(Tabular dollar and unit amounts, except per unit data, are in millions) The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with (i) our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q; and (ii) the consolidated financial statements and management’s discussion and analysis of financial condition and results of operations included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2025 filed with the SEC on February 19, 2026. 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 “Part I – Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2025 filed with the SEC on February 19, 2026. Additional information on forward-looking statements is discussed in “Forward-Looking Statements.” Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “Energy Transfer” mean Energy Transfer LP and its consolidated subsidiaries. RECENT DEVELOPMENTS Acquisitions TanQuid Acquisition by Sunoco LP On January 16, 2026, Sunoco LP completed the 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 credit facility. Delta Acquisition by Sunoco LP On April 1, 2026, Sunoco LP completed the acquisition of Delta Petroleum Group (BVI) Limited (“Delta”) for approximately $81 million, excluding cash and net working capital. Delta owns and operates terminals and fuel distribution assets across five Caribbean markets. The transaction was funded using cash on hand and amounts available under Sunoco LP's credit facