initiatives to address potential energy transition related risks, we cannot guarantee that we will be able to execute these projects in a timely manner because of permitting, technology, or other risks or that such opportunities will ultimately be successful.
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. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring, and reporting on many ESG matters. Additionally, while we may also announce various voluntary ESG targets in the future, such targets are aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including, but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent that we do meet such targets, we may consider the acquisition of various credits or offsets that may be deemed to assist in the achievement of such targets or otherwise mitigate our ESG impact instead of actual achievements of such targets or actual changes in our ESG performance. 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.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital. 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.
The swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder could have an adverse effect on our ability to use derivative instruments to mitigate the risks of changes in commodity prices and interest rates and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) requires that certain classes of swaps be cleared on a derivatives clearing organization and traded on a designated contract markets or other regulated exchange, unless exempt from such clearing and trading requirements, which could result in the application of certain margin requirements imposed by derivatives clearing organizations and their members. The CFTC and prudential regulators have also adopted mandatory margin requirements for uncleared swaps entered into between swap dealers and certain other counterparties. We currently qualify for and rely upon an end-user exception from such clearing and margin requirements for the swaps we enter into to hedge our commercial risks. However, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirements to other market participants, such as swap dealers, may adversely affect the cost and availability of the swaps that we use for hedging.
In addition to the Dodd-Frank Act, the European Union and other foreign regulators have adopted and are implementing local reforms generally comparable with the reforms under the Dodd-Frank Act. Implementation and enforcement of these regulatory provisions may reduce our ability to hedge our market risks with non-U.S. counterparties and may make transactions involving cross-border swaps more expensive and burdensome. Additionally, the lack of regulatory equivalency across jurisdictions may increase compliance costs and make it more difficult to satisfy our regulatory obligations.
Additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and decommissioning plans, and other related developments may have a material adverse effect on our business, financial condition, or results of operations.
The Federal Bureau of Ocean Energy Management (“BOEM”) and the federal Bureau of Safety and Environmental Enforcement (“BSEE”), each agencies of the DOI, have imposed more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. 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. For instance, in January 2021, the Biden Administration issued an executive order focused on climate change that, among other things, directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs.
In addition, new regulatory initiatives may be adopted or enforced by the BOEM or the BSEE in the future that could result in additional costs, delays, restrictions, or obligations with respect to oil and natural gas exploration and production operations conducted offshore by certain of our customers. Separately, in April 2023, BOEM and BSEE published a final rule regarding financial assurance requirements for offshore leases, particularly regarding requirements for bonds above base amounts prescribed by regulation. In June 2023, BOEM issued a notice of proposed rulemaking seeking to modify its criteria for determining bonds and financial assurance for offshore oil and gas lessees and other operators, which generally imposes more stringent requirements for waiving supplemental bonding requirements and changes how BOEM calculates the amount of supplemental financial assurance required, amongst other matters. At this time, we cannot determine with any certainty the amount of any additional financial assurance that may be ordered by BOEM and required of us in the future, or that such additional financial assurance amounts can be obtained. 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. Also, if material spill events were to occur in the future, the United States or other countries could elect to issue directives to temporarily cease drilling activities offshore and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and gas exploration and development. The overall costs imposed on our customers to implement and complete any such spill response activities or any decommissioning obligations could exceed estimated accruals, insurance limits, or supplemental bonding amounts, which could result in the incurrence of additional costs to complete. Separately, in January 2021, the Biden Administration issued orders temporarily suspending the issuance of new authorizations and suspending the issuance of new leases pending completion of a review of current practices, for oil and gas development on federal lands and waters. The suspension of these federal leasing activities prompted legal action by several states against the Biden Administration, resulting in issuance of a nationwide preliminary injunction by a federal district judge in Louisiana in June 2021 and permanent injunction in August 2022, effectively halting implementation of the leasing suspension. Additionally, provisions in the IRA 2022 require that particular offshore oil and gas lease sales under the 2017 - 2022 leasing program proceed, and the DOI has reinstated or announced plans for those 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 Mexico leasing sales. Relatedly, the DOI released its report on federal gas leasing and permitting practices in November 2021, referencing a number of recommendations and an overarching intent to modernize the federal oil and gas leasing program, including by adjusting royalty and bonding rates, prioritizing leasing in areas with known resource potential, and avoiding leasing that conflicts with recreation, wildlife habitat, conservation, and historical and cultural resources. Implementation of many of the recommendations in the DOI report will require Congressional action and we cannot predict the extent to which the recommendations may be implemented now or in the future, but restrictions on federal oil and gas activities have the potential to result in increased costs on us and our customers, decrease demand for our services on federal lands, and adversely impact our business and adversely impact our business. 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. The Biden Administration also published an order calling for an increase in the production of offshore wind energy, which may impact the use of federal waters. We cannot predict with any certainty the full impact of any new laws or regulations on our customers’ drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations. The occurrence of any one or more of these developments could result in decreased demand for our services, which could have a material adverse effect on our business as well as our financial position, results of operation and liquidity.
Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.
The petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. 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.
In addition, our patented butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect our ability to market our butane blending service licenses and which would ultimately affect our ability to recover the costs incurred to acquire and integrate our butane blending assets.
Risks Relating to Our Partnership Structure
Issuance of Common Units or Other Classes of Equity
We may issue an unlimited number of limited partner interests or other classes of equity without the consent of our Unitholders, which will dilute Unitholders’ ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.
Our Partnership Agreement allows us to issue an unlimited number of additional limited partner interests, including securities senior to the Common Units, without the approval of our Unitholders. 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.
Cash Distributions to Unitholders and Governance
Cash distributions are not guaranteed and may fluctuate with our performance and other external factors.
The amount of cash we can distribute to our Unitholders depends upon the amount of cash we generate from our operations and from our subsidiaries, Sunoco LP and USAC. The amount of cash we generate from our operations will fluctuate from quarter to quarter and will depend upon, among other things:
•the amount of natural gas, NGLs, crude oil and refined products transported in our pipelines;
•the level of throughput in our processing and treating operations;
•the fees we charge and the margins we realize for our services;
•the price of natural gas, NGLs, crude oil and refined products;
•the relationship between natural gas, NGL and crude oil prices;
•the weather in our operating areas;
•the level of competition from other midstream, transportation and storage and other energy providers;
•the level of our operating costs;
•prevailing economic conditions; and
•the level and results of our derivative activities.
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.
Because of all these factors, we cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our current quarterly distribution. The actual amount of cash that is available for distribution to our Unitholders will depend on numerous factors, many of which are beyond our control or the control of our general partner.
Furthermore, our Unitholders should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow and is not solely a function of profitability, which is affected by non-cash items. As a result, we may declare and/or pay cash distributions during periods when we record net losses.
Our general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to Unitholders.
Our Partnership Agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. 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.
Unitholders may have liability to repay distributions.
Under certain circumstances, Unitholders may have to repay us amounts wrongfully distributed to them. Under Delaware law, we may not make a distribution to Unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that a limited partner who receives such a distribution and knew at the time of the distribution that the distribution violated Delaware law, will be liable to the limited partnership for the distribution amount for three years from the distribution date.
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. Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, our Unitholders do not have the same protections afforded to stockholders of corporations that are subject to all of the corporate governance requirements of the applicable stock exchange.
Our General Partner
The control of our general partner may be transferred to a third party without Unitholder consent.
Our general partner may transfer its general partner interest to a third party without the consent of the Unitholders. Any new owner of the general partner would be in a position to replace the officers and directors of the general partner with its own designees and thereby exert significant influence over the decisions made by such officers and directors.
The majority owner of our general partner has rights that protect him against dilution.
Through his controlling interest in our general partner, Kelcy Warren owns all of the outstanding Energy Transfer Class A Units, which represents an approximately 20% voting interest in the Partnership. Under the terms of the Energy Transfer Class A Units, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to the general partner additional Energy Transfer Class A Units such that Mr. Warren maintains a voting interest in the Partnership that is equivalent to his voting interest in the Partnership with respect to such Energy Transfer Class A Units (approximately 20%) prior to such issuance of common units. As a result, Mr. Warren is partially protected against the dilutive effect of additional common unit issuances by the Partnership with respect to voting. As of December 31, 2023, the Partnership had outstanding 833,486,004 Energy Transfer Class A Units.
Cost reimbursements due to our general partner may be substantial and may reduce our ability to pay the distributions to Unitholders.
Prior to making any distributions to our Unitholders, we will reimburse our general partner for all expenses it has incurred on our behalf. In addition, our general partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by the general partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to the Unitholders. Our general partner has sole discretion to determine the amount of these expenses and fees.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
Unlike the holders of common stock in a corporation, our common unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our Unitholders have no right to elect our general partner or the board of directors of our general partner. Our general partner has the right to appoint and replace the members of the board, including all of its independent directors. Mr. Warren owns an 81.2% membership interest in our general partner and controls our general partner and therefore has the ability to direct our general partner with respect to the exercise of these governance rights.
If our Unitholders are dissatisfied with the general partner’s performance, they have limited ability to remove the general partner. The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove the general partner; however, Mr. Warren owns a significant number of common units and, through his controlling interest in the general partner, owns all of the outstanding Energy Transfer Class A Units, which vote together with the common units and entitle the holders of the Energy Transfer Class A Units to maintain the voting percentage in Energy Transfer represented by such Energy Transfer Class A Units as of the date the initial Energy Transfer Class A Units were issued (approximately 20%) any time new common units are issued. As of February 9, 2024, Mr. Warren’s combined common unit and Energy Transfer Class A Unit ownership results in a voting interest in the Partnership of 27%. As a result of this and other limitations, it may be more difficult to remove the general partner.
Furthermore, our Partnership Agreement contains provisions limiting the ability of common unitholders to call meetings or to obtain information about our operations, as well as other provisions limiting our common unitholders’ ability to influence the manner or direction of management. Common unitholders’ voting rights are further restricted by a provision of our Partnership Agreement providing that any units held by a person or group that owns 20% or more of such class of units then outstanding, other than, with respect to our common units, the general partner, its affiliates, their direct transferees and their indirect transferees approved by our general partner (which approval may be granted in its sole discretion) and persons who acquired such common units with the prior approval of the general partner, cannot vote on any matter.
Kelcy Warren owns a majority interest in, and controls, our general partner, and our general partner has sole responsibility for conducting our business and managing our operations. The general partner may have conflicts of interest with us and limited fiduciary duties, and it may favor its own interests to the detriment of us and our Unitholders.
Mr. Warren owns an 81.2% membership interest in, and therefore controls, the general partner and accordingly has the right to appoint and replace all of the officers and directors of the general partner. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our Unitholders, the directors and officers of the general partner also have a fiduciary duty to manage the general partner in a manner that is beneficial to its majority owner, Mr. Warren. Conflicts of interest will arise between the general partner and its owner, on the one hand, and us and our Unitholders, on the other hand. In resolving these conflicts of interest, the general partner may favor its own interests and the interests of its owner over our interests and the interests of our Unitholders.
Unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.
Under Delaware law, unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of limited partners to remove our general partner or to take other action under the Partnership Agreement constituted participation in the “control” of our business. Additionally, under Delaware law, our general partner has unlimited liability for the obligations of Energy Transfer, such as our debts and environmental liabilities, except for those contractual obligations of Energy Transfer that are expressly made without recourse to the general partner.
The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do 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.
Our general partner has a limited call right that may require Unitholders to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 90% of our outstanding units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. 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.
Our Subsidiaries
We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.
We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We do not have significant assets other than the partnership interests and the equity in our subsidiaries. As a result, our ability to pay distributions to our Unitholders and to service our debt depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities and applicable state partnership laws and other laws and regulations. In particular, our Five-Year Credit Facility, limits our and certain of our subsidiaries’ ability to make distributions. If we are unable to obtain funds from our subsidiaries, we may not be able to pay distributions to our Unitholders or to pay interest or principal on our debt when due.
The interruption of distributions to us from our operating subsidiaries and equity investees may affect our ability to satisfy our obligations and to make distributions to our partners.
We are a holding company with no business operations other than that of our operating subsidiaries. Our only significant assets are the equity interests we own in our operating subsidiaries and equity investees. As a result, we depend upon the earnings and cash flow of our operating subsidiaries and equity investees and any interruption of distributions to us may affect our ability to meet our obligations, including any obligations under our debt agreements, and to make distributions to our partners.
Our subsidiaries are not prohibited from competing with us.
Neither our Partnership Agreement nor the partnership agreements of our subsidiaries, including Sunoco LP and USAC, prohibit our subsidiaries from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, our subsidiaries may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.
Sunoco LP and USAC may issue additional common units, which may increase the risk that each Partnership will not have sufficient available cash to maintain or increase its per unit distribution level.
The partnership agreements of Sunoco LP and USAC allow each partnership to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by each respective partnership will have the following effects:
•unitholders’ current proportionate ownership interest in each partnership 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 may be diminished; and
•the market price of each partnership’s common units may decline.
The payment of distributions on any additional units issued by Sunoco LP and USAC may increase the risk that either partnership may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to meet our obligations
A reduction in Sunoco LP’s distributions will disproportionately affect the amount of cash distributions to which Energy Transfer is entitled.
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. Energy Transfer currently receives its pro rata share of cash distributions from Sunoco LP based on the highest sharing level of 50% in respect of the Sunoco LP IDRs.
A decrease in the amount of distributions by Sunoco LP to less than $0.65625 per unit per quarter would reduce Energy Transfer’s percentage of the incremental cash distributions from Sunoco LP above $0.546875 per unit per quarter from 50% to 25%. As a result, any such reduction in quarterly cash distributions from Sunoco LP would have the effect of disproportionately reducing the amount of all distributions that Energy Transfer receives, based on its ownership interest in the IDRs as compared to cash distributions received from its Sunoco LP common units.
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.
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. Sunoco LP revenues are dependent on various trends, such as trends in commercial truck traffic, travel and tourism in their areas of operation, and these trends can change. Regulatory action, including government imposed fuel efficiency standards, may also affect demand for motor fuel. Because certain of Sunoco LP’s operating costs and expenses are fixed and do not vary with the volumes of motor fuel distributed, their costs and expenses might not decrease ratably or at all should they experience such a reduction. As a result, Sunoco LP may experience declines in their profit margin if fuel distribution volumes decrease.
Any technological advancements, regulatory changes or changes in consumer preferences causing a significant shift toward alternative motor fuels could reduce demand for the conventional petroleum based motor fuels Sunoco LP currently sells. Additionally, a shift toward electric, hydrogen, natural gas or other alternative-power vehicles could fundamentally change customers’ shopping habits or lead to new forms of fueling destinations or new competitive pressures.
New technologies have been developed and governmental mandates have been implemented to improve fuel efficiency, which may result in decreased demand for petroleum-based fuel. For example, in December 2021, the Biden Administration announced revised GHG emissions standards for light-duty vehicle fleets for Model Years 2023-2026, which some manufacturers may meet by increasing fuel efficiency or increasing the prevalence of zero-emissions vehicles in their fleets. The Biden Administration has also set a goal for federal vehicle acquisitions to be 100% zero-emissions vehicles by 2035, which may further influence the composition of vehicle fleets. 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. Any 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.
Sunoco LP’s financial condition and results of operations are influenced by changes in the prices of motor fuel, which may adversely impact margins, customers’ financial condition and the availability of trade credit.
Sunoco LP’s operating results are influenced by prices for motor fuel. General economic and political conditions, acts of war or terrorism and instability in oil producing regions, particularly in the Middle East and South America, could significantly impact crude oil supplies and petroleum costs. Significant increases or high volatility in petroleum costs could impact consumer demand for motor fuel and convenience merchandise. Such volatility makes it difficult to predict the impact that future petroleum costs fluctuations may have on Sunoco LP’s operating results and financial condition. Sunoco LP is subject to dealer tank wagon pricing structures at certain locations further contributing to margin volatility. A significant change in any of these factors could materially impact both wholesale and retail fuel margins, the volume of motor fuel distributed or sold at retail, and overall customer traffic, each of which in turn could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.
Significant increases in wholesale motor fuel prices could impact Sunoco LP as some of their customers may have insufficient credit to purchase motor fuel from us at their historical volumes. Higher prices for motor fuel may also reduce access to trade credit support or cause it to become more expensive.
The industries in which Sunoco LP operates are subject to seasonal trends, which may cause its operating costs to fluctuate, affecting its cash flow.
Sunoco LP relies in part on customer travel and spending patterns and may experience more demand for gasoline in the late spring and summer months than during the fall and winter. Travel, recreation and construction are typically higher in these months in the geographic areas in which Sunoco LP or its commission agents and dealers operate, increasing the demand for motor fuel that they sell and distribute. Therefore, Sunoco LP’s revenues and cash flows are typically higher in the second and third quarters of our fiscal year. As a result, Sunoco LP’s results from operations may vary widely from period to period, affecting Sunoco LP’s cash flow.
The dangers inherent in the storage and transportation of motor fuel could cause disruptions in Sunoco LP’s operations and could expose them to potentially significant losses, costs or liabilities.
Sunoco LP stores motor fuel in underground and aboveground storage tanks. Sunoco LP transports the majority of its motor fuel in its own trucks, instead of by third-party carriers. Sunoco LP’s operations are subject to significant hazards and risks inherent in transporting and storing motor fuel. These hazards and risks include, but are not limited to, traffic accidents, fires, explosions, spills, discharges, and other releases, any of which could result in distribution difficulties and disruptions, environmental pollution, governmentally-imposed fines or clean-up obligations, personal injury or wrongful death claims, and other damage to its properties and the properties of others. Any such event not covered by Sunoco LP’s insurance could have a material adverse effect on its business, financial condition, results of operations and cash available for distribution to its unitholders.
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 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.
The occurrence of any of the above situations, amongst others, may affect operations at their fuel storage terminals and may adversely affect Sunoco LP’s business, financial condition, results of operations, cash flows and ability to make distributions to its unitholders.
Negative events or developments associated with Sunoco LP’s branded suppliers could have an adverse impact on its revenues.
Sunoco LP believes that the success of its operations is dependent, in part, on the continuing favorable reputation, market value, and name recognition associated with the motor fuel brands sold at Sunoco LP’s convenience stores and at stores operated by its independent, branded dealers and commission agents. Erosion of the value of those brands could have an adverse impact on the volumes of motor fuel Sunoco LP distributes, which in turn could have a material adverse effect on its business, financial condition, results of operations and ability to make distributions to its unitholders.
Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. A disruption in supply or a change in either relationship could have a material adverse effect on its business.
Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. If any of Sunoco LP’s principal suppliers elect not to renew their contracts, Sunoco LP may be unable to replace the volume of merchandise inventory and products and ingredients currently purchased from them on similar terms or at all in those operating areas. Further, a disruption in supply or a significant change in Sunoco LP’s relationship with any of these suppliers could have a material adverse effect on Sunoco LP’s business, financial condition and results of operations and cash available for distribution to its unitholders.
The wholesale motor fuel distribution industry and convenience store industry are characterized by intense competition and fragmentation and impacted by new entrants. Failure to effectively compete could result in lower margins.
The market for distribution of wholesale motor fuel is highly competitive and fragmented, which results in narrow margins. Sunoco LP has numerous competitors, some of which may have significantly greater resources and name recognition than it does. Sunoco LP relies on its ability to provide value-added, reliable services and to control its operating costs in order to maintain our margins and competitive position. If Sunoco LP fails to maintain the quality of its services, certain of its customers could choose alternative distribution sources and margins could decrease. While major integrated oil companies have generally continued to divest retail sites and the corresponding wholesale distribution to such sites, such major oil companies could shift from this strategy and decide to distribute their own products in direct competition with Sunoco LP, or large customers could attempt to buy directly from the major oil companies. The occurrence of any of these events could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.
The geographic areas in which Sunoco LP operates and supplies independently operated commission agent and dealer locations are highly competitive and marked by ease of entry and constant change in the number and type of retailers offering products and services of the type we and our independently operated commission agents and dealers sell in stores. Sunoco LP competes with other convenience store chains, independently owned convenience stores, motor fuel stations, supermarkets, drugstores, discount stores, dollar stores, club stores, mass merchants and local restaurants. Over the past two decades, several non-traditional retailers, such as supermarkets, hypermarkets, club stores and mass merchants, have impacted the convenience store industry, particularly in the geographic areas in which Sunoco LP operates, by entering the motor fuel retail business. These non-traditional motor fuel retailers have captured a significant share of the motor fuels market, and Sunoco LP expects their market share will continue to grow.
In some of Sunoco LP’s markets, its competitors have been in existence longer and have greater financial, marketing, and other resources than they or their independently operated commission agents and dealers do. As a result, Sunoco LP’s competitors may be able to better respond to changes in the economy and new opportunities within the industry. To remain competitive, Sunoco LP must constantly analyze consumer preferences and competitors’ offerings and prices to ensure that they offer a selection of convenience products and services at competitive prices to meet consumer demand. Sunoco LP must also maintain and upgrade our customer service levels, facilities and locations to remain competitive and attract customer traffic to our stores. Sunoco LP may not be able to compete successfully against current and future competitors, and competitive pressures faced by Sunoco LP could have a material adverse effect on its business, results of operations and cash available for distribution to its unitholders.
Sunoco LP may be subject to adverse publicity resulting from concerns over food quality, product safety, health or other negative events or developments that could cause consumers to avoid its retail locations or independently operated commission agent or dealer locations.
Sunoco LP may be the subject of complaints or litigation arising from food-related illness or product safety which could have a negative impact on its business. Negative publicity, regardless of whether the allegations are valid, concerning food quality, food safety or other health concerns, food service facilities, employee relations or other matters related to its operations may materially adversely affect demand for its food and other products and could result in a decrease in customer traffic to its retail stores or independently operated commission agent or dealer locations.
It is critical to Sunoco LP’s reputation that they maintain a consistent level of high quality at their food service facilities and other franchise or fast food offerings. Health concerns, poor food quality or operating issues stemming from one store or a limited number of stores could materially and adversely affect the operating results of some or all of their stores and harm the company-owned brands, continuing favorable reputation, market value and name recognition.
Sunoco LP does not own all of the land on which its retail service stations are located, and Sunoco LP leases certain facilities and equipment, and Sunoco LP is subject to the possibility of increased costs to retain necessary land use which could disrupt its 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. As such, Sunoco LP is subject to the possibility of increased costs under rental agreements with landowners, primarily through rental increases and renewals of expired agreements. Sunoco LP is also subject to the risk that such agreements may not be renewed. Additionally, certain facilities and equipment (or parts thereof) used by Sunoco LP are leased from third parties for specific periods. Sunoco LP’s inability to renew leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material adverse effect on its financial condition, results of operations and cash flows.
Sunoco LP is subject to federal laws related to the Renewable Fuel Standard.
New laws, new interpretations of existing laws, increased governmental enforcement of existing laws or other developments could require us to make additional capital expenditures or incur additional liabilities. For example, certain independent refiners have initiated discussions with the EPA to change the way the Renewable Fuel Standard (“RFS”) is administered in an attempt to shift the burden of compliance from refiners and importers to blenders and distributors. Under the RFS, which requires an annually increasing amount of biofuels to be blended into the fuels used by U.S. drivers, refiners/importers are obligated to obtain renewable identification numbers (“RINs”) either by blending biofuel into gasoline or through purchase in the open market. If the obligation was shifted from the importer/refiner to the blender/distributor, the Partnership would potentially have to utilize the RINs it obtains through its blending activities to satisfy a new obligation and would be unable to sell RINs to other obligated parties, which may cause an impact on the fuel margins associated with Sunoco LP’s sale of gasoline. 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. Subject to certain limitations, EPA now has significant discretion to set renewable fuel targets under the RFS, which could result in increased compliance obligations on refiners and importers and transportation fuels. The price of RINs to meet compliance obligations under the RFS could be substantial and adversely impact our financial condition.
The occurrence of any of the events described above could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.
Sunoco LP is subject to federal, state and local laws and regulations that govern the product quality specifications of refined petroleum products it purchases, stores, transports, and sells to its distribution customers.
Various federal, state, and local government agencies have the authority to prescribe specific product quality specifications for certain commodities, including commodities that Sunoco LP distributes. Changes in product quality specifications, such as reduced sulfur content in refined petroleum products, or other more stringent requirements for fuels, could reduce Sunoco LP’s ability to procure product, require it to incur additional handling costs and/or require the expenditure of capital. If Sunoco LP is unable to procure product or recover these costs through increased selling price, it may not be able to meet its financial obligations. Failure to comply with these regulations could result in substantial penalties for Sunoco LP.
If third-party pipelines and other facilities interconnected to Sunoco LP’s fuel storage terminals and transmix processing facilities become partially or fully unavailable to transport refined products, Sunoco LP’s revenues could be adversely affected.
Sunoco LP depends upon third-party pipelines and other facilities that provide delivery options to and from its fuel storage terminals and transmix processing facilities. Since Sunoco LP does not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within Sunoco LP’s control. If any of these third-party facilities become partially or fully unavailable, or if the quality specifications for their facilities change so as to restrict our ability to utilize them, Sunoco LP’s financial condition and results of operations could be adversely affected.
The third parties on whom Sunoco LP relies for transportation services to its fuel storage terminals and transmix processing facilities are subject to complex federal, state, and other laws that could adversely affect Sunoco LP’s financial condition and results of operations.
The operations of the third parties on whom Sunoco LP relies for transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing
laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that Sunoco LP pays for services. Similarly, a failure to comply with such laws and regulations by the third parties could have a material adverse effect on Sunoco LP’s financial condition and results of operations.
Failure of Sunoco LP to complete its acquisition of NuStar and successfully integrate the businesses of Sunoco LP and NuStar in the expected time frame could negatively impact the price of Sunoco LP’s common units and have a material adverse effect on its results of operations, cash flows and financial position.
If Sunoco LP’s acquisition of NuStar is not completed for any reason, including as a result of failure to obtain all requisite regulatory approvals or Sunoco LP’s unitholders failing to approve the applicable proposals, the anticipated benefits of the acquisition may not be realized or may take longer to realize than expected. The success of the merger will depend, in part, on the ability of Sunoco LP to realize the anticipated benefits from combining its business and NuStar. If Sunoco LP and NuStar are unable to successfully combine their businesses, the anticipated benefits of the merger may take longer to realize than expected. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the merger.
Additionally, Sunoco LP would be subject to a number of risks, including the following:
•negative reactions from the financial markets, including negative impacts on the price of Sunoco LP’s common units;
•negative reactions from Sunoco LP’s customers, distributors, suppliers, vendors, landlords, joint venture partners and/or other business partners;
•Sunoco LP will still be obligated to pay certain significant costs relating to its acquisition of NuStar, such as legal, accounting, financing, advisory and/or printing fees;
•Sunoco LP may be obligated to pay a termination fee as required by the merger agreement governing the acquisition;
•the merger agreement governing the acquisition places certain restrictions on the conduct of Sunoco LP’s business, which may delay or prevent the undertaking of business opportunities that, absent the merger agreement governing the acquisition, may have been pursued;
•matters relating to Sunoco LP’s acquisition of NuStar (including integration planning) require substantial commitments of time and resources by Sunoco LP’s management, which may have resulted in the distraction from ongoing business operations and pursuing other opportunities that could have been beneficial;
•litigation related to any failure of Sunoco LP to complete its acquisition of NuStar or related to any enforcement proceeding commenced against Sunoco LP to perform its respective obligations under the merger agreement governing the acquisition; and
•loss of key employees, the disruption of each of Sunoco LP’s and NuStar’s ongoing businesses and relationships with customers, or inconsistencies in their standards, controls, procedures and policies.
If the acquisition is not completed, the risks described above may materialize and they may have a material adverse effect on Sunoco LP’s results of operations, cash flows, financial position and/or price of its common units.
USAC’s customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, increasing the number of compression units they currently own or using alternative technologies for enhancing crude oil production.
USAC’s customers that are significant producers, processors, gatherers and transporters of natural gas and crude oil may choose to vertically integrate their operations by purchasing and operating their own compression fleets in lieu of using USAC’s compression services. The historical availability of attractive financing terms from financial institutions and equipment manufacturers facilitates this possibility by making the purchase of individual compression units more affordable to USAC’s customers. In addition, there are many technologies available for the artificial enhancement of crude oil production, and USAC’s customers may elect to use these alternative technologies instead of the gas lift compression services USAC provides. 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.
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.
USAC’s contracts typically have initial terms between six months to five years, depending on the application and location of the compression unit. After the expiration of the initial term, the contract continues on a month-to-month or longer basis until terminated by USAC or USAC’s customers upon notice as provided for in the applicable contract. 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. If a significant number of these customers were to terminate their month-to-month services, or attempt to renegotiate their month-to-month contracts at substantially lower rates, it could have a material adverse effect on USAC’s business, results of operations, financial condition and cash available for distribution.
USAC’s preferred units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of its common units.
USAC’s preferred units rank senior to all of its other classes or series of equity securities with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for its common units or could make it more difficult for USAC to sell its common units in the future.
In addition, distributions on USAC’s preferred units accrue and are cumulative, at the rate of 9.75% per annum on the original issue price, which amounts to a quarterly distribution of $24.375 per preferred unit. If USAC does not pay the required distributions on its preferred units, USAC will be unable to pay distributions on its common units. Additionally, because distributions on USAC’s preferred units are cumulative, USAC will have to pay all unpaid accumulated distributions on the preferred units before USAC can pay any distributions on its common units. Also, because distributions on USAC’s common units are not cumulative, if USAC does not pay distributions on its common units with respect to any quarter, USAC’s common unitholders will not be entitled to receive distributions covering any prior periods if USAC later recommences paying distributions on its common units.
USAC’s preferred units are convertible into common units by the holders of USAC’s preferred units or by USAC in certain circumstances. USAC’s obligation to pay distributions on USAC’s preferred units, or on the common units issued following the conversion of USAC’s preferred units, could impact USAC’s liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions and other general Partnership purposes. USAC’s obligations to the holders of USAC’s preferred units could also limit its ability to obtain additional financing or increase its borrowing costs, which could have an adverse effect on its financial condition.
Risks Related to Conflicts of Interest
The fiduciary duties of our general partner’s officers and directors may conflict with those of Sunoco LP’s or USAC’s respective general partners.
Conflicts of interest may arise because of the relationships among Sunoco LP, USAC, their general partners and us. Our General Partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our Unitholders. Some of our general partner’s directors or officers are also directors and/or officers of Sunoco LP’s general partner or USAC’s general partner, and have fiduciary duties to manage the respective businesses of Sunoco LP and USAC in a manner beneficial to Sunoco LP, USAC and their respective unitholders. The resolution of these conflicts may not always be in our best interest or that of our Unitholders.
Although we control Sunoco LP and USAC through our ownership of Sunoco LP’s and USAC’s general partners, Sunoco LP’s and USAC’s general partners owe duties to Sunoco LP and Sunoco LP’s unitholders and USAC and USAC’s unitholders, respectively, which may conflict with our interests.
Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and Sunoco LP and USAC and their respective limited partners, on the other hand. The directors and officers of Sunoco LP’s and USAC’s general partners have duties to manage Sunoco LP and USAC, respectively, in a manner beneficial to us. At the same time, the general partners have fiduciary duties to manage Sunoco LP and USAC in a manner beneficial to Sunoco LP and USAC and their respective limited partners. The boards of directors of Sunoco LP’s and USAC’s general partner will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest.
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.
Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of us.
Conflicts of interest may arise among our general partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following:
•our general partner is allowed to take into account the interests of parties other than us, including Sunoco LP and USAC, and their respective affiliates and any general partners and limited partnerships acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duties to us.
•our general partner has limited its liability and reduced its fiduciary duties under the terms of our Partnership Agreement, while also restricting the remedies available for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, Unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.
•our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution.
•our general partner determines which costs it and its affiliates have incurred are reimbursable by us.
•our Partnership Agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.
•our general partner controls the enforcement of obligations owed to us by it and its affiliates.
•our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
Our Partnership Agreement limits our general partner’s fiduciary duties to us and restricts the remedies available for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our Partnership Agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our Partnership Agreement:
•permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. 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;
•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.
Our general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our Unitholders.
Our Partnership Agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. 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.
Affiliates of our general partner may compete with us.
Except as provided in our Partnership Agreement, affiliates and related parties of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us.
Tax Risks to Unitholders
Our tax treatment depends on our continuing status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation. If the IRS were to treat us and our subsidiaries, including Sunoco LP and USAC as a corporation for federal income tax purposes or if we, Sunoco LP or USAC become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter. The value of our investments in Sunoco LP and USAC, depend largely on Sunoco LP and USAC being treated as partnerships for federal income tax purposes. Despite the fact that we, Sunoco LP and USAC are each a limited partnership under Delaware law, we would each be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations and current Treasury Regulations, we believe we, Sunoco LP and USAC satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us, Sunoco LP or USAC to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we, Sunoco LP or USAC were treated as a corporation for federal income tax purposes, we would pay federal income tax at the corporate tax rate and we would likely pay additional state income taxes at varying rates. Distributions to Unitholders would generally be taxed again as corporate distributions, and none of our income, gains, losses or deductions would flow through to Unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to Unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the Unitholders, likely causing a substantial reduction in the value of our units.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. We currently own property or conduct business in many states that impose a margin or franchise tax. In the future, we may expand our operations. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our cash available for distribution to our Unitholders. 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.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present United States federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. Members of Congress have frequently proposed and considered substantive changes to the existing United States federal income tax laws that affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment. Recent proposals have provided for the expansion of the qualifying income exception for publicly traded partnerships in certain circumstances and other proposals have provided for the total elimination of the qualifying income exception upon which we rely for our partnership tax treatment. Further, while Unitholders of publicly traded partnerships are, subject to certain limitations, entitled to a deduction equal to 20% of their allocable share of a publicly traded partnership’s “qualified business income,” this deduction is scheduled to expire with respect to taxable years beginning after December 31, 2025.
In addition, the U.S. Department of the Treasury has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to United States federal income tax laws or the U.S. Department of the Treasury’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.
Any modification to the United States federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for United States federal income tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any future legislative changes could negatively impact the value of an investment in our units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our units.
If the IRS contests the federal income tax positions we take, the market for our units may be adversely affected and the costs of any such contest will reduce cash available to pay our debt securities and for distributions to our Unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our units, and the prices at which they trade. In addition, the costs of any contest between us and the IRS will result in a reduction in our cash available to pay our debt securities and for distribution to our Unitholders and thus will be borne indirectly by our Unitholders.
If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available to pay our debt securities and for distribution to our Unitholders might be substantially reduced.
If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue an information statement to each Unitholder and former Unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our Unitholders and former Unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current Unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such Unitholders did not own units in us during the tax year under audit. 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.
Our Unitholders are required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us. 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.
If a Unitholder sells their units, the Unitholder will recognize a gain or loss equal to the difference between the amount realized and that Unitholder’s tax basis in those units. Because distributions in excess of a Unitholder’s allocable share of our net taxable income decrease such Unitholder’s tax basis in their units, the amount, if any, of such prior excess distributions with respect to the units a Unitholder sells will, in effect, become taxable income to a Unitholder if such units are sold at a price greater than their tax basis in those units, even if the price such Unitholder receives is less than their original costs. In addition, because the amount realized includes a Unitholder’s share of our nonrecourse liabilities, if a Unitholder sells their units, a Unitholder may incur a tax liability in excess of the amount of cash received from the sale.
A substantial portion of the amount realized from a Unitholder’s sale of their units, whether or not representing gain, may be taxed as ordinary income to such Unitholder due to potential recapture items, including depreciation recapture. Thus, a Unitholder may recognize both ordinary income and capital loss from the sale of Common Units if the amount realized on a sale of such units is less than such Unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a Unitholder sells their units, such Unitholder may recognize ordinary income from our allocations of income and gain to such Unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.
Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from United States federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Additionally, all or part of any gain recognized by such tax-exempt organization upon a sale or other disposition of our units may be unrelated business taxable income and may be taxable to them. Tax-exempt entities should consult a tax advisor before investing in our units.
Non-United States Unitholders will be subject to United States taxes and withholding with respect to their income and gain from owning our units.
Non-United States Unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a United States trade or business (“effectively connected income”). Income allocated to our Unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a United States trade or business. As a result, distributions to a non-United States Unitholder will be subject to withholding at the highest applicable effective tax rate and a non-United States Unitholder who sells or otherwise disposes of a unit will also be subject to United States federal income tax on the gain realized from the sale or disposition of that unit. In addition to the withholding tax imposed on distributions of effectively connected income, distributions to a non-U.S. unitholder will also be subject to a 10% withholding tax on the amount of any distribution in excess of our cumulative net income. We intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject to such 10% withholding tax. Accordingly, distributions to a non-U.S. unitholder will be subject to a combined withholding tax rate equal to the sum of the highest applicable effective tax rate and 10%.
Moreover, the transferee of an interest in a partnership that is engaged in a United States trade or business is generally required to withhold 10% of the “amount realized” by the transferor unless the transferor certifies that it is not a foreign person. While the determination of a partner’s “amount realized” generally includes any decrease of a partner’s share of the partnership’s liabilities, the Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. For a transfer of interests in a publicly traded partnership that is effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Current and prospective non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our units.
We have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.
Even though we (as a partnership for United States federal income tax purposes) are not subject to United States federal income tax, some of our operations are conducted through subsidiaries that are organized as corporations for United States federal income tax purposes. The taxable income, if any, of subsidiaries that are treated as corporations for United States federal income tax purposes, is subject to corporate-level United States federal income taxes, which may reduce the cash available for distribution to us and, in turn, to our Unitholders. If the IRS or other state or local jurisdictions were to successfully assert that these corporations have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the
cash available for distribution could be further reduced. The income tax return filings positions taken by these corporate subsidiaries require significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts of deductible and taxable items. Despite our belief that the income tax return positions taken by these subsidiaries are fully supportable, certain positions may be successfully challenged by the IRS, state or local jurisdictions.
We treat each purchaser of units as having the same tax benefits without regard to the actual units purchased. The IRS may challenge this treatment, which could result in a Unitholder owing more tax and may adversely affect the value of the units.
Because we cannot match transferors and transferees of units and because of other reasons, we have adopted certain methods for allocating depreciation, depletion and amortization that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to our Unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of units and could have a negative impact on the value of our units or result in audit adjustments to tax returns of our Unitholders. Moreover, because we have subsidiaries that are organized as C corporations for federal income tax purposes, a successful IRS challenge could result in these subsidiaries having a greater tax liability than we anticipate and, therefore, reduce the cash available for distribution to our partnership and, in turn, to our Unitholders.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge aspects of our proration method, and if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month (the “Allocation Date”), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets and (iii) in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.
A Unitholder whose common or preferred units are the subject of a securities loan (e.g. a loan to a short seller to cover a short sale of common or preferred units) may be considered as having disposed of those units. If so, such Unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a Unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the Unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller, and the Unitholder and may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the Unitholder and any cash distributions received by the Unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
We have adopted certain valuation methodologies in determining Unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations, and such a challenge could adversely affect the value of our Common Units.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of our Unitholders and our general partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets ourselves using a methodology based on the market value of our Common Units as a means to measure the fair market value of our assets. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain Unitholders and our general partner, which may be unfavorable to such Unitholders. Moreover, under our current valuation methods, subsequent purchasers of our Common Units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge
our valuation methods, or our allocation of Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our Unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our Unitholders. It also could affect the amount of gain on the sale of Common Units by our Unitholders and could have a negative impact on the value of our Common Units or result in audit adjustments to the tax returns of our Unitholders without the benefit of additional deductions.
Unitholders will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where they do not live as a result of investing in our units.
In addition to United States federal income taxes, the Unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or our subsidiaries conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, Unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each Unitholder to file all federal, state and local tax returns.
Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, our deduction for “business interest” is generally limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, adjusted taxable income is computed without regard to any business interest expense or business interest income.
If our “business interest” is subject to limitation under these rules, our Unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
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.
The tax treatment of our Preferred Units is uncertain. With respect to Preferred Units (other than Series I Preferred Units), we will treat Preferred Unitholders as partners for tax purposes and will treat distributions on such Preferred Units as guaranteed payments for the use of capital that will generally be taxable to such Preferred Unitholders as ordinary income. Preferred Unitholders of our Preferred Units (other than Series I Preferred Units) will recognize taxable income from the accrual of such a guaranteed payment (even in the absence of a contemporaneous cash distribution). Otherwise, except in the case of our liquidation, Preferred Unitholders of our Preferred Units (other than Series I Preferred Units) are generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to such Preferred Unitholders. If the Energy Transfer Preferred Units (other than Series I Preferred Units) were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to Preferred Unitholders.
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. As a result income attributable to a guaranteed payment for use of capital recognized by holders of our Preferred Units is not eligible for the 20% deduction for qualified business income.
With respect to Series I Preferred Units, we will treat distributions as distributions to a partner and will treat Preferred Unitholders that hold Series I Preferred Units (the “Series I Preferred Unitholders”) as receiving an allocable share of gross income from us, to the extent we have sufficient gross income to make such allocations. In the event there is not sufficient gross income to match such distributions, the distributions on the Series I Preferred Units would reduce the capital accounts of the Series I Preferred Units, requiring a subsequent allocation of income or gain to provide the Series I Preferred Units with their liquidation preference, if possible. However, if the IRS were to determine that such distributions were guaranteed payments for the use of capital, the distributions would generally be taxable to each of the Series I Preferred Unitholders as ordinary income and the Series I Preferred Unitholders would recognize taxable income from the accrual of such guaranteed payment (even in the absence of a contemporaneous cash distribution), as described above with respect to Preferred Units (other than Series I Preferred Units). If the Series I Preferred Units are not treated as partnership interests, they would likely constitute indebtedness for tax purposes, and distributions on the Series I Preferred Units likely would be treated as payments of interest by us to such Series I Preferred Unitholders.
A Preferred Unitholder will be required to recognize gain or loss on a sale of Energy Transfer Preferred Units equal to the difference between the amount realized by such Preferred Unitholder and such Preferred Unitholder’s tax basis in the Energy Transfer Preferred Units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such Preferred Unitholder receives in exchange for such Energy Transfer Preferred Units. Subject to general rules requiring a blended basis among multiple partnership interests and the rules applicable in determining the exchanged tax basis of a Series I Preferred Unit received by a Unitholder pursuant to the Crestwood acquisition, the tax basis of a Preferred Unit will generally be equal to the sum of the cash and the fair market value of other property paid by the Preferred Unitholder to acquire such Energy Transfer Preferred Units. Gain or loss recognized by a Preferred Unitholder on the sale or exchange of Energy Transfer Preferred Units held for more than one year generally will be taxable as long-term capital gain or loss. Because Preferred Unitholders will generally not be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such Preferred Unitholders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.
Investment in our Preferred Units by tax-exempt investors, such as employee benefit plans and individual retirement accounts, and non-United States persons raises issues unique to them. With respect to Preferred Units (other than Series I Preferred Units), the treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and such payments may be treated as unrelated business taxable income for federal income tax purposes. With respect to Series I Preferred Units, virtually all of our gross income allocated to tax-exempt investors will be unrelated business taxable income and will be taxable to them. Distributions to non-United States Preferred Unitholders will be subject to withholding taxes. If the amount of withholding exceeds the amount of United States federal income tax actually due, non-United States Preferred Unitholders may be required to file United States federal income tax returns in order to seek a refund of such excess.
All Preferred Unitholders are urged to consult a tax advisor with respect to the consequences of owning Energy Transfer Preferred Units.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES
A description of our properties is included in “Item 1. Business.” In addition, we own office buildings for our executive offices in Dallas, Texas and office buildings in Newton Square, Pennsylvania; Houston, Texas and San Antonio, Texas. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.
We believe that we have satisfactory title to or valid rights to use all of our material properties. Although some of our properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements and immaterial encumbrances, easements and restrictions, we do not believe that any such burdens will materially interfere with our continued use of such properties in our business, taken as a whole. In 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.
Substantially all of our pipelines, which are described in “Item 1. Business,” are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, properties on which our pipelines were built were purchased in fee. We also own and operate multiple natural gas and NGL storage facilities and own or lease other processing, treating and conditioning facilities in connection with our midstream operations.

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ITEM 3. LEGAL PROCEEDINGS
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.
Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. 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.
ETC Sunoco and Energy Transfer R&M (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.
As of March 31, 2023, Sunoco Defendants are defendants in two cases: one case initiated by the State of Maryland and one by the Commonwealth of Pennsylvania. The actions brought also named as defendants ETO, ETP Holdco and Sunoco Partners Marketing & Terminals L.P., now known as Energy Transfer Marketing & Terminals L.P.
It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.
In late 2016, FERC Enforcement Staff began a non-public investigation related to Rover’s purchase and removal of a potentially historic home (known as the Stoneman House) while Rover’s application for permission to construct the new 711-mile interstate natural gas pipeline and related facilities was pending. On March 18, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN19-4-000), ordering Rover to explain why it should not pay a $20 million civil penalty for alleged violations of FERC regulations requiring certificate holders to be forthright in their submissions of information to the FERC. Rover filed its answer and denial to the order on June 21, 2021 and a surreply on September 15, 2021. FERC issued an order on January 20, 2022 setting the matter for hearing before an administrative law judge. On January 25, 2022, the chief judge assigned an administrative law judge and set a timeline for a prehearing conference.
On February 1, 2022, Energy Transfer and Rover filed a Complaint for Declaratory Relief in the United States District Court for the Northern District of Texas seeking an order declaring that FERC must bring its enforcement action in federal district court (instead of before an administrative law judge). Also on February 1, 2022, Energy Transfer and Rover filed an expedited request to stay the proceedings before the FERC administrative law judge pending the outcome of the federal district court case. On May 24, 2022, the District Court ordered a stay of the FERC’s enforcement case and the District Court case pending the resolution of two cases pending before the United States Supreme Court. Arguments were heard in those cases on November 7, 2022. On April 14, 2023, the United States Supreme Court held against the government in both cases, finding that the federal district courts had jurisdiction to hear those suits and to resolve the parties’ constitutional challenges. The cases were remanded to the federal district courts for further proceedings.
On September 13, 2023 the District Court ordered that the District Court case would be stayed pending the resolution of another case pending before the United States Supreme Court and that the FERC enforcement case would remain stayed. Energy Transfer and Rover intend to vigorously defend this claim. On November 13, 2023, the FERC appealed the District Court order to the United States Court of Appeals for the Fifth Circuit. On December 11, 2023, FERC filed a motion to withdraw that
appeal, which the Fifth Circuit granted on December 12, 2023. The FERC and District Court proceedings remain stayed pending resolution of the case pending before the United States Supreme Court.
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. 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. On December 16, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN17-4-000), ordering Rover to show cause why it should not be found to have violated Section 7(e) of the NGA, Section 157.20 of FERC’s regulations, and the Rover Pipeline Certificate Order, and assessed civil penalties of $40 million.
Rover and Energy Transfer filed their answer to this order on March 21, 2022, and Enforcement Staff filed a reply on April 20, 2022. Rover and Energy Transfer filed their surreply to this order on May 13, 2022. FERC has taken no further action on the case since that time. Any and all losses, including any fines and penalties from government agencies, resulting from the general contractor’s alleged actions in conducting such HDD operations are subject to indemnity rights in favor of Rover and the Partnership. Given the stage of the proceedings, the Partnership is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any; however, the Partnership believes the indemnity described above will be applicable to the penalty proposed by Enforcement Staff and intends to vigorously defend itself against the subject claims.
