ET 10-K & 10-Q changes, risk factors and insider trading

•general economic, financial and political conditions, including the impact of tariffs, to the extent enactedtariffs;

•any increased costs or reduced demand for crude oil and natural gas as a result of thepolicy Inflation Reduction Act of 2022 (“IRA 2022”)changes or otherwise;

•failure to execute our growth strategy due to increased competition within any of our core businesses; and

•failure to attract and retain qualified employees; andemployees.

•failure to recover the full amount of increases in the costs of our pipeline or refinery operations;

•fiduciary duties owed to SunocoCorp, Sunoco LP, USAC and their respective unitholders by their managing member or general partnerspartners, as applicable; and

The following discussion provides additional information regarding each of our risk factors listed above. In addition, SunocoCorp, Sunoco LP and USAC file Annual Reports on Form 10-K that include risk factors that can be reviewed for further information.

•the price of natural gas, NGLs, crude oiloil, feedstock at Sunoco LP’s refining operations and refined products;

•the level of competition from other midstream, transportation and storage and retail marketing companiescompanies, refinery operators and other energy providers;

•debt service requirementsrequirements, distributions and other liabilities;

•the level of domestic natural gas, NGL,NGLs, refined products and oil production;

•the level of natural gas, NGL,NGLs, refined products and oil imports and exports, including liquefied natural gas;

•the impact of weather, geopolitical events such as the armed conflictconflicts in Ukraine and Venezuela, political instability in the Middle East, including Iran, public health crises, and other events of nature on the demand for natural gas, NGLs, refined products and oil;

General economic, financial, and political conditions, including the impact of tariffs to the extent enacted,tariffs, 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, followingon March 12, 2025, the electionU.S. government imposed a 25% tariff on steel imports, which was increased to 50% on June 4, 2025, and on April 2, 2025, the U.S. government announced a 10% tariff on product imports from almost all foreign countries and individualized higher tariffs on certain other countries. Several tariff announcements have been followed by announcements of Presidentlimited Trumpexemptions and thetemporary implementationpauses. ofThese certainactions tariffs,have itcaused uncertainty and volatility in financial markets and may result in retaliatory measures on U.S. goods. It is possible that our operations may be affected by the resulting 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 botheach of our business segments.

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.projects, and our maintenance capital expenditures, potentially in excess of budgeted amounts.

Recently,On March 12, 2025 the TrumpU.S Administrationgovernment announcedimposed plansa 25% tariff on steel imports, which was increased to implement50% oron increaseJune tariffs,4, 2025, and on FebruaryApril 10,2, confirmed2025, extensionthe ofU.S 25government percentannounced importa 10% tariff on product imports from almost all countries and individualized higher tariffs on steelcertain globallyother tocountries. goSeveral intotariff effectannouncements have been followed by announcements of limited exemptions and temporary pauses. These actions have caused uncertainty and volatility in financial markets and may result in retaliatory measures on MarchU.S 12.goods. The ultimate impact of thisthese tarifftariffs 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.

The U.S. inflation rate steadilyremained roserelatively stable through 2024 and 2025, after an extended period of rising rates, which began in 2021 and into 2022 before eventually declining modestly throughout 2023 and 2024.2022. A sustained increase in inflation may continue to increase our costs for labor, services,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,market 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.disruptions. 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 costs, operating margins, 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 100 basis points in late 2024, and 75 basis points in late 2024,2025, the prospect of additional interest rate cuts remains uncertain and 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.

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 decisionexpansions 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 twofew 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.

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,position or cash flows.

In August 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA 2022,2022”), 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 imposesamended 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. TheHowever, methanethe emissionsOne chargeBig startedBeautiful inBill calendarAct year(“OBBBA”) 2024amended atthe $900Clean perAir ton of methane, increasedAct to $1,200postpone inthe 2025, and will be set at $1,500 for 2026 and each year after. Calculationimplementation of the fee isuntil based2034. onAlthough certainthe thresholdsOBBBA establishedmade invarious changes to the incentives created under the IRA 2022.2022, Inincluding addition,elimination of electric vehicle credits, if the multiple incentives offered for various clean energy industries referenced above are pursued in the future, it could further accelerate the transition of the economy away from the use of fossil fuels and decrease demand for crude oilgasoline and natural gas,diesel, 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.

