ET/Filings/10-K Diff

ET 10-K diff: FY 2023-12-31 → FY 2024-12-31

Paragraph-level diff of Risk Factors (Item 1A) and Management's Discussion & Analysis (Item 7).

Item 1A · Risk Factors

+148 paragraphs −124 paragraphs ~124 changed

FY 2023-12-31 (earlier)

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;47 Table of Contents Index to Financial Statements• laws, regulations and policies governing the rates, terms and conditions of our services; • failure to recover the full amount of increases in the costs of our pipeline operations; • imposition of regulation on assets not previously subject to regulation; • costs and liabilities resulting from performance of pipeline integrity programs and related repairs; • new or more stringent pipeline safety controls or enforcement of legal requirements; • costs and liabilities associated with environmental and worker health and safety laws and regulations; • climate change legislation or regulations restricting emissions of GHGs, limiting oil and gas leases on federal lands, discouraging oil and gas development or otherwise increasing our or our customers’ costs; • increased attention to environmental, social, and governance (“ESG”) matters and conservation measures; • regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder; • deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and decommissioning plans, and related developments; and • laws and regulations governing the specifications of products that we store and transport. 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.48Table of Contents Index to Financial Statements 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.49Table of Contents Index to Financial Statements Furthermore, Unitholders should be aware that the amount of cash that our subsidiaries have available for distribution depends primarily upon cash flow and is not solely a function of profitability, which is affected by non-cash items. 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. 50Table of Contents Index to Financial StatementsAn 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 transportation51 Table of Contents Index to Financial Statementssystem. 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.52 Table of Contents Index to Financial StatementsUnder 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.53 Table of Contents Index to Financial StatementsShippers 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.54 Table of Contents Index to Financial StatementsA 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,55 Table of Contents Index to Financial Statementsincluding, 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.56 Table of Contents Index to Financial StatementsThe 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” safety57 Table of Contents Index to Financial Statementsrating; 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. 58 Table of Contents Index to Financial StatementsWe 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.59 Table of Contents Index to Financial StatementsCapital 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 60 Table of Contents Index to Financial Statements 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 fluctuate61 Table of Contents Index to Financial Statementsbased 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;62 Table of Contents Index to Financial Statements• maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and • integrating new technology systems for financial reporting. 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.63 Table of Contents Index to Financial StatementsWe 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 a64 Table of Contents Index to Financial Statementsstay 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.65 Table of Contents Index to Financial StatementsThe 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 this66 Table of Contents Index to Financial Statementsproceeding 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. Upon67 Table of Contents Index to Financial Statementsan 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.68 Table of Contents Index to Financial StatementsOur 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.69 Table of Contents Index to Financial StatementsIn 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 w astes 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 mandate70 Table of Contents Index to Financial Statementsdifficult 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 that71 Table of Contents Index to Financial Statementsaffect 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,72 Table of Contents Index to Financial Statementsreconstructed 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.73 Table of Contents Index to Financial StatementsThere 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 for74 Table of Contents Index to Financial Statementsoil 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 in75 Table of Contents Index to Financial Statementsdecisions 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 76 Table of Contents Index to Financial Statements construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.In addition, 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;77 Table of Contents Index to Financial Statements• fluctuations in our and our subsidiaries’ working capital needs; • our and our subsidiaries’ ability to borrow under our revolving credit facility; • our and our subsidiaries’ ability to access capital markets; • restrictions on distributions contained in our and our subsidiaries’ debt agreements; and • the amount of cash reserves established by our general partner in its discretion for the proper conduct of our business. 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 PartnerThe 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. 78 Table of Contents Index to Financial StatementsCost 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 79 Table of Contents Index to Financial Statements replace our general partner, to approve some amendments to our Partnership Agreement or to take other actions under the Partnership Agreement constituted “control” of our business.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 its80 Table of Contents Index to Financial Statementspartnership 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. 81 Table of Contents Index to Financial Statements 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. 82 Table of Contents Index to Financial Statements 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.83 Table of Contents Index to Financial StatementsSunoco 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 84Table of Contents Index to Financial Statementslaws 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.85Table of Contents Index to Financial Statements A significant portion of USAC’s services are provided to customers on a month-to-month basis, and USAC cannot be sure that such customers will continue to utilize its services.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.86Table of Contents Index to Financial Statements For example, conflicts of interest with Sunoco LP and USAC may arise in the following situations: • the allocation of shared overhead expenses to Sunoco LP, USAC and us;• the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Sunoco LP and USAC, on the other hand; • the determination of the amount of cash to be distributed to Sunoco LP’s and USAC’s partners and the amount of cash to be reserved for the future conduct of Sunoco LP’s and USAC’s businesses; • the determination whether to make borrowings under Sunoco LP’s and USAC’s revolving credit facilities to pay distributions to their respective partners; • the determination of whether a business opportunity (such as a commercial development opportunity or an acquisition) that we may become aware of independently of Sunoco LP and USAC is made available for Sunoco LP and USAC to pursue; and • any decision we make in the future to engage in business activities independent of Sunoco LP and USAC. 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; 87Table of Contents Index to Financial Statements• provides that unless our general partner has acted in bad faith, the action taken by our general partner shall not constitute a breach of its fiduciary duty; • provides that our general partner may resolve any conflicts of interest involving us and our general partner and its affiliates, and any resolution of a conflict of interest by our general partner that is “fair and reasonable” to us will be deemed approved by all partners, including the Unitholders, and will not constitute a breach of the Partnership Agreement; • provides that our general partner may, but is not required, in connection with its resolution of a conflict of interest, to seek “special approval” of such resolution by appointing a conflicts committee of the general partner’s board of directors composed of two or more independent directors to consider such conflicts of interest and to recommend action to the board of directors, and any resolution of the conflict of interest by the conflicts committee shall be conclusively deemed “fair and reasonable” to us; and • provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence. 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. 88Table of Contents Index to Financial Statementsfederal, 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. 89Table of Contents Index to Financial StatementsTax 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 90Table of Contents Index to Financial Statementscash 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 91Table of Contents Index to Financial Statementsour 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. 92Table of Contents Index to Financial StatementsA 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.

FY 2024-12-31 (later)

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;• general economic, financial and political conditions, including the impact of tariffs, to the extent enacted; • the imposition or increase of tariffs on steel or other raw materials, or changes in trade agreements or trade relations;• an impairment of goodwill and intangible assets; • an interruption of supply of crude oil to our facilities; • the loss of any key producers or customers; • failure to retain or replace existing customers or volumes due to declining demand or increased competition; • unfavorable changes in natural gas price spreads between two or more physical locations; • production declines over time, which we may not be able to replace with production from newly drilled wells; • competition for water resources or limitations on water usage for hydraulic fracturing; • our customers’ ability to use our pipelines and third-party pipelines over which we have no control; • the inability to access or continue to access lands owned by third parties; • the overall forward market for crude oil and other products we store; • a natural disaster, catastrophe, terrorist attack or other similar event; • extreme weather events that may be more severe or frequent than historically experienced and that may be attributable to changes in climate due to the adverse effects of an industrialized economy; • union disputes and strikes or work stoppages by unionized employees; • cybersecurity breaches and other disruptions or failures of our information systems; • failure to establish or maintain adequate corporate governance; • product liability claims and litigation, or increased insurance costs including as a result of increased risks due to the potential adverse effects of changes in climate; • actions taken by certain of our joint ventures that we do not control; • increasing levels of congestion in the Houston Ship Channel; • the costs of providing pension and other postretirement health care benefits and related funding requirements; • mergers among customers and competitors; • fraudulent activity or misuse of proprietary data involving our outsourcing partners; and • losses resulting from the use of derivative financial instruments. 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;• failure to attract and retain qualified employees; and • failure of the liquefaction project to secure long-term contractual arrangements or necessary approvals.46 Table of Contents Index to Financial StatementsRegulatory 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.47Table of Contents Index to Financial Statements 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.48Table of Contents Index to Financial Statements Furthermore, Unitholders should be aware that the amount of cash that our subsidiaries have available for distribution depends primarily upon cash flow and is not solely a function of profitability, which is affected by non-cash items. 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.General economic, financial, and political conditions, including the impact of tariffs to the extent enacted, may materially adversely affect our results of operations and financial condition. General economic, financial, and political conditions may have a material adverse effect on our results of operations and financial condition. For example, following the election of President Trump and the implementation of certain tariffs, it is possible that our operations may be affected by volatility in pricing and demand. Similarly, declines in consumer confidence and/or consumer spending, changes in unemployment, significant inflationary or deflationary changes or disruptive regulatory or geopolitical events could contribute to increased volatility and diminished expectations for the economy and our markets, including the market for our goods and services, and lead to demand or cost pressures that could negatively and adversely impact our business. These conditions could affect both of our business segments. Examples of such conditions could include: • a general or prolonged decline in, or shocks to, regional or broader macro-economies; • regulatory changes that could impact the markets in which we operate, such as immigration, tariffs or trade reform laws, which could reduce demand for or supply of our goods and services or lead to pricing, currency, or other pressures; and • deflationary economic pressures, which could hinder our ability to operate profitably in view of the challenges inherent in making corresponding deflationary adjustments to our cost structure. 49Table of Contents Index to Financial StatementsThe nature of these types of risks, which are often unpredictable, makes them difficult to plan for, or otherwise mitigate, and they are generally uninsurable—which compounds their potential impact on our business. Changes in U.S. administrative policy, including the imposition of or increases in tariffs on steel and/or other raw materials, changes to existing trade agreements and any resulting changes in international trade relations, may have an adverse effect on us. We own and operate pipelines and terminals and, like others in our industry, we use significant amounts of steel in our projects and rely on our ability to obtain that steel in an affordable way to maintain our operating margins. Any imposition of or increase in tariffs on steel and/or other raw materials could increase our growth project costs, which may impact the profitability of new projects. Recently, the Trump Administration announced plans to implement or increase tariffs, and on February 10, confirmed extension of 25 percent import tariffs on steel globally to go into effect on March 12. The ultimate impact of this tariff is unknown at this time. Additionally, ongoing changes in U.S. and foreign government trade policies, including potential modifications to existing trade agreements and further restrictions on free trade, could introduce additional uncertainty. Any escalation of trade tensions, additional tariffs, retaliatory measures by foreign governments or shifts in U.S. or international trade policies could adversely impact our supply chain and increase costs, particularly on our expansion projects. A trade war or other significant changes in trade regulations could have an adverse effect on our business and results of operations. Our business could be negatively impacted by inflationary pressures which may decrease our operating margins and increase working capital investments required to operate our business. The U.S. inflation rate steadily rose in 2021 and into 2022 before eventually declining modestly throughout 2023 and 2024. 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 reduced benchmark interest rates by 75 basis points in late 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, 2024, our consolidated balance sheet reflected $3.90 billion of goodwill and $5.97 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.50 Table of Contents Index to Financial StatementsOur 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 2024, two customers accounted for approximately 23% of our intrastate transportation and storage revenues. During 2024, four customers collectively accounted for 29% 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 57% of its 2024 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.51 Table of Contents Index to Financial StatementsWe 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 52 Table of Contents Index to Financial Statements 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 “Indigenous53 Table of Contents Index to Financial StatementsProtections.” 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 54 Table of Contents Index to Financial Statements 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, 2024, approximately 9% of our workforce is covered by a number of collective bargaining agreements with various terms and dates of expiration. There can be no assurances that we will not experience a work stoppage in the future as a result of labor disagreements. 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 and operational 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. If these third parties fail to adequately safeguard our data or their systems, or if they experience security breaches, our operations and reputation may be adversely affected. Our information and operational technology and infrastructure, physical assets and data, may be vulnerable to unauthorized access, computer viruses, malicious attacks and other events (e.g., distributed denial of service attacks, ransomware attacks) that are beyond our control. 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 globally 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. Although we have implemented and maintain commercially reasonable security measures, including detection and prevention systems, regular cybersecurity assessments, employee training programs, and an incident response plan, there is no guarantee that these measures will successfully prevent security threats, detect them in a timely manner, or mitigate their impact. 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 and operational technology infrastructure or physical assets, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, data loss or corruption, misdirected wire transfers, an inability to maintain our books and records or an inability to prevent environmental damage, any or all of which could, in turn, have a material adverse effect on our operations, financial position and results of operations. 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 or55 Table of Contents Index to Financial Statementsproceedings, 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 and regulations and to modify and enhance our information and operational 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 insurance may not compensate us adequately for losses that may occur. Prolonged outages or disruptions in our information technology infrastructure could impair our ability to deliver services, meet customer expectations or comply with regulatory requirements.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 our56 Table of Contents Index to Financial Statementsexposure 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 America, 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.57 Table of Contents Index to Financial StatementsIndebtedness 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, 2024, we had approximately $59.76 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.