On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants (collectively, the “Defendants”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. The Defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District court of appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court. On April 22, 2020, the Ohio Supreme Court granted the review. On March 17, 2022, the Ohio Supreme Court reversed in part and remanded to the Ohio trial court. The Ohio Supreme Court agreed with Rover that the State of Ohio had waived its rights under Section 401 of the Clean Water Act but remanded to the trial court to determine whether any of the allegations fell outside the scope of the waiver. On remand, the Ohio EPA voluntarily dismissed four of the other five defendants and dismissed one of its counts against Rover. In its Fourth Amended Complaint, the Ohio EPA removed all paragraphs that alleged violations by the four dismissed defendants, including those where the dismissed defendants were alleged to have acted jointly with Rover or others. At a June 2, 2022, status conference, the trial judge set a schedule for Rover and the other remaining defendant to file motions to dismiss the Fourth Amended Complaint. On August 1, 2022, Rover and the other remaining defendant each filed their respective motions. Briefing on those motions was completed on November 4, 2022. By order issued on October 20, 2023, the trial judge dismissed the Ohio EPA’s Fourth Amended 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.
In January 2019, we received notice from the DOJ on behalf of the EPA that a civil penalty enforcement action was being pursued under the Clean Water Act for an estimated 450 barrel crude oil release from the Mid Valley Pipeline operated by SPLP and owned by Mid Valley. 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. In December of 2019, SPLP reached an agreement in principal with the EPA regarding payment of a civil penalty which will be subject to public comment. 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. 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. D-101-CV-2022-00174 in the First Judicial District Court, County of Santa Fe, State of New Mexico, seeking to recover statewide damages for contamination with PCBs used for decades by the oil and gas industry in the operation and maintenance of pipeline infrastructure. 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.
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. 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. 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. 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. Mid Valley received a Notice of Federal Interest regarding the incident and is awaiting final invoicing from the federal agencies (United States Environmental Protection Agency and United States Fish and Wildlife Service) and their consultants related to the incident. Mid Valley has also supplied PHMSA with information as requested. 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. 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.
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. Plaintiffs alleged actual monetary damages and punitive damages totaling $380 million. The Energy Transfer Defendants were served on or around July 5, 2023, and timely filed a notice of removal of the lawsuit to federal court in the Western District of Tennessee-Eastern Division on August 2, 2023. 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.
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 NOPSO requests that Mid Valley perform several proposed corrective measures within six months of receipt of a Safety Order; however, in response, Mid Valley requested that PHMSA engage in informal consultations prior to issuing a Safety Order in an effort for the parties to potentially enter into a Consent Agreement and Order. Informal consultation is underway. In the event a Consent Agreement and Order is not reached between the parties during this process, Mid Valley may request a Hearing on the NOPSO. It is too early to predict the outcome, timeline, or costs associated with this administrative action.
On October 28, 2022, the EPA issued a Notice of Proposed Debarment (“NPD”) arising from SPLP’s and ETC Northeast Pipeline, LLC’s nolo contendere plea agreements and convictions for violations of Pennsylvania’s Clean Streams Law related to the Revolution and Mariner 2 pipelines. The following entities were proposed for debarment: (1) SPLP (pleading entity); (2) ETC Northeast Pipeline, LLC (pleading entity); (3) Energy Transfer LP; (4) SemGroup LLC; and (5) LE GP, LLC. The NPD presently prevents the named entities from pursuing or renewing Federal government contracts or Federal financial assistance agreements. We are engaging with the EPA to address the EPA’s concerns. Currently, none of the entities named in the NPD are party to any Federal government contracts or Federal financial assistance agreements.
On June 15, 2023, PHMSA issued a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (collectively “NOPV”), CPF 4-2023-011-NOPV, identifying three probable violations with compliance order actions associated with two of them and civil penalties proposed in an amount totaling $2,473,912. 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, and requested an administrative hearing, which is set for April 24, 2024 before a PHMSA Presiding Official.
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. Civil Action No. 2:23-cv-214, against Sunoco and two other parties seeking to recover past CERCLA response costs allegedly incurred by the EPA in excess of $500,000 and certain declaratory relief related to compliance. Suntide Refining Company (Sunoco as successor) is alleged to have arranged for the transport and disposal of refinery wastes containing hazardous substances at the Brine Service Company Superfund Site in Corpus Christi, Nueces County, TX. 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. Please see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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. 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. Our common units are registered under the Exchange Act, and are listed for trading on the NYSE under the ticker symbol “ET.” Each holder of a common unit is entitled to one vote per unit on all matters presented to the limited partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all common units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our Partnership Agreement. 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 Energy Transfer Class A Units are entitled to vote together with the Partnership’s common units, as a single class, except as required by law. Additionally, Energy Transfer’s Partnership Agreement provides that, under certain circumstances, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to any holder of Energy Transfer Class A Units additional Energy Transfer Class A Units such that the holder maintains a voting interest in the Partnership that is identical to its voting interest in the Partnership prior to such issuance of common units. The Energy Transfer Class A Units are not entitled to distributions and otherwise have no economic attributes.
Energy 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. 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.
(2)In connection with the Enable acquisition in December 2021, Energy Transfer issued 384,780 additional Series G Preferred Units. 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.
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.
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. 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. Available Cash is defined in the Partnership Agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to:
•provide for the proper conduct of its business;
•comply with applicable law and/or debt instrument or other agreement; and
•provide funds for distributions to Unitholders and its General Partner in respect of any one or more of the next four quarters.
Recent Sales of Unregistered Securities
None.
Issuer Purchases of Equity Securities
None.
Securities Authorized for Issuance Under Equity Compensation Plans
For information on the securities authorized for issuance under Energy Transfer’s equity compensation plans, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. 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. 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.
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.
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “Energy Transfer” mean Energy Transfer LP and its consolidated subsidiaries.
OVERVIEW
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.
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. 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. Energy Transfer distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.
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.
General
Our primary objective is to increase the level of our distributable cash flow to our Unitholders over time by pursuing a business strategy that is currently focused on growing our subsidiaries’ natural gas and liquids businesses through, among other things, pursuing certain construction and expansion opportunities relating to our subsidiaries’ existing infrastructure and acquiring certain strategic operations and businesses or assets. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash our subsidiaries generate from their operations.
Our reportable segments are as follows:
•intrastate transportation and storage;
•interstate transportation and storage;
•midstream;
•NGL and refined products transportation and services;
•crude oil transportation and services;
•investment in Sunoco LP;
•investment in USAC; and
•all other.
Recent Developments
Crestwood Acquisition
On November 3, 2023, Energy Transfer acquired Crestwood, which owns gathering and processing assets located in the Williston, Delaware and Powder River basins. Under the terms of the merger agreement, holders of Crestwood common units received 2.07 Energy Transfer common units for each Crestwood common unit held by them (the “Common Unit Merger Consideration”). Additionally, each outstanding Crestwood preferred unit was, at the election of the holder of such Crestwood preferred unit, either, (i) converted into a Series I Preferred Unit, which is a new preferred unit of Energy Transfer that has substantially similar terms, including with respect to economics and structural protections, as the Crestwood preferred units; (ii) redeemed in exchange for $9.857484 in cash plus accrued and unpaid distributions to the date of such redemption; or (iii) converted into a Crestwood common unit at the then-applicable conversion ratio of one Crestwood common unit for ten Crestwood preferred units, and such Crestwood common units then received the Common Unit Merger Consideration.
In total, consideration issued in the transaction included approximately 216 million Energy Transfer common units, 41 million Series I Preferred Units and $300 million in cash. Concurrent with the closing of the Crestwood acquisition, the Partnership assumed $2.85 billion aggregate principal amount of Crestwood senior notes and terminated its revolving credit facility, which included the repayment of $613 million in outstanding borrowings.
Lotus Midstream Acquisition
On May 2, 2023, Energy Transfer acquired Lotus Midstream for total consideration of $1.50 billion, including working capital. Consideration included $930 million in cash and approximately 44.5 million newly issued Energy Transfer common units, which had an aggregate acquisition-date fair value of $574 million. Lotus Midstream owns and operates Centurion Pipeline Company LLC, an integrated crude midstream platform located in the Permian Basin.
Sunoco LP’s Acquisitions and Divestiture
On January 22, 2024, Sunoco LP entered into a definitive agreement with NuStar to acquire NuStar in an all-equity transaction valued at approximately $7.3 billion, including assumed debt. Under the terms of the agreement, NuStar common unitholders will receive 0.4 Sunoco common units for each NuStar common unit. NuStar has approximately 9,500 miles of pipeline and 63 terminal and storage facilities that store and distribute crude oil, refined products, renewable fuels, ammonia and specialty liquids. The transaction is expected to close in the second quarter of 2024, subject to customary closing conditions.
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. As part of the sale, Sunoco LP will also amend its existing take-or-pay fuel supply agreement with 7-Eleven, Inc. to incorporate additional fuel gross profit. The transaction is expected to close promptly upon receipt of regulatory approvals and satisfaction of customary closing conditions.
On January 11, 2024, Sunoco LP also announced that it will acquire liquid fuels terminals in Amsterdam, Netherlands and Bantry Bay, Ireland from Zenith Energy for €170 million including working capital. The transaction is expected to close in the first quarter of 2024, subject to customary closing conditions.
On May 1, 2023, Sunoco LP completed the acquisition of 16 refined product terminals located across the East Coast and Midwest from Zenith Energy for $111 million, including working capital.
Regulatory Update
Interstate Natural Gas Transportation Regulation
Rate Regulation
Effective January 2018, the 2017 Tax Cuts and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC clarified that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’ income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding the FERC’s decision denying a separate master limited partnership recovery of an income tax allowance and its decision not to require the master limited partnership to refund accumulated deferred income tax balances. In light of the rehearing order’s clarification regarding an individual entity’s ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impact of the FERC’s policy on the treatment of income taxes on the rates we can charge for FERC-regulated transportation services is unknown at this time.
Even without application of the FERC’s rate making-related policy statements and rulemakings, the FERC or our shippers may challenge the cost-of-service rates we charge. 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. 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. Many of our interstate pipelines, such as Tiger Pipeline, Midcontinent Express Pipeline and Fayetteville Express Pipeline, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as Florida Gas Transmission Pipeline, Transwestern and Panhandle, have a mix of tariff rate, discount rate and negotiated rate agreements. The revenues we receive from natural gas transportation services we provide pursuant to cost-of-service based rates may decrease in the future as a result of changes to FERC policies, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost-of-service rates, if any, will depend on a detailed review of all of our cost-of-service components and the outcomes of any challenges to our rates by the FERC or our shippers.
On July 18, 2018, the FERC issued a final rule establishing procedures to evaluate rates charged by the FERC-jurisdictional gas pipelines in light of the Tax Act and the FERC’s Revised Policy Statement. By an order issued on January 16, 2019, the FERC initiated a review of Panhandle’s then existing rates pursuant to Section 5 of the NGA to determine whether the rates charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the NGA. The NGA Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021, and on December 16, 2022, the FERC issued its order on the initial decision. On January 17, 2023, Panhandle and the Michigan Public Service Commission each filed a request for rehearing of FERC’s order on the initial decision, which were denied by operation of law as of February 17, 2023. On March 23, 2023, Panhandle appealed these orders to the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”), and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the Court of Appeals consolidated Panhandle’s and Michigan Public Service Commission’s appeals and stayed the consolidated appeal proceeding while the FERC further considered the requests for rehearing of its December 16, 2022 order. On September 25, 2023, the FERC issued its order addressing arguments raised on rehearing and compliance, which denied our requests for rehearing. Panhandle has timely filed its Petition for Review with the Court of Appeals regarding the September 25, 2023 order. On October 25, 2023, Panhandle filed a limited request for rehearing of the September 25 order addressing arguments raised on rehearing and compliance, which was subsequently denied by operation of law on November 27, 2023. On November 30, 2023, Panhandle submitted a refund report regarding the consolidated rate proceedings, which has been protested by several parties. On January 5, 2024, the FERC issued a second order addressing arguments raised on rehearing in which it modified certain discussion from its September 25, 2023 order and sustained its prior conclusions. Panhandle has timely filed its Petition for Review with the Court of Appeals regarding the January 5, 2024 order.
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. On February 18, 2021, the FERC issued another NOI (“2021 NOI”), reopening its review of the 1999 Policy Statement. Comments on the 2021 NOI were due on May 26, 2021; we filed comments in the FERC proceeding. In September 2021, FERC issued a Notice of Technical Conference on Greenhouse Gas Mitigation related to natural gas infrastructure projects authorized under Sections 3 and 7 of the NGA. A technical conference was held on November 19, 2021, and post-technical conference comments were submitted to the FERC on January 7, 2022.
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 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. Comments on the 2022 Policy Statements were due on April 25, 2022, and reply comments were due on May 25, 2022. 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 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”). Under the ICA, the FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. Many existing pipelines utilize the FERC liquids index to change transportation rates annually. 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%. The FERC received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG minus 0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period July 1, 2022 to June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the January 20 order with FERC, which was denied by FERC on May 6, 2022. 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. Specifically, the policy statement adopted the proposal in the FERC’s earlier Notice of Inquiry issued on March 25, 2020 to eliminate the “Substantially Exacerbate Test” as the preliminary screen applied to complaints against index rate increases and instead adopt the proposal to apply the “Percentage Comparison Test” as the preliminary screen for both protests and complaints against index rate increases. At this time, we cannot determine the effect of a change in the FERC’s preliminary screen for complaints against index rates changes, however, a revised screen would result in a threshold aligned with the existing threshold for protests against index rate increases. Any complaint or protest raised by a shipper could materially and adversely affect our financial condition, results of operations or cash flows.
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. As part of the Plan, the EPA announced that it would be issuing prescriptive emission standards for several sectors, including certain new and existing internal combustion engines of a certain size used in pipeline transportation of natural gas. The EPA’s final rule was to become effective on August 4, 2023, and the prescribed emission standards were scheduled to be effective in 2026; however, of the nine states impacted within the Partnership’s footprint, effectiveness of the rule is currently stayed in six states and pending a decision on a stay in three other states. Additionally, other operators and industry groups have challenged the Plan and sought a stay in the D.C. Circuit. Although the stay was denied, it was promptly followed by the filing of an emergency stay application with the U.S. Supreme Court, which will be heard on February 19, 2024, all while EPA has proposed adding five more states to the Plan. The Partnership currently estimates that the final rule would require retrofitting or replacement of approximately 192 engines in its interstate and intrastate natural gas transportation and storage operations. The Partnership is involved in challenging application of the Plan in the nine states impacted within its footprint. Compliance with the Plan (if implementation is not stayed or otherwise delayed) will still require substantial capital expenditures which could adversely affect our business in future periods. However, at this time, we are still assessing the potential costs of this rule and, given uncertainties resulting from the multiple legal challenges filed against the Plan in various states, in the DC Circuit and the U.S. Supreme Court, we cannot predict with any certainty what the final costs of compliance for the Plan for the Partnership ultimately may be.
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.
While we anticipate that current and projected commodity prices and the related impact to activity levels in both the upstream and midstream sectors will continue to impact our business, we cannot predict the ultimate magnitude of that impact and expect it to be varied across our operations, depending on the region, customer, type of service, contract term and other factors.
In addition, the U.S. economy has experienced higher-than-average inflation in recent years, which has resulted in higher costs for labor, services, and materials. Our suppliers and customers also face inflationary pressures, and our throughput volumes may be impacted if producers are constrained. While the rate and scope of various inflationary factors may increase our operating costs and capital expenditures materially, we anticipate that any such impacts would be recoverable in the prices of our services.
Ultimately, the extent to which our business will be impacted by future market developments depends on factors beyond our control, which are highly uncertain and cannot be predicted. In response to the recent market volatility and uncertainties, we have reduced growth capital spending in recent years, and we expect to continue to maintain a prudent level of growth capital spending going forward. See “Liquidity and Capital Resources” for additional information on our capital expenditures over the last two years and our forecasted capital expenditures for 2024.
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 to the trends and outlook discussed above with respect to the Partnership’s existing business and finances, we also anticipate that the Partnership will continue to increase its focus on the development of alternative energy projects. The Partnership has announced several such projects recently and will continue to pursue opportunities aimed at continuing to reduce its environmental footprint throughout its operations.
Results of Operations
We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total Partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items, as well as certain non-recurring gains and losses. Inventory adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at LIFO. These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.
Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.
Segment Adjusted EBITDA, as reported for each segment in the following table, is analyzed in the section titled “Segment Operating Results.” Adjusted EBITDA is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’s fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures.
Year Ended December 31, 2023 Compared to the Year Ended December 31, 2022
Consolidated Results
Years Ended December 31,
2023 2022 Change
Segment Adjusted EBITDA:
Intrastate transportation and storage $ 1,111 $ 1,396 $ (285)
Interstate transportation and storage 2,009 1,753 256
Midstream 2,525 3,210 (685)
NGL and refined products transportation and services 3,894 3,025 869
Crude oil transportation and services 2,681 2,187 494
Investment in Sunoco LP 964 919 45
Investment in USAC 512 426 86
All other 2 177 (175)
Adjusted EBITDA (consolidated) $ 13,698 $ 13,093 $ 605
Years Ended December 31,
2023 2022 Change
Reconciliation of net income to Adjusted EBITDA:
Net income $ 5,294 $ 5,868 $ (574)
Depreciation, depletion and amortization 4,385 4,164 221
Interest expense, net of interest capitalized 2,578 2,306 272
Income tax expense 303 204 99
Impairment losses and other 12 386 (374)
Gains on interest rate derivatives (36) (293) 257
Non-cash compensation expense 130 115 15
Unrealized gains on commodity risk management activities (3) (42) 39
Inventory valuation adjustments (Sunoco LP) 114 (5) 119
Gains on extinguishments of debt (2) - (2)
Adjusted EBITDA related to unconsolidated affiliates 691 565 126
Equity in earnings of unconsolidated affiliates (383) (257) (126)
Non-operating litigation-related loss 627 - 627
Other, net (12) 82 (94)
Adjusted EBITDA (consolidated) $ 13,698 $ 13,093 $ 605
Net Income. For the year ended December 31, 2023 compared to the prior year, net income decreased $574 million, or approximately 10%, primarily due to the recognition of a $627 million non-operating litigation-related loss, as well as decreases in gains on interest rate derivatives and increases in interest expense, income tax expense and depreciation, depletion and amortization expense; each of these items is discussed further below. The impacts of these decreases were partially offset by an increase in equity in earnings of unconsolidated affiliates, as well as the impacts of impairment and other losses recognized in the prior period; these items are also discussed further below. The change to net income also reflects changes in Adjusted EBITDA, which are summarized below and discussed in more detail in “Segment Operating Results.”
Adjusted EBITDA (consolidated). For the year ended December 31, 2023 compared to the prior year, Adjusted EBITDA increased $605 million primarily due to favorable results in multiple segments. The most significant increase was in our NGL and refined products transportation and services segment, which reflected higher throughput and contractual rates, as well as favorable impacts from optimization. Our crude oil transportation and services segment and our interstate transportation and storage segment also contributed to the increase in Adjusted EBITDA primarily due to higher volumes, as well as the impacts of recently acquired assets and assets recently placed in service. The increases from these segments were partially offset by a decrease in our midstream segment, primarily driven by the impacts of natural gas and NGL prices, and a decrease in our intrastate transportation and storage segment, which was impacted by lower pipeline optimization.
Additional information on changes impacting Adjusted EBITDA for the year ended December 31, 2023 compared to the prior year is available below and in “Segment Operating Results.”
Depreciation, Depletion and Amortization. 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. For the year ended December 31, 2023 compared to the same period last year, income tax expense increased due to higher earnings from the Partnership’s consolidated corporate subsidiaries.
Impairment Losses and Other. For the year ended December 31, 2023, impairment losses and other consisted of impairment losses incurred by USAC related to its compression equipment.
For the year ended December 31, 2022, impairment losses and other included an $85 million loss on the deconsolidation of Energy Transfer Canada, which was recorded upon the completion of the sale in August 2022. The amount also included a $300 million impairment related to Energy Transfer Canada’s assets recorded in March 2022 based on the anticipated proceeds from the expected sale of those assets. The remainder of the impairment losses were from USAC’s recognition of impairment losses related to its compression equipment.
Gains on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Gains on interest rate derivatives resulted from changes in forward interest rates, which caused our forward-starting swaps to change in value. The magnitude of the gains during the respective periods also reflected changes in the aggregate notional amount of interest rate swaps outstanding during the respective periods.
Unrealized Gains 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. Information on the unrealized gains and losses within each segment are included in “Segment Operating Results” below, and additional information on the commodity-related derivatives, including notional volumes, maturities and fair values, is available in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and in Note 14 to our consolidated financial statements included in “Item 8. 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. 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.
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 Williams Litigation, which is discussed in Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Other, net. Other, net primarily includes amortization of regulatory assets and other income and expense amounts.
Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated affiliates:
Years Ended December 31,
2023 2022 Change
Equity in earnings (losses) of unconsolidated affiliates:
Citrus
$ 146 $ 141 $ 5
MEP
87 10 77
White Cliffs (1)
10 (8) 18
Explorer 37 25 12
Other
103 89 14
Total equity in earnings of unconsolidated affiliates
$ 383 $ 257 $ 126
Adjusted EBITDA related to unconsolidated affiliates(2):
Citrus
$ 335 $ 326 $ 9
MEP
121 45 76
White Cliffs
29 20 9
Explorer 57 41 16
Other
149 133 16
Total Adjusted EBITDA related to unconsolidated affiliates
$ 691 $ 565 $ 126
Distributions received from unconsolidated affiliates:
Citrus $ 135 $ 133 $ 2
MEP 115 27 88
White Cliffs 25 19 6
Explorer 38 27 11
Other 103 88 15
Total distributions received from unconsolidated affiliates $ 416 $ 294 $ 122
(1)For the year ended December 31, 2022, equity in earnings (losses) of unconsolidated affiliates included the impact of non-cash impairments recorded by White Cliffs, which reduced the Partnership’s equity in earnings by $9 million.
(2)These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.
Segment Operating Results
We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.
The following tables identify the components of Segment Adjusted EBITDA, which is calculated as follows:
•Segment margin, operating expenses and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.
•Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. 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.
•Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses related to equity awards. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.
•Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.
In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.
In addition, for certain segments, the following sections include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.
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. For the year ended December 31, 2023 compared to the prior year, transported volumes increased primarily due to increased utilization on our Texas intrastate assets, partially offset by decreased production from our Haynesville assets.
Segment Margin. 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. 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.
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. 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, 2023 compared to the prior year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:
•an increase of $143 million in segment margin primarily due to a $141 million increase resulting from our Gulf Run system being placed in service in December 2022, a $47 million increase in transportation revenue from several of our interstate pipeline systems due to higher contracted volumes and higher rates, an $18 million increase related to a shipper bankruptcy, a $20 million increase in parking and storage revenue and a $5 million increase in interruptible utilization. These increases were partially offset by a $58 million decrease due to lower operational gas sales resulting from lower prices, a $23 million decrease due to lower rates on our Panhandle system resulting from a FERC rate case and an $8 million decrease in liquids revenue due to lower prices;
•a decrease of $45 million in operating expenses primarily due to a $65 million decrease from the revaluation of system gas and a $10 million decrease in ad valorem taxes due to lower assessments on several of our interstate pipelines. These decreases were partially offset by $25 million of incremental expenses from our Gulf Run system being placed in service in December 2022 and higher maintenance project costs of $4 million;
•a decrease of $16 million in selling, general and administrative expenses primarily due to an $11 million decrease in M&A related expenses and a $7 million decrease in professional fees. These decreases were partially offset by $3 million of incremental expenses from our Gulf Run system being placed in service in December 2022; and
•an increase of $88 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to an increase of $76 million from our Midcontinent Express Pipeline joint venture due to capacity sold at higher rates, a $9 million increase from our Citrus joint venture due to revenues from new projects and lower operating expenses and an $8 million increase from our Southeast Supply Header joint venture due to increased capacity sold at higher rates. These increases were partially offset by a $6 million decrease from our Fayetteville Express Pipeline joint venture due to the expiration of a foundation shipper contract; partially offset by
•a decrease of $36 million in other Adjusted EBITDA primarily due to the 2022 recognition of certain amounts related to shipper bankruptcies.