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.

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,On January 20, 2025, President Trump issued an executive order rescinding the Departmentsuspension; ofhowever, litigation challenging 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 reductionrescission 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 theU.S. 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 ruleAlaska 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.ongoing.

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. CommentsIn toDecember 2025, the Draft EIS were due on December 13, 2023. The USACE anticipates thatissued a Final EIS willconcluding bethat the USACE’s preferred alternative is that the USACE reissue its easement to DAPL subject to additional easement conditions. The USACE has not yet issued in December 2025 and a Record of Decision willwith beDAPL’s issuedeasement, but it is expected to issue 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.

By an order issued on January 16, 2019, the FERC initiated a review of Panhandle’s then existingthen-existing rates pursuant to Section 5 of the Natural Gas ActNGA 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.NGA. The Natural Gas ActNGA 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 UnitedD.C. States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”),Circuit, and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the CourtD.C. of AppealsCircuit 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 CourtD.C. of AppealsCircuit 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 CourtD.C. of AppealsCircuit 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 CourtD.C. of AppealsCircuit 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. TheOn requestMarch 24, 2025, Panhandle petitioned the D.C. Circuit for rehearingreview willof bethe addressedDecember 5, 2024 and February 3, 2025 orders. On April 4, 2025, the FERC issued an Order on Rehearing and Clarification. On May 16, 2025, Panhandle petitioned the D.C. Circuit for review of the April 4, 2025 order. On May 19, 2025, the D.C. Circuit consolidated all cases before it and placed the consolidated cases in abeyance pending further order of the D.C. Circuit. On August 12, 2025, the D.C. Circuit issued an order returning all cases to the court’s active docket and issued a futurebriefing order.schedule. Panhandle filed its initial brief on November 10, 2025, and FERC’s brief is due on February 9, 2026.

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. TheOn September 12, 2025, the FERC hasissued takenan noorder further action onwithdrawing the 2022 Certificate Policy Statement. We are unable to predict what, if any, changes may be proposed as a result of thedraft 2022 Certificate Policy Statement thatand 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 interminating the United States.proceeding.

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 proposesproposed a reduction to the currently effective index by one percent. TheOn November 20, 2025, FERC withdrew the Supplemental NOPR,NOPR whichand remainsconfirmed pendingthat beforethe FERC,PPI-FG-0.78% couldindex resultestablished in theDecember reimplementation2020 will remain in place through June 30, 2026. On the same day, FERC approved limited relief for pipelines. Oil pipelines with index-based rates may recover applicable rate differences from March 1, 2022 to September 17, 2024 but only if such pipelines charged the maximum rate allowed under the applicable index ceiling during the relevant time period. Parties have since filed requests for clarification or rehearing, as well as court appeals, to determine whether pipelines may recover rate differences in other scenarios. Also on November 20, 2025, FERC issued a notice-and-commentNotice rulemakingof Proposed Rulemaking for the Five-Year Review of the sameOil rulingsPipeline thatIndex wereproposing vacatedan byindex level of Producer Price Index for Finished Goods (PPI-FG) minus 1.42% for the D.C.period Circuitfrom inJuly LEPA1, v.2026 FERC.to June 30, 2031.

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 20232024 to $266,015$272,926 per violation per day, with a maximum of $2,660,135$2,729,245 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. TheIn October 2025, members of Congress introduced the Pipeline Safety Act of 2025, which would reauthorize appropriations for PHMSA and modernize pipeline 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.regulations.

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.

In addition, we own investments in other businesses, including Sunoco LP and USAC, both of which are master limited partnerships.partnerships, and we own the managing member of SunocoCorp, a publicly traded limited liability company.