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.58 Table of Contents Index to Financial StatementsIncreases 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 $4.33 billion of our consolidated debt as of December 31, 2024 bears interest at variable interest rates and the remainder bears interest at fixed rates. To the extent that we have debt with floating interest rates, our results of operations, cash flows and financial condition could be materially adversely affected by increases in interest rates.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.59 Table of Contents Index to Financial StatementsFurthermore, 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, increased to $1,200 in 2025, and will be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022. 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. We cannot predict if Congress may take action to repeal or revise the IRA 2022, including with respect to the methane emissions charge. Thus, at this time, it is currently uncertain which programs will be affected and what impact such changes may have.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;60 Table of Contents Index to Financial Statements• we are unable to raise financing for our identified pipeline construction opportunities; or • we are unable to secure sufficient transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons. 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.61 Table of Contents Index to Financial StatementsThe 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 stated that these studies would take several months to complete, after which they would be made available for public comment. This process was not completed prior to the U.S. Presidential election in November 2024. On July 1, 2024, the federal court for the Western District of Louisiana ordered that the DOE was enjoined and restrained from halting or pausing the approval process for pending and future applications for LNG exports to non-FTA countries. On December 17, 2024, the DOE released an updated study of U.S. LNG exports with a 60-day comment period that was later extended to March 20, 2025. On January 20, 2025, President Trump issued the Unleashing American Energy executive order directing the DOE Secretary to restart reviews of applications for approvals of LNG export projects as expeditiously as possible, consistent with applicable law. The executive order stated that in assessing the “public interest” to be advanced by any particular application, the DOE Secretary shall consider the economic and employment impacts to the United States and the impact to the security of allies and partners that would result from granting the application. On January 21, 2025, the DOE announced that it was ending the moratorium imposed by the Biden Administration on the approvals of LNG export authorizations by the DOE and returning to regular order following direction given by President Trump in the Unleashing American Energy executive order. At this time, it is unclear what actions the Trump Administration may take, if any at all, with respect to the DOE study. Additionally, while President Trump’s executive order resumes permitting applications, 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.62 Table of Contents Index to Financial StatementsAlso, 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.63 Table of Contents Index to Financial StatementsRegulatory 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 2024, the DOI finalized 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 March 2024, the Bureau of Land Management (“BLM”) finalized a rule that requires operators to 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. The rule was challenged by various states in the District Court for the District of North Dakota and, in September 2024, the court ordered that the rule cannot be enforced against the plaintiff states pending the outcome of the litigation. Although the rule is currently being implemented against leases not covered by the order, the future of the rule is uncertain. In addition, the Colorado Energy and Carbon Management Commission (formerly the Colorado Oil and Gas Conservation Commission) adopted new rules to cover a variety of matters related to public health, safety, welfare, wildlife, and environmental resources, and has issued new rules regarding the cumulative impacts of oil and gas projects; most significantly, these rule changes establish more stringent setbacks (2,000-foot, instead of the prior 500-foot) on new oil and gas development and eliminate routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions. 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 2664 Table of Contents Index to Financial Statementsorder, 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 will be issued in December 2025 and a Record of Decision will be issued in early 2026. For further information, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this annual report.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 tariff 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 pipeline companies, including Panhandle. If the FERC were to initiate additional proceedings against us and find that our rates were not just and reasonable or were unduly discriminatory, the maximum rates we are permitted to charge may be reduced and the reduction could have an adverse effect on our revenues and results of operations.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 a65 Table of Contents Index to Financial Statementsremand 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 Natural Gas Act to determine whether the rates charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the Natural Gas Act. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021, and on December 16, 2022, the FERC issued its order on the initial decision. On January 17, 2023, Panhandle and the Michigan Public Service Commission each filed a request for rehearing of FERC’s order on the initial decision, which were denied by operation of law as of February 17, 2023. On March 23, 2023, Panhandle appealed these orders to the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”), and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the Court of Appeals consolidated Panhandle’s and Michigan Public Service Commission’s appeals and stayed the consolidated appeal proceeding while the FERC further considered the requests for rehearing of its December 16, 2022 order. On September 25, 2023, the FERC issued its order addressing arguments raised on rehearing and compliance, which denied our requests for rehearing. Panhandle filed its Petition for Review with the Court of Appeals regarding the September 25, 2023 order. On October 25, 2023, Panhandle filed a limited request for rehearing of the September 25 order addressing arguments raised on rehearing and compliance, which was subsequently denied by operation of law on November 27, 2023. On November 17, 2023, Panhandle provided refunds to shippers and on November 30, 2023, Panhandle submitted a refund report regarding the consolidated rate proceedings, which was protested by several parties. On January 5, 2024, the FERC issued a second order addressing arguments raised on rehearing in which it modified certain discussion from its September 25, 2023 order and sustained its prior conclusions. Panhandle has timely filed its Petition for Review with the Court of Appeals regarding the January 5, 2024 order. On May 28, 2024, the FERC issued an order rejecting Panhandle’s refund report. On June 27, 2024, Panhandle filed a revised refund report in compliance with the FERC’s May 28, 2024 order rejecting Panhandle’s refund report and a request for rehearing of the FERC’s May 28, 2024 order rejecting Panhandle’s refund report, and provided revised refunds to shippers, or in the case of shippers whose revised refunds are less than the original amounts refunded, notices of upcoming debits. One party protested Panhandle’s revised refund report, and Panhandle submitted a response to the protest on July 24, 2024. By notice issued July 29, 2024, Panhandle’s rehearing request was deemed denied. In an ordered issued September 9, 2024, FERC addressed arguments raised on rehearing, modified the discussion in the May 28, 2024 order and continued to reach the same result. On September 18, 2024, Panhandle petitioned the Court of Appeals for review of the September 9, 2024, July 29, 2024, and May 28, 2024 orders. On December 5, 2024, the FERC issued an order rejecting Panhandle’s June 27, 2024, refund report, ordering a corrected refund report and directing the issuance of additional refunds. On January 3, 2025, Panhandle submitted an adjusted refund report as well as a request for rehearing of the FERC’s December 5, 2024 order. The FERC approved the adjusted refund report by letter order dated January 23, 2025. On February 3, 2025, the66 Table of Contents Index to Financial StatementsFERC issued a Notice of Denial of Rehearing by Operation of Law and Providing for Further Consideration. The request for rehearing will be addressed in a future order. On 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.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 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 (“2022 Certificate Policy Statement”) and (2) a Policy Statement on the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (“GHG Policy Statement), to be effective that same day. On March 24, 2022, the FERC issued an order designating the 2022 Certificate Policy Statement and the GHG Policy Statement as draft policy statements, and requested further comments. The FERC stated that it will not apply the now draft policy statements to pending applications or applications to be filed at FERC until it issues any final guidance on these topics. Comments on the 2022 Certificate Policy Statement and the GHG Policy Statement were due on April 25, 2022, and reply comments were due on May 25, 2022. On January 24, 2025, the FERC issued an order withdrawing the draft GHG Policy Statement and terminating the proceeding. The FERC has taken no further action on the 2022 Certificate Policy Statement. We are unable to predict what, if any, changes may be proposed as a result of the 2022 Certificate Policy Statement that might affect our natural gas pipeline or LNG facility projects, or when such new policy, if any, might become effective. We do not expect that any change in this policy statement would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.Rate regulation or market conditions may not allow us to recover the full amount of increases in the costs of our crude oil, NGL and refined products pipeline operations.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, upon67 Table of Contents Index to Financial Statementscompletion 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. On July 26, 2024, the D.C. Circuit ruled in LEPA v. FERC that FERC violated the Administrative Procedure Act because the January 20 order modified the index without following notice and comment. As a result, the D.C. Circuit vacated the January 20 order and on September 17, 2024, the Commission reinstated the index level established by its original December 17 order, directed pipelines to file an informational filing to show their recomputed ceiling levels reflecting the reinstated index level and stated that pipelines may file to prospectively increase their indexed rates to their recomputed levels. On October 17, 2024, FERC issued a Supplemental NOPR that proposes a reduction to the currently effective index by one percent. The Supplemental NOPR, which remains pending before FERC, could result in the reimplementation through a notice-and-comment rulemaking of the same rulings that were vacated by the D.C. Circuit in LEPA v. FERC . Under the EPAct of 1992, 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 EPAct of 1992, 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.68 Table of Contents Index to Financial StatementsState 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 that are determined to be in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval. 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 ICA and the EPAct of 1992. 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.69 Table of Contents Index to Financial StatementsWe 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. PHMSA is required to adjust the maximum penalties it may impose for violations for inflation; these maximum civil penalties were most recently increased in December 2023 to $266,015 per violation per day, with a maximum of $2,660,135 for a related series of violations. Upon reauthorization of PHMSA, Congress directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemaking, To that end, PHMSA issued the three final rules discussed above, significantly expanding reporting and safety requirements of operators of gas gathering pipelines, imposing safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators, and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. The 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.70 Table of Contents Index to Financial StatementsOur business involves the generation, handling and disposal of hazardous substances, hydrocarbons and w astes 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.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, several groups filed litigation over the December 2020 decision, and the Biden Administration announced plans to formally review this decision. In August 2023, the EPA announced a new review of the ozone NAAQS to reflect updated ozone science in combination with the reconsideration of the December 2020 decision. However, the review remains ongoing and is not expected to be completed before the EPA’s five-year cycle for NAAQS review in December 2025. At this time, it is not clear what actions the Trump Administration may take with respect to the review. However, 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 the71 Table of Contents Index to Financial Statementsmore 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, the OPA, and state laws impose regulatory burdens on terminal operations. Spill prevention control and countermeasure requirements of federal and state laws require containment to mitigate or prevent contamination of waters in the event of a refined product overflow, rupture, or leak from above-ground pipelines and storage tanks. 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 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. 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, increased to $1,200 in 2025, and will be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022. We cannot predict if Congress may take actions to repeal or revise the IRA 2022, including with respect to the methane emissions charge. Additionally, the EPA has adopted rules under authority of the Clean Air Act that, among other things, establish 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 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, in72 Table of Contents Index to Financial StatementsDecember 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. However, the EPA’s final rule is currently being challenged by 23 states and a coalition of industry groups in the U.S. Circuit Court of Appeals for the D.C. Circuit. 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. However, in January 2025, President Trump signed an executive order once again withdrawing the United States from the Paris Agreement and from any other commitments made under the United Nations Framework Convention on Climate Change. Additionally, President Trump revoked any purported financial commitments made by the United States pursuant to the same. The full impact of these recent developments is uncertain at this timeThe 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. 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 2024 the SEC released a final rule requiring climate disclosures. However, the future of the rule is uncertain at this time given that its implementation has been stayed pending the outcome of legal challenges. Moreover, the SEC may, under the current administration, seek to change or revoke the rule, though we cannot predict whether such action will occur or its timing. 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 term73 Table of Contents Index to Financial Statements“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 from investors, customers, employees, regulatory bodies and other stakeholders 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, heightened scrutiny of our statements and initiatives, 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, assumptions and hypothetical scenarios. Such expectations, assumptions and hypothetical scenarios 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 have or may announce various voluntary ESG targets in the future, such targets are often 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 we meet such targets, it may be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our ESG impact instead of actual changes in our business operations. Some of these arrangements may receive scrutiny from certain constituencies. Also, despite any aspirational goals, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles. Certain statements or initiatives with respect to ESG matters that we may pursue or assert are increasingly subject to heightened scrutiny from the public and governmental authorities, as well as other parties. For example, the SEC has recently taken enforcement action against companies for ESG-related misconduct, including alleged “greenwashing,” (i.e., the process of conveying misleading information or making false claims that overstate potential ESG benefits). Certain regulators, such as the SEC and various state agencies, as well as nongovernmental organizations and other private actors have filed lawsuits under various securities and consumer protection laws alleging that certain ESG statements, goals or standards were misleading, false or otherwise deceptive. Certain employment practices and social initiatives are the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve. More recent political74 Table of Contents Index to Financial Statementsdevelopments could mean that the Partnership faces increasing criticism or litigation risks from certain “anti-ESG” parties, including various governmental agencies. Such sentiment may focus on the Partnership’s environmental commitments (such as reducing GHG emissions) or its pursuit of certain employment practices or social initiatives that are alleged to be political or polarizing in nature or are alleged to violate laws based, in part, on changing priorities of, or interpretations by, federal agencies or state governments. Consideration of ESG-related factors in the Partnership’s decision-making could be subject to increasing scrutiny and objection from such anti-ESG parties. We cannot be certain of the impact of such regulatory, legal and other developments on our business. As a result, the Partnership may be subject to pressure in the media or through other means, such as governmental investigations, enforcement actions, or other proceedings, all of which could adversely affect our reputation, business, financial performance, market access and growth. Accordingly, there may be increased costs related to reviewing, implementing and managing such policies, as well as compliance and litigation risks based both on positions we do or do not take, or work we do or do not perform. 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. While such ratings do not impact all investors’ investment or voting decisions, 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-related 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. 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 2024, BOEM issued a final rule which significantly increases the amount of new supplemental financial assurance required for offshore oil and gas lessees and other operators. The final rule, which became effective in June 2024, adopts a three-year phased compliance period for full payment of a supplemental financial assurance demand. BOEM anticipates it will take up to 24 months to complete the processing of75 Table of Contents Index to Financial Statementsfinancial assurance demands for execution. Rules such as this, as well as any new rules, regulations, or legal initiatives, could delay or disrupt our customers’ operations, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding and costs, limit activities in certain areas, or cause our customers’ to incur penalties, or shut-in production or lease cancellation. 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. In September 2023, the DOI published a proposed final offshore leasing program for 2024 – 2029, which was then approved by the Secretary of the Interior and authorized three Gulf of America leasing sales. 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 2024, the DOI finalized a rule to modernize the fiscal terms of the leasing program, increase costs associated with such leases and add new criteria for the DOI to consider when deciding whether to lease nominated lands. 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;76 Table of Contents Index to Financial Statements• the relative voting strength of each previously outstanding Common Unit and/or Preferred Unit may be diminished; and • the market price of our Common Units and/or Preferred Units may decline. 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.77 Table of Contents Index to Financial StatementsUnitholders 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 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 PartnerThe 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, 2024, the Partnership had outstanding 847,443,096 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 7, 2025, Mr. Warren’s combined common unit and Energy Transfer Class A Unit ownership 78 Table of Contents Index to Financial Statements results in a voting interest in the Partnership of 25%. 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, 2024, the directors and executive officers of our general partner owned approximately 7% 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.79 Table of Contents Index to Financial StatementsThe 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, crude oil or refined products, including increased consumer preference for alternative motor fuels, improvements in fuel efficiency or a material shift toward electric or other alternative-power vehicles, in the areas Sunoco LP serves would reduce their ability to make distributions to its unitholders. For the year ended December 31, 2024, sales of refined motor fuels accounted for approximately 95% of Sunoco LP’s total revenues and 47% of gross profit. A significant decrease in demand for motor fuel in the areas Sunoco LP serves could significantly reduce revenues and Sunoco LP’s ability to make distributions to its unitholders, including Energy Transfer. 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.80 Table of Contents Index to Financial StatementsAny 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 March 2024, the EPA finalized new emissions standards for light and medium-duty vehicles, including passenger cars, vans, pickups, sedans and sport utility vehicles for model years 2027 through 2032 and beyond. The final rule sets new, strict standards intended to reduce air pollutant emissions, including greenhouse gas emissions; however, the new standards are now subject to legal challenge. Moreover, it remains uncertain what actions, if any, the Trump Administration may take to repeal or otherwise modify this rule. Additionally, laws such as the Bipartisan Infrastructure Act and the IRA 2022 allocate funds to the development of electric vehicle infrastructure and provide incentives for consumers and manufacturers related to their use or development of electric vehicles, and the adoption rate of electric vehicles in the U.S. has continued to accelerate, with projections for the future rate of adoption in some reports more than doubling in recent years. However, in January 2025, President Trump signed an Executive Order, Unleashing American Energy , which directs all agencies to immediately pause the disbursement of funds appropriated through the IRA 2022 or the Infrastructure Investment and Jobs Act, including funds for electric vehicle charging stations made available through the National Electric Vehicle Infrastructure Formula Program and the Charging and Fueling Infrastructure Discretionary Grant Program, though this pause is generally currently subject to legal challenge. While the Trump Administration may ultimately take steps to reduce or eliminate incentives for zero-emission vehicles, at this time Sunoco LP cannot predict what actions the new administration may take or the timing of such actions. Any of these or similar actions could result in fewer visits to Sunoco LP’s convenience stores or independently operated commission agents and dealer locations, a reduction in demand from Sunoco LP’s wholesale customers, decreases in both fuel and merchandise sales revenue, or reduced profit margins, any of which could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to our unitholders. • a recession, high interest rates, inflation or other adverse economic conditions that result in lower spending by consumers on gasoline, diesel and travel; • events that negatively impact global economic activity, travel and demand generally; • higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline; • an increase in aggregate automotive engine fuel economy; • new government and regulatory actions or court decisions requiring the phase out or reduced use of gasoline-fueled vehicles; • the increased use of and public demand for use of alternative fuel sources or electric vehicles; • an increase in the market price of crude oil that increases refined product prices, which may reduce demand for refined products and increase demand for alternative products; and • adverse weather events resulting in decreased corn acres planted, which may reduce demand for anhydrous ammonia.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. 81 Table of Contents Index to Financial Statements 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, crude oil, refined petroleum products and anhydrous ammonia could cause disruptions in Sunoco LP’s operations and could expose them to potentially significant losses, costs or liabilities. Sunoco LP’s operations are subject to significant hazards and risks inherent in transporting and storing motor fuel, crude oil, refined petroleum products and anhydrous ammonia. 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. Additionally, Sunoco LP’s pipelines, terminals and storage assets are generally long-lived assets, and some have been in service for many years. The age and condition of Sunoco LP’s assets could result in increased maintenance or repair expenditures in the future. If any of Sunoco LP’s facilities, or those of its customers or suppliers, suffer significant damage or are forced to shut down for a significant period of time, it may have a material adverse effect on Sunoco LP’s results of operations and financial condition as a whole. Sunoco LP’s pipelines and fuel storage terminals are subject to operational and business risks which may adversely affect its financial condition, results of operations, cash flows and ability to make distributions to its unitholders. Sunoco LP’s pipelines and fuel storage terminals are subject to operational and business risks, the most significant of which include the following: • the inability to renew a ground lease for certain of its pipelines or fuel storage terminals on similar terms or at all; • the dependence on third parties to supply its fuel storage terminals; • outages at its pipelines or fuel storage terminals or interrupted operations due to weather-related or other natural causes;• the threat that the nation’s terminal infrastructure may be a future target of terrorist organizations;• the volatility in the prices of the products transported on its pipelines or stored at its fuel storage terminals and the resulting fluctuations in demand for storage services;• the effects of a sustained recession or other adverse economic conditions;• the possibility of federal and/or state regulations that may discourage its customers from transporting or storing gasoline, diesel fuel, ethanol and jet fuel at its fuel storage terminals or reduce the demand by consumers for petroleum products; • competition from other pipelines and fuel storage terminals that are able to provide its customers with comparable transportation service or storage capacity at lower prices; and • climate change legislation or regulations that restrict emissions of GHGs could result in increased operating and capital costs and reduced demand for its transportation and storage services.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. 82 Table of Contents Index to Financial Statements 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 competes with other midstream service providers, including certain major energy and chemical companies, that possess, or have greater financial resources to acquire, assets better suited to meet customer demand, which could undermine Sunoco LP’s ability to obtain and retain customers or reduce utilization of its assets, which could adversely affect its revenues and cash flows, thereby reducing Sunoco LP’s ability to make its quarterly distributions to unitholders. Sunoco LP faces competition in all aspects of its business and can give no assurances that it will be able to compete effectively against its competitors. Sunoco LP’s competitors include major energy and chemical companies, some of which have greater financial resources, more pipelines or storage terminals, greater capacity pipelines or storage terminals and greater access to supply than does Sunoco LP. Certain of Sunoco LP’s competitors also have advantages in competing for acquisitions or other new business opportunities because of their financial resources and synergies in operations. As a consequence of increased competition in the industry or market conditions, some customers are and others may be in the future reluctant to renew or enter into long-term contracts or contracts that provide for minimum throughput amounts. Sunoco LP’s inability to renew or replace a significant portion of its current contracts as they expire, to enter into contracts for newly acquired, constructed or expanded assets and to respond appropriately to changing market conditions would have a negative effect on Sunoco LP’s revenue, cash flows and ability to make quarterly distributions to its unitholders.83 Table of Contents Index to Financial StatementsSunoco 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 38% of Sunoco LP, commission agent or dealer operated retail service stations where Sunoco LP currently controls the real estate. Sunoco LP also has rental agreements for certain logistics facilities. 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. Like other pipeline and storage logistics services providers, certain of Sunoco LP’s pipelines, storage terminals and other facilities are located on land owned by third parties and governmental agencies that Sunoco LP has obtained the right to utilize for these purposes through contract (rather than through outright purchase). Many of Sunoco LP’s rights-of-way or other property rights are perpetual in duration, but others are for a specific period of time. In addition, some of Sunoco LP’s facilities are located on leased premises. A potential loss of property rights through Sunoco LP’s inability to renew right-of-way contracts or leases or otherwise retain property rights on acceptable terms or the increased costs to renew such rights could adversely affect its financial condition, results of operations and cash flows available for distribution to its unitholders.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 June 2023, the EPA released a final rule under the RFS for renewable fuel volumes for the years 2023-2025 that further increases targets for the production of renewable fuels. 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.84 Table of Contents Index to Financial StatementsSunoco 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. Integration of assets and businesses acquired by Sunoco LP in past acquisitions or future acquisitions with its existing business will be a complex, time-consuming and costly process, particularly given that assets acquired to date significantly increased Sunoco LP’s size and diversified the geographic areas in which it operates. A failure to successfully integrate the acquired assets or businesses, such as NuStar, with Sunoco LP’s existing business in a timely manner may have a material adverse effect on its business, financial condition, results of operations or cash available for distribution to its unitholders. The difficulties of integrating past and future acquisitions with Sunoco LP’s business includes, 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 Sunoco LP’s 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 Sunoco LP’s existing business; • assimilation of acquired assets and operations, including additional regulatory programs, operational philosophies and complex systems; • loss of customers, suppliers 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; • integrating new technology systems for financial reporting; and • assuming contractual obligations of acquired businesses, potential unknown liabilities and unforeseeable increased expenses as a result of such acquisitions. If any of these risks or other unanticipated liabilities or costs were to materialize, then desired benefits from past acquisitions and future acquisitions could result in a negative impact to Sunoco LP’s future results of operations. In addition, acquired assets may perform at levels below the forecasts used to evaluate them, due to factors beyond Sunoco LP’s control. If the acquired assets perform at levels below the forecasts, then Sunoco LP’s future results of operations could be negatively impacted. 85Table of Contents Index to Financial StatementsAlso, Sunoco LP’s 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, such as groundwater contamination, may not be observable even when an inspection is undertaken. For example, Sunoco LP’s acquisition of NuStar involved the combination of two master limited partnerships that operated as independent public partnerships until May 3, 2024. The combination of two independent businesses is complex, costly and time consuming, and Sunoco LP will be required to continue to devote significant management attention and resources to integrating the business practices and operations of NuStar into Sunoco LP to achieve, among other things, the targeted cost synergies associated with the acquisition. To the extent Sunoco LP is unable to successfully integrate its business and operations of NuStar into Sunoco LP, its business, results of operations and its ability to achieve the anticipated benefits of the acquisition may be adversely affected. Sunoco LP could be subject to liabilities from its assets that predate the acquisition of those assets, but that are not covered by indemnification rights Sunoco LP has against the sellers of the assets. Sunoco LP has acquired assets and businesses and it is not always indemnified by the seller for liabilities that precede its ownership. In addition, in some cases, Sunoco LP has indemnified the previous owners and operators of acquired assets or businesses. Some of Sunoco LP’s assets have been used for many years to transport and store crude oil and refined products, and past releases could require costly future remediation. If a significant release or event occurred in the past, the liability for which was not retained by the seller, or for which indemnification by the seller is not available, it could adversely affect Sunoco LP’s financial position and results of operations. Conversely, if liabilities arise from assets Sunoco LP has sold, it could incur costs related to those liabilities if the buyer possesses valid indemnification rights against Sunoco LP with respect to those assets. Sunoco LP operates assets outside of the United States, which exposes it to different legal and regulatory requirements and additional risk. A portion of Sunoco LP’s revenues are generated from its assets located in northern Mexico and Europe. Sunoco LP’s operations are subject to various risks that could have a material adverse effect on its business, results of operations and financial condition, including political and economic instability from civil unrest; labor strikes; war and other armed conflict; inflation; currency fluctuations, devaluation and conversion restrictions or other factors. Any deterioration of social, political, labor or economic conditions, including the increasing threat of terrorist organizations and drug cartels in Mexico, or affecting a customer with whom Sunoco LP does business, as well as difficulties in staffing, obtaining necessary equipment and supplies and managing foreign operations, may adversely affect Sunoco LP’s operations or financial results. Sunoco LP is also exposed to the risk of foreign and domestic governmental actions that may: impose additional costs on Sunoco LP; delay permits or otherwise impede Sunoco LP’s operations; limit or disrupt markets for Sunoco LP’s operations, restrict payments or limit the movement of funds; impose sanctions on or otherwise restrict Sunoco LP’s ability to conduct business with certain customers or persons or in certain countries; or result in the deprivation of contract rights. Sunoco LP’s operations outside the United States may also be affected by changes in trade protection laws, policies and measures, and other regulatory requirements affecting trade and investment, including the Foreign Corrupt Practices Act and foreign laws prohibiting corrupt payments, as well as travel restrictions and import and export regulations.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.86Table of Contents Index to Financial Statements A significant portion of USAC’s services are provided to customers on a month-to-month basis, and USAC cannot be sure that such customers will continue to utilize its services.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, 2024, approximately 14% of USAC’s compression services on a revenue basis were provided on a month-to-month basis to customers who continue to utilize its services following expiration of the primary term of their contracts. These customers can generally terminate their month-to-month compression services contracts on 30-days’ written notice. 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.87Table of Contents Index to Financial Statements For example, conflicts of interest with Sunoco LP and USAC may arise in the following situations: • the allocation of shared overhead expenses to Sunoco LP, USAC and us;• the management of the ET-S Permian joint venture;• the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Sunoco LP and USAC, on the other hand; • the determination of the amount of cash to be distributed to Sunoco LP’s and USAC’s partners and the amount of cash to be reserved for the future conduct of Sunoco LP’s and USAC’s businesses; • the determination whether to make borrowings under Sunoco LP’s and USAC’s revolving credit facilities to pay distributions to their respective partners; • the determination of whether a business opportunity (such as a commercial development opportunity or an acquisition) that we may become aware of independently of Sunoco LP and USAC is made available for Sunoco LP and USAC to pursue; and • any decision we make in the future to engage in business activities independent of Sunoco LP and USAC. 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 88Table of Contents Index to Financial Statementstotality 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 89Table of Contents Index to Financial Statementsfor 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.90Table of Contents Index to Financial StatementsUnitholders 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.91Table of Contents Index to Financial StatementsWe 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.92Table of Contents Index to Financial StatementsWe 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 before December 31, 2025, the Treasury Regulations provide that income attributable to a guaranteed payment for the use of capital is not eligible for the 20% deduction for qualified business income. 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. 93Table of Contents Index to Financial StatementsWith 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.

Item 7 · Management's Discussion & Analysis

+386 paragraphs −390 paragraphs ~386 changed

FY 2023-12-31 (earlier)

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.100 Table of Contents Index to Financial StatementsOVERVIEW 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 DevelopmentsCrestwood 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. 101Table of Contents Index to Financial StatementsIn 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 102Table of Contents Index to Financial Statementsof 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 CertificationThe 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 103Table of Contents Index to Financial Statementsindexing 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 StandardsThe 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. 104Table of Contents Index to Financial StatementsUltimately, 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. 105Table of Contents Index to Financial StatementsYear Ended December 31, 2023 Compared to the Year Ended December 31, 2022Consolidated Results Years Ended December 31,2023 2022 ChangeSegment 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 $ 605Years Ended December 31,2023 2022 ChangeReconciliation 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.” 106Table of Contents Index to Financial StatementsDepreciation, 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 $5 million, which increased net income.Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below.Non-Operating Litigation-Related Loss. Non-operating litigation-related loss recognized for the year ended December 31, 2023 represents the loss associated with the Williams Litigation, which is discussed in Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” Other, net. Other, net primarily includes amortization of regulatory assets and other income and expense amounts. 107Table of Contents Index to Financial StatementsSupplemental Information on Unconsolidated Affiliates The following table presents financial information related to unconsolidated affiliates: Years Ended December 31,2023 2022 Change Equity in earnings (losses) of unconsolidated affiliates:Citrus$ 146 $ 141 $ 5MEP87 10 77 White Cliffs (1) 10 (8) 18 Explorer 37 25 12Other103 89 14Total equity in earnings of unconsolidated affiliates$ 383 $ 257 $ 126 Adjusted EBITDA related to unconsolidated affiliates (2) :Citrus$ 335 $ 326 $ 9MEP121 45 76White Cliffs29 20 9 Explorer 57 41 16Other149 133 16Total Adjusted EBITDA related to unconsolidated affiliates$ 691 $ 565 $ 126Distributions 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. 108Table of Contents Index to Financial Statements• 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 ChangeNatural 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 margin1,346 1,818 (472) Unrealized (gains) losses on commodity risk management activities 66 (67) 133Operating expenses, excluding non-cash compensation expense(279) (334) 55Selling, general and administrative expenses, excluding non-cash compensation expense(51) (53) 2Adjusted EBITDA related to unconsolidated affiliates25 26 (1)Other4 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. 109Table of Contents Index to Financial Statements Segment Margin . The components of our intrastate transportation and storage segment margin were as follows: Years Ended December 31,2023 2022 ChangeTransportation fees$ 852 $ 828 $ 24Natural 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; 110Table of Contents Index to Financial Statements• 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 $223 million due to newly acquired assets as well as higher volumes across all regions. 111Table of Contents Index to Financial Statements NGL and Refined Products Transportation and Services Years Ended December 31,2023 2022 ChangeNGL transportation volumes (MBbls/d)2,116 1,882 234Refined products transportation volumes (MBbls/d)540 521 19NGL and refined products terminal volumes (MBbls/d)1,430 1,274 156NGL fractionation volumes (MBbls/d)1,023 911 112Revenues$ 21,903 $ 25,657 $ (3,754)Cost of products sold17,049 21,656 (4,607)Segment margin4,854 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 — 1Segment Adjusted EBITDA$ 3,894 $ 3,025 $ 869 Volumes. For the year ended December 31, 2023 compared to the prior year, NGL transportation volumes increased p rimarily due to higher volumes from the Permian region, on our Mariner East pipeline system and on our Gulf Coast export pipelines. 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 112Table of Contents Index to Financial Statementsloaded 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 $6 million increase in insurance costs.Crude Oil Transportation and Services Years Ended December 31,2023 2022 Change Crude oil transportation volumes (MBbls/d) 5,282 4,345 937 Crude oil terminals volumes (MBbls/d) 3,377 2,964 413Revenue$ 26,536 $ 25,982 $ 554Cost of products sold23,071 22,917 154Segment margin3,465 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 113Table of Contents Index to Financial Statements• an increase of $54 million in operating expenses primarily due to a $66 million increase from recently acquired assets, a $13 million increase in volume-driven expenses and an $8 million increase in employee-related expenses, partially offset by a $4 million decrease in measurement expenses, a $5 million decrease in ad valorem taxes and a $20 million decrease in maintenance project expenses.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 $ 45The 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 $ 86The 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 114Table of Contents Index to Financial Statements• an increase of $24 million in operating expenses primarily due to higher employee costs associated with increased revenue-generating horsepower as well as higher parts and service costs.All Other Years Ended December 31,2023 2022 ChangeRevenue$ 1,798 $ 3,574 $ (1,776)Cost of products sold1,740 3,328 (1,588)Segment margin58 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 22Segment 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.”115Table of Contents Index to Financial StatementsWe 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 MaintenanceLow High Low High Intrastate transportation and storage $ 115 $ 125 $ 50 $ 55 Interstate transportation and storage 45 55 190 195 Midstream 590 645 220 225NGL and refined products transportation and services (1)1,400 1,500 135 140Crude oil transportation and services (1)195 215 175 180 All other (including eliminations) 55 60 65 70Total 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 ActivitiesChanges 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 116Table of Contents Index to Financial StatementsEnergy 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, 2023Cash 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, 2023Cash 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. 117Table of Contents Index to Financial Statements The following is a summary of the Partnership’s capital expenditures (including only our proportionate share of the Bakken, Rover, Bayou Bridge and Orbit Gulf Coast NGL Exports joint ventures, net of contributions in aid of construction costs) by period: Capital Expenditures Recorded During Period Growth Maintenance TotalYear 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 $ 2,868Year 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 $ 3,026Financing 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, 2023Cash 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. 118Table of Contents Index to Financial Statements Description of Indebtedness Our outstanding consolidated indebtedness was as follows: December 31,2023 2022Energy Transfer Indebtedness:Notes and Debentures (1)(2) $ 43,016 $ 39,468Five-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 TransactionsIn 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 119Table of Contents Index to Financial Statementsto 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 FacilityThe 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 FacilityAs 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 FacilityAs 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 AgreementsThe 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;120 Table of Contents Index to Financial Statements• make Distributions (as defined in the Five-Year Credit Facility) during certain Defaults (as defined in the Five-Year Credit Facility) and during any Event of Default (as defined in the Five-Year Credit Facility); • engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries; • engage in transactions with affiliates; and • enter into restrictive agreements. The 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.121 Table of Contents Index to Financial StatementsCompliance with our CovenantsWe 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 RateDecember 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 0.3050March 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 0.3150The 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 122Table of Contents Index to Financial StatementsEnergy 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 IMarch 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 DistributionsEnergy 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%123 Table of Contents Index to Financial StatementsDistributions 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 0.8420The total amount of distributions to the Partnership from Sunoco LP for the periods presented below is as follows: Years Ended December 31,2023 2022Distributions from Sunoco LP Limited Partner interests$ 96 $ 94General Partner interest and IDRs77 72Total distributions from Sunoco LP$ 173 $ 166USAC Cash DistributionsEnergy 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 124Table of Contents Index to Financial StatementsThe total amount of distributions to the Partnership from USAC for the periods presented below is as follows: Years Ended December 31,2023 2022Distributions 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. 125Table of Contents Index to Financial StatementsThe 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 126Table of Contents Index to Financial Statementsassets, 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 127Table of Contents Index to Financial Statementstotaling $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;128 Table of Contents Index to Financial Statements • governmental regulation and taxation;• changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines; • hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs; • competition from other midstream companies and interstate pipeline companies; • loss of key personnel; • loss of key natural gas producers or the providers of fractionation services; • reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries pipelines and facilities; • the effectiveness of risk-management policies and procedures and the ability of our subsidiaries liquids marketing counterparties to satisfy their financial commitments; • the nonpayment or nonperformance by our subsidiaries’ customers; • risks related to the development of new infrastructure projects or other growth projects, including failure to make sufficient progress to justify continued development, delays in obtaining customers, increased costs of financing and regulatory, environmental, political and legal uncertainties that may affect the timing and cost of these projects; • risks associated with the construction of new pipelines, treating and processing facilities or other facilities, or additions to our subsidiaries’ existing pipelines and their facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors; • the availability and cost of capital and our subsidiaries’ ability to access certain capital sources; • a deterioration of the credit and capital markets; • risks associated with the assets and operations of entities in which our subsidiaries own a noncontrolling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence; • the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses; • changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; • the costs and effects of legal and administrative proceedings; and• risks associated with a potential failure to successfully combine our business with that of Crestwood.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.

FY 2024-12-31 (later)

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, 2024 and 2023 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 risks and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” of this report. Discussion and analysis of matters pertaining to the year ended December 31, 2022 and year-to-year comparisons between the years ended December 31, 2023 and 2022 are not included in this Form 10-K, but can be found under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2023 that was filed with the SEC on February 16, 2024.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 services and acquisition and marketing activities, as well as NGL storage and fractionation services and LNG regasification.In addition, we own investments in other businesses, including Sunoco LP and USAC, both of which are master limited partnerships.101 Table of Contents Index to Financial Statements Energy Transfer derives cash flows from distributions related to its investment in its subsidiaries, including Sunoco LP and USAC. The amount of cash that our subsidiaries distribute to us is based on earnings from their respective business activities and the amount of available cash. Energy Transfer’s primary cash requirements are for distributions to its partners, capital expenditures, general and administrative expenses and debt service requirements. 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 DevelopmentsWTG Midstream Acquisition On July 15, 2024, Energy Transfer completed the acquisition of 100% of the membership interest in WTG Midstream. Consideration for the transaction was comprised of $2.28 billion in cash and approximately 50.8 million newly issued Energy Transfer common units, which had a fair value of approximately $833 million. The acquired assets include approximately 6,000 miles of complementary gas gathering pipelines that extended Energy Transfer’s network in the Midland Basin. Also, as part of the transaction, the Partnership added eight gas processing plants with a total capacity of approximately 1.3 Bcf/d, and two additional processing plants that were under construction at closing. Since closing the transaction, one of these 200 MMcf/d processing plants was placed into service. Sunoco LP NuStar Acquisition On May 3, 2024, Sunoco LP completed the acquisition of all of the common units of NuStar. Under the terms of the merger agreement, NuStar common unitholders received 0.400 Sunoco LP common units for each NuStar common unit. In connection with the acquisition, Sunoco LP issued approximately 51.5 million common units, which had a fair value of approximately $2.85 billion, assumed debt totaling approximately $3.5 billion, including approximately $56 million of lease related financing obligations, and assumed preferred units with a fair value of approximately $800 million. Subsequent to the closing of the NuStar acquisition, Sunoco LP redeemed all outstanding NuStar preferred units totaling $784 million, redeemed NuStar's subordinated notes totaling $403 million and repaid and terminated the NuStar credit facility totaling $455 million. NuStar has approximately 9,500 miles of pipeline and 63 terminal and storage facilities that store and distribute crude oil, refined products, renewable fuels, ammonia and specialty liquids. 102Table of Contents Index to Financial StatementsZenith European Terminals Acquisition On March 13, 2024, Sunoco LP completed the acquisition of liquid fuels terminals in Amsterdam, Netherlands and Bantry Bay, Ireland from Zenith Energy for approximately €170 million ($185 million), including working capital. The acquisition is expected to supply optimization for Sunoco LP’s existing East Coast business and continues its focus on growing its portfolio of stable midstream income. Other Acquisition On August 30, 2024, Sunoco LP acquired a terminal in Portland, Maine for approximately $24 million, including working capital. West Texas Sale On April 16, 2024, Sunoco LP completed the sale of 204 convenience stores located in West Texas, New Mexico and Oklahoma to 7-Eleven, Inc. for approximately $1.00 billion, including customary adjustments for fuel and merchandise inventory. As part of the sale, Sunoco LP also amended its existing take-or-pay fuel supply agreement with 7-Eleven, Inc. to incorporate additional fuel gross profit. Joint Venture Transaction ET-S Permian Effective July 1, 2024, Energy Transfer and Sunoco LP formed ET-S Permian, a joint venture combining their respective crude oil and produced water gathering assets in the Permian Basin. Energy Transfer contributed its Permian crude oil and produced water gathering assets and operations to ET-S Permian. Sunoco LP contributed all of its Permian crude oil gathering assets and operations to ET-S Permian. Energy Transfer’s long-haul crude pipeline network that provides transportation of crude oil out of the Permian Basin to Nederland, Houston and Cushing is excluded from ET-S Permian. ET-S Permian operates more than 5,000 miles of crude oil and water gathering pipelines with crude oil storage capacity in excess of 11 million barrels. Energy Transfer holds a 67.5% interest, with Sunoco LP holding the remaining 32.5% interest in ET-S Permian. Energy Transfer is the operator of ET-S Permian.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 103Table of Contents Index to Financial Statementscomponents, 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 Natural Gas Act to determine whether the rates charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the Natural Gas Act. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021, and on December 16, 2022, the FERC issued its order on the initial decision. On January 17, 2023, Panhandle and the Michigan Public Service Commission each filed a request for rehearing of FERC’s order on the initial decision, which were denied by operation of law as of February 17, 2023. On March 23, 2023, Panhandle appealed these orders to the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”), and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the Court of Appeals consolidated Panhandle’s and Michigan Public Service Commission’s appeals and stayed the consolidated appeal proceeding while the FERC further considered the requests for rehearing of its December 16, 2022 order. On September 25, 2023, the FERC issued its order addressing arguments raised on rehearing and compliance, which denied our requests for rehearing. Panhandle filed its Petition for Review with the Court of Appeals regarding the September 25, 2023 order. On October 25, 2023, Panhandle filed a limited request for rehearing of the September 25 order addressing arguments raised on rehearing and compliance, which was subsequently denied by operation of law on November 27, 2023. On November 17, 2023, Panhandle provided refunds to shippers and on November 30, 2023, Panhandle submitted a refund report regarding the consolidated rate proceedings, which was protested by several parties. On January 5, 2024, the FERC issued a second order addressing arguments raised on rehearing in which it modified certain discussion from its September 25, 2023 order and sustained its prior conclusions. Panhandle has timely filed its Petition for Review with the Court of Appeals regarding the January 5, 2024 order. On May 28, 2024, the FERC issued an order rejecting Panhandle’s refund report. On June 27, 2024, Panhandle filed a revised refund report in compliance with the FERC’s May 28, 2024 order rejecting Panhandle’s refund report and a request for rehearing of the FERC’s May 28, 2024 order rejecting Panhandle’s refund report, and provided revised refunds to shippers, or in the case of shippers whose revised refunds are less than the original amounts refunded, notices of upcoming debits. One party protested Panhandle’s revised refund report, and Panhandle submitted a response to the protest on July 24, 2024. By notice issued July 29, 2024, Panhandle’s rehearing request was deemed denied. In an ordered issued September 9, 2024, FERC addressed arguments raised on rehearing, modified the discussion in the May 28, 2024 order and continued to reach the same result. On September 18, 2024, Panhandle petitioned the Court of Appeals for review of the September 9, 2024, July 29, 2024, and May 28, 2024 orders. On December 5, 2024, the FERC issued an order rejecting Panhandle’s June 27, 2024, refund report, ordering a corrected refund report and directing the issuance of additional refunds. On January 3, 2025, Panhandle submitted an adjusted refund report as well as a request for rehearing of the FERC’s December 5, 2024 order. The FERC approved the adjusted refund report by letter order dated January 23, 2025. On February 3, 2025, the FERC issued a Notice of Denial of Rehearing by Operation of Law and Providing for Further Consideration. The request for rehearing will be addressed in a future order.Pipeline CertificationThe FERC issued a Notice of Inquiry (“NOI”) on April 19, 2018, thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. 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 (“2022 Certificate Policy Statement”) and (2) a Policy Statement on the Consideration of 104Table of Contents Index to Financial StatementsGreenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (“GHG Policy Statement”), to be effective that same day. On March 24, 2022, the FERC issued an order designating the 2022 Certificate Policy Statement and the GHG Policy Statement as draft policy statements, and requested further comments. The FERC stated that it will not apply the now draft policy statements to pending applications or applications to be filed at FERC until it issues any final guidance on these topics. Comments on the 2022 Certificate Policy Statement and GHG Policy Statement were due on April 25, 2022, and reply comments were due on May 25, 2022. On January 24, 2025, the FERC issued an order withdrawing the draft GHG Policy Statement and terminating the proceeding. The FERC has taken no further action on the 2022 Certificate Policy Statement. We are unable to predict what, if any, changes may be proposed as a result of the 2022 Certificate Policy Statement that might affect our natural gas pipeline or LNG facility projects, or when such new policy, if any, might become effective. We do not expect that any change in this policy statement would affect us in a materially different manner than any other natural gas pipeline company operating in the United States. Interstate Common Carrier Regulation Liquids pipelines transporting in interstate commerce are regulated by FERC as common carriers under the ICA. 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 appealed the January 20 and May 6 orders. On July 26, 2024, the D.C. Circuit ruled in LEPA v. FERC that FERC violated the Administrative Procedure Act because the January 20 order modified the index without following notice and comment. As a result, the D.C. Circuit vacated the January 20 order and on September 17, 2024, the Commission reinstated the index level established by its original December 17 order, directed pipelines to file an informational filing to show their recomputed ceiling levels reflecting the reinstated index level and stated that pipelines may file to prospectively increase their indexed rates to their recomputed levels. On October 17, 2024, FERC issued a Supplemental NOPR that proposes a reduction to the currently effective index by one percent. The Supplemental NOPR, which remains pending before FERC, could result in the reimplementation through a notice-and-comment rulemaking of the same rulings that were vacated by the D.C. Circuit in LEPA v. FERC .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 StandardsIn 2023, the United States Environmental Protection Agency (“EPA”) finalized its Good Neighbor Plan (the “Plan”) which seeks to reduce nitrogen oxide pollution from power plants and other industrial facilities from 23 upwind states which the EPA determined is contributing to National Ambient Air Quality Standards (NAAQS) nonattainment and interfering with maintenance of the 2015 ozone NAAQS in downwind states. 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. 105Table of Contents Index to Financial StatementsOperators and industry groups have challenged the Plan in the D.C. Circuit, as well as the legal predicates to the individual upwind states’ inclusion in the Plan in the regional circuits. The effectiveness of the rule is currently stayed in the nine states within the Partnership’s footprint, by nature of judicial stays of the legal predicate to the Plan, by judicial stay of the Plan itself by the U.S. Supreme Court, or by the administrative stay issued by the EPA in October 2024. Proceedings as to both on the merits are ongoing. In the challenge to the Plan in the D.C. Circuit, oral argument is expected in early 2025 and a decision could take several months, projected late 2025. 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 continue to believe the Partnership’s outlook is strong, as it has a stable business that has demonstrated its ability to manage through various market cycles. We expect future growth to be supported by production improvements and increased utilization of our existing assets, as well as continued strong domestic and international demand for our products. 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. For 2025 and beyond, we expect increased demand from new data centers, power plants and LNG exports to support increased production, while increased global demand for petrochemicals and NGL feedstocks is expected to support higher volumes of NGL production and exports on existing assets and assets currently being developed or under construction. In addition, in the United States, we expect a more constructive regulatory environment under the new presidential administration, which we anticipate being favorable for project development and our operations in general. 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 market volatility and other uncertainties, we have reduced growth capital spending in recent years. While we anticipate a healthy capital expenditure program in 2025 and beyond, we expect to continue to be prudent going forward as we allocate capital across our business segments. See “Liquidity and Capital Resources” for additional information on our capital expenditures over the last two years and our forecasted capital expenditures for 2025.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 develop 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.106Table of Contents Index to Financial StatementsSegment 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, 2024 Compared to the Year Ended December 31, 2023Consolidated Results Years Ended December 31,2024 2023 ChangeSegment Adjusted EBITDA:Intrastate transportation and storage $ 1,358 $ 1,111 $ 247 Interstate transportation and storage 1,828 2,009 (181) Midstream 2,910 2,525 385 NGL and refined products transportation and services 4,179 3,894 285 Crude oil transportation and services 3,177 2,681 496 Investment in Sunoco LP 1,457 964 493 Investment in USAC 584 512 72 All other (10) 2 (12) Adjusted EBITDA (consolidated) $ 15,483 $ 13,698 $ 1,785Years Ended December 31,2024 2023 ChangeReconciliation of net income to Adjusted EBITDA:Net income $ 6,565 $ 5,294 $ 1,271 Depreciation, depletion and amortization 5,165 4,385 780 Interest expense, net of interest capitalized 3,125 2,578 547 Income tax expense 541 303 238 Impairment losses and other 52 12 40 Gains on interest rate derivatives (6) (36) 30 Non-cash compensation expense 151 130 21 Unrealized (gains) losses on commodity risk management activities 56 (3) 59 Inventory valuation adjustments (Sunoco LP) 86 114 (28) (Gains) losses on extinguishments of debt 12 (2) 14 Adjusted EBITDA related to unconsolidated affiliates 692 691 1 Equity in earnings of unconsolidated affiliates (379) (383) 4 Non-operating litigation-related loss — 627 (627) Gain on sale of West Texas assets (Sunoco LP) (586) — (586) Other, net 9 (12) 21 Adjusted EBITDA (consolidated) $ 15,483 $ 13,698 $ 1,785 107Table of Contents Index to Financial StatementsNet Income. For the year ended December 31, 2024 compared to the prior year, net income increased $1.27 billion, or approximately 24%, primarily due to the recognition of a $586 million gain on Sunoco LP’s sale of its West Texas assets in the current year, as well as the recognition of a $627 million non-operating litigation-related loss in the prior year. The change in net income also reflected higher segment margin from multiple segments, partially offset by increases in operating expenses, selling, general and administrative expenses, depreciation, depletion and amortization, impairment losses, interest expense and income tax expense; these changes are discussed in more detail below and in “Segment Operating Results.” Adjusted EBITDA ( consolidated ). For the year ended December 31, 2024 compared to the prior year, Adjusted EBITDA increased $1.79 billion, or approximately 13%, primarily due to favorable results in multiple segments. The most significant increases were in our midstream segment, our crude oil transportation and services segment and our Investment in Sunoco LP segment, each of which reflected increases from recently acquired assets. Our midstream segment also reflected increases from higher volumes, as did our NGL and refined products transportation and services segment. Our intrastate transportation and storage segment also reflected increases from higher pipeline optimization. Additional information on changes impacting Adjusted EBITDA for the year ended December 31, 2024 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 aggregate debt balances and higher interest rates on floating rate and recently refinanced debt. Income Tax Expense. For the year ended December 31, 2024 compared to the same period last year, income tax expense increased due to the taxable gain recognized by a corporate subsidiary of Sunoco LP on its sale of West Texas assets. Impairment Losses and Other . For the year ended December 31, 2024, impairment losses and other were primarily related to Sunoco LP’s termination of a lease in June 2024. For the year ended December 31, 2023 impairment losses and other consisted of impairment losses incurred by USAC primarily related to its compression equipment. Gains on Interest Rate Derivatives. Gains on interest rate derivatives resulted from changes in forward interest rates, which caused our forward-starting swaps to change in value. Unrealized (Gains) Losses on Commodity Risk Management Activities. The unrealized gains and losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships. 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 (Sunoco LP). Inventory valuation adjustments represent changes in lower of cost or market using the last-in, first-out method on Sunoco LP’s inventory. These amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory at the end of the period. For the years ended December 31, 2024 and 2023, decreases in fuel prices caused the lower of cost or market reserve requirements to increase by $86 million and $114 million, respectively, which reduced net income. (Gains) Losses on Extinguishment of Debt. For the year ended December 31, 2024, losses on extinguishment of debt included a $5 million loss on Energy Transfer’s redemption of its $450 million aggregate principal amount of 8.00% senior notes due April 2029 and $500 million aggregate principal amount of 5.75% senior notes due April 2025, a $2 million loss recognized by Sunoco LP and a $5 million loss related to USAC’s redemption of its $725 million aggregate principal amount of 6.875% senior notes due 2026.Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below.Non-Operating Litigation-Related Loss. Non-operating litigation-related loss recognized for the year ended December 31, 2023 represents the loss associated with the The Williams Companies, Inc. litigation. Gain on Sale of West Texas Assets (Sunoco LP). The gain on sale of West Texas assets relates to the gain recognized by Sunoco LP upon completion of the sale of convenience stores to 7-Eleven Inc. in April 2024. During the fourth quarter of 2024, Sunoco LP recorded a $12 million reduction to the gain to reflect adjustments to the cash proceeds and certain balance sheet accounts associated with the business sold. 108Table of Contents Index to Financial StatementsOther, net. Other, net primarily includes amortization of regulatory assets and other income and expense amounts.Supplemental Information on Unconsolidated Affiliates The following table presents financial information related to unconsolidated affiliates: Years Ended December 31,2024 2023 Change Equity in earnings of unconsolidated affiliates:Citrus$ 136 $ 146 $ (10)MEP63 87 (24) White Cliffs 19 10 9 Explorer 34 37 (3) SESH 45 31 14Other82 72 10Total equity in earnings of unconsolidated affiliates$ 379 $ 383 $ (4) Adjusted EBITDA related to unconsolidated affiliates (1) :Citrus$ 329 $ 335 $ (6)MEP98 121 (23)White Cliffs38 29 9 Explorer 53 57 (4) SESH 53 45 8Other121 104 17Total Adjusted EBITDA related to unconsolidated affiliates$ 692 $ 691 $ 1Distributions received from unconsolidated affiliates:Citrus $ 129 $ 135 $ (6) MEP 86 115 (29) White Cliffs 38 25 13 Explorer 36 38 (2) SESH 59 33 26 Other 83 70 13 Total distributions received from unconsolidated affiliates $ 431 $ 416 $ 15 (1) 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 109Table of Contents Index to Financial Statementsin 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 31,2024 2023 ChangeNatural gas transported (BBtu/d)13,418 14,814 (1,396) Withdrawals from storage natural gas inventory (BBtu) 20,905 14,840 6,065 Revenues $ 3,053 $ 3,962 $ (909) Cost of products sold 1,390 2,616 (1,226)Segment margin1,663 1,346 317 Unrealized (gains) losses on commodity risk management activities (35) 66 (101)Operating expenses, excluding non-cash compensation expense(246) (279) 33Selling, general and administrative expenses, excluding non-cash compensation expense(50) (51) 1Adjusted EBITDA related to unconsolidated affiliates24 25 (1)Other2 4 (2)Segment Adjusted EBITDA$ 1,358 $ 1,111 $ 247 Volumes. For the year ended December 31, 2024 compared to the prior year, transported volumes of gas on our Texas and Oklahoma intrastate pipelines decreased primarily due to less third-party transportation and decreased gas production from the Haynesville area. Transported volumes reported above exclude volumes attributable to purchases and sales of gas for our pipelines’ own accounts and the optimization of any unused capacity. 110Table of Contents Index to Financial Statements Segment Margin . The components of our intrastate transportation and storage segment margin were as follows: Years Ended December 31,2024 2023 ChangeTransportation fees$ 866 $ 852 $ 14Natural gas sales and other (excluding unrealized gains and losses)657 392 265Retained fuel revenues (excluding unrealized gains and losses)35 64 (29)Storage margin, including fees (excluding unrealized gains and losses)70 104 (34) Unrealized gains (losses) on commodity risk management activities 35 (66) 101Total segment margin$ 1,663 $ 1,346 $ 317 Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impact of the following: • an increase of $265 million in realized natural gas sales and other primarily due to higher pipeline optimization from physical sales and settled derivatives; and • an increase of $14 million in transportation fees primarily due to the recovery of certain fees earned in a prior period on our Texas system; partially offset by • a decrease of $34 million in storage margin primarily due to lower storage optimization from settled derivatives.Interstate Transportation and Storage Years Ended December 31,2024 2023 Change Natural gas transported (BBtu/d) 16,877 16,481 396 Natural gas sold (BBtu/d) 32 28 4 Revenues $ 2,296 $ 2,375 $ (79) Cost of products sold 9 6 3 Segment margin 2,287 2,369 (82) Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses (807) (746) (61) Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses (129) (115) (14) Adjusted EBITDA related to unconsolidated affiliates 477 496 (19) Other — 5 (5) Segment Adjusted EBITDA $ 1,828 $ 2,009 $ (181) Volumes. For the year ended December 31, 2024 compared to the prior year, transported volumes increased primarily due to more capacity sold and higher utilization on our Panhandle, Trunkline and Gulf Run systems due to increased demand. Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impact of the following: • a decrease of $82 million in segment margin primarily due to a $36 million decrease due to lower operational gas sales resulting from lower prices, a $22 million decrease in parking revenue, a $21 million decrease due to lower volumes and a $10 million decrease due to lower rates on several of our interstate pipeline systems. These decreases were partially offset by an $8 million increase in storage revenue; • an increase of $61 million in operating expenses primarily due to a $35 million increase in maintenance project costs, an aggregate $22 million increase in employee related costs, outside services, materials and office expense, and a $6 million increase from the revaluation of system gas; • a decrease of $19 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to a $23 million decrease from our Midcontinent Express Pipeline joint venture due to capacity sold at lower rates and a $6 million decrease from our Citrus joint venture primarily due to higher operating expenses. These decreases were partially offset by a $10 million increase from our Southeast Supply Header joint venture due to higher contracted volumes; 111Table of Contents Index to Financial Statements• an increase of $14 million in selling, general and administrative expenses primarily due to higher professional fees and employee costs; and • a decrease of $5 million in other primarily due to the prior period recognition of certain amounts related to a shipper bankruptcy.Midstream Years Ended December 31,2024 2023 Change Gathered volumes (BBtu/d) 20,272 19,937 335 NGLs produced (MBbls/d) 1,019 880 139 Equity NGLs (MBbls/d) 58 43 15 Revenues $ 11,199 $ 10,406 $ 793 Cost of products sold 6,637 6,503 134 Segment margin 4,562 3,903 659 Operating expenses, excluding non-cash compensation expense (1,550) (1,204) (346) Selling, general and administrative expenses, excluding non-cash compensation expense (199) (199) — Adjusted EBITDA related to unconsolidated affiliates 23 20 3 Other 74 5 69 Segment Adjusted EBITDA $ 2,910 $ 2,525 $ 385 Volumes. For the year ended December 31, 2024 compared to the prior year, gathered volumes increased primarily due to recently acquired assets and higher volumes in the Permian region. NGL production increased primarily due to recently acquired assets and increased Permian plant utilization. Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impact of the following: • an increase of $686 million in segment margin primarily due to recently acquired assets and higher volumes in the Permian region; • an increase of $69 million in other primarily from the recognition of proceeds from a business interruption claim; and • an increase of $3 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to recently acquired assets; partially offset by • an increase of $346 million in operating expenses primarily due to a $297 million increase related to recent acquisitions and assets placed in service, a $30 million increase in employee costs and a $10 million increase in expense projects; and • a decrease of $27 million in segment margin due to lower natural gas prices of $59 million, partially offset by higher NGL prices of $32 million. 112Table of Contents Index to Financial Statements NGL and Refined Products Transportation and Services Years Ended December 31,2024 2023 ChangeNGL transportation volumes (MBbls/d)2,206 2,116 90Refined products transportation volumes (MBbls/d)579 540 39NGL and refined products terminal volumes (MBbls/d)1,469 1,430 39NGL fractionation volumes (MBbls/d)1,110 1,023 87Revenues$ 24,530 $ 21,903 $ 2,627Cost of products sold19,406 17,049 2,357Segment margin5,124 4,854 270 Unrealized (gains) losses on commodity risk management activities 38 (38) 76 Operating expenses, excluding non-cash compensation expense (957) (892) (65) Selling, general and administrative expenses, excluding non-cash compensation expense (160) (157) (3) Adjusted EBITDA related to unconsolidated affiliates 134 126 8 Other — 1 (1)Segment Adjusted EBITDA$ 4,179 $ 3,894 $ 285 Volumes. For the year ended December 31, 2024 compared to the prior year, NGL transportation volumes increased primarily due to higher volumes from the Permian and Eagle Ford regions and on our Mariner East pipeline system. The increase in transportation volumes and the commissioning of our eighth fractionator in August 2023 also led to higher fractionated volumes at our Mont Belvieu NGL Complex.Segment Margin . The components of our NGL and refined products transportation and services segment margin were as follows: Years Ended December 31,2024 2023 Change Fractionators and refinery services margin $ 935 $ 888 $ 47 Transportation margin 2,582 2,399 183 Storage margin 315 319 (4) Terminal services margin 984 892 92 Marketing margin 347 318 29 Unrealized gains (losses) on commodity risk management activities (38) 38 (76) Total segment margin $ 5,125 $ 4,854 $ 271 Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impact of the following: • an increase of $183 million in transportation margin primarily due to a $161 million increase from higher throughput and contractual rate escalations on our Mariner East and our Gulf Coast pipeline systems and a $24 million increase on our refined products pipelines, as well as a $12 million increase in intrasegment margin which was fully offset within our fractionators margin. These increases were partially offset by an $12 million decrease in intrasegment margin which is fully offset within our marketing margin and a $5 million decrease from the timing of third-party deficiency payments on our Northeast region pipelines; • an increase of $92 million in terminal services margin primarily due to an $80 million increase in fees from loading volumes for export at our Nederland and Marcus Hook terminals and a $12 million increase from higher throughput and storage at our refined product terminals; • an increase of $47 million in fractionators and refinery services margin primarily due to a $56 million increase resulting from higher throughput as our eighth fractionator was placed in service in August 2023 and a $3 million increase from our refinery services business. These increases were partially offset by a $12 million decrease in intrasegment margin which was fully offset within our transportation margin; 113Table of Contents Index to Financial Statements• an increase of $29 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to higher gains during 2024 from the optimization of hedged NGL and refined product inventories and an $12 million increase in intrasegment margin which is fully offset within our transportation margin; and • an increase of $8 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to increased volume on our White Cliffs NGL Pipeline; partially offset by • an increase of $65 million in operating expenses primarily due to a $24 million increase in employee costs, a $17 million increase resulting from the timing of project related expenses, a $15 million increase in outside services expenses, a $13 million increase in ad valorem taxes and increases totaling $13 million from various other operating expenses. These increases were partially offset by an $18 million decrease in gas and power utility costs; and • an increase of $3 million in selling, general and administrative expenses primarily due to increased costs from recently acquired assets.Crude Oil Transportation and Services Years Ended December 31,2024 2023 Change Crude oil transportation volumes (MBbls/d) 6,612 5,282 1,330 Crude oil terminals volumes (MBbls/d) 3,346 3,377 (31)Revenue$ 28,539 $ 26,536 $ 2,003Cost of products sold24,407 23,071 1,336Segment margin4,132 3,465 667 Unrealized losses on commodity risk management activities 16 13 3 Operating expenses, excluding non-cash compensation expense (852) (699) (153) Selling, general and administrative expenses, excluding non-cash compensation expense (149) (120) (29) Adjusted EBITDA related to unconsolidated affiliates 28 19 9 Other 2 3 (1) Segment Adjusted EBITDA $ 3,177 $ 2,681 $ 496 Volumes. For the year ended December 31, 2024 compared to the prior year, crude oil transportation volumes were higher due to continued growth on our gathering systems, as well as contributions from recently acquired assets and from assets contributed upon the recent formation of the ET-S Permian joint venture with Sunoco LP, partially offset by lower volumes on our Bakken Pipeline. Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impact of the following: • an increase of $670 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $541 million increase from recently acquired assets and assets contributed upon the recent formation of the ET-S Permian joint venture, a $122 million increase in transportation revenues from existing assets and a $7 million increase in our crude oil acquisition and marketing business from more favorable market conditions; and • an increase of $9 million in Adjusted EBITDA related to unconsolidated affiliates due to recently acquired assets and higher volumes on our White Cliffs crude pipeline; partially offset by • an increase of $153 million in operating expenses primarily due to a $106 million increase from recently acquired assets and assets contributed upon the recent formation of the ET-S Permian joint venture, a $15 million increase in outside services, an $11 million increase in ad valorem taxes, a $10 million increase in employee expenses and various increases in volume-driven expenses; and • an increase of $29 million in selling, general and administrative expenses primarily due to a $27 million increase from recently acquired assets and assets contributed upon the recent formation of the ET-S Permian joint venture, as well as higher employee costs. 114Table of Contents Index to Financial StatementsInvestment in Sunoco LP Years Ended December 31,2024 2023 Change Revenues $ 22,693 $ 23,068 $ (375) Cost of products sold 20,595 21,703 (1,108) Segment margin 2,098 1,365 733 Unrealized (gains) losses on commodity risk management activities 12 (21) 33 Operating expenses, excluding non-cash compensation expense (611) (420) (191) Selling, general and administrative, excluding non-cash compensation expense (266) (113) (153) Adjusted EBITDA related to unconsolidated affiliates 101 10 91 Inventory valuation adjustments 86 114 (28) Other, net 37 29 8 Segment Adjusted EBITDA $ 1,457 $ 964 $ 493The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP segment increased due to the net impact of the following: • an increase of $738 million in segment margin (excluding unrealized gains and losses on commodity risk management activities and inventory valuation adjustments) primarily due to the acquisitions of NuStar and Zenith European terminals; and • an increase of $91 million in Adjusted EBITDA related to unconsolidated affiliates due to the formation of the ET-S Permian joint venture; partially offset by • an increase of $191 million in operating expenses and $153 million in selling, general and administrative expenses primarily due to the acquisitions of NuStar and Zenith European terminals.Investment in USAC Years Ended December 31,2024 2023 Change Revenues $ 950 $ 846 $ 104 Cost of products sold 146 137 9 Segment margin 804 709 95 Operating expenses, excluding non-cash compensation expense (166) (147) (19) Selling, general and administrative, excluding non-cash compensation expense (54) (51) (3) Other, net — 1 (1) Segment Adjusted EBITDA $ 584 $ 512 $ 72The investment in USAC segment reflects the consolidated results of USAC.Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to the net impact of the following: • an increase of $95 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 $19 million in operating expenses primarily due to an increase in employee costs associated with increased revenue-generating horsepower; and • an increase of $3 million in selling, general and administrative expenses primarily due to an increase in professional fees. 115Table of Contents Index to Financial StatementsAll Other Years Ended December 31,2024 2023 ChangeRevenue$ 1,747 $ 1,798 $ (51)Cost of products sold1,709 1,740 (31)Segment margin38 58 (20) Unrealized (gains) losses on commodity risk management activities 25 (22) 47 Operating expenses, excluding non-cash compensation expense (20) (40) 20 Selling, general and administrative expenses, excluding non-cash compensation expense (62) (85) 23 Adjusted EBITDA related to unconsolidated affiliates 6 4 2 Other and eliminations 3 87 (84)Segment Adjusted EBITDA$ (10) $ 2 $ (12)Amounts reflected in our all other segment primarily include: • our natural gas marketing operations;• our wholly owned natural gas compression operations; and • our natural resources business. Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA decreased due to the net impact of the following: • a decrease of $42 million primarily due to intersegment eliminations of Sunoco LP’s 32.5% share of the ET-S Permian joint venture, which is consolidated in our crude oil transportation and services segment and also reflected as an unconsolidated affiliate in our investment in Sunoco LP segment, partially offset by higher acquisition costs in 2023 related to the Lotus Midstream and Crestwood acquisitions; • a decrease of $9 million due to favorable results from our captive insurance company in the prior year; and • a decrease of $5 million from our dual drive compression business due to lower gas prices; partially offset by • an increase of $45 million in our natural gas marketing business due to increased residue sales resulting from the integration of the recently acquired WTG Midstream assets, as well as higher gains from storage positions.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, 2024, we had cash and cash equivalents of $312 million and availability under our revolving credit facility of $2.21 billion.The Partnership’s material contractual obligations include long-term debt service, payments under operating leases and purchase commitments. 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 116Table of Contents Index to Financial Statementsestablished at the inception of the contract. We have material purchase commitments for crude oil; as of December 31, 2024, those purchase commitments totaled an estimated $50.34 billion (of which $22.45 billion would be due in 2025) based on either the current market price for variable price contracts or the contracted price for fixed price contracts. We currently expect capital expenditures in 2025 to be approximately as follows (including capitalized interest and overhead, but excluding capital expenditures related to our investments in Sunoco LP and USAC):Growth MaintenanceIntrastate transportation and storage $ 1,400 $ 70 Interstate transportation and storage 170 205 Midstream 1,625 380NGL and refined products transportation and services (1)1,375 145Crude oil transportation and services (1)295 190 All other (including eliminations) 135 110Total capital expenditures$ 5,000 $ 1,100(1) Includes capital expenditures related to the Partnership’s proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline joint ventures as well as the Orbit Gulf Coast NGL Exports joint venture. 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 $400 million in growth capital expenditures and approximately $150 million in maintenance capital expenditures in 2025. USAC currently has budgeted between $38 million and $42 million in maintenance capital expenditures and currently has budgeted between $120 million and $140 million in expansion capital expenditures in 2025.Cash Flows Our cash flows may change in the future due to a number of factors, some of which we cannot control. 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 ActivitiesChanges 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. 117Table of Contents Index to Financial StatementsFollowing is a summary of operating activities by period:Year Ended December 31, 2024 Cash provided by operating activities in 2024 was $11.51 billion and net income was $6.57 billion. The difference between net income and net cash provided by operating activities in 2024 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions and divestitures) of $196 million and other items totaling $4.84 billion, which includes non-cash items and items related to investing and financing activities that are included in net income. The non-cash activity in 2024 consisted primarily of depreciation, depletion and amortization of $5.17 billion, deferred income taxes of $276 million, unfavorable inventory valuation adjustments of $86 million, non-cash compensation expense of $151 million and impairment losses of $52 million. Net income also included equity in earnings of unconsolidated affiliates of $379 million, a $586 million gain on Sunoco LP’s sale of its West Texas assets and losses on extinguishments of debt of $12 million in 2024. Cash provided by operating activities includes cash distributions received from unconsolidated affiliates that are deemed to be paid from cumulative earnings, which distributions were $356 million in 2024.Year Ended December 31, 2023Cash provided by operating activities in 2023 was $9.56 billion and net income was $5.29 billion. The difference between net income and net cash provided by operating activities in 2023 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions and divestitures) of $451 million and other items totaling $4.43 billion, which includes non-cash items and items related to financing activities that are included in net income. The non-cash activity in 2023 consisted primarily of depreciation, depletion and amortization of $4.39 billion, deferred income taxes of $203 million, unfavorable inventory valuation adjustments of $114 million, non-cash compensation expense of $130 million and impairment losses of $12 million. Net income also included equity in earnings of unconsolidated affiliates of $383 million and gains on extinguishments of debt of $2 million. Cash provided by operating activities includes cash distributions received from unconsolidated affiliates that are deemed to be paid from cumulative earnings, which distributions were $353 million in 2023.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, 2024 Cash used in investing activities in 2024 was $5.90 billion. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) were $4.09 billion. Additional detail related to our capital expenditures is provided in the following table. We received $24 million of cash proceeds from the sale of assets. The Partnership also received distributions of $75 million from unconsolidated affiliates. In 2024, we paid $2.17 billion, net of cash received, for the WTG Midstream acquisition, we paid $84 million to acquire the outstanding noncontrolling interest in Edwards Lime Gathering, LLC, which is now a wholly owned subsidiary, and we also paid $250 million, net of cash received, for other acquisitions. In 2024, Sunoco LP paid $224 million in cash for acquisitions of terminals and other assets and received $27 million in cash from the NuStar acquisition. Additionally, in 2024, Sunoco LP received cash proceeds of $987 million from its sale of West Texas assets.Year Ended December 31, 2023Cash 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 terminals. 118Table of Contents Index to Financial Statements The following is a summary of the Partnership’s capital expenditures (including only our proportionate share of the Bakken, Rover, Bayou Bridge and Orbit Gulf Coast NGL Exports joint ventures, net of contributions in aid of construction costs) by period: Capital Expenditures Recorded During Period Growth Maintenance TotalYear Ended December 31, 2024: Intrastate transportation and storage $ 58 $ 60 $ 118 Interstate transportation and storage 135 197 332 Midstream 929 394 1,323 NGL and refined products transportation and services 1,291 133 1,424 Crude oil transportation and services 271 152 423 Investment in Sunoco LP 220 124 344 Investment in USAC 244 32 276 All other (including eliminations) 272 70 342 Total capital expenditures $ 3,420 $ 1,162 $ 4,582Year 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 $ 2,868Financing 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, 2024 Cash used in financing activities was $5.45 billion in 2024. In 2024, we had a net increase in our debt level of $4.74 billion. During 2024, we paid distributions of $4.62 billion to our partners, we paid distributions of $1.78 billion to noncontrolling interests and we paid distributions of $67 million to our redeemable noncontrolling interests. In 2024, we paid $2.65 billion in cash for the redemption of our Series A, Series C, Series D and Series E Preferred Units and we paid $37 million in cash to redeem a portion of the outstanding Crestwood Niobrara LLC preferred units. In 2024, we received capital contributions of $638 million in cash from noncontrolling interests and we received capital contributions of $2 million in cash from redeemable noncontrolling interests. In 2024, we incurred debt issuance costs of $147 million. Additionally, in 2024, USAC paid $749 million in cash for investments in government securities in connection with the legal defeasance of senior notes, and Sunoco LP paid $784 million in cash for the redemption of NuStar preferred units.Year Ended December 31, 2023Cash 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. Additionally, in 2023, we received capital contributions of $3 million in cash from noncontrolling interests, and we incurred debt issuance costs of $45 million. 119Table of Contents Index to Financial Statements Description of Indebtedness Our outstanding consolidated indebtedness was as follows: December 31,2024 2023Energy Transfer Indebtedness:Notes and debentures (1)(2) $ 46,269 $ 43,016Five-Year Credit Facility (2)2,759 1,412 Subsidiary indebtedness: Transwestern senior notes 75 250 Bakken Project senior notes (2) 850 1,850 Sunoco LP senior notes, bonds and lease-related obligations (1)(2)(3) 7,304 3,194 USAC Senior Notes (2) 1,750 1,475 Sunoco LP Credit Facility 203 411 USAC Credit Facility 772 872 Other long-term debt 11 18 Net unamortized premiums, discounts and fair value adjustments 77 127 Deferred debt issuance costs (310) (237) Total debt 59,760 52,388 Less: current maturities of long-term debt (4) 8 1,008 Long-term debt, less current maturities $ 59,752 $ 51,380 (1) As of December 31, 2024, these balances included a total of $3.08 billion aggregate principal amount of senior notes and bonds due on or before December 31, 2025 which were classified as long-term as management has the intent and ability to refinance the borrowings on a long-term basis.(2) See additional information below under “Recent Transactions.”(3) Sunoco LP assumed $2.57 billion aggregate principal amount of NuStar senior notes and bonds in connection with the closing of the NuStar acquisition in May 2024. (4) 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 a subsidiary of Dakota Access which were repaid in April 2024, as described below under “Recent Transactions.”