Midstream
Years Ended December 31,
2023 2022 Change
Gathered volumes (BBtu/d) 19,937 18,582 1,355
NGLs produced (MBbls/d) 880 800 80
Equity NGLs (MBbls/d) 43 44 (1)
Revenues $ 10,406 $ 17,101 $ (6,695)
Cost of products sold 6,503 12,682 (6,179)
Segment margin 3,903 4,419 (516)
Operating expenses, excluding non-cash compensation expense (1,204) (1,087) (117)
Selling, general and administrative expenses, excluding non-cash compensation expense (199) (186) (13)
Adjusted EBITDA related to unconsolidated affiliates 20 25 (5)
Other 5 39 (34)
Segment Adjusted EBITDA $ 2,525 $ 3,210 $ (685)
Volumes. 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, 2023 compared to the prior year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:
•a decrease of $739 million due to lower natural gas prices of $478 million and lower NGL prices of $261 million;
•an increase in operating expenses of $117 million due to a $36 million increase in services and materials, including repairs, volume-driven consumables and maintenance, compliance and pricing, a $31 million increase in employee costs due to segment reallocations, increased headcount and wage and benefit costs, a $43 million increase from newly acquired and installed assets, and a $10 million increase in ad valorem taxes, partially offset by a $4 million decrease in utility costs;
•an increase of $13 million in selling, general and administrative expenses primarily due to higher corporate allocations and M&A expenses;
•a decrease of $5 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to the sale of the Partnership’s membership interest in Ranch Westex JV LLC in 2022; and
•a decrease of $34 million in other Adjusted EBITDA primarily due to the realization in the previous period of certain amounts related to a shipper bankruptcy; partially offset by
•an increase of $223 million due to newly acquired assets as well as higher volumes across all regions.
NGL and Refined Products Transportation and Services
Years Ended December 31,
2023 2022 Change
NGL transportation volumes (MBbls/d)
2,116 1,882 234
Refined products transportation volumes (MBbls/d)
540 521 19
NGL and refined products terminal volumes (MBbls/d)
1,430 1,274 156
NGL fractionation volumes (MBbls/d)
1,023 911 112
Revenues
$ 21,903 $ 25,657 $ (3,754)
Cost of products sold
17,049 21,656 (4,607)
Segment margin
4,854 4,001 853
Unrealized (gains) losses on commodity risk management activities (38) 16 (54)
Operating expenses, excluding non-cash compensation expense
(892) (962) 70
Selling, general and administrative expenses, excluding non-cash compensation expense
(157) (127) (30)
Adjusted EBITDA related to unconsolidated affiliates
126 97 29
Other
1 - 1
Segment Adjusted EBITDA
$ 3,894 $ 3,025 $ 869
Volumes. For the year ended December 31, 2023 compared to the prior year, NGL transportation volumes increased primarily due to higher volumes from the Permian region, on our Mariner East pipeline system and on our Gulf Coast export pipelines. 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 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. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:
•an increase of $273 million in transportation margin primarily due to a $136 million increase resulting from higher throughput and contractual rate escalations on our Texas y-grade pipeline system, a $95 million increase resulting from higher throughput and contractual rate escalations on our Mariner East pipeline system, a $41 million increase from higher export volumes feeding into our Nederland Terminal, a $27 million increase from higher throughput and contractual rate escalations on our refined product pipelines, a $12 million increase from the timing of third-party deficiency payments on our Northeast region pipelines and a $7 million increase from higher throughput on our Mariner West pipeline. These increases were partially offset by intrasegment charges of $29 million and $17 million which were fully offset within our marketing and fractionation margins, respectively;
•an increase of $260 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to higher gains during 2023 from the optimization of hedged NGL and refined product inventories, as well as intrasegment margin of $29 million which was fully offset within our transportation margin;
•an increase of $193 million in terminal services margin primarily due to a $120 million increase from our Marcus Hook Terminal due to contractual rate escalations and higher throughput, a $65 million increase from higher export volumes
loaded at our Nederland Terminal, a $4 million increase due to higher throughput from our refined product marketing terminals and a $3 million increase from tank leases at our Eagle Point Terminal;
•a decrease of $70 million in operating expenses primarily due to an $87 million decrease in gas and power utility costs, partially offset by a $16 million increase in employee costs;
•an increase of $38 million in fractionators and refinery services margin primarily due to a $29 million increase resulting from higher volumes and $17 million in intrasegment margin which was fully offset within our transportation margin. These increases were partially offset by an $8 million decrease from our refinery services business;
•an increase of $35 million in storage margin associated with increased NGL export volumes; and
•an increase of $29 million in Adjusted EBITDA related to unconsolidated affiliates due to higher volumes on certain joint venture pipelines; partially offset by
•an increase of $30 million in selling, general and administrative expenses primarily due to a $13 million increase resulting from a one-time charge related to regulatory expenses, a $9 million increase in overhead expenses and a $6 million increase in insurance costs.
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. For the year ended December 31, 2023 compared to the prior year, crude oil transportation volumes were higher on our Texas pipeline system due to higher Permian crude oil production, higher gathered volumes and contributions from assets acquired in 2023. Bakken Pipeline volumes were also higher. Volumes on our Bayou Bridge Pipeline were higher due to continuing strong Gulf Coast refinery demand. Midcontinent systems were higher, driven by contributions from assets acquired in 2023. We also realized higher Bakken gathering volumes. Crude terminal volumes were higher due to growth in Permian and Bakken volumes, stronger Gulf Coast refinery utilization and contributions from assets acquired in 2023.
Segment Adjusted EBITDA. For 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
•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.
Investment in Sunoco LP
Years Ended December 31,
2023 2022 Change
Revenues $ 23,068 $ 25,729 $ (2,661)
Cost of products sold 21,703 24,350 (2,647)
Segment margin 1,365 1,379 (14)
Unrealized (gains) losses on commodity risk management activities (21) 21 (42)
Operating expenses, excluding non-cash compensation expense
(420) (396) (24)
Selling, general and administrative, excluding non-cash compensation expense
(113) (111) (2)
Adjusted EBITDA related to unconsolidated affiliates
10 10 -
Inventory valuation adjustments
114 (5) 119
Other, net
29 21 8
Segment Adjusted EBITDA
$ 964 $ 919 $ 45
The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP segment decreased due to the net impacts of the following:
•an increase in the gross profit on motor fuel sales of $34 million primarily due to an 8% increase in gallons sold; and
•an increase in non-motor fuel sales and lease profit of $37 million primarily due to increased throughput and storage margin from the Gladieux and Zenith acquisitions and increased rental income; partially offset by
•an increase in operating costs of $26 million, including other operating expense, general and administrative expense and lease expense. The increase was primarily due to higher costs as a result of the recent acquisitions of refined product terminals and the transmix processing and terminal facility.
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.
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to the net impacts of the following:
•an increase of $115 million in segment margin primarily due to higher revenue-generating horsepower as a result of increased demand for compression services, higher market-based rates on newly deployed and redeployed compression units and higher average rates on existing customer contracts; partially offset by
•an increase of $24 million in operating expenses primarily due to higher employee costs associated with increased revenue-generating horsepower as well as higher parts and service costs.
All Other
Years Ended December 31,
2023 2022 Change
Revenue
$ 1,798 $ 3,574 $ (1,776)
Cost of products sold
1,740 3,328 (1,588)
Segment margin
58 246 (188)
Unrealized (gains) losses on commodity risk management activities (22) 2 (24)
Operating expenses, excluding non-cash compensation expense
(40) (80) 40
Selling, general and administrative expenses, excluding non-cash compensation expense
(85) (60) (25)
Adjusted EBITDA related to unconsolidated affiliates
4 4 -
Other and eliminations
87 65 22
Segment Adjusted EBITDA
$ 2 $ 177 $ (175)
Amounts reflected in our all other segment primarily include:
•our natural gas marketing operations;
•our wholly owned natural gas compression operations;
•our investment in coal handling facilities; and
•our Canadian operations, until those assets were divested in August 2022.
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA decreased primarily due to the net impacts of the following:
• a decrease of $35 million due to higher M&A expenses;
•a decrease of $80 million due to the sale of Energy Transfer Canada in 2022;
•a decrease of $25 million from our dual drive compression business due to lower gas prices and increased electricity cost;
•a decrease of $21 million due to less favorable power trading market conditions;
•an increase of $8 million in ad valorem taxes due to tax credits utilized in 2022; and
•a decrease of $9 million in storage and trading gains; partially offset by
•an increase of $27 million due to increased sales in our compressor packaging business.
LIQUIDITY AND CAPITAL RESOURCES
Our ability to satisfy our obligations and pay distributions to Unitholders will depend on our future performance, which will be subject to prevailing economic, financial, business, weather conditions and other factors, many of which are beyond management’s control. The significant trends and uncertainties that we currently believe could significantly impact our liquidity and cash flows going forward are discussed in “Trends and Outlook” above.
We believe that we have sufficient liquidity and sources of funding to meet our cash requirements over the near term and for the longer term. 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. The Partnership’s obligations under its long-term debt agreements are described below under “Description of Indebtedness,” and information on the maturities and interest rates related to the Partnership’s long-term debt is available in Note 6 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” In addition, information on the Partnership’s obligations under its lease arrangements is included in Note 13 to our consolidated financial statements included in “Item 8. 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. We have long and short-term product purchase obligations for commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract. 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 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.
The assets used in our natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, we do not have any significant financial commitments for maintenance capital expenditures in our businesses. From time to time, we experience increases in pipe costs due to a number of reasons, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond our control. However, we include these factors in our anticipated growth capital expenditures for each year.
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.
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. These include regulatory changes, the price of our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions and other factors.
Operating Activities
Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisitions of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value for such grants. 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. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of derivative assets and liabilities, timing of accounts receivable collection, payments on accounts payable, the timing of purchases and sales of inventories, and the timing of advances and deposits received from customers.
Following is a summary of operating activities by period:
Year Ended December 31, 2023
Cash provided by operating activities in 2023 was $9.56 billion and net income was $5.29 billion. 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 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 Partnership also received distributions of $353 million from unconsolidated affiliates.
Year Ended December 31, 2022
Cash provided by operating activities in 2022 was $9.05 billion and net income was $5.87 billion. The difference between net income and cash provided by operating activities in 2022 primarily consisted of non-cash items totaling $4.53 billion offset by net changes in operating assets and liabilities of $1.50 billion. The non-cash activity in 2022 consisted primarily of depreciation, depletion and amortization of $4.16 billion, impairment losses of $386 million, non-cash compensation expense of $115 million, equity in earnings of unconsolidated affiliates of $257 million, favorable inventory valuation adjustments of $5 million, and deferred income taxes of $187 million. The Partnership also received distributions of $232 million from unconsolidated affiliates.
Investing Activities
Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash distributions from our joint ventures, and cash proceeds from sales or contributions of assets or businesses. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.
Following is a summary of investing activities by period:
Year Ended December 31, 2023
Cash used in investing activities in 2023 was $4.33 billion. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) were $3.09 billion. Additional detail related to our capital expenditures is provided in the following table. We received $38 million of cash proceeds from the sale of assets. The Partnership also received distributions of $63 million from unconsolidated affiliates. 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 16 refined product terminals from Zenith Energy.
Year Ended December 31, 2022
Cash used in investing activities in 2022 was $4.02 billion. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) were $3.33 billion. Additional detail related to our capital expenditures is provided in the following table. We received $78 million of cash proceeds from the sale of assets. The Partnership also received distributions of $62 million from unconsolidated affiliates. In 2022, we paid $1.14 billion in cash for acquisitions, net of cash received. In 2022, we received $302 million in cash from the sale of our interest in Energy Transfer Canada.
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. 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. 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. During 2023, we incurred debt issuance costs of $45 million.
Year Ended December 31, 2022
Cash used in financing activities was $5.11 billion in 2022. In 2022, we had a net decrease in our debt level of $843 million. During 2022, we paid distributions of $3.05 billion to our partners, we paid distributions of $1.55 billion to noncontrolling interests, and we paid distributions of $49 million to our redeemable noncontrolling interests. In addition, we received capital contributions of $405 million in cash from noncontrolling interests. During 2022, we incurred debt issuance costs of $27 million.
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.
(2)See additional information below under “Recent Transactions.”
(3)As of December 31, 2023, current maturities of long-term debt reflected on the Partnership’s consolidated balance sheet included $1.00 billion of senior notes issued by the Bakken Pipeline entities which mature in April 2024. The Partnership’s proportional ownership in the Bakken Pipeline entities is 36.4%.
The terms of our consolidated indebtedness and that of our subsidiaries are described in more detail below and in Note 6 to our consolidated financial statements included in “Item 8. 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. 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.
In November 2023, concurrent with the closing of the Crestwood acquisition, the Partnership assumed $2.85 billion aggregate principal amount of Crestwood senior notes and terminated its revolving credit facility, which included the repayment of $613 million in outstanding borrowings.
In November 2023, the Partnership redeemed $600 million aggregate principal amount of its 4.50% Senior Notes due November 2023 using proceeds from the senior notes offering discussed in the following paragraph.
In October 2023, the Partnership issued $1.00 billion aggregate principal amount of 6.05% Senior Notes due 2026, $500 million aggregate principal amount of 6.10% Senior Notes due 2028, $1.00 billion aggregate principal amount of 6.40% Senior Notes due 2030 and $1.50 billion aggregate principal amount of 6.55% Senior Notes due 2033. The Partnership used the net proceeds
to refinance existing indebtedness, including borrowings under its Five-Year Credit Facility and for general partnership purposes.
In September 2023, the Partnership redeemed $500 million aggregate principal amount of its 4.20% Senior Notes due September 2023 using proceeds from its Five-Year Credit Facility.
In May 2023, the Partnership refinanced all of the $225 million outstanding principal amount of HFOTCO tax-exempt bonds with new 10-year tax-exempt bonds. The new bonds, which were issued through the Harris County Industrial Development Corporation and are obligations of Energy Transfer, accrue interest at a fixed rate of 4.05% and are mandatorily redeemable in 2033. Upon redemption, these tax-exempt bonds may be remarketed on different terms through final maturity of November 1, 2050.
In the first quarter of 2023, the Partnership redeemed $350 million aggregate principal amount of its 3.45% Senior Notes due January 2023, $800 million aggregate principal amount of its 3.60% Senior Notes due February 2023 and $1.00 billion aggregate principal amount of its 4.25% Senior Notes due March 2023 using proceeds from its Five-Year Credit Facility.
In September 2023, Sunoco LP completed a private offering of $500 million aggregate principal amount of 7.00% senior notes due 2028. Sunoco LP used the proceeds from the private offering to repay a portion of its outstanding borrowings under their revolving credit facility.
Credit Facilities and Commercial Paper
Five-Year Credit Facility
The Partnership’s Five-Year Credit Facility allows for unsecured borrowings up to $5.00 billion and matures on April 11, 2027. The Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $7.00 billion under certain conditions.
As of December 31, 2023, the Five-Year Credit Facility had $1.41 billion of outstanding borrowings, $1.37 billion of which consisted of commercial paper. The amount available for future borrowings was $3.56 billion, after accounting for outstanding letters of credit in the amount of $29 million. The weighted average interest rate on the total amount outstanding as of December 31, 2023 was 5.87%.
Sunoco LP Credit Facility
As of December 31, 2023, the Sunoco LP Credit Facility had $411 million of outstanding borrowings and $5 million in standby letters of credit and matures in April 2027. The amount available for future borrowings was $1.08 billion at December 31, 2023. The weighted average interest rate on the total amount outstanding as of December 31, 2023 was 7.54%.
USAC Credit Facility
As of December 31, 2023, USAC had $872 million of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of December 31, 2023, USAC had $728 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $529 million was available to be drawn. The weighted average interest rate on the total amount outstanding as of December 31, 2023 was 7.98%.
Covenants Related to Our Credit Agreements
The agreements relating to the Senior Notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.
The Five-Year Credit Facility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:
•incur indebtedness;
•grant liens;
•enter into mergers;
•dispose of assets;
•make certain investments;
•make Distributions (as defined in the Five-Year Credit Facility) during certain Defaults (as defined in the Five-Year Credit Facility) and during any Event of Default (as defined in the Five-Year Credit Facility);
•engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;
•engage in transactions with affiliates; and
•enter into restrictive agreements.
The applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the Five-Year Credit Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the Five-Year Credit Facility ranges from 0.125% to 0.300%.
The Five-Year Credit Facility contains various covenants including limitations on the creation of indebtedness and liens and related to the operation and conduct of our business. The Five-Year Credit Facility also limits us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreement, of 5.00 to 1.00, which can generally be increased to 5.50 to 1.00 during a Specified Acquisition Period. Our Leverage Ratio was 3.31 to 1.00 at December 31, 2023, as calculated in accordance with the credit agreement.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions to Unitholders.
Covenants Related to Transwestern
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Covenants Related to Sunoco LP
The Sunoco LP Credit Facility contains various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. Sunoco LP’s Credit Facility requires Sunoco LP to maintain a specified net leverage ratio and interest coverage ratio.
In connection with Sunoco LP’s acquisition of NuStar, Sunoco LP expects to assume NuStar’s debt and issue additional debt, aggregating approximately $4.2 billion, subsequent to which it expects to remain in compliance with all existing financial covenants.
Covenants Related to USAC
The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things:
•grant liens;
•make certain loans or investments;
•incur additional indebtedness or guarantee other indebtedness;
•enter into transactions with affiliates;
•merge or consolidate;
•sell our assets; and
•make certain acquisitions.
The USAC Credit Facility is also subject to the following financial covenants, including covenants requiring USAC to maintain:
•a minimum EBITDA to interest coverage ratio;
•a ratio of total secured indebtedness to EBITDA within a specified range; and
•a maximum funded debt to EBITDA ratio.
Compliance with our Covenants
We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2023.
Cash Distributions
Cash Distributions Paid by Energy Transfer
Under its Partnership Agreement, Energy Transfer will distribute all of its Available Cash, as defined in the Partnership Agreement, within 50 days following the end of each fiscal quarter. Available Cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of our general partner that is necessary or appropriate to provide for future cash requirements.
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
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.
(1) Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis. Pursuant to their terms, distributions on the Series A preferred units began to be paid quarterly on February 15, 2023, and distributions on the Series B preferred units will begin to be paid quarterly on February 15, 2028.
Sunoco LP Cash Distributions
Energy Transfer owns approximately 28.5 million Sunoco LP common units and all of Sunoco LP’s IDRs. As of December 31, 2023, Sunoco LP had approximately 84.4 million common units outstanding.
The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
Marginal Percentage Interest in Distributions
Total Quarterly Distribution Target Amount Common Unitholders Holder of IDRs
Minimum Quarterly Distribution
$0.4375 100% -%
First Target Distribution
$0.4375 to $0.503125 100% -%
Second Target Distribution
$0.503125 to $0.546875 85% 15%
Third Target Distribution
$0.546875 to $0.656250 75% 25%
Thereafter
Above $0.656250 50% 50%
Distributions on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows:
Quarter Ended Record Date Payment Date Rate
December 31, 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. As of December 31, 2023, USAC had approximately 101.0 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs.
Distributions on USAC’s units declared and/or paid by USAC were as follows:
Quarter Ended Record Date Payment Date Rate
December 31, 2020 January 25, 2021 February 5, 2021 $ 0.5250
March 31, 2021 April 26, 2021 May 7, 2021 0.5250
June 30, 2021 July 26, 2021 August 6, 2021 0.5250
September 30, 2021 October 25, 2021 November 5, 2021 0.5250
December 31, 2021 January 24, 2022 February 4, 2022 0.5250
March 31, 2022 April 25, 2022 May 6, 2022 0.5250
June 30, 2022 July 25, 2022 August 5, 2022 0.5250
September 30, 2022 October 24, 2022 November 4, 2022 0.5250
December 31, 2022 January 23, 2023 February 3, 2023 0.5250
March 31, 2023 April 24, 2023 May 5, 2023 0.5250
June 30, 2023 July 24, 2023 August 4, 2023 0.5250
September 30, 2023 October 23, 2023 November 3, 2023 0.5250
December 31, 2023 January 22, 2024 February 2, 2024 0.5250
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. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. Our critical accounting policies are discussed below. For further details on our accounting policies see Note 2 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results are estimated using volume estimates and market prices for our intrastate transportation and storage segment, our midstream segment, and our NGL and refined products transportation and services segment. 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.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation, depletion and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
Fair Value Estimates in Business Combination Accounting and Impairment of Long-Lived Assets, Goodwill, Intangible Assets and Investments in Unconsolidated Affiliates. Business combination accounting and quantitative impairment testing are required from time to time due to the occurrence of events, changes in circumstances, or annual testing requirements. For business combinations, assets and liabilities are required to be recorded at estimated fair value in connection with the initial recognition of the transaction. For impairment testing, long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill and intangibles with indefinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value. Calculating the fair value of assets or reporting units in connection with business combination accounting or impairment testing requires management to make several estimates, assumptions and judgements, and in some circumstances management may also utilize third-party specialists to assist and advise on those calculations.
In order to allocate the purchase price in a business combination or to test for recoverability when performing a quantitative impairment test, we must make estimates of projected cash flows related to the asset, which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, we make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of commodities, our ability to negotiate favorable sales agreements, the risks that exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers, and competition from other companies, including major energy producers. While we believe we have made reasonable assumptions to calculate the fair value, if future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations.
The Partnership determines the fair value of its assets and/or reporting units using the discounted cash flow method, the guideline company method, the reproduction and replacement methods, or a weighted combination of these methods. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our business combination accounting and impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a multi-year average. In addition, the Partnership estimates a reasonable control premium, when appropriate, representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business. Under the reproduction and replacement methods, the Partnership determines the fair value of assets based on the estimated installation, engineering, and set-up costs related to the asset; these methods require the use of trend factors, such as inflation indices.
One key assumption in these fair value calculations is management’s estimate of future cash flows and EBITDA. In accounting for a business combination, these estimates are generally based on the forecasts that were used to analyze the deal economics. For impairment testing, these estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks described in “Item 1A. Risk Factors.” Therefore, the actual results could differ significantly from the amounts used for business combination accounting and impairment testing, and significant changes in fair value estimates could occur in a given period. Such changes in fair value estimates could result in changes to the fair value estimates used in business combination accounting, which could significantly impact results of operations in a period subsequent to the business combination, depending on multiple factors, including the timing of such changes. In the case of impairment testing, such changes could result in additional impairments in future periods; therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period, resulting in additional impairments.
In addition, we may change our method of impairment testing, including changing the weight assigned to different valuation models. Such changes could be driven by various factors, including the level of precision or availability of data for our assumptions. Any changes in the method of testing could also result in an impairment or impact the magnitude of an impairment.
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. Additional information on the impairments recorded during these periods is available in Note 2 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Management does not believe that any of the Partnership’s goodwill balances, long-lived assets or investments in unconsolidated affiliates is currently at significant risk of a material impairment; however, of the $4.02 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 2023, approximately $368 million is recorded in reporting units for which the estimated fair value exceeded the carrying value by approximately 20% or less in the most recent quantitative test.