Other AcquisitionAcquisitions

OnIn Augustthe 30,third 2024,quarter of 2025, Sunoco LP acquired aapproximately terminal70 fuel distribution consignment sites and 100 supply agreements in Portland,five Maineseparate transactions for total cash consideration of approximately $24$85 million, includingplus working capital.

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 StatesU.S. Court of Appeals for the District of Columbia Circuit (“D.C. 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-taxincome 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 ColumbiaD.C. 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 ROEreturn on equity 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 existingthen-existing rates pursuant to Section 5 of the Natural Gas ActNGA 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.NGA. The Natural Gas ActNGA 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 UnitedD.C. States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”),Circuit, and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the CourtD.C. of AppealsCircuit 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 CourtD.C. of AppealsCircuit 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 CourtD.C. of AppealsCircuit 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 CourtD.C. of AppealsCircuit 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. TheOn requestMarch 24, 2025, Panhandle petitioned the D.C. Circuit for rehearingreview willof bethe addressedDecember 5, 2024 and February 3, 2025 orders. On April 4, 2025, the FERC issued an Order on Rehearing and Clarification. On May 16, 2025, Panhandle petitioned the D.C. Circuit for review of the April 4, 2025 order. On May 19, 2025, the D.C. Circuit consolidated all cases before it and placed the consolidated cases in abeyance pending further order of the D.C. Circuit. On August 12, 2025, the D.C. Circuit issued an order returning all cases to the court’s active docket and issued a futurebriefing order.schedule. Panhandle filed its initial brief on November 10, 2025, and FERC’s brief is due on February 9, 2026.

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 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 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. TheOn September 12, 2025, the FERC hasissued takenan noorder further action onwithdrawing the 2022 Certificate Policy Statement. We are unable to predict what, if any, changes may be proposed as a result of thedraft 2022 Certificate Policy Statement thatand 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 interminating the United States.proceeding.

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 CommissionFERC 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, the FERC issued a Supplemental NOPR that proposes a reduction to the currently effective index by one percent. TheOn November 20, 2025, the FERC withdrew the Supplemental NOPR,NOPR whichand remainsconfirmed pendingthat beforethe FERC,PPI-FG-0.78% couldindex resultestablished in theDecember reimplementation2020 will remain in place through June 30, 2026. On the same day, the FERC approved limited relief for pipelines. Oil pipelines with index-based rates may recover applicable rate differences from March 1, 2022 to September 17, 2024 but only if such pipelines charged the maximum rate allowed under the applicable index ceiling during the relevant time period. Parties have since filed requests for clarification or rehearing, as well as court appeals, to determine whether pipelines may recover rate differences in other scenarios. Also on November 20, 2025, the FERC issued a notice-and-commentNotice rulemakingof Proposed Rulemaking for the Five-Year Review of the sameOil rulingsPipeline thatIndex wereproposing vacatedan byindex level of Producer Price Index for Finished Goods (PPI-FG) minus 1.42% for the D.C.period Circuitfrom inJuly LEPA1, v.2026 FERC.to June 30, 2031.

In 2023, the United StatesU.S. 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. However, on March 12, 2025, the EPA announced plans to end the Plan.

Operators 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. ProceedingsOn asJune to18, both on2025, the meritsU.S. Supreme Court ruled that the regional circuits are ongoing.the Inappropriate venue for the challengeproceedings. toOn July 30, 2025, the Court of Appeals for the Tenth Circuit placed the case in abeyance pending the EPA’s reconsideration of its disapproval of upwind states’ state implementation plans addressing their Plan obligations. Proceedings challenging the Plan in the D.C. Circuit,Circuit oralwere argumentalso placed in abeyance on May 2, 2025 pending the EPA’s reconsideration of the Plan. The EPA is expectedpreparing a proposed rulemaking as part of the reconsideration process, and on January 27, 2026, the EPA announced its proposal to approve state implementation plans for eight states, including those in earlywhich 2025we andoperate, awhich decisionwould couldresolve takethose severalstates’ months,obligations projectedunder latethe 2025.Good Neighbor Plan. We cannot predict with any certainty the substance of any later proposed rule or the potential impacts on the Partnership.