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 TransactionsEnergy Transfer 2024 Senior Notes Redemptions During the first quarter of 2024, the Partnership redeemed its $1.15 billion aggregate principal amount of 5.875% senior notes due January 2024, $350 million aggregate principal amount of 4.90% senior notes due February 2024 and $82 million aggregate principal amount of 7.60% senior notes due February 2024 using proceeds from its January 2024 notes issuance described below. During the second quarter of 2024, the Partnership redeemed its $500 million aggregate principal amount of 4.25% senior notes due April 2024, $750 million aggregate principal amount of 4.50% senior notes due April 2024, $450 million aggregate principal amount of 8.00% senior notes due April 2029 and $600 million aggregate principal amount of 3.90% senior notes due May 2024 using cash on hand and proceeds from its Five-Year Credit Facility. During the fourth quarter of 2024, the Partnership redeemed its $65 million aggregate principal amount of 9.00% debentures due November 2024, its Transwestern $175 million aggregate principal amount of 5.66% senior notes due December 2024 and 120Table of Contents Index to Financial Statementsits $500 million aggregate principal amount of 5.75% senior notes due April 2025 using cash on hand and proceeds from its Five-Year Credit Facility. Bakken Project Debt Redemption In April 2024, the Bakken Pipeline entities redeemed $1.00 billion aggregate principal amount of 3.90% senior notes due April 2024 using proceeds from member contributions, which included $637 million reflected as capital contributions from noncontrolling interests recorded in the Partnership’s consolidated financial statements. Energy Transfer 2024 Notes Issuance In January 2024, the Partnership issued $1.25 billion aggregate principal amount of 5.55% senior notes due 2034, $1.75 billion aggregate principal amount of 5.95% senior notes due 2054 and $800 million aggregate principal amount of 8.00% fixed-to-fixed reset rate junior subordinated notes due 2054. The Partnership used the net proceeds to refinance existing indebtedness, including borrowings under its Five-Year Credit Facility (defined below), to redeem its outstanding Series C Preferred Units and Series D Preferred Units and for general partnership purposes. The Partnership also used the proceeds to redeem its Series E Preferred Units in May 2024. In June 2024, the Partnership issued $1.00 billion aggregate principal amount of 5.25% senior notes due 2029, $1.25 billion aggregate principal amount of 5.60% senior notes due 2034, $1.25 billion aggregate principal amount of 6.05% senior notes due 2054 and $400 million aggregate principal amount of 7.125% fixed-to-fixed reset rate junior subordinated notes due 2054. The Partnership used part of the net proceeds to redeem its outstanding Series A Preferred Units. It also used the net proceeds to fund a portion of its acquisition of WTG Midstream, refinance existing indebtedness, including borrowings under its Five-Year Credit Facility, and for general partnership purposes. Sunoco LP April 2024 Notes Issuance On April 30, 2024, the Sunoco LP issued $750 million aggregate principal amount of 7.000% senior notes due 2029 and $750 million aggregate principal amount of 7.250% senior notes due 2032 in a private offering. Sunoco LP used the net proceeds from the offering to (i) repay certain outstanding indebtedness of NuStar, in connection with the merger between the Sunoco LP and NuStar, (ii) fund the redemption of NuStar's preferred units in connection with the merger and (iii) pay offering fees and expenses. NuStar Subordinated Note Redemption and Credit Facility Termination During the second quarter of 2024, subsequent to the closing of the NuStar acquisition, Sunoco LP redeemed NuStar's subordinated notes totaling $403 million and repaid and terminated NuStar's credit facility totaling $455 million. Upon the closing of the NuStar acquisition, the commitments under NuStar’s receivables financing agreement were reduced to zero during a suspension period, for which the period end has not been determined. As of December 31, 2024, this facility had zero outstanding borrowings. USAC March 2024 Notes Issuance In March 2024, USAC issued $1.00 billion aggregate principal amount of 7.125% senior notes due 2029. The net proceeds from this issuance were used to repay a portion of existing borrowings under USAC’s revolving credit facility, to redeem its $725 million aggregate principal amount of 6.875% senior notes due 2026, which constituted a legal defeasance under GAAP, and for general partnership purposes.Credit Facilities and Commercial Paper Five-Year Credit FacilityThe Partnership’s Five-Year Credit Facility allows for unsecured borrowings up to $5.00 billion until April 11, 2027, and, following the Partnership’s exercise of its option to extend the maturity date on December 18, 2024, up to $4.84 billion until April 11, 2029. The Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $7.00 billion under certain conditions. As of December 31, 2024, the Five-Year Credit Facility had $2.76 billion of outstanding borrowings, all of which consisted of commercial paper. The amount available for future borrowings was $2.21 billion, after accounting for outstanding letters of credit in the amount of $30 million. The weighted average interest rate on the total amount outstanding as of December 31, 2024 was 4.65%. 121 Table of Contents Index to Financial StatementsSunoco LP Credit FacilityAs of December 31, 2024, the Sunoco LP Credit Facility had $203 million of outstanding borrowings and $43 million in standby letters of credit and matures in May 2029. The amount available for future borrowings was $1.25 billion at December 31, 2024. The weighted average interest rate on the total amount outstanding as of December 31, 2024 was 6.57%.USAC Credit FacilityAs of December 31, 2024, USAC had $772 million of outstanding borrowings and $1 million in outstanding letters of credit under the credit agreement. As of December 31, 2024, USAC had $827 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $783 million was available to be drawn. The weighted average interest rate on the total amount outstanding as of December 31, 2024 was 6.98%.Covenants Related to Our Credit AgreementsThe agreements relating to the senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.The Five-Year Credit Facility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things: • incur indebtedness; • grant liens; • enter into mergers; • dispose of assets; • make certain investments;• make Distributions (as defined in the Five-Year Credit Facility) during certain Defaults (as defined in the Five-Year Credit Facility) and during any Event of Default (as defined in the Five-Year Credit Facility); • engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries; • engage in transactions with affiliates; and • enter into restrictive agreements. The applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the Five-Year Credit Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the Five-Year Credit Facility ranges from 0.125% to 0.300%.The Five-Year Credit Facility contains various covenants including limitations on the creation of indebtedness and liens and related to the operation and conduct of our business. The Five-Year Credit Facility also limits us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreement, of 5.00 to 1.00, which can generally be increased to 5.50 to 1.00 during a Specified Acquisition Period. Our Leverage Ratio was 3.12 to 1.00 at December 31, 2024, as calculated in accordance with the credit agreement.Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions to Unitholders. Covenants Related to Transwestern The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.122 Table of Contents Index to Financial StatementsCovenants Related to Sunoco LP The Sunoco LP Credit Facility contains various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. Sunoco LP’s Credit Facility requires Sunoco LP to maintain a specified net leverage ratio and interest coverage ratio.Covenants Related to USAC The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things: • grant liens; • make certain loans or investments; • incur additional indebtedness or guarantee other indebtedness; • enter into transactions with affiliates; • merge or consolidate; • sell our assets; and • make certain acquisitions. The USAC Credit Facility is also subject to the following financial covenants, including covenants requiring USAC to maintain: • a minimum EBITDA to interest coverage ratio; • a ratio of total secured indebtedness to EBITDA within a specified range; and • a maximum funded debt to EBITDA ratio.Compliance with our CovenantsWe and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2024.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 RateDecember 31, 2022 February 7, 2023 February 21, 2023 $ 0.3050March 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 0.3150March 31, 2024 May 13, 2024 May 20, 2024 0.3175 June 30, 2024 August 9, 2024 August 19, 2024 0.3200 September 30, 2024 November 8, 2024 November 19, 2024 0.3225 December 31, 2024 February 7, 2025 February 19, 2025 0.3250 123Table of Contents Index to Financial StatementsThe total amounts of distributions declared and paid during the periods presented (all from Available Cash from Energy Transfer’s operating surplus and are shown in the period to which they relate) are as follows: Years Ended December 31, 2024 2023 Limited Partners $ 4,384 $ 3,984 General Partner interest 4 3 Total Energy Transfer distributions $ 4,388 $ 3,987Energy 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 ASeries B (1) Series C Series D Series E Series F (1) Series G (1) Series H (1) Series IDecember 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 — — — 0.2111March 31, 2024 May 1, 2024 May 15, 2024 23.99 — — — 0.4750 33.7500 35.63 32.50 0.2111 June 30, 2024 August 1, 2024 August 15, 2024 9.88 33.125 — — — — — — 0.2111 (2) September 30, 2024 November 1, 2024 November 15, 2024 — — — — — 33.7500 35.63 32.50 0.2111 (2) December 31, 2024 February 1, 2025 February 15, 2024 — 33.125 — — — — — — 0.2111 (2) (1) Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis. Distributions on the Series B Preferred Units will begin to be paid quarterly on February 15, 2028. (2) For the period ended December 31, 2024, the cash distribution for the Series I Preferred Units was paid on February 14, 2025 to unitholders of record as of the close of business on February 4, 2025. For the period ended September 30, 2024, the cash distribution for the Series I Preferred Units was paid on November 14, 2024 to unitholders of record as of the close of business on November 4, 2024. For the period ended June 30, 2024, the cash distribution for the Series I Preferred Units was paid on August 14, 2024 to unitholders of record as of the close of business on August 2, 2024.Sunoco LP Cash DistributionsEnergy Transfer owns approximately 28.5 million Sunoco LP common units and all of Sunoco LP’s IDRs. As of December 31, 2024, Sunoco LP had approximately 136.2 million common units outstanding. The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” 124 Table of Contents Index to Financial Statements The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.Marginal Percentage Interest in Distributions Total Quarterly Distribution Target Amount Common Unitholders Holder of IDRs Minimum Quarterly Distribution $0.4375 100% —% First Target Distribution $0.4375 to $0.503125 100% —% Second Target Distribution $0.503125 to $0.546875 85% 15% Third Target Distribution $0.546875 to $0.656250 75% 25% Thereafter Above $0.656250 50% 50%Distributions on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows:Quarter Ended Payment Date Rate December 31, 2022 February 21, 2023 $ 0.8255 March 31, 2023 May 22, 2023 0.8420 June 30, 2023 August 21, 2023 0.8420 September 30, 2023 November 20, 2023 0.8420 December 31, 2023 February 20, 2024 0.8420 March 31, 2024 May 20, 2024 0.8756 June 30, 2024 August 19, 2024 0.8756 September 30, 2024 November 19, 2024 0.8756 December 31, 2024 February 19, 2025 0.8865The total amount of distributions to the Partnership from Sunoco LP for the periods presented below is as follows: Years Ended December 31,2024 2023Distributions from Sunoco LP Limited Partner interests$ 100 $ 96General Partner interest and IDRs145 77Total distributions from Sunoco LP$ 245 $ 173USAC Cash DistributionsEnergy Transfer owns approximately 46.1 million USAC common units. As of December 31, 2024, USAC had approximately 117 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs. 125Table of Contents Index to Financial StatementsDistributions on USAC’s units declared and/or paid by USAC were as follows: Quarter Ended Payment Date Rate December 31, 2022 February 3, 2023 $ 0.5250 March 31, 2023 May 5, 2023 0.5250 June 30, 2023 August 4, 2023 0.5250 September 30, 2023 November 3, 2023 0.5250 December 31, 2023 February 2, 2024 0.5250 March 31, 2024 May 3, 2024 0.5250 June 30, 2024 August 2, 2024 0.5250 September 30, 2024 November 1, 2024 0.5250 December 31, 2024 February 7, 2025 0.5250The total amount of distributions to the Partnership from USAC for the periods presented below is as follows: Years Ended December 31,2024 2023Distributions 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, 2024 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 126Table of Contents Index to Financial Statementsshould 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, 2024, 2023 and 2022, the Partnership recorded total assets of approximately $11.36 billion, $9.71 billion and $1.38 billion, respectively, in connection with business combinations. 127Table of Contents Index to Financial StatementsDuring the years ended December 31, 2024, 2023 and 2022, the Partnership recorded impairments totaling $52 million, $12 million and $386 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.” 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, 2024 and 2023, accruals of $281 million and $285 million, respectively, were reflected in our consolidated balance sheets related to these contingent obligations.For more information on our litigation and contingencies, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this annual report. Environmental Remediation Activities. The 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 $278 million and $277 million in environmental accruals as of December 31, 2024 and 2023, 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 128Table of Contents Index to Financial Statementsadverse 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 $197 million have been included in Energy Transfer’s consolidated balance sheet as of December 31, 2024. The state NOL carryforward benefits of $81 million ($64 million net of federal benefit) began expiring in 2024 with a substantial portion expiring between 2033 and 2039. Energy Transfer’s corporate subsidiaries have federal NOLs of $537 million ($113 million in benefits), all of which was generated in 2018 or later. 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. A foreign subsidiary of Sunoco LP had a net operating loss of $56 million ($15 million in benefits) which 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;129 Table of Contents Index to Financial Statements• actions taken by foreign oil and gas producing nations; • the political and economic stability of petroleum producing nations; • the effect of weather conditions on demand for oil, natural gas and NGLs; • availability of local, intrastate and interstate transportation systems; • the continued ability to find and contract for new sources of natural gas supply; • availability and marketing of competitive fuels; • the impact of energy conservation efforts; • energy efficiencies and technological trends;• governmental regulation, taxation and tariffs;• changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines; • hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs; • competition from other midstream companies and interstate pipeline companies; • loss of key personnel; • loss of key natural gas producers or the providers of fractionation services; • reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries pipelines and facilities; • the effectiveness of risk-management policies and procedures and the ability of our subsidiaries liquids marketing counterparties to satisfy their financial commitments; • the nonpayment or nonperformance by our subsidiaries’ customers; • risks related to the development of new infrastructure projects or other growth projects, including failure to make sufficient progress to justify continued development, delays in obtaining customers, increased costs of financing and regulatory, environmental, political and legal uncertainties that may affect the timing and cost of these projects; • risks associated with the construction of new pipelines, treating and processing facilities or other facilities, or additions to our subsidiaries’ existing pipelines and their facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors; • the availability and cost of capital and our subsidiaries’ ability to access certain capital sources; • a deterioration of the credit and capital markets; • risks associated with the assets and operations of entities in which our subsidiaries own a noncontrolling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence; • the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses; • changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; • the costs and effects of legal and administrative proceedings; and• risks associated with a potential failure to successfully combine our business with those of companies we have acquired or may acquire in the future.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.130 Table of Contents Index to Financial Statements