Estimated Useful Lives of Long-Lived Assets. Depreciation and amortization of long-lived assets is provided using the straight-line method based on their estimated useful lives. 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. However, changes in facts and circumstances could cause us to change the estimated useful lives of the
assets, which could significantly impact the Partnership’s results of operations. Additional information on our accounting policies and the estimated useful lives associated with our long-lived assets is available in Note 2 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data.”
Legal and Regulatory Matters. We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from claims, orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised, as required, as better information becomes available to us. The factors we consider when recording an accrual for contingencies include, among others: (i) the opinions and views of our legal counsel; (ii) our previous experience; and (iii) the decision of our management as to how we intend to respond to the complaints. 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. 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. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.
Losses attributable to unasserted claims are generally reflected in the accruals on an undiscounted basis, to the extent they are probable of occurrence and reasonably estimable. We have established a wholly owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
In general, each remediation site/issue is evaluated individually based upon information available for the site/issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (e.g., service station sites) in determining the amount of probable loss accrual to be recorded. The Partnership’s estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance requires that the minimum of the range be accrued. 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.
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. 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. However, if changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to time, significant charges against income for environmental remediation may occur; however, management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position.
Deferred Income Taxes. Energy Transfer recognizes benefits in earnings and related deferred tax assets for net operating loss carryforwards (“NOLs”) and tax credit carryforwards. If necessary, a charge to earnings and a related valuation allowance are recorded to reduce deferred tax assets to an amount that is more likely than not to be realized by the Partnership in the future. Deferred income tax assets attributable to state and federal NOLs and federal excess business interest expense carryforwards
totaling $371 million have been included in Energy Transfer’s consolidated balance sheet as of December 31, 2023. 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. A total of $341 million of the federal net operating loss carryforward is limited under IRC §382. Although we expect to fully utilize the IRC §382 limited federal net operating loss, the amount utilized in a particular year may be limited. Any federal NOL generated in 2018 and future years can be carried forward indefinitely. In making the assessment of the future realization of the deferred tax assets, we rely on future reversals of existing taxable temporary differences, tax planning strategies and forecasted taxable income based on historical and projected future operating results. The potential need for valuation allowances is regularly reviewed by management. If it is more likely than not that the recorded asset will not be realized, additional valuation allowances which increase income tax expense may be recognized in the period such determination is made. Likewise, if it is more likely than not that additional deferred tax assets will be realized, an adjustment to the deferred tax asset will increase income in the period such determination is made.
Forward-Looking Statements
This annual report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this annual report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. 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;
•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.
You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under “Item 1A. Risk Factors” in this annual report. Any forward-looking statement made by us in this Annual Report on Form 10-K is based only on information currently available to us and speaks only as of the date on which it is made. 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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
(Tabular dollar amounts are in millions)
Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity variations, risk and interest rate variations, and to a lesser extent, credit risks. From time to time, we may utilize derivative financial instruments as described below to manage our exposure to such risks.
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.
We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off-peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are
settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.
We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.
We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of natural gas, refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. These contracts are not designated as hedges for accounting purposes.
We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our intrastate transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our intrastate transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.
The following 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. Dollar amounts are presented in millions.
December 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.
The fair values of the commodity-related financial positions have been determined using independent third-party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. 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.
Interest Rate Risk
As of December 31, 2023, we and our subsidiaries had $3.29 billion of floating rate debt outstanding. 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. 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.
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.
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. 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.
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. 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. 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.
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. 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. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
Our natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. In addition to oil and gas producers, the Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected
positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements starting on page of this report are incorporated by reference.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
An evaluation was performed under the supervision and with the participation of our management, including Marshall S. McCrea, III and Thomas E. Long, Co-Chief Executive Officers of our General Partner (Co-Principal Executive Officers), and Dylan A. Bramhall (Principal Financial Officer), of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, management, including Messrs. McCrea, Long and Bramhall, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2023.
Management’s Report on Internal Control over Financial Reporting
The management of Energy Transfer LP and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including the Co-Chief Executive Officers and Chief Financial Officer of our General Partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO Framework”).
On November 3, 2023, Energy Transfer LP completed its acquisition of Crestwood. Management acknowledges that it is responsible for establishing and maintaining a system of internal controls over financial reporting for Crestwood. We are in the process of integrating Crestwood, and we therefore have excluded Crestwood from our December 31, 2023 assessment of the effectiveness of internal control over financial reporting. Crestwood had total assets of $8.24 billion as of December 31, 2023 and third-party revenues of $789 million from November 3, 2023 to December 31, 2023, which are included in our consolidated financial statements as of and for the year ended December 31, 2023. The impact of the acquisition of Crestwood has not materially affected and is not expected to materially affect our internal control over financial reporting. As a result of these integration activities, certain controls are being evaluated and may be changed. We believe, however, that we will be able to maintain sufficient controls over the substantive results of our financial reporting throughout this integration process.
Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2023.
Grant Thornton LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2023, as stated in their report, which is included herein.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors of LE GP, LLC and
Unitholders of Energy Transfer LP
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Energy Transfer LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2023, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2023, and our report dated February 16, 2024 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Our audit of, and opinion on, the Partnership’s internal control over financial reporting does not include the internal control over financial reporting of Crestwood Equity Partners LP (“Crestwood”), a consolidated subsidiary, whose financial statements reflect total assets and revenues constituting seven percent and one percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2023. As indicated in Management’s Report on Internal Control over Financial Reporting, Crestwood was acquired during 2023. Management’s assertion on the effectiveness of the Partnership’s internal control over financial reporting excluded internal control over financial reporting of Crestwood.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Dallas, Texas
February 16, 2024
Changes in Internal Controls over Financial Reporting
There has been no change in our internal controls over financial reporting (as defined in Rules 13a-15(f) or Rule 15d-15(f)) that occurred in the three months ended December 31, 2023 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Board of Directors
Our general partner, LE GP, LLC, manages and directs all of our activities. The officers and directors of Energy Transfer are officers and directors of LE GP, LLC. The members of our general partner elect our general partner’s Board of Directors. The board of directors of our general partner has the authority to appoint our executive officers, subject to provisions in the limited liability company agreement of our general partner. Pursuant to other authority, the board of directors of our general partner may appoint additional management personnel to assist in the management of our operations and, in the event of the death, resignation or removal of our chief executive officer, to appoint a replacement.
As of January 1, 2024, our Board of Directors is comprised of nine persons, four of whom qualify as “independent” under the NYSE’s corporate governance standards. As a limited partnership, we are not required under the NYSE’s corporate governance standards (Section 303A) to have a majority of independent directors. We have determined that Messrs. Anderson, Brannon, Grimm and Perry are all “independent” under the NYSE’s corporate governance standards.
As a limited partnership, we are not required by the rules of the NYSE to seek Unitholder approval for the election of any of our directors. We believe that the members of our general partner have appointed as directors individuals with experience, skills and qualifications relevant to the business of Energy Transfer, such as experience in energy or related industries or with financial markets, expertise in natural gas operations or finance, and a history of service in senior leadership positions. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration of diversity in identifying director nominees, but we believe that the members of our general partner have endeavored to assemble a group of individuals with the qualities and attributes required to provide effective oversight of Energy Transfer.
Board Leadership Structure. We have no policy requiring either that the positions of the Chairman of the Board and the Chief Executive Officer, or CEO, be separate or that they be occupied by the same individual. The Board of Directors believes that this issue is properly addressed as part of the succession planning process and that a determination on this subject should be made when it elects a new chief executive officer or at such other times as when consideration of the matter is warranted by circumstances. Previously, the Board of Directors believed that the CEO was best situated to serve as Chairman because he was the director most familiar with the Partnership’s business and industry, and most capable of effectively identifying strategic priorities and leading the discussion and execution of strategy. Beginning in 2021, the Board of Directors has established separate roles for the Executive Chairman and Co-Chief Executive Officers. Independent directors and management have different perspectives and roles in strategy development. Our independent directors bring experience, oversight and expertise from outside the Partnership and from a variety of industries, while the Executive Chairman and Co-Chief Executive Officers bring extensive experience and expertise specifically related to the Partnership’s business.
Risk Oversight. Our Board of Directors generally administers its risk oversight function through the board as a whole. Our Co-CEOs, who report to the Board of Directors, have day-to-day risk management responsibilities. Our Co-CEOs attend the meetings of our Board of Directors, where the Board of Directors routinely receives reports on our financial results, the status of our operations, and other aspects of implementation of our business strategy, with ample opportunity for specific inquiries of management. In addition, at each regular meeting of the Board, management provides a report of Energy Transfer’s financial and operational performance, which often prompts questions or feedback from the Board of Directors. The Audit Committee provides additional risk oversight through its quarterly meetings, where it receives a report from Energy Transfer’s internal auditor, who reports directly to the Audit Committee, and reviews Energy Transfer’s contingencies with management and our independent auditors.
Corporate Governance
The Board of Directors has adopted both a Code of Business Conduct and Ethics applicable to our directors, officers and employees, and Corporate Governance Guidelines for directors and the Board. Current copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines and charters of the Audit and Compensation Committees of our Board of Directors are available on our website at www.energytransfer.com and will be provided in print form to any Unitholder requesting such information.
Please note that the preceding internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found and/or provided at such internet address or contained on our website in general is intended or deemed to be incorporated by reference in this report.
Annual Certification
In 2023, our Co-Chief Executive Officers provided to the NYSE the annual CEO certification regarding our compliance with the NYSE’s corporate governance listing standards.
Conflicts Committee
Our Partnership Agreement provides that the Board of Directors may, from time to time, appoint members of the Board to serve on the Conflicts Committee with the authority to review specific matters for which the Board of Directors believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the general partner is fair and reasonable to Energy Transfer and our Unitholders. As a policy matter, the Conflicts Committee generally reviews any proposed related-party transaction that may be material to Energy Transfer to determine if the transaction presents a conflict of interest and whether the transaction is fair and reasonable to Energy Transfer. Pursuant to the terms of our Partnership Agreement, any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to the Energy Transfer, approved by all partners of Energy Transfer and not a breach by the general partner or its Board of Directors of any duties they may owe Energy Transfer or the Unitholders. These duties are limited by our Partnership Agreement (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report).
Audit Committee
The Board of Directors has established an Audit Committee in accordance with Section 3(a)(58)(A) of the Exchange Act. The Board of Directors appoints persons who are independent under the NYSE’s standards for audit committee members to serve on its Audit Committee. In addition, the Board determines that at least one member of the Audit Committee has such accounting or related financial management expertise sufficient to qualify such person as the audit committee financial expert in accordance with Item 407(d)(5) of Regulation S-K. The Board determined that based on relevant experience, Audit Committee member Michael K. Grimm qualified as an audit committee financial expert during 2023. A description of the qualifications of Mr. Grimm may be found elsewhere in this Item 10 under “Directors and Executive Officers of the General Partner.”
The Audit Committee meets on a regularly scheduled basis with our independent accountants at least four times each year and is available to meet at their request. The Audit Committee has the authority and responsibility to review our external financial reporting, review our procedures for internal auditing and the adequacy of our internal accounting controls, consider the qualifications and independence of our independent accountants, engage and direct our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work which may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by auditing standards, and approves the filing of our Form 10-K, which includes our audited financial statements. The Audit Committee periodically recommends to the Board of Directors any changes or modifications to its charter that may be required. The Audit Committee has received written disclosures and the letter from Grant Thornton required by applicable requirements of the Audit Committee concerning independence and has discussed with Grant Thornton that firm’s independence. The Audit Committee recommended to the Board that the audited financial statements of Energy Transfer be included in Energy Transfer’s Annual Report on Form 10-K for the year ended December 31, 2023.
The Board of Directors adopts the charter for the Audit Committee. Steven R. Anderson, Richard D. Brannon and Michael K. Grimm serve as elected members of the Audit Committee.
Compensation and Nominating/Corporate Governance Committees
Although we are not required under NYSE rules to appoint a Compensation Committee or a Nominating/Corporate Governance Committee because we are a limited partnership, the Board of Directors of LE GP, LLC has previously established a Compensation Committee to establish standards and make recommendations concerning the compensation of our officers and directors. In addition, the Compensation Committee determines and establishes the standards for any awards to our employees and officers under the equity compensation plans, including the performance standards or other restrictions pertaining to the vesting of any such awards. Messrs. Anderson and Grimm serve as members of the Compensation Committee.
The responsibilities of the Energy Transfer Compensation Committee include, among other duties, the following:
•annually review and approve goals and objectives relevant to compensation of our Co-CEOs and CFO, if applicable;
•annually evaluate the CEO and CFO’s performance in light of these goals and objectives, and make recommendations to the Board of Directors with respect to the CEO and CFO’s compensation levels, if applicable, based on this evaluation;
•make determinations with respect to the grant of equity-based awards to executive officers under Energy Transfer’s equity incentive plans;
•periodically evaluate the terms and administration of Energy Transfer’s long-term incentive plans to assure that they are structured and administered in a manner consistent with Energy Transfer’s goals and objectives;
•periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate;
•periodically evaluate the compensation of the directors;
•retain and terminate any compensation consultant to be used to assist in the evaluation of director, CEO and CFO or executive officer compensation; and
•perform other duties as deemed appropriate by the Board of Directors.
Code of Business Conduct and Ethics
The Board of Directors has adopted a Code of Business Conduct and Ethics applicable to our officers, directors and employees. Specific provisions are applicable to the co-principal executive officers, principal financial officer, principal accounting officer and controller, or those persons performing similar functions, of our general partner. Amendments to, or waivers from, the Code of Business Conduct and Ethics will be available on our website and reported as may be required under SEC rules. Any technical, administrative or other non-substantive amendments to the Code of Business Conduct and Ethics may not be posted.
Meetings of Non-management Directors and Communications with Directors
Our non-management directors meet in regularly scheduled sessions. Our non-management directors alternate as the presiding director of such meetings.
We have established a procedure by which Unitholders or interested parties may communicate directly with the Board of Directors, any committee of the Board, any of the independent directors, or any one director serving on the Board of Directors by sending written correspondence addressed to the desired person, committee or group to the attention of Sonia Aubé at Energy Transfer LP, 8111 Westchester Drive, Suite 600, Dallas, Texas, 75225. Communications are distributed to the Board of Directors, or to any individual director or directors as appropriate, depending on the facts and circumstances outlined in the communication.
Directors and Executive Officers of Our General Partner
The following table sets forth certain information with respect to the executive officers and members of the Board of Directors of our general partner as of February 16, 2024. Executive officers and directors are elected for indefinite terms.
Name Age Position with Our General Partner
Kelcy L. Warren 68 Executive Chairman of the Board of Directors
Thomas E. Long 67 Co-Chief Executive Officer and Director (Co-Principal Executive Officer)
Marshall S. (Mackie) McCrea, III 64 Co-Chief Executive Officer and Director (Co-Principal Executive Officer)
Dylan A. Bramhall 47 Executive Vice President and Group Chief Financial Officer (Principal Financial Officer)
Thomas P. Mason 67 Executive Vice President - Alternative Energy and President - LNG
Bradford D. Whitehurst 49 Executive Vice President of Tax and Corporate Initiatives
James M. Wright, Jr. 55 Executive Vice President, General Counsel and Chief Compliance Officer
A. Troy Sturrock 53 Group Senior Vice President and Controller (Principal Accounting Officer)
Steven R. Anderson 74 Director
Richard D. Brannon 65 Director
Michael K. Grimm 69 Director
John W. McReynolds 73 Director
James R. (Rick) Perry 73 Director
Matthew S. Ramsey 68 Director
Mr. Long, Mr. Mason and Mr. Whitehurst serve as directors of the general partner of USAC.
Set forth below is biographical information regarding the foregoing officers and directors of our general partner:
Kelcy L. Warren. Mr. Warren serves as Executive Chairman of our general partner. Mr. Warren served as Chief Executive Officer from August 2007 through December 2020. He was appointed Co-Chairman of the Board of Directors of our general partner, effective upon the closing of our IPO, and in August 2007, he became the sole Chairman of the Board of our general partner and the Chief Executive Officer and Chairman of the Board of the general partner of ETO until its merger into Energy Transfer LP in April 2021. Prior to August 2007, Mr. Warren had served as Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of ETO since the combination of the midstream and intrastate transportation storage operations of La Grange Acquisition, L.P. and the retail propane operations of Heritage in January 2004. Mr. Warren also served as the Chief Executive Officer of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Warren was selected to serve as a director and as Executive Chairman because he previously served as Chief Executive Officer and has more than 30 years in the natural gas industry. Mr. Warren also has relationships with chief executives and other senior management at natural gas transportation companies throughout the United States and brings a unique and valuable perspective to the Board of Directors.
Thomas E. Long. Mr. Long has served as the Co-Chief Executive Officer of our general partner since January 2021. Mr. Long served as Chief Financial Officer of Energy Transfer’s general partner from February 2016 until January 2021, and has been a director of our general partner since April 2019. Mr. Long also served as the Chief Financial Officer and as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Long also served as Chief Financial Officer of ETO until its merger into Energy Transfer LP in April 2021, and was previously Executive Vice President and Chief Financial Officer of Regency GP LLC from November 2010 to April 2015. Mr. Long served as a director of Sunoco LP from May 2016 until May 2021, and has served on the Board of USAC since April 2018. In May 2022, Mr. Long was appointed to the board of directors of Texas Capital Bancshares, Inc (NASDAQ: TCBI). Mr. Long was selected to serve on our Board of Directors because of his understanding of energy-related corporate finance gained through his extensive experience in the energy industry.
Marshall S. (Mackie) McCrea, III. Mr. McCrea has served as the Co-Chief Executive Officer of our general partner since January 2021. Prior to that he was the President and Chief Commercial Officer of our general partner, having served in that role since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Prior to that time, he had been the Group Chief Operating Officer and Chief Commercial Officer of the Energy Transfer family since November 2015. Mr. McCrea has served on the Board of Directors of our general partner since December 2009. Mr. McCrea was appointed as a director of the general partner of ETO in December 2009 and served in that capacity until ETO’s merger into Energy Transfer LP in April 2021. Prior to December 2009, he served as President and Chief Operating Officer of ETO’s general partner from June 2008 to November 2015 and President - Midstream from March 2007 to June 2008. Previously he served as the Senior Vice President - Commercial Development since January 2004. In March 2005, Mr. McCrea was named President of La Grange Acquisition LP, ETO’s primary operating subsidiary, after serving as Senior Vice President-Business Development and Producer Services since 1997. Mr. McCrea also served as the Chairman of the Board of Directors of the general partner of Sunoco Logistics Partners L.P. from October 2012 to April 2017. Mr. McCrea was selected to serve as a director because he brings extensive project development and operational experience to the Board. He has held various positions in the natural gas business over the past 25 years and is able to assist the Board of Directors in creating and executing the Partnership’s strategic plan.
Dylan A. Bramhall. Mr. Bramhall has served as Executive Vice President and Group Chief Financial Officer of our general partner since November 2022 and currently is also Chief Financial Officer of Sunoco LP’s general partner. Mr. Bramhall joined Energy Transfer in 2015 as a result of its merger with Regency Energy Partners and is responsible for oversight of the Partnership’s Financial Planning and Analysis, Credit and Commodity Risk Management, Insurance, Cash Management, Capital Markets, Accounting, Financial Reporting and Investor Relations groups. He also serves as a member of Energy Transfer’s Risk Oversight Committee. While at Regency, Mr. Bramhall held management positions in the finance, risk, commercial and operations groups. Mr. Bramhall holds a Bachelor of Business Administration in finance and Master of Business Administration in finance and operations management, both from the University of Iowa.
Thomas P. Mason. Mr. Mason has served as Executive Vice President and President - LNG since December 2022. He became Executive Vice President and General Counsel of the general partner of Energy Transfer in December 2015, and served as the Executive Vice President, General Counsel and President - LNG from October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. until December 2022 when he resigned from his role as General Counsel. In February 2021, Mr. Mason assumed leadership responsibility over the Partnership’s newly created Alternative Energy Group, which focuses on the development of alternative energy projects aimed at continuing to reduce Energy Transfer’s environmental footprint throughout its operations. Mr. Mason previously served as Senior Vice President, General Counsel and Secretary of ETO’s general partner from April 2012 to December 2015, as Vice President, General Counsel and Secretary from June 2008 and as General Counsel and Secretary from February 2007. Prior to joining Energy Transfer, he was a partner in the Houston office of Vinson & Elkins. Mr. Mason served as a director on the Board of Directors of the general partner of Sunoco Logistics Partners L.P. from October 2012 to April 2017 and as a director on the Board of Directors of PennTex Midstream
Partners, LP’s general partner from November 2016 to July 2017. Mr. Mason has also served as a member of the Board of Directors of USAC since April 2018.
Bradford D. Whitehurst. Mr. Whitehurst has served as Executive Vice President of Tax and Corporate Initiatives of Energy Transfer since November 2022. From January 2021 to November 2022, he served as Chief Financial Officer. From August 2014 through December 2020, he served as Executive Vice President - Head of Tax. Prior to joining Energy Transfer, Mr. Whitehurst was a partner in the Washington, DC office of Bingham McCutchen LLP and an attorney in the Washington, DC offices of both McKee Nelson LLP and Hogan & Hartson. Mr. Whitehurst has specialized in partnership taxation and has advised Energy Transfer and its subsidiaries in his role as outside counsel since 2006. He has served as a member of the board of directors of USAC since April 2019.
James M. Wright, Jr. Mr. Wright was appointed as Executive Vice President, General Counsel and Chief Compliance Officer of our general partner in December 2022. He became Executive Vice President - Legal and Chief Compliance Officer of ET’s general partner in October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Mr. Wright has been a part of the Energy Transfer legal team with increasing levels of responsibility since July 2005 and has held various senior-level positions in the legal department including General Counsel of the general partner of Energy Transfer Partners, L.P. from December 2015 to October 2018 and Deputy General Counsel from May 2008 to December 2015. Prior to joining Energy Transfer, Mr. Wright gained significant experience at Enterprise Products Partners, L.P., El Paso Corp., Sonat Exploration Company and KPMG Peat Marwick LLP. Mr. Wright earned a Bachelor of Business Administration degree in Accounting and Finance from Texas A&M University and a JD from South Texas College of Law.
A. Troy Sturrock. Mr. Sturrock has served as the Group Senior Vice President, Controller and Principal Accounting Officer of our general partner since September 2022. He previously served as Senior Vice President, Controller and Principal Accounting Officer, having assumed that role in October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. He served as the Senior Vice President, Controller and Principal Accounting Officer of the general partner of ETO from August 2016 until ETO’s merger into Energy Transfer LP in April 2021, and previously served as Vice President, Controller and Principal Accounting Officer of our general partner beginning in June 2015. Mr. Sturrock is a Certified Public Accountant.
Steven R. Anderson. Mr. Anderson was elected to the Board of Directors of our general partner in June 2018 and serves on the audit committee and compensation committee. Mr. Anderson began his career in the energy business in the early 1970’s with Conoco in the Permian Basin area. He then spent some 25 years with ANR Pipeline and its successor, The Coastal Corporation, as a natural gas supply and midstream executive. He later was Vice President of Commercial Operations with Aquila Midstream and, upon the sale of that business to Energy Transfer in 2002, he became a part of the management team there. For the six years prior to his retirement from Energy Transfer in October 2009, he served as Vice President of Mergers and Acquisitions. Since that time, he has been involved in private investments and has served on the boards of directors of the St. John Health System and Saint Simeon’s Episcopal Home in Tulsa, Oklahoma, as well as various other community and civic organizations. Mr. Anderson also served as a member of the board of directors of Sunoco Logistics Partners L.P. from October 2012 until April 2017. Mr. Anderson was selected to serve on our Board of Directors based on his experience in the midstream energy industry generally, and his knowledge of Energy Transfer’s business specifically. Mr. Anderson also brings recent experience on audit and compensation committees of another publicly traded partnership.
Richard D. Brannon. Mr. Brannon was appointed to the Board of Directors of our general partner in March 2016 and has served as the Chairman of the audit committee since April 2016. Mr. Brannon is the CEO of CH4 Energy Six, LLC and Uinta Wax, LLC, both independent companies focused on horizontal oil and gas development. Mr. Brannon previously served on the board of directors of WildHorse Resource Development from its IPO in December 2016 until June 2018. Mr. Brannon also formerly served on the Board of Directors and as a member of the audit committee and compensation committee of Sunoco LP, Regency, OEC Compression and Cornerstone Natural Gas Corp. He has over 35 years of experience in the energy business, having started his career in 1981 with Texas Oil & Gas. The members of our general partner selected Mr. Brannon to serve as director based on his knowledge of the energy industry and his experience as a director and audit and compensation committee member for other public companies.
Michael K. Grimm. Mr. Grimm was appointed to the Board of Directors of our general partner in October 2018, and has served on the audit committee and compensation committee since that time. Prior to that time, Mr. Grimm served as a director of ETO’s general partner beginning in December 2005, and served on the audit and compensation committee during that time. Mr. Grimm is one of the original founders of Rising Star Energy, L.L.C., a privately held upstream exploration and production company active in onshore continental United States, and served as its President and Chief Executive Officer from 1995 until 2006 when it was sold. Mr. Grimm is currently President of Rising Star Petroleum, LLC. Mr. Grimm was formerly Chairman of the Board of RSP Permian, Inc. (NYSE: RSPP) from January 2014 until June 2018. From November 2018 until it was sold in 2019, Mr. Grimm served on the Board of Directors of Anadarko Petroleum Corporation. Prior to the formation of Rising Star,
Mr. Grimm was Vice President of Worldwide Exploration and Land for Placid Oil Company from 1990 to 1994. Prior to joining Placid Oil Company, Mr. Grimm was employed by Amoco Production Company for thirteen years where he held numerous positions throughout the exploration department in Houston, New Orleans and Chicago. Mr. Grimm has been an active member of the American Association of Professional Landmen, Dallas Wildcat Committee, Dallas Producers Club, and the All-American Wildcatters. He has a B.B.A. from the University of Texas at Austin. Mr. Grimm was selected to serve as a director because of his extensive experience in the energy industry and his service as a senior executive at several energy-related companies, in addition to his contacts in the industry gained through his involvement in energy-related organizations.
John W. McReynolds. Mr. McReynolds is a director of Energy Transfer LP, having served in that capacity since August 2004. Mr. McReynolds previously served as the President of Energy Transfer LP from March 2005 until October 2018, at which time he became Special Advisor to the Partnership. Mr. McReynolds also previously served as our Chief Financial Officer from August 2005 to June 2013. Prior to becoming President of Energy Transfer LP, Mr. McReynolds was a partner in the international law firm of Hunton & Williams LLP for over 20 years. As a lawyer, he specialized in energy related finance, securities, partnerships, mergers and acquisitions, syndication and litigation matters, and served as an expert in numerous arbitration, litigation, and governmental proceedings, including as an expert in special projects for boards of directors of public companies. Mr. McReynolds was selected to serve in the indicated roles with Energy Transfer because of this extensive background and experience, as well as his many contacts and relationships in the industry.
James R. (Rick) Perry. Mr. Perry was appointed to the Board of Directors of our general partner in January 2020. He formerly served as U.S. Secretary of Energy from March 2017 until December 2019. Prior to that, he served as the Governor of the State of Texas from 2000 until January 2015. Mr. Perry served as Lieutenant Governor of Texas from 1998 to 2000, and as Agriculture Commissioner from 1991 to 1998. Prior to 1991, he also served in the Texas House of Representatives. Mr. Perry previously served on the Board of Directors of ETO from February 2015 until December 2016. Mr. Perry was selected to serve as a director because of his vast experience as an executive in the highest office of state government. In addition, Mr. Perry has been involved in finance and budget planning processes throughout his career in government as a member of the Texas House Appropriations Committee, the Legislative Budget Board and as Governor.
Matthew S. Ramsey. Mr. Ramsey was appointed as a director of Energy Transfer’s general partner in July 2012 and served as a director of ETO’s general partner from November 2015 until its merger into Energy Transfer LP in April 2021. Mr. Ramsey served as the Chief Operating Officer or our general partner from October 2018 until his retirement in April 2022, and served as President and Chief Operating Officer of ETO’s general partner from November 2015 until its merger into Energy Transfer LP in April 2021. Mr. Ramsey also served as President and Chief Operating Officer and Chairman of the board of directors of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Ramsey also previously served as a director of Sunoco LP, having served as chairman of Sunoco LP’s board from April 2015 until March 2022, and of USAC, having served on that board from April 2018 until March 2022. Mr. Ramsey previously served as President of RPM Exploration, Ltd., a private oil and gas exploration partnership, and previously served as a director of RSP Permian, Inc. where he served on the audit and compensation committees. In addition to his work in the energy business, Mr. Ramsey formerly served on the board of directors of the National Association of Manufacturers, and he is currently a Trustee of the Southwestern Medical Foundation. He is the former Chairman of the University of Texas Chancellor’s Council. Mr. Ramsey holds a B.B.A. in Marketing from the University of Texas at Austin and a J.D. from South Texas College of Law. Mr. Ramsey was selected to serve based on vast experience in the oil and gas space and Energy Transfer believes that he provides valuable industry insight as a member of our Board of Directors.
Delinquent Section 16(a) Reports
Section 16(a) of the Securities Exchange Act of 1934 requires the directors and executive officers of our general partner, as well as persons who own more than ten percent of the common units representing limited partnership interests in us, to file reports of ownership and changes of ownership on Forms 3, 4 and 5 with the SEC. The SEC regulations also require that copies of these Section 16(a) reports be furnished to us by such reporting persons. Based upon a review of copies of these reports, we believe all applicable Section 16(a) reports were timely filed in 2023, except for one late Form 4 filing by each Messrs. McReynolds and Wright.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
Named Executive Officers
Energy Transfer does not have officers or directors. Instead, we are managed by the board of directors of our General Partner, and the executive officers of our General Partner perform all of Energy Transfer’s management functions. As a result, the executive officers of our General Partner are Energy Transfer’s executive officers, and their compensation is administered by our General Partner. This Compensation Discussion and Analysis is, therefore, focused on the total compensation of the executive officers of our General Partner as set forth below. The persons we refer to in this discussion as our “named executive officers” are the following:
•Marshall S. (Mackie) McCrea, III, Co-Chief Executive Officer;
•Thomas E. Long, Co-Chief Executive Officer;
•Dylan A. Bramhall, Executive Vice President and Group Chief Financial Officer;
•Bradford D. Whitehurst, Executive Vice President - Tax and Corporate Initiatives;
•Thomas P. Mason, Executive Vice President - Alternative Energy and President - LNG; and
•James M. Wright, Jr., Executive Vice President, General Counsel and Chief Compliance Officer.
Our Philosophy for Compensation of Executives
In general, our General Partner’s philosophy for executive compensation is based on the premise that a significant portion of each executive’s compensation should be incentive-based or “at-risk” compensation and that executives’ total compensation levels should be highly competitive in the marketplace for executive talent and abilities. Our General Partner seeks a total compensation program for its executive officers, including the named executive officers, that provides for a slightly below the median market annual base compensation (i.e., approximately the 30th to 40th percentile of market) but incentive-based compensation composed of a combination of compensation vehicles to reward both short- and long-term performance that are both targeted to pay out at approximately the top-quartile of market. Our General Partner believes the incentive-based balance is achieved by (i) the payment of annual discretionary cash bonuses that consider the achievement of the Partnership’s financial performance objectives for a fiscal year set at the beginning of such fiscal year and the individual contributions of its executive officers, including the named executive officers, to the success of the Partnership and the achievement of the annual financial performance objectives and (ii) the annual grant of time-based restricted unit, phantom unit awards or cash restricted unit awards under the Partnership’s equity incentive plan(s) or the equity incentive programs of Sunoco LP, as applicable based on the allocation of executive officers awards, including awards to the named executive officers, which awards are intended to provide a longer term incentive and retention value to its key employees to focus their efforts on increasing the market price of its publicly traded units and to increase the cash distribution the Partnership and/or the other affiliated partnerships pay to their respective unitholders.
The Partnership has historically granted restricted unit and/or phantom unit awards (“RSUs”) that vest, based generally upon continued employment, at a rate of 60% after the third year of service and the remaining 40% after the fifth year of service. Beginning in 2020, Energy Transfer began granting cash restricted units (“CRSUs”) that vest, based generally upon continued employment, at a rate of 1/3 annually over a three-year period. For 2020, the awards to employees were generally split equally between RSUs and CRSUs; subsequent to 2020, the awards are generally split based on 75% RSUs and 25% CRSUs. The Partnership believes that these equity-based incentive arrangements are important in attracting and retaining executive officers and key employees as well as motivating these individuals to achieve stated business objectives. The equity-based compensation reflects the importance our General Partner places on aligning the interests of its named executive officers with those of Unitholders. While the Partnership utilizes time-based forms of equity awards, the grant date valuation utilizes a modified total unitholder return (“TUR”) performance as measured against the average return of Energy Transfer’s identified peer group over defined time periods. The modified TUR is designed to create a recognition of a performance adjustment to the equity awards based on the prior periods measured to add an element of performance impact in setting grant date value even though the RSUs and CRSUs themselves are a time-vested vehicle.
As discussed below, our compensation committee and/or the compensation committee of the general partner of Sunoco LP, as applicable, all in consultation with our General Partner, are responsible for the compensation policies and compensation level of our executive officers, including the named executive officers of our General Partner. In this discussion, we refer to our compensation committee as the “Energy Transfer Compensation Committee.”
For a more detailed description of the compensation to the Partnership’s named executive officers, please see “- Compensation Tables” below.
Distributions to Our General Partner
Our General Partner is majority-owned by Mr. Kelcy Warren. We pay quarterly distributions to our General Partner in accordance with our Partnership Agreement with respect to its ownership of its general partner interest as specified in our Partnership Agreement. The cash distributions we make to our General Partner bear no relationship to the level or components of compensation of our General Partner’s executive officers. Distributions to our General Partner are described in detail in Note 8 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” Our named executive officers also own directly and indirectly certain of our limited partner interests and, accordingly, receive quarterly distributions. Such per-unit distributions equal the per-unit distributions made to all our limited partners and bear no relationship to the level of compensation of the named executive officers or the services they perform as employees.
For a more detailed description of the compensation of our named executive officers, please see “- Compensation Tables” below.
Compensation Philosophy
Our compensation programs are structured to achieve the following:
•reward executives with an industry-competitive total compensation package of base salaries and significant incentive opportunities yielding a total compensation package approaching the top-quartile of the market;
•attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers and key management employees employed by publicly traded limited partnerships or other peer companies of similar size and in similar lines of business;
•motivate executive officers and key employees to achieve strong financial and operational performance;
•emphasize performance-based, or “at-risk,” compensation; and
•reward individual performance.
Components of Executive Compensation
For the year ended December 31, 2023, the compensation paid to our named executive officers consisted of the following components:
•annual base salary;
•non-equity incentive plan compensation consisting solely of discretionary cash bonuses;
•time-vested RSUs and CRSUs under the equity incentive plan(s);
•payment of distribution equivalent rights (“DERs”) on unvested time-based RSUs under our equity incentive plan;
•vesting of previously issued time-based RSUs issued pursuant to our equity incentive plans or the equity incentive plans(s) of affiliates; and
•401(k) plan employer contributions.
Methodology
The Energy Transfer Compensation Committee considers relevant data available to it to assess our competitive position with respect to base salary, annual short-term incentives and long-term incentive compensation for our executive officers, including the named executive officers. The Energy Transfer Compensation Committee also considers individual performance, levels of responsibility, skills and experience.
Periodically, the Energy Transfer Compensation Committee engages a third-party independent compensation consultant to provide a full market competitive compensation analysis for compensation levels at peer companies in order to assist in the determination of compensation levels for our executive officers, including the named executive officers. Most recently, in 2023 Meridian Compensation Partners, LLC (“Meridian”) completed an evaluation of the market competitiveness of total compensation levels of a number of officers of the Partnership, including the named executive officers. The Meridian review provided market information with respect to compensation of Partnership executives, including named executive officers during the year ended December 31, 2023. In particular, the review by Meridian was designed to (i) evaluate the market competitiveness of total compensation levels for certain members of senior management, including our named executive
officers; (ii) assist in the determination of appropriate compensation levels for our senior management, including the named executive officers; and (iii) confirm that our compensation programs were yielding compensation packages consistent with our overall compensation philosophy.
In conducting its review, Meridian assisted in the development of the final “peer group” of leading companies in the energy industry that most closely reflect the profile of Energy Transfer. The final “peer group” consisted of the core group of peers (i.e. the eight most similar peers in terms of business, revenues, assets and market value as well as competition for talent at the senior management level) and a group of expanded reference companies composed of a broader group of oil and gas companies, including additional integrated, upstream and midstream comparators whose data provided additional market context. As part of the evaluation conducted by Meridian, a determination was made to focus the analysis largely on the core energy industry peers. This decision was based on a determination that the core peer group provided a more than sufficient amount of comparative data to consider and evaluate total compensation. This focus allowed Meridian to report on this specific core peer data comparing the levels of annual base salary, annual short-term cash bonus and long-term equity incentive awards at industry peer group companies with those of the named executive officers to ensure that compensation of the named executive officers is both consistent with the compensation philosophy and competitive with the compensation for executive officers of these other companies, while at the same time considering whether the context provided by the expanded group offered additional information that should be considered by the Compensation Committee. The core identified companies were:
Energy Peer Group:
• Conoco Phillips • Marathon Petroleum Corporation
• Enterprise Products Partners, L.P. • Kinder Morgan, Inc.
• Plains All American Pipeline, L.P. • The Williams Companies, Inc.
• Valero Energy Corporation • Phillips 66
The compensation analysis provided by Meridian covered all major components of total compensation, including annual base salary, annual short-term cash bonus and long-term incentive awards for the senior executives. In preparing the review materials, Meridian utilized generally accepted compensation principles and gathered data from public disclosures of peer companies, including Form 10-K and proxy data and published survey data from multiple sources that are relevant to Energy Transfer’s core peer group, industry, financial size and operational breadth. The Meridian review process also included significant engagement with management to fully understand job scope, responsibilities and roles of each of the executive officers, which discussions allow Meridian the ability to completely evaluate specific aspects of an executive officer’s position to allow for more accurate comparisons.
Following Meridian’s 2023 review, the Energy Transfer Compensation Committee reviewed the information provided, including Meridian’s specific summary observations and recommended considerations for all compensation going forward. The observations addressed overall competitive benchmarking, peer company approaches to compensation and short and long-term incentive plan design, the Energy Transfer Compensation Committee considered and reviewed the results of the study performed by Meridian to determine if the results indicated that the compensation programs were yielding a competitive total compensation model prioritizing incentive-based compensation and rewarding achievement of short and long-term performance objectives and considered Meridian’s conclusions and recommendations. While Meridian found that the Partnership is continuing to achieve its stated objectives with respect to the “at-risk” approach, Meridian also recommended certain adjustments for consideration, which considerations were designed to allow the Partnership to continue to achieve its targeted percentiles on base compensation and incentive compensation (short and long-term). In respect of the 2023 Meridian review, the Energy Transfer Compensation Committee, in consultation with Meridian and executive management, approved the adoption of the Amended and Restated Energy Transfer LP Annual Bonus Plan (the “Amended Bonus Plan”) effective as January 1, 2023. The Amended Bonus Plan enhanced potential pay-out for achievement of specific performance goals allowing for a maximum Amended Bonus Plan payout of 130% of target as opposed to the prior Bonus Plan maximum payout of 116%. Specific changes are discussed below under the title of Annual Bonus. Certain of Meridian’s other suggested considerations as part of the review were implemented and others were determined to require additional review and consideration.
In addition to the information received as part of Meridian’s review, the Energy Transfer Compensation Committee also utilizes information obtained from other sources in its determination of compensation levels for our named executive officers, such as annual third-party surveys, although third-party survey data is not used by the Energy Transfer Compensation Committee to benchmark the amount of total compensation or any specific element of compensation for the named executive officers.
Base Salary. Base salary is designed to provide for a competitive fixed level of pay that attracts and retains executive officers and compensates them for their level of responsibility and sustained individual performance (including experience, scope of responsibility and results achieved). The salaries of the named executive officers are reviewed on an annual basis. As discussed
above, the base salaries of our named executive officers are targeted to yield an annual base salary slightly below the median level of market (i.e., approximately the 30th to 40th percentile of market) and are determined by the Energy Transfer Compensation Committee after taking into account the recommendations of Mr. Warren.
During the merit review process, the Energy Transfer Compensation Committee considers the recommendations of Mr. Warren, any relevant compensation study data (with the data aged as appropriate) and the merit increase pool set for all employees of the Partnership and/or its employing affiliates. During 2023, the Energy Transfer Compensation Committee approved a 4.75% increase to the base salary of Mr. McCrea to $1,465,788 from the prior level of $1,399,320; a 4.75% increase to the base salary of Mr. Long to $1,465,788 from the previous level of $1,399,320; an approximately 6.75% increase to the base salary of Mr. Bramhall to $613,813 from the previous level of $575,000; and an approximately 4.75% increase to the base salary of Mr. Wright to $576,125 from the previous level of $550,000. In the case of Messrs. Whitehurst and Mason, the Energy Transfer Compensation Committee approved lump-sum cash payments equal to 4.75 % of their existing base salaries, which for Mr. Whitehurst such lump sum was $30,420 and for Mr. Mason was $32,285. The determination regarding the lump-sum payments to Messrs. Whitehurst and Mason were related to certain changes to their roles and responsibilities and the results of the Meridian benchmarking analysis.
Executive Compensation Clawback Policy. In November 2023, the Energy Transfer Compensation Committee adopted the Energy Transfer Executive Officer Incentive Compensation Clawback Policy (the “Clawback Policy”), which requires the Partnership to recover erroneously awarded incentive-based compensation from executive officers in the event the Partnership is required to prepare an accounting restatement. The Clawback Policy applies to any individual who is currently or was previously designated as an “officer” of the Partnership as defined in Rule 16a-1(f) under the Securities Exchange Act of 1934, including all of our current NEOs. The Clawback Policy is designed to comply with the requirements of the SEC and the NYSE Listed Company Manual, including (i) the definition of an accounting restatement, (ii) the applicable types of incentive-based compensation, (iii) the relevant recovery period, and (iv) the approach for calculating the recovery amount.
Annual Bonus. In addition to base salary, the Energy Transfer Compensation Committee makes determinations whether to make discretionary annual cash bonus awards to executives, including our named executive officers, following the end of the year under the Amended Bonus Plan. As noted the Amended Bonus Plan replaced the Bonus Plan in connection with certain recommendations contained in Merdian’s 2023 review.
The Amended Bonus Plan is a discretionary annual cash bonus plan available to all employees, including the named executive officers. The purpose of the Amended Bonus Plan is to reward employees for contributions towards the Partnership’s business goals and to aid in motivating employees. The Amended Bonus Plan is administered by the Energy Transfer Compensation Committee and the Energy Transfer Compensation Committee has the authority to establish and interpret the rules and regulations relating to the Amended Bonus Plan, to select participants, to determine and approve the size of any actual award amount, to make all determinations, including factual determinations and to take all other actions necessary or appropriate for the proper administration of the Amended Bonus Plan.
Prior to January 1, 2023, the Bonus Plan provided during each calendar year or any other period designated by the Energy Transfer Compensation Committee (the “Performance Period”) for the Energy Transfer Compensation Committee to evaluate and determine an overall funded cash bonus pool based on achievement of (i) an internal Adjusted EBITDA target (“Adjusted EBITDA Target”), (ii) an internal distributable cash flow target (“DCF Target”) and (iii) performance of each department compared to the applicable departmental budget (“Departmental Budget Target”). For purposes of the Adjusted EBITDA Target and the DCF Target established in the Bonus Plan, the measures of Adjusted EBITDA and Distributable Cash Flow were calculated using the same definitions as used in the Partnership’s publicly reported financial information, including the Partnership’s earnings press releases, investor presentations, and annual and quarterly filings on Forms 10-K and 10-Q. The performance criteria are weighted 60% on the achievement of the Adjusted EBITDA Target, 20% on the achievement of the DCF Target and 20% on the achievement of the Departmental Budget Target (collectively, “Budget Targets”). The total amount of cash to be allocated to the funded bonus pool will range from 0% to 120% for each of the budgeted DCF Target and Adjusted EBITDA Target and will range from 0% to 100% of the Departmental Budget Target. The maximum funding of the bonus pool is 116% of the total pool target and to achieve such funding each of the Adjusted EBITDA and the DCF Target must achieve 120% funding and the Department Budget target must achieve its 100% target. While the funded bonus pool will reflect an aggregation of performance under each target, in the event performance under the Adjusted EBITDA Target is below 80% of its target, no bonus pool will be funded. If the bonus pool is funded, a participant may earn a cash award for the Performance Period based upon the level of attainment of the Budget Targets and his or her individual performance. Awards are paid in cash as soon as practicable after the end of the Performance Period but in no event later than two and one-half months after the end of the Performance Period.
Under the Amended Bonus Plan, for each Performance Period after January 1, 2023, the Energy Transfer Compensation Committee will evaluate and determine an overall funded cash bonus pool based on achievement of (i) an Adjusted EBITDA
Target, (ii) a DCF Target and (iii) a Departmental Budget Target. Under the Amended Bonus Plan, the Budget Targets were weighted 60% on the achievement of the Adjusted EBITDA Target, 25% on the achievement of the DCF Target and 15% on the achievement of the Departmental Budget Target. Under the Amended Bonus Plan, the DCF Target weighting increased to 25% from 20% under the Bonus and the Budget Target weighting was reduced from 20% to 15%. The total amount of cash to be allocated to the funded bonus pool will range from 0% to 135% for each of the budgeted DCF Target and Adjusted EBITDA Target and will range from 0% to 100% of the Departmental Budget Target. The increased range on the funded bonus pool to 135% of the budgeted DCF Target and Adjusted EBITDA Target under the Amended Bonus Plan represented an increase from 120% each under the Bonus Plan.
The maximum funding of the bonus pool of 130% of the total pool target under the Amended Bonus Plan is an increase from 116% under the Bonus Plan. Maximum funding of the Adjusted EBITDA and the DCF Target under the Amended Bonus Plan requires achievement of 110% of the target as opposed to 120% under the Bonus Plan. The maximum funding of the Amended Bonus Plan at 130% is an increase from the 116% maximum under the Bonus Plan.
While the funded bonus pool will reflect an aggregation of performance under each target, in the event performance under the Adjusted EBITDA Target is below 80% of its target, no bonus pool will be funded. If the bonus pool is funded, a participant may earn a cash award for the Performance Period based upon the level of attainment of the Budget Targets and his or her individual performance. Awards under both the Bonus Plan and the Amended Bonus Plan are paid in cash as soon as practicable after the end of the Performance Period but in no event later than two and one-half months after the end of the Performance Period.
While the achievement of the Budget Targets sets a bonus pool under the Bonus Plan and the Amended Bonus Plan, actual bonus awards are discretionary. These discretionary bonuses, if awarded, are intended to reward our named executive officers for the achievement of the Budget Targets during the Performance Period in light of the contribution of each individual to our profitability and success during such year. The Energy Transfer Compensation Committee also considers the recommendation of Mr. Warren in determining the specific annual cash bonus amounts for each of the named executive officers. The Energy Transfer Compensation Committee does not establish its own financial performance objectives in advance for purposes of determining whether to approve any annual bonuses, and it does not utilize any formulaic approach to determine annual bonuses.
For Messrs. McCrea and Long, their 2023 bonus pool targets were 160% of their respective annual base earnings, consistent with their previous 2022 targets. For 2023, the Energy Transfer Compensation Committee approved short-term annual cash bonus pool targets for Messrs. Whitehurst, Bramhall, Mason and Wright of 130% of their respective annual base earnings, consistent with their previous 2022 targets.
In February 2024, the Energy Transfer Compensation Committee certified 2023 performance results under the Amended Bonus Plan and authorized payment of 100% of the targeted pool. This bonus payout reflected the achievement of 100.9% of the Adjusted EBITDA Target, 99.7% of the DCF Target and 99.7% of, or $28 million under, the Department Budget Target.
Based on the approved results, the Energy Transfer Compensation Committee approved a cash bonus relating to the 2023 calendar year to Messrs. McCrea, Long, Bramhall, Whitehurst, Mason and Wright in the amounts of $2,300,000, $2,300,000, $825,000, $800,000, $840,000 and $775,000, respectively.
Equity Awards. Energy Transfer maintains and operates (i) the Second Amended and Restated Energy Transfer LP 2008 Incentive Plan (the “2008 Incentive Plan”); (ii) the Energy Transfer LP 2011 Long-Term Incentive Plan (the “2011 Incentive Plan”); the (iii) Energy Transfer LP 2015 Long-Term Incentive Plan (the “2015 Plan”); (iv) the Amended and Restated Energy Transfer LP Long-Term Incentive Plan (the “Energy Transfer Plan,” together with the 2008 Incentive Plan, the 2011 Incentive Plan and the 2015 Plan, the “Energy Transfer Incentive Plans”). The Energy Transfer Incentive Plans authorize the Energy Transfer Compensation Committee, in its discretion, to grant awards, as applicable, under each respective plan of RSUs upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the Energy Transfer Incentive Plans. Energy Transfer has generally used time-vested restricted units and/or phantom units as the vehicle for its annual equity awards to eligible employees, including the named executive officers.
In addition, in 2020, Energy Transfer adopted the Energy Transfer LP Long-Term Cash Restricted Unit Plan (the “CRU Plan”). The CRU Plan authorizes the Energy Transfer Compensation Committee, in its discretion, to grant awards, as applicable, of CRSUs, upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the CRU Plan. Like awards from the Energy Transfer Incentive Plans, awards from the CRU Plan will be used to incentivize and reward eligible employees over a long-term basis, and the CRU Plan is included for purposes of these discussions as an “Energy Transfer Incentive Plan.”
For 2023, the Energy Transfer Compensation Committee established long-term incentive targets for Messrs. McCrea and Long of 900% of their annual base earnings, consistent with their previous targets. For 2023, the Energy Transfer Compensation Committee approved long-term incentive targets for Messrs. Bramhall, Whitehurst, Mason and Wright of 500%, 500%, 500% and 500%, respectively, of their respective annual base earnings, consistent with their previous targets.
The annual long-term incentive targets are used as the basis to determine the target number of units to be awarded to the eligible participant, including the named executive officers. A multiple of base salary is used to set the pool target, that number is then divided by a weighted average price determined by considering Energy Transfer’s modified total unitholder return (“TUR”) performance as measured against the average return of Energy Transfer’s identified peer group over defined time periods. The modified TUR is designed to create a recognition of a performance adjustment to the equity awards based on the prior periods measured to add an element of performance impact in setting grant date value even though the RSUs and CRSUs themselves are time-vested vehicles. For purposes of establishing an initial price, Energy Transfer utilizes a 60 trading-day trailing weighted average price of Energy Transfer common units prior to November 1 of the respective year. This average trading price is then subject to adjustment when Energy Transfer’s TUR is more than 5% greater or less than that of its identified peer group. If the TUR analysis yields a result that is within 5% of its identified peer group, the Energy Transfer Compensation Committee will simply use the 60 trading day trailing weighted average price divided by the applicable salary multiple to establish a target pool for each eligible participant, including the named executive officers. If Energy Transfer’s TUR is outside of the 5% deviation, the 60 trading day trailing weighted average will be adjusted up or down to a maximum of 15% from the trailing weighted average price based on Energy Transfer’s performance as compared to the identified group. For 2022, the peer group included the following:
• Enterprise Products Partners, L.P. • Plains All American Pipeline, L.P.
• The Williams Companies, Inc. • MPLX LP
• Kinder Morgan, Inc.
For 2023, the Partnership’s TUR outperformed the identified peer group by approximately 6% based on the average of the identified comparison periods. Consequently, the 2023 long-term incentive base price was decreased to increase the total available restricted pool by approximately 6%.
In December 2023, the Energy Transfer Compensation Committee in consultation with Mr. Warren approved grants of RSUs to Messrs. McCrea, Long, Bramhall, Whitehurst, Mason and Wright of 782,138 units, 782,138 units, 189,750 units, 187,500 units, 187,500 units, and 170,775 units, respectively. The Energy Transfer Compensation Committee also approved grants of CRSUs to Messrs. McCrea, Long, Bramhall, Whitehurst, Mason and Wright of 260,712 units, 260,712 units, 63,250 units, 62,500 units, 62,500 units and 56,925 units, respectively.
The RSUs granted in 2023 provide for incremental vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year. Vesting of the awards is generally subject to continued employment through each specified vesting date. The RSU awards entitle the recipients to receive, with respect to each Energy Transfer unit subject to such award that has not either vested or been forfeited, a DER cash payment promptly following each such distribution by Energy Transfer to its common unitholders.
The CRSUs granted in 2023 provide for incremental vesting over a three-year period, with 1/3 vesting at the end of each year. Each CRSU entitles the award recipient to receive cash equal to the market value of one Energy Transfer common unit upon vesting. The CRSU do not include rights to DER cash payments.
In approving the grant of such RSUs and CRSUs, including to the named executive officers, the Energy Transfer Compensation Committee considered several factors, including the long-term objective of retaining such individuals as key drivers of Energy Transfer’s future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting. Vesting of the 2023 awards would accelerate in the event of the death or disability of the recipient, including the named executive officers, or in the event of a change in control of Energy Transfer as that term is defined under the Energy Transfer Incentive Plans.
As discussed below under “Potential Payments Upon a Termination or Change of Control,” all outstanding equity awards would automatically accelerate upon a change in control event, which means vesting automatically accelerates upon a change of control irrespective of whether the officer is terminated. In addition, the award agreements also include certain acceleration provisions upon retirement with the ability to accelerate 40% of outstanding unvested awards under the Energy Transfer Incentive Plans at age 65 and 50% at age 68. These acceleration provisions require that the participant have not less than five (5) years of employment service to the Partnership or an affiliate and are subject to the applicable provisions of IRC Section
409(A), which may include a six (6) month delay in the vesting after retirement. Beginning in 2022, the retirement provision also requires that the award be held for at least one year after the grant date in order to be eligible for acceleration.
We believe that permitting the accelerated vesting of equity awards upon a change in control creates an important retention tool for us by enabling employees to realize value from these awards in the event that we undergo a change in control transaction. In addition, we believe permitting acceleration of vesting upon a change in control creates a sense of stability in the course of transactions that could create uncertainty regarding their future employment and encourage these officers to remain focused on their job responsibilities.
Affiliate and Subsidiary Equity Awards. In addition to his role as an officer for Energy Transfer during 2023, Mr. Bramhall has certain responsibilities for Sunoco LP, including a leadership role for certain shared service functions. Notwithstanding such responsibilities beginning in 2023, 100% of Mr. Bramhall’s compensation, including his long-term incentive awards, were attributable on to Energy Transfer.
Special One-Time Awards to Co-Chief Executive Officers. In recognition of their assumption of their new roles as Co-Chief Executive Officers effective January 1, 2021, the Energy Transfer Compensation Committee approved certain one-time awards to Messrs. McCrea and Long.
Mr. McCrea received a special one-time award of 241,815 RSUs under the Energy Transfer Incentive Plans and a special cash payment of $1,625,000 in connection with his appointment as Co-Chief Executive Officer, effective January 1, 2021.
Mr. Long received a special one-time award of 483,630 RSUs under the Energy Transfer Incentive Plans in connection with his appointment as Co-Chief Executive Officer, effective January 1, 2021.
The RSU awards to Messrs. McCrea and Long were made at the same grant date valuation and vesting schedules used for the annual equity awards described above under “-Equity Awards” section above. These awards were approved by the Energy Transfer Compensation Committee on December 30, 2020 to be effective immediately upon Messrs. McCrea and Long assuming their new roles on January 1, 2021 and are reflected as compensation in 2021 in the Compensation Tables section below.
Unit Ownership Guidelines. In 2021, the Board of Directors of our General Partner adopted an update to the Executive Unit Ownership Guidelines (the “Guidelines”), which sets forth minimum ownership guidelines applicable to certain executives of Energy Transfer with respect to Energy Transfer and Sunoco LP common units, as applicable. The applicable Guidelines are denominated as a multiple of base salary, and the amount of common units required to be owned increases with the level of responsibility. Under these Guidelines, (i) the Chief Executive Officer/Co-Chief Executive Officer(s) are expected to own common units having a minimum value of six times base salary; (ii) the Chief Operating Officer, the Chief Financial Officer, the General Counsel and other C-Suite executives expected to own common units having a minimum value of four times their respective base salary; and (iii) Senior Vice Presidents are expected to own common units having a minimum value of two times their respective base salary. In addition to the named executive officers, these Guidelines also apply to other covered executives, which executives are expected to own either directly or indirectly in accordance with the terms of the Guidelines, common units having minimum values ranging from one to four times their respective base salary.
The Energy Transfer Compensation Committee believes that the ownership of Energy Transfer and/or Sunoco LP common units, as reflected in these Guidelines, is an important means of tying the financial risks and rewards for its executives to Energy Transfer’s total unitholder return, aligning the interests of such executives with those of Unitholders, and promoting Energy Transfer’s interest in good corporate governance.
Covered executives are generally required to achieve their ownership level within five years of becoming subject to the Guidelines. As of December 31, 2023, all of the named executive officers were compliant with the level required of the Guidelines as of that date.
Covered executives may satisfy the Guidelines through direct ownership of Energy Transfer and/or Sunoco LP common units or indirect ownership by certain immediate family members. Direct or indirect ownership of Energy Transfer and/or Sunoco LP common units shall count on a one-to-one ratio for purposes of satisfying minimum ownership requirements; however, unvested unit awards may not be used to satisfy the minimum ownership requirements.
Executive officers, including the named executive officers, who have not yet met their respective guideline must retain and hold all common units (less common units sold to cover the executive’s applicable taxes and withholding obligation) received in connection with long-term incentive awards. Once the required ownership level is achieved, ownership of the required common units must be maintained for as long as the covered executive is subject to the Guidelines. However, those individuals who have met or exceeded their applicable ownership level guideline may dispose of the common units in a manner consistent with
applicable laws, rules and regulations, including regulations of the SEC and our internal policies, but only to the extent that such individual’s remaining ownership of common units would continue to exceed the applicable ownership level.
Qualified Retirement Plan Benefits. The Energy Transfer LP 401(k) Plan (the “Energy Transfer 401(k) Plan”) is a defined contribution 401(k) plan, which covers substantially all of our employees, including the named executive officers. Employees may elect to defer up to 100% of their eligible compensation after applicable taxes, as limited under the Internal Revenue Code. We make a matching contribution that is not less than the aggregate amount of matching contributions that would be credited to a participant’s account based on a rate of match equal to 100% of each participant’s elective deferrals up to 5% of covered compensation. The amounts deferred by the participant are fully vested at all times, and the amounts contributed by the Partnership become vested based on years of service. We provide this benefit as a means to incentivize employees and provide them with an opportunity to save for their retirement.
The Partnership provides a 3% profit sharing contribution to employee 401(k) accounts for all employees with a base compensation below a specified threshold. The contribution is in addition to the 401(k) matching contribution and employees become vested based on years of service.
Health and Welfare Benefits. All full-time employees, including our named executive officers may participate in the Partnership’s health and welfare benefit programs including medical, dental, vision, flexible spending, life insurance and disability insurance.
Termination Benefits. Our named executive officers do not have any employment agreements that call for payments of termination or severance benefits or that provide for any payments in the event of a change in control of our General Partner; however, the award agreement to the named executive officers under the Energy Transfer Incentive Plans, the 2018 Sunoco LP Plan and the Sunoco LP 2012 Long-Term Incentive Plan (the “2012 Sunoco LP Plan”) provide for immediate vesting of all unvested restricted unit awards in the event of a (i) change of control, as defined in the plan; (ii) death or (iii) disability, as defined in the applicable plan. Please refer to “Compensation Tables - Potential Payments Upon a Termination or Change of Control” for additional information.
In addition, in 2021 the Partnership has also adopted the Partnership Severance Plan and Summary Plan Description (the “Severance Plan”), which provides for payment of certain severance benefits in the event of Qualifying Termination (as that term is defined in the Severance Plan). In general, the Severance Plan provides payment of two weeks of annual base salary for each year or partial year of employment service up to a maximum of fifty-two weeks or one year of annual base salary (with a minimum of four weeks of annual base salary) and up to three months of continued group health insurance coverage. The Severance Plan also provides that we may determine to pay benefits in addition to those provided under the Severance Plan based on special circumstances, which additional benefits shall be unique and non-precedent setting. The Severance Plan is available to all salaried employees on a nondiscriminatory basis; therefore, amounts that would be payable to our named executive officers upon a Qualified Termination have been excluded from “Compensation Tables - Potential Payments Upon a Termination or Change of Control” below.
Energy Transfer LP Non-Qualified Deferred Compensation Plan (the “Energy Transfer NQDC Plan”) is a deferred compensation plan, which permits eligible highly compensated employees to defer a portion of their salary, bonus, and/or quarterly non-vested phantom unit distribution equivalent income until retirement, termination of employment or other designated distribution event. Each year under the Energy Transfer NQDC Plan, eligible employees are permitted to make an irrevocable election to defer up to 50% of their annual base salary, 50% of their quarterly non-vested phantom unit distribution income, and/or 50% of their discretionary performance bonus compensation during the following year. Pursuant to the Energy Transfer NQDC Plan, Energy Transfer may make annual discretionary matching contributions to participants’ accounts; however, Energy Transfer has not made any discretionary contributions to participants’ accounts and currently has no plans to make any discretionary contributions to participants’ accounts. All amounts credited under the Energy Transfer NQDC Plan (other than discretionary credits) are immediately 100% vested. Participant accounts are credited with deemed earnings or losses based on hypothetical investment fund choices made by the participants among available funds.
Participants may elect to have their account balances distributed in one lump sum payment or in annual installments over a period of three or five years upon retirement, and in a lump sum upon other termination events. Participants may also elect to take lump-sum in-service withdrawals five years or longer in the future, and such scheduled in-service withdrawals may be further deferred prior to the withdrawal date. Upon a change in control (as defined in the Energy Transfer NQDC Plan) of Energy Transfer, all Energy Transfer NQDC Plan accounts are immediately vested in full. However, distributions are not accelerated and, instead, are made in accordance with the Energy Transfer NQDC Plan’s normal distribution provisions unless a participant has elected to receive a change of control distribution pursuant to his deferral agreement.
Risk Assessment Related to our Compensation Structure. We believe that the compensation plans and programs for our named executive officers, as well as our other employees, are appropriately structured and are not reasonably likely to result in material
risk to us. We believe these compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could harm our value or reward poor judgment. We also believe we have allocated compensation among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. In particular, we generally do not adjust base annual salaries for executive officers and other employees significantly from year to year, and therefore the annual base salary of our employees is not generally impacted by our overall financial performance or the financial performance of a portion of our operations. Our subsidiaries generally determine whether, and to what extent, their respective named executive officers receive a cash bonus based on achievement of specified financial performance objectives as well as the individual contributions of our named executive officers to the Partnership’s success. We and our subsidiaries use restricted units and phantom units rather than unit options for equity awards because restricted units and phantom units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or keep, options “in-the-money.” Finally, the time-based vesting over five years for our long-term incentive awards ensures that the interests of employees align with those of Unitholders and our subsidiaries’ unitholders for our long-term performance.
Tax and Accounting Implications of Equity-Based Compensation Arrangements
Deductibility of Executive Compensation
We are a limited partnership and not a corporation for United States federal income tax purposes. Therefore, we believe that the compensation paid to the named executive officers is not subject to the deduction limitations under Section 162(m) of the Internal Revenue Code and therefore is generally fully deductible for United States federal income tax purposes.
Accounting for Non-Cash Compensation
For non-cash compensation arrangements, we record compensation expense over the vesting period of the awards, as discussed further in Note 2 and Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Compensation Committee Interlocks and Insider Participation
Mr. Steven R. Anderson and Mr. Michael K. Grimm are the only members of the Energy Transfer Compensation Committee. During 2023, no member of the Energy Transfer Compensation Committee was an officer or employee of us or any of our subsidiaries or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. Mr. Grimm is not a former employee of ours or any of our subsidiaries. Mr. Anderson was previously an employee of the Partnership until his retirement in October 2009, as discussed in his biographical information included in “Item 10. Directors, Executive Officers and Corporate Governance.”
Report of Compensation Committee
The board of directors of our General Partner has reviewed and discussed the section entitled “Compensation Discussion and Analysis” with the management of Energy Transfer. Based on this review and discussion, we have recommended that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.
The Compensation Committee of the
Board of Directors of LE GP, LLC,
general partner of Energy Transfer LP
Steven R. Anderson
Michael K. Grimm
The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this annual report on Form 10-K into any filing under the Securities Act of 1933, as amended, or the Exchange Act, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under those Acts.
Compensation Tables
Summary Compensation Table
Name and Principal Position Year Salary
($) Bonus
($) Equity
Awards (1)
($)
Non-Equity
Incentive Plan
Compensation(2)
($)
Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings ($) All Other
Compensation (3)
($)
Total
($)
Thomas E. Long 2023 $ 1,432,554 $ - $ 13,282,060 $ 2,300,000 $ - $ 25,167 $ 17,039,781
Co-Chief Executive Officer 2022 1,372,410 - 14,344,161 2,635,027 - 23,917 18,375,515
2021 1,322,750 - 15,224,039 3,156,400 - 27,014 19,730,203
Marshall S. (Mackie) McCrea, III (4)
2023 1,432,554 - 13,282,060 2,300,000 - 24,044 17,038,658
Co-Chief Executive Officer 2022 1,372,410 1,600,000 14,344,161 2,635,027 - 22,794 19,974,392
2021 1,322,750 3,225,000 13,734,458 3,156,400 - 22,044 21,460,652
Dylan A. Bramhall 2023 594,406 - 3,222,286 825,000 - 17,760 4,659,452
Group Chief Financial Officer 2022 429,808 - 3,241,514 700,000 - 16,298 4,387,620
Bradford D. Whitehurst 2023 670,845 - 3,184,077 800,000 - 19,760 4,674,682
Executive Vice President - Tax and Corporate Initiatives 2022 628,125 - 3,646,060 950,000 - 18,510 5,242,695
2021 605,413 - 3,102,694 1,174,000 - 15,760 4,897,867
Thomas P. Mason 2023 711,980 - 3,184,077 840,000 - 23,167 4,759,224
Executive Vice President - Alternative Energy and President - LNG 2022 666,595 - 3,870,995 1,040,900 - 21,917 5,600,407
2021 642,445 - 3,279,498 1,252,000 - 22,706 5,196,649
James M. Wright, Jr. 2023 563,063 - 2,900,058 775,000 13,991 90,391 4,342,503
Executive Vice President, General Counsel and Chief Compliance Officer
2022 488,808 - 1,963,263 762,540 18,550 19,120 3,252,281
(1)Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718, disregarding any estimates for forfeitures. For Messrs. Bramhall and Whitehurst amounts for one or more periods include equity awards of our subsidiary, Sunoco LP, as reflected in the “Grants of Plan-Based Awards Table.” See Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards. Although the CRSU awards may only be settled in cash, they are based upon the value of Energy Transfer common units and are accounted for as equity awards within these compensation tables.
(2)Energy Transfer maintains the Bonus Plan which provides for discretionary bonuses. Awards of discretionary bonuses are tied to achievement of targeted performance objectives and described in the Compensation Discussion and Analysis.
(3)The amounts reflected for 2023 in this column include (i) matching contributions to the Energy Transfer 401(k) Plan made on behalf of the named executive officers of $16,500 each for Messrs. Long, McCrea, Bramhall, Whitehurst, Mason and Wright, and (ii) health savings account contributions made on behalf of the named executive officers of $2,000 each for Messrs. Long, McCrea, Whitehurst and Wright, (iii) the dollar value of life insurance premiums paid for the benefit of the named executive officers, and (iv) $68,279 in relocation costs for Mr. Wright. The amounts reflected for all periods exclude distribution payments in connection with distribution equivalent rights on unvested unit awards, because the dollar value of such distributions are factored into the grant date fair value reported in the “Equity Awards” column of the Summary Compensation Table at the time that the unit awards and distribution equivalent rights were originally granted. For 2023, distribution payments in connection with distribution equivalent rights totaled $3,762,597 for Mr. Long, $4,425,772 for Mr. McCrea, $625,571 for Mr. Bramhall, $1,121,545 for Mr. Whitehurst, $1,180,863 for Mr. Mason, and $531,209 for Mr. Wright; these amounts include distribution payments on Sunoco LP unit awards for those executives with such unvested awards.
(4)The amounts reflected in the bonus column for Mr. McCrea in 2022 and 2021 include $1,600,000 per year paid in connection with a time-vested cash award granted in 2020, which represented 50% of Mr. McCrea’s total equity award target for that year; no additional amounts remain outstanding under that award. The amount reflected in the bonus column for 2021 for Mr. McCrea also includes the vesting and payment on February 1, 2021 of a one-time, time-vested cash award of $1,625,000 to Mr. McCrea, which was originally granted in October 2020 in connection with Mr. McCrea’s assumption of his role as Co-Chief Executive Officer.
Grants of Plan-Based Awards in 2023
Name Grant Date All Other Unit Awards: Number of Units
(#) Grant Date Fair Value of Unit Awards (1)
Energy Transfer Unit Awards:
Thomas E. Long 12/8/2023 782,138 $ 10,402,435
Marshal S. (Mackie) McCrea, III 12/8/2023 782,138 10,402,435
Dylan A. Bramhall 12/8/2023 189,750 2,523,675
Bradford D. Whitehurst 12/8/2023 187,500 2,493,750
Thomas P. Mason 12/8/2023 187,500 2,493,750
James M. Wright, Jr. 12/8/2023 170,775 2,271,308
Energy Transfer Cash Restricted Unit Awards:
Thomas E. Long 12/8/2023 260,712 2,879,625
Marshal S. (Mackie) McCrea, III 12/8/2023 260,712 2,879,625
Dylan A. Bramhall 12/8/2023 63,250 698,611
Bradford D. Whitehurst 12/8/2023 62,500 690,327
Thomas P. Mason 12/8/2023 62,500 690,327
James M. Wright, Jr. 12/8/2023 56,925 628,750
(1)We have computed the grant date fair value of unit awards in accordance with FASB ASC Topic 718, as further described above and in Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” For Energy Transfer cash restricted unit awards, the grant date fair value is discounted for the expected distribution yield during the vesting period, as those awards do not include distribution equivalent rights.
Narrative Disclosure to Summary Compensation Table and Grants of the Plan-Based Awards Table
A description of material factors necessary to understand the information disclosed in the tables above with respect to salaries, bonuses, equity awards, and 401(k) plan contributions can be found in the Compensation Discussion and Analysis that precedes these tables.
Outstanding Equity Awards at 2023 Fiscal Year-End
Name Grant Date(1)
Unit Awards (1)
Number of Units That Have Not Vested(2)
(#)
Market or Payout Value of Units That Have Not Vested (3)
($)
Energy Transfer Unit Awards:
Thomas E. Long 12/8/2023 782,138 $ 10,793,504
12/12/2022 958,950 13,233,510
12/16/2021 1,121,250 15,473,250
12/30/2020 264,872 3,655,234
12/16/2019 86,000 1,186,800
Marshal S. (Mackie) McCrea, III 12/8/2023 782,138 10,793,504
12/12/2022 958,950 13,233,510
12/16/2021 1,121,250 15,473,250
12/30/2020 395,266 5,454,671
12/16/2019 272,960 3,766,848
Dylan A. Bramhall 12/8/2023 189,750 2,618,550
12/12/2022 175,125 2,416,725
12/16/2021 83,400 1,150,920
12/30/2020 15,000 207,000
12/16/2019 21,000 289,800
Bradford D. Whitehurst 12/8/2023 187,500 2,587,500
12/12/2022 243,750 3,363,750
12/16/2021 228,000 3,146,400
12/30/2020 66,640 919,632
12/16/2019 60,920 840,696
Thomas P. Mason 12/8/2023 187,500 2,587,500
12/12/2022 258,788 3,571,274
12/16/2021 300,300 4,144,140
12/30/2020 93,960 1,296,648
12/16/2019 85,920 1,185,696
James M. Wright, Jr. 12/8/2023 170,775 2,356,695
12/12/2022 131,250 1,811,250
12/16/2021 131,944 1,820,827
12/30/2020 39,502 545,128
12/16/2019 36,120 498,456
Energy Transfer Cash Restricted Unit Awards:
Thomas E. Long 12/8/2023 260,712 3,004,546
12/12/2022 213,100 2,568,488
12/16/2021 124,584 1,570,643
Marshal S. (Mackie) McCrea, III 12/8/2023 260,712 3,004,546
12/12/2022 213,100 2,455,847
12/16/2021 124,584 1,501,607
Dylan A. Bramhall 12/8/2023 63,250 728,918
12/12/2022 38,917 469,061
12/16/2021 9,267 116,830
Bradford D. Whitehurst 12/8/2023 62,500 720,274
12/12/2022 54,167 652,869
12/16/2021 25,334 319,389
Thomas P. Mason 12/8/2023 62,500 720,274
12/12/2022 57,508 693,142
12/16/2021 33,367 420,662
James M. Wright, Jr. 12/8/2023 56,925 656,026
12/12/2022 29,167 351,549
12/16/2021 14,661 184,833
Sunoco LP Unit Awards:
Thomas E. Long 12/30/2020 11,120 666,422
12/16/2019 7,800 467,454
Dylan A. Bramhall 12/12/2022 14,200 851,006
12/16/2021 13,000 779,090
12/30/2020 6,400 383,552
10/27/2020 8,000 479,440
Bradford D. Whitehurst 12/16/2021 16,100 964,873
12/30/2020 10,400 623,272
12/16/2019 7,280 436,290
(1)Certain of these outstanding awards represent subsidiary awards that converted into Energy Transfer awards upon the in connection with restructuring transactions in prior periods.
(2)Energy Transfer and Sunoco LP unit awards outstanding vest as follows:
•at a rate of 60% in December 2026 and 40% in December 2028 for awards granted in December 2023;
•at a rate of 60% in December 2025 and 40% in December 2027 for awards granted in December 2022;
•at a rate of 60% in December 2024 and 40% in December 2026 for awards granted in December 2021;
•100% in December 2025 for the remaining outstanding portion awards granted in October and December 2020; and
•100% in December 2024 for the remaining outstanding portion of awards granted in December 2019.
Such awards may be settled at the election of the Energy Transfer Compensation Committee in (i) common units of Energy Transfer (subject to the approval of the Energy Transfer Incentive Plans prior to the first vesting date by a majority of Unitholders pursuant to the rules of the New York Stock Exchange); (ii) cash equal to the Fair Market Value (as such term is defined in the Energy Transfer Incentive Plans) of the Energy Transfer common units that would otherwise be delivered
pursuant to the terms of each named executive officers grant agreement; or (iii) other securities or property in an amount equal to the Fair Market Value of Energy Transfer common units that would otherwise be delivered pursuant to the terms of the grant agreement, or a combination thereof as determined by the Energy Transfer Compensation Committee in its discretion.
Energy Transfer cash restricted unit awards granted in December 2023 vest 1/3 per year in December 2024, 2025 and 2026. Energy Transfer cash restricted unit awards granted in December 2022 vest 1/2 per year in December 2024 and 2025. The remaining outstanding Energy Transfer cash restricted unit awards granted in December 2021 vest in December 2024.
(3)Market value was computed as the number of unvested awards as of December 31, 2023 multiplied by the closing price of respective common units of Energy Transfer and Sunoco LP. For Energy Transfer cash restricted unit awards, the grant date fair value is discounted for the expected distribution yield during the vesting period, as those awards do not include distribution equivalent rights.
Units Vested in 2023
Unit Awards
Name Number of Units
Acquired on Vesting
(#) Value Realized on Vesting
($) (1)
Energy Transfer Unit Awards:
Thomas E. Long
497,978 $ 6,852,177
Marshall S. (Mackie) McCrea, III
835,195 11,492,283
Dylan A. Bramhall 40,500 557,280
Bradford D. Whitehurst 154,036 2,119,535
Thomas P. Mason
217,196 2,988,617
James M. Wright, Jr. 91,313 1,256,467
Energy Transfer Cash Restricted Unit Awards:
Thomas E. Long
290,650 3,999,344
Marshall S. (Mackie) McCrea, III
231,133 3,180,390
Dylan A. Bramhall 41,225 567,261
Bradford D. Whitehurst 107,950 1,485,397
Thomas P. Mason
140,421 1,932,193
James M. Wright, Jr. 62,162 855,349
Sunoco LP Unit Awards:
Thomas E. Long
24,410 1,293,242
Dylan A. Bramhall 21,600 1,144,368
Bradford D. Whitehurst 23,258 1,232,209
(1)Amounts presented represent the value realized upon vesting of these awards, which is calculated as the number of units vested multiplied by the applicable closing market price of applicable common units upon the vesting date.
We have not issued option awards.
Nonqualified Deferred Compensation Table
A description of the key provisions of the Partnership’s deferred compensation plan can be found in the compensation discussion and analysis above.
Name Executive Contributions in Last FY ($)
Acquired on Vesting
(#) Registrant Contributions in Last FY ($)
($) (1)
Aggregate Earnings in Last FY ($) (1)
Aggregate Withdrawals/Distributions ($) Aggregate Balance at Last FYE ($)
James M. Wright, Jr. - - 13,991 - 83,736
(1)Amounts included in the aggregate earnings column above have been included in the change in non-qualified deferred compensation earnings column of the summary compensation table.
Potential Payments Upon a Termination or Change of Control
Equity Awards. As discussed in our Compensation Discussion and Analysis above, any unvested equity awards (including cash restricted unit awards) granted pursuant the Energy Transfer Incentive Plans will automatically become vested upon a change of control, which is generally defined as the occurrence of one or more of the following events: (i) any person or group becomes the beneficial owner of 50% or more of the voting power or voting securities of Energy Transfer or its general partner; (ii) LE GP, LLC or an affiliate of LE GP, LLC ceases to be the general partner of Energy Transfer; or (iii) the sale or other disposition, including by liquidation or dissolution, of all or substantially all of the assets of Energy Transfer in one or more transactions to anyone other than an affiliate of Energy Transfer.
In addition, as explained in Equity Awards section of our Compensation Discussion and Analysis above, the restricted unit awards, phantom unit awards and cash restricted unit awards under the Energy Transfer Incentive Plans, the Sunoco LP Plan and the 2012 Sunoco LP Plan generally require the continued employment of the recipient during the vesting period, provided however, the unvested awards will be accelerated in the event of the death or disability of the award recipient prior to the applicable vesting period being satisfied. All awards outstanding to the named executive officers under the Energy Transfer Incentive Plans, the 2018 Sunoco LP Plan or the 2012 Sunoco LP Plan would be accelerated in the event of a change in control of the Partnership.
In addition, the Energy Transfer Compensation Committee and the compensation committee of the general partner of Sunoco LP, have approved a retirement provision, which provides that employees, including the named executive officers with at least five years of service with the general partner, who leave the respective general partner voluntarily due to retirement (i) after age 65 but prior to age 68 are eligible for accelerated vesting of 40% of his or her award; or (ii) after 68 are eligible for accelerated vesting of 50% his or her award. The acceleration of the awards is subject to the applicable provisions of IRC Section 409(A). Beginning with awards granted in 2022, the retirement provision also requires that the award be held for at least one year after the grant date in order to be eligible for acceleration.
The following table shows the amount of incremental value that would have been received by each of the NEOs upon certain events of termination or a change of control resulting in the accelerated vesting of the restricted units and/or restricted phantom units held by our NEOs on December 31, 2023:
Name Benefit Termination due to Death or Disability ($) (1)
Termination for Any Other Reason ($) Change of Control
with or without Continued
Employment
($) (1)
Not for Cause Termination ($)
Thomas E. Long (2)
Unit Vesting $ 53,734,034 $ - $ 53,734,034 $ -
Marshall S. (Mackie) McCrea, III Unit Vesting 56,979,648 - 56,979,648 -
Dylan A. Bramhall (2)
Unit Vesting 10,713,868 - 10,713,868 -
Bradford D. Whitehurst (2)
Unit Vesting 15,310,675 - 15,310,675 -
Thomas P. Mason Unit Vesting 14,901,833 - 14,901,833 -
James M. Wright, Jr. Unit Vesting 8,422,747 - 8,422,747 -
(1)The amounts reflected above represent the product of the number of RSUs and CRSUs units that were subject to vesting/restrictions on December 31, 2023 multiplied by the closing price of applicable common units on that date.
(2)For Messrs. Long, Bramhall and Whitehurst, the amounts reported above include outstanding Energy Transfer plan-based awards and outstanding Sunoco LP restricted units.
Deferred Compensation Plan. As discussed in our Compensation Discussion and Analysis above, all amounts under the Energy Transfer NQDC Plan (other than discretionary credits) are immediately 100% vested. Upon a change of control (as defined in the Energy Transfer NQDC Plan), distributions from the respective plan would be made in accordance with the normal distribution provisions of the respective plan. A change of control is generally defined in the Energy Transfer NQDC Plan as any change of control event within the meaning of Treasury Regulation Section 1.409A-3(i)(5).
CEO Pay Ratio
In accordance with Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, set forth below is information about the relationship of the annual total compensation of Messrs. Long and McCrea, Co-Chief Executive Officers, and the annual total compensation of our employees.
For the 2023 calendar year, the annual total compensation of Messrs. Long and McCrea, as reported in the Summary Compensation Table of this Item 11 was $17,039,781 and $17,038,658, respectively.
The median total compensation of the employees supporting the Partnership (other than Messrs. Long and McCrea) was $147,362 for 2023.
Based on this information, for 2023 the ratio of the annual total compensation of Messrs. Long and McCrea to the median of the annual total compensation of the employees supporting the Partnership as of December 31, 2023 was approximately 116 to 1.
To identify the median of the annual total compensation of the employees supporting the Partnership, the following steps were taken:
1.It was determined that, as of December 31, 2023, the applicable employee populations consisted of 10,579 with all of the identified individuals being employed in the United States. This population consisted of all of our full-time and part-time employees. We did not engage any independent contractors in 2023 that are required to be included in our employee population for the CEO pay ratio evaluation.
2.To identify the “median employee” from our employee population, we compared the total earnings of our employees as reflected in our payroll records as reported on Form W-2 for 2023.
3.We identified our median employee using W-2 reporting and applied this compensation measure consistently to all of our employees required to be included in the calculation. We did not make any cost of living adjustments in identifying the “median employee.”
4.Once we identified our median employee, we combined all elements of the employee’s compensation for 2023 resulting in an annual compensation of $147,362 with total cash compensation of $126,264 The difference between such employee’s total earnings and the employee’s total compensation represents the estimated value of the employee’s health care benefits (estimated for the employee and such employee’s eligible dependents at $13,908) and the employee’s 401(k) matching contribution and profit sharing contribution (estimated at $7,190 per employee, includes $4,501 per employee on average matching contribution and $2,689 per employee on average profit sharing contribution (employees earning over $175,000 in base are ineligible for profit sharing)).
5.With respect to Messrs. Long and McCrea, we used the amount reported in the “Total” column of our 2023 Summary Compensation Table under this Item 11.
Director Compensation
In 2023, the compensation arrangements for outside directors included a $100,000 annual retainer for services on the board. If a director served on the Energy Transfer Audit Committee, such director would receive an annual cash retainer ($15,000 or $25,000 in the case of the chairman). If a director served on the Energy Transfer Compensation Committee, such director would receive an annual cash retainer ($7,500 or $15,000 in the case of the chairman). The fees for membership on the Conflicts Committee are determined on a per instance basis for each committee assignment.
The outside directors of our General Partner are also entitled to an annual restricted unit award under the Energy Transfer Incentive Plans equal to an aggregate of $125,000 based on the same grant date valuation as is used for annual long-term incentive awards made to Partnership officers, including the named executive officers, through the annual modified total unitholder return analysis. These Energy Transfer common units will vest 60% after the third year and the remaining 40% after the fifth year after the grant date. The compensation expense recorded is based on the grant-date market value of the Energy Transfer common units and is recognized over the vesting period. Distributions are paid during the vesting period.
The compensation paid to the non-employee directors of our General Partner in 2023 is reflected in the following table:
Name Fees Paid in Cash(1)
($)
Unit Awards(2)
($)
All Other Compensation
($) Total
($)
Steven R. Anderson
$ 122,500 $ 137,162 $ - $ 259,662
Richard D. Brannon
125,000 137,162 - 262,162
Ray C. Davis (3)
25,000 - - 25,000
Michael K. Grimm
130,000 137,162 - 267,162
John W. McReynolds 100,000 137,162 - 237,162
James R. Perry 100,000 137,162 - 237,162
Matthew S. Ramsey 100,000 137,162 - 237,162
(1)Fees paid in cash are based on amounts paid during the period.
(2)Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718, disregarding any estimates for forfeitures. See Note 9 to our consolidated
financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards.
As discussed above, the number of units awarded is based on the annual award amount of $125,000 divided by the same grant-date valuation as is used for annual long-term incentive award to Partnership officers through the modified total unitholders return analysis.
(3)Mr. Davis resigned from the board of directors of our General Partner, effective December 31, 2022, the fess paid in cash in 2023 above relate to services performed in 2022.
As of December 31, 2023, Mr. Anderson had 46,584 unvested Energy Transfer restricted units outstanding, Mr. Brannon had 46,584 unvested Energy Transfer restricted units outstanding, Mr. Grimm had 46,584 unvested Energy Transfer restricted units outstanding, Mr. McReynolds had 24,172 unvested Energy Transfer restricted units outstanding, Mr. Perry had 44,565 unvested Energy Transfer restricted units outstanding and Mr. Ramsey had 21,302 unvested Energy Transfer restricted units outstanding.
The executive chairman and the employee directors do not receive compensation for their service on the board of our General Partner.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
Equity Compensation Plan Information
The following table sets forth in tabular format, a summary of our equity plan information as of December 31, 2023:
Plan Category Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights
(a) Weighted-average
exercise price of
outstanding options,
warrants and rights
(b) Number of securities
remaining available for
future issuance under
equity compensation plans
(excluding securities
reflected in column (a))
(c)
Equity compensation plans approved by security holders
- $ - -
Equity compensation plans not approved by security holders 39,105,067 - 42,904,968
Total 39,105,067 $ - 42,904,968
Energy Transfer LP Units
The following table sets forth certain information as of February 9, 2024, regarding the beneficial ownership of our voting securities by (i) certain beneficial owners of more than 5% of our Common Units, (ii) each director and named executive officer
of our General Partner and (iii) all current directors and executive officers of our General Partner as a group. The General Partner knows of no other person not disclosed herein who beneficially owns more than 5% of our Common Units.
Beneficially Owned (2)
Percent of Class
Name and Address of
Beneficial Owner (1)
Common Units Class A
Units(3)
Common Units Class A Units
Kelcy L. Warren (4)
298,799,984 833,543,364 8.9 % 100.0 %
Thomas E. Long 1,075,649 - * N/A
Marshall S. (Mackie) McCrea, III (5)
3,783,579 - * N/A
Dylan A. Bramhall 134,506 - * N/A
Thomas P. Mason 891,285 - * N/A
Bradford D. Whitehurst (6)
663,131 - * N/A
James M. Wright, Jr. 276,646 - * N/A
Steven R. Anderson (7)
1,569,047 - * N/A
Richard D. Brannon (8)
708,936 - * N/A
Michael K. Grimm (9)
768,811 - * N/A
John W. McReynolds (10)
30,225,200 - * N/A
James R. Perry 135,873 - * N/A
Matthew S. Ramsey 1,121,845 - * N/A
All Directors and Executive Officers as a group (14 persons) 340,294,745 833,543,364 10.1 % 100.0 %
*Less than 1%
(1)The address for all listed beneficial owners is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225.
(2)Beneficial ownership for the purposes of this table is defined by Rule 13d-3 under the Exchange Act of 1934. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof or to dispose or direct the disposition thereof or has the right to acquire either of those powers within sixty days. The nature of beneficial ownership for all listed persons is direct with sole investment and disposition power unless otherwise noted. The beneficial ownership of each listed person is based on 3,367,757,556 common units outstanding in the aggregate as of February 9, 2024.
(3)The Energy Transfer Class A Units are entitled to vote together with the Partnership’s common units and are not entitled to distributions and otherwise have no economic attributes. The Energy Transfer Class A Units are not convertible into, or exchangeable for, Partnership common units. Under the terms of the Energy Transfer Class A Units, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to the general partner additional Energy Transfer Class A Units such that Mr. Warren, through his majority ownership of our general partner, maintains the approximately 20% voting percentage in the Partnership represented by such Energy Transfer Class A Units equivalent to such Energy Transfer Class A Unit voting interest prior to such issuance of additional common units. This provision of the Energy Transfer Class A Units shall terminate at such time as Mr. Warren ceases to be an officer or director of our general partner, provided that all Energy Transfer Class A Units outstanding at such time shall be unchanged and remain outstanding. Mr. Warren’s combined common unit and Energy Transfer Class A Unit ownership results in a voting interest in the Partnership of 27%.
(4)Includes 120,385,650 common units held by Kelcy Warren Partners, L.P. and 10,224,429 common units held by Kelcy Warren Partners II, L.P., the general partners of which are owned by Mr. Warren. Also includes 100,577,803 common units held by Kelcy Warren Partners III, LLC formerly known as Seven Bridges Holdings, LLC, of which Mr. Warren is a member. Also includes 328,383 common units attributable to the interest of Mr. Warren in ET Company Ltd and Three Dawaco, Inc., over which Mr. Warren exercises shared voting and dispositive power with Ray Davis. Also includes 601,076 common units and 833,543,364 Energy Transfer Class A Units held by LE GP, LLC. Mr. Warren may be deemed to own common units and Energy Transfer Class A Units held by LE GP, LLC due to his ownership of 81.2% of its member interests. Mr. Warren disclaims beneficial ownership of common units and Energy Transfer Class A Units owned by LE GP, LLC other than to the extent of his interest in such entity. Also includes 104,166 common units held by Mr. Warren’s spouse. Mr. Warren’s combined common unit and Energy Transfer Class A Unit ownership results in a voting interest in the Partnership of 27%.
(5)Includes 45,389 common units held by a trust for the benefit of Mr. McCrea’s son, for which Mr. McCrea serves as trustee. Mr. McCrea disclaims beneficial ownership of these units.
(6)Includes 328,617 common units held by Mr. Whitehurst in a margin account.
(7)Includes 1,544,558 common units held by Steven R. Anderson Revocable Trust, for which Mr. Anderson serves as trustee. Includes 603,100 common units pledged as collateral for a line of credit.
(8)Includes 580,000 common units held by B4 Capital Investments, LP, a limited partnership of which a limited liability company owned by Mr. Brannon and his wife is the sole general partner and of which Mr. Brannon and his wife are the sole limited partners.
(9)Includes 581,799 common units held Grimm Family Limited Partnership, a limited partnership of which a limited liability company owned by Mr. Grimm is the sole general partner.
(10)Includes 17,445,608 common units held by McReynolds Energy Partners L.P. and 12,142,593 common units held by McReynolds Equity Partners L.P., the general partners of which are owned by Mr. McReynolds. Mr. McReynolds disclaims beneficial ownership of common units owned by such limited partnerships other than to the extent of his interest in such entities.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The Partnership’s principal sources of cash flow are derived from cash flows from the operations of its subsidiaries, including its direct and indirect investments in the limited partner and general partner interests in Sunoco LP and USAC, both of which are limited partnerships engaged in energy-related services.
In making its director independence determination, the Board considered business arrangements involving a director who owns equity interest in, and is the CEO of, a company that owns working interests in oil and gas wells, and affiliates of the Partnership who made nominal payments to that company. None of the arrangements involved payments to the company of more than $1 million in any of the past three fiscal years and the Board determined that the relationship did not impact the director’s independence.
For a discussion of director independence, see “Item 10. Directors, Executive Officers and Corporate Governance.”
As a policy matter, our Conflicts Committee generally reviews any proposed related party transaction that may be material to the Partnership to determine whether the transaction is fair and reasonable to the Partnership. The Partnership’s board of directors makes the determinations as to whether there exists a related party transaction in the normal course of reviewing transactions for approval as the Partnership’s board of directors is advised by its management of the parties involved in each material transaction as to which the board of directors’ approval is sought by the Partnership’s management. In addition, the Partnership’s board of directors makes inquiries to independently ascertain whether related parties may have an interest in the proposed transaction. While there are no written policies or procedures for the board of directors to follow in making these determinations, the Partnership’s board makes those determinations in light of its contractually-limited fiduciary duties to the Unitholders. The Partnership Agreement of Energy Transfer provides that any matter approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to Energy Transfer, approved by all the partners of Energy Transfer and not a breach by the General Partner or its Board of Directors of any duties they may owe Energy Transfer or the Unitholders (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report).
Additional information on our related party transactions is included in Note 2 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following sets forth fees billed by Grant Thornton LLP for the audit of our annual financial statements and other services rendered (dollars in millions):
Years Ended December 31,
2023 2022
Audit fees (1)
$ 9.4 $ 9.2
Audit-related fees(2)
1.8 1.6
Total $ 11.2 $ 10.8
(1)Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal control over financial reporting.
(2)Includes fees for audit-related services of subsidiary entities.
Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and establish the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.
The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Grant Thornton LLP including audit services, audit-related services, tax services and other services, must be pre-approved by the Audit Committee. All fees paid or expected to be paid to Grant Thornton LLP for fiscal years 2023 and 2022 were pre-approved by the Audit Committee in accordance with this policy.
The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):
•the auditors’ internal quality-control procedures;
•any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;
•the independence of the external auditors;
•the aggregate fees billed by our external auditors for each of the previous two years; and
•the rotation of the lead partner.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following documents are filed as a part of this Report:
Page
(1) Financial Statements - see Index to Financial Statements F - 1
(2) Financial Statement Schedules - None
(3) Exhibits - see Index to Exhibits 163