The Partnership currently estimates that the existing 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 DCD.C. 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.

For 20252026 and beyond, we expect increasedcontinued increasing 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,environment, 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. InOur responsepreviously toannounced marketoutlook volatilityincludes andan otherexpected uncertainties,increase we have reducedin growth capital spendingexpenditures up to a range of $5.0 billion to $5.5 billion in recent2026, years.primarily on projects enhancing the Partnership’s natural gas and NGL networks. While we anticipate a healthy capital expenditure program in 20252026 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 2025.2026.

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 debtdebt, certain foreign currency transaction gains and losses and other non-operating income or expense items, as well as certain non-recurring gains and losses. Inventory valuation 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, as reported for each segment in the following table, is analyzed for each segment 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.

Net Income. For the year ended December 31, 20242025 compared to the prior year, net income increaseddecreased $1.27$857 billion,million, or approximately 24%,13%, primarily due to the recognition of a $586 million gain onrecognized by Sunoco LP’sLP on its sale of its West Texas assets in the currentprior year, asa well$517 asmillion theincrease recognitionin depreciation, depletion and amortization and a $349 million increase in interest expense, net of ainterest $627 million non-operating litigation-related loss in the prior year. The change in net income also reflected higher segment margin from multiple segments,capitalized, partially offset by increasesa $501 million increase in operatingAdjusted expenses,EBITDA, selling,a general$191 andmillion administrativedecrease expenses, depreciation, depletion and amortization, impairment losses, interest expense andin income tax expense; theseand a $186 million favorable impact from unrealized gains and losses on commodity risk management activities. These changes are discussed in more detail below and in “Segment Operating Results.”below.

Adjusted EBITDA (consolidated). For the year ended December 31, 20242025 compared to the prior year, Adjusted EBITDA increased $1.79$501 billion,million, or approximately 13%,3%, primarily due to favorable results in multiple segments. The most significant increases were in our midstream segment, our interstate transportation and storage segment and our investment in Sunoco LP segment, partially offset by decreases in our intrastate transportation and storage segment and 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.

Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, increased primarily due to higheran increase in aggregate debt balances andfollowing higherthe interestacquisitions ratesof onNuStar, floating rateParkland and recentlyWTG refinancedMidstream Holdings LLC and the refinancing of certain preferred units with long-term debt.

Income Tax Expense. For the year ended December 31, 20242025 compared to the same period last year, income tax expense increaseddecreased primarily due to thea taxable gain recognized by a corporate subsidiary of Sunoco LP onupon its completion of the sale of Westconvenience Texasstores assets.to 7-Eleven, Inc. in 2024.

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-Eleven7-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.

Volumes. For the year ended December 31, 20242025 compared to the prior year, transported volumes of gas on our Texas and Oklahoma intrastate pipelines decreasedincreased primarily due to lessmore third-party transportation and decreased gas production from the Haynesville area.transportation. 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.

On January 16, 2026, Sunoco LP completed the previously announced acquisition of TanQuid for €206 million ($239 million) and assumed debt with a fair value of €298 million ($346 million ). TanQuid owns and operates 15 fuel terminals in Germany and one fuel terminal in Poland. The transaction was funded using cash on hand and amounts available under Sunoco LP’s Creditcredit Facility.facility.

In the first quarterand second quarters of 2026, Sunoco LP completed other acquisitions for total cash considerationsconsideration of approximately $50 million and $22 million, respectively, plus working capital. These transactions were accounted for as asset acquisitions.

On January 12, 2026, USAC completed the acquisition of J-W Energy Company (“J-W Energy”) and its subsidiary, J-W Power Company (“J-W Power”), a large privately-held provider of compression services in the United States. USAC purchased all of the issued and outstanding capital stock of J-W Energy from Westerman, Ltd. (the “J-W Power Acquisition”). USAC completed the acquisition for a total consideration of approximately $912 million, subject to customary purchase price adjustments, consisting of (i) approximately $455 million in cash and (ii) approximately 18.2 million newly issued USAC common units, which had a fair value on the J-W Power Acquisition date of approximately $457 million, subject to customary post-closing price adjustments. Upon consummation of the J-W Power Acquisition, J-W Power and J-W Energy became consolidated subsidiaries of the Partnership.USAC.

In AprilJuly 2026, Energy Transfer announced a quarterly distribution of $0.3375$0.3400 per unit ($1.35$1.36 annualized) on Energy Transfer common units for the quarter ended MarchJune 31,30, 2026.

Even without application of the FERC’s rate making-relatedratemaking-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 ROEreturn on equity 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 existingthen-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 D. C.D.C. Circuit, and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the D. C.D.C. Circuit 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 D. C.D.C. Circuit 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 D. C.D.C. Circuit 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 order 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 D. C.D.C. Circuit 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. On March 24, 2025, Panhandle petitioned the D. C.D.C. Circuit for review of the December 5, 2024 and February 3, 2025 orders. On April 4, 2025, the FERC issued an Order on Rehearing and Clarification. On May 16, 2025, Panhandle petitioned the D.C. Circuit for review of the April 4, 2025 order. On May 19, 2025, the D.C. Circuit consolidated all cases before it and placed the consolidated cases in abeyance pending further order of the D.C. Circuit. On August 12, 2025, the D.C. Circuit issued an order returning all cases to the court’s active docket and issued a briefing schedule. Panhandle filed its initial brief on November 10, 2025, FERC filed its brief on February 9, 2026, intervenors filed their brief on February 23, 2026, and Panhandle filed its reply brief on March 16, 2026. Oral argument is scheduled for September 24, 2026.

In December 2020, FERC issued an order setting the indexed rate at the Producer Price Index for Finished Goods (PPI-FG) plus 0.78% during the five-year period commencing July 1, 2021 and ending June 30, 2026. The FERC received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates were permitted to adjust their indexed ceilings annually by PPI-FG minus 0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period July 1, 2022 through June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceeded 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, 2022 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, 2022 order modified the index without following notice and comment. As a result, the D.C. Circuit vacated the January 20, 2022 order and on September 17, 2024, the Commission reinstated the index level established by its original December 17, 2020 order, directed pipelines to file an informational filing to show their recomputed ceiling levels reflecting the reinstated index level and stated that pipelines could file to prospectively increase their indexed rates to their recomputed levels. On October 17, 2024, FERC issued a Supplemental Notice of Proposed Rulemaking (“Supplemental NOPR”) that proposed a reduction to the then- effective index by one percent.

Also on November 20, 2025, the FERC issued a Notice of Proposed Rulemaking on the 2026 Five-Year Oil Pipeline Index (“2026 Index NOPR”), proposing to use the Producer Price Index for Finished Goods (PPI-FG) minus 1.42% as the index level beginning July 1, 2026 to June 30, 2031. The NOPR proceeded through the standard notice-and-comment process, with comments submitted in late 2025 and early 2026, and remains pending final Commission action.2026.

Separately, on December 15, 2022, the FERC had issued a Proposed Policy Statement on Oil Pipeline Affiliate Committed Service, which addressesaddressed whether a contract for committed transportation service complies with the ICA where the only shipper to obtain the committed service is an affiliate of the regulated entity. If adopted, theThe proposed policy statement would createhave created a rebuttable presumption that affiliate contracts are unduly discriminatory and not just and reasonable in certain circumstances and requirerequired a pipeline to produce additional evidentiary support for affiliate contracts rates and terms. ThisOn followsFebruary a19, trend2026, of increased scrutiny bythe FERC on affiliated contracts across all industries regulated by the FERC. The FERC has taken no further action onwithdrew the proposed policy statement on the basis that the record contained insufficient evidence of discriminatory open season terms and conditions to merit an industry-wide policy statement. FERC noted, however, that it would continue to address issues related to affiliated-only committed service in individual proceedings.

Operators 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.United States Supreme Court, or by the administrative stay issued by the EPA in October 2024. On June 18, 2025, the U.S.United States Supreme Court ruled that the regional circuits are the appropriate venue for the proceedings. On July 30, 2025, the Court of Appeals for the Tenth Circuit placed the case in abeyance pending the EPA’s reconsideration of its disapproval of upwind states’ state implementation plans addressing their Plan obligations. Proceedings challenging the Plan in the D.C. Circuit were also placed in abeyance on May 2, 2025 pending the EPA’s reconsideration of the Plan. The EPA is preparing a proposed rulemaking as part of the reconsideration process, and on January 27, 2026, the EPA announced its proposal to approve state implementation plans for eight states, including those in which we operate, which would resolve those states’ obligations under the Good Neighbor Plan. We cannot predict with any certainty the substance of any later proposed rule or the potential impacts on the Partnership.

The Partnership currently estimates that the existing final rule regarding the Plan 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 D.C. Circuit and the U.S.United States Supreme Court, we cannot predict with any certainty what the final costs of compliance for the Plan for the Partnership ultimately may be.

The acquisition of Parkland brings the Partnership into scope for Pillar Two global minimum tax. Several jurisdictions in which we now operate have enacted legislation implementing the Organization for Economic Co-operation and Development ("OECD") Pillar Two global minimum tax framework. These rules generally impose a 15% minimum top-up tax on the profits of large multinational enterprises. Sunoco LP estimates its Pillar Two global minimum tax expense to be immaterial in 2026 and has not accrued any current tax expense related to Pillar Two induring the quarter.six months ended June 30, 2026.

On January 5, 2026, the OECD released new guidance that provides relief for U.S. parented multinationals and establishes a side-by-side framework for the U.S. tax system to coexist with Pillar Two global minimum tax. Effective for fiscal years beginning on or after January 1, 2026, U.S. parented multinationals would be exempt from the main charging provisions of Pillar Two. Sunoco LP will continue to estimate and potentially accrue Pillar Two global minimum tax until the relevant jurisdictions in which Sunoco LP operates enact the side-by-side framework in tointo law.

Net Income. For the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods last year, net income increased by$1.07 $256billion million,and or$1.33 approximatelybillion, 15%,respectively, primarily due to higher segment margin from multipleall our segments. The most significant increases were in (i) our intrastate transportation and storage segment, where segment margin was favorably impacted by wider pricebasis spreadsdifferentials and favorableearly impactsvolumes from optimization,the commissioning of the Hugh Brinson Pipeline, (ii) our midstream segment, where segment margin was favorably impacted by higher gathering and processing volumes, as well as higher NGL and natural gas prices, (iii) our NGL and refined products transportation and storage segment, where segment margin benefited from higher premiums from the sale of NGLs for export and for domestic supply and from higher spreads and prices, (iv) our crude oil transportation and services segment, where segment margin was favorable due to market conditions, higher crude oil prices and higher throughput,volumes and (iiiv) our investment in Sunoco LP segment, where segment margin included increases resulting from recent acquisitions and strategic transactions. The increase in segment margin was partially offset by increases in operating expenses, selling, general and administrative expenses, depreciation, depletion and amortization and interest expense. These changes are discussed in more detail below and in “Segment Operating Results.”

Adjusted EBITDA (consolidated). For the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods last year, Adjusted EBITDA increased by $839$1.20 million,billion orand approximately$2.04 20%,billion, respectively, primarily due to increases in our intrastate transportation and storage segment, midstream segment, NGL and refined products transportation and services segmentsegment, crude oil and transportation and services segment, and our investment in Sunoco LP segment.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased for the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods last year 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 for the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods last year primarily due to an increase in aggregate debt balances following the acquisition of Parkland and the refinancing of certain preferred units with long-term debt.

Impairment Loss.Losses. For the three and six months ended MarchJune 31,30, 2025, the impairment losslosses waswere related to USAC’s evaluation of the future deployment of its idle fleet under current market conditions.

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 gain and loss within each segment is included in “Segment Operating Results,” and additional information on the commodity-related derivatives, including notional volumes, maturities and fair values, is available in “Item 3. Quantitative and Qualitative Disclosures About Market Risk” and in Note 12 to our consolidated financial statements included in “Item 1. Financial Statements.”

Inventory Valuation Adjustments. Inventory valuation adjustments represent changes in lower of cost or market reserves using the LIFO 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 three months ended MarchJune 31,30, 2026 and 2025, the Partnership’s cost of products sold included Sunoco LP’s unfavorable inventory valuation adjustments of $18 million and $40 million, respectively, which decreased net income. For the six months ended June 30, 2026 and 2025, the Partnership’s cost of products sold included Sunoco LP’s favorable LIFO inventory valuation adjustments of $444$426 million and $61$21 million, respectively, which increased net income.

Losses on Extinguishments of Debt. For the three and six months ended MarchJune 31,30, 2025,2026, loss on extinguishment of debt was due to Sunoco LP's redemption of senior notes. For the three and six months ended June 30, 2025, loss on extinguishment of debt was primarily related to Sunoco LP’s termination of bridge financing related to the Parkland acquisition.

Volumes. For the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods last year, transported volumes of gas on our Texas intrastate pipelines decreased primarily due to lower third-party utilization of firm capacity. 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.

Segment Adjusted EBITDA. For the three months ended MarchJune 31,30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impact of the following:

•an increase of $54$113 million in realized natural gas sales and other primarily due to wider basis differentialsdifferentials, as well as a $21 million increase from early volumes during the commissioning of the Hugh Brinson Pipeline; and

•an increase of $6$5 million in transportation fees primarily due to higher reservation revenues on long-term third-party contracts; andpartially offset by

•ana increasedecrease of $2$10 million in retained fuelstorage margin due to favorableunfavorable gasstorage pricingoptimization; partially offset by

•an increase of $8$14 million in operating expenses primarily due to a $3$4 million increase in corporatemaintenance allocations,and project related expenses, a $4 million increase from one-time expenses, a $4 million increase from the commissioning of the Hugh Brinson pipeline, and increases totaling $2 million increasefrom invarious maintenance,other operating expenses; and a $1 million increase in employee costs.

Volumes. For the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods last year, transported volumes decreased primarily due to lower utilization on several of our interstateTrunkline, pipelineGulf Run and Mississippi River systems due to lower demand.

Segment Adjusted EBITDA. For the three months ended MarchJune 31,30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impact of the following:

•an increase of $12$18 million in segment margin primarily due to a $23$12 million increase in parking, storage and liquids revenue and a $10 million increase in transportation revenue from several of our interstate pipeline systems due to higher contracted volumes atand higher rates,utilization, partially offset by a $6 million decrease in storage and parking revenue, and a $3$4 million decrease in operational gas sales; and

•an increase of $14$9 million in Adjustedoperating EBITDA related to unconsolidated affiliatesexpenses primarily due to a $7$4 million increase fromin ourmaintenance Citrus joint venture,projects, a $5$3 million increase fromin ouremployee Midcontinent Express Pipeline joint venturecosts and a $2$1 million increase fromin ournew Southeastor Supplyrenegotiated Header joint ventureleases; partially offset byand

•an increase of $26$30 million in operatingsegment expensesmargin primarily due to a $10$33 million increase in transportation expense,revenue from several of our interstate pipeline systems due to higher contracted volumes and higher utilization, and a $5 million environmental claim settlement and an aggregate $10 million increase in various other items, including maintenance projectsstorage and employeeliquids costs.revenue, partially offset by a $7 million decrease in operational gas sales;

Volumes. For the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods last year, volumes increased from dry gas gathering in the Northeast and Ark-La-Tex regions as well as increased processing volumes from new and upgraded plants in the Permian region. NGL production increased primarily due to increased Permian plant utilization.utilization from new and existing plants.

Segment Adjusted EBITDA. For the three months ended MarchJune 31,30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment decreasedincreased due to the net impact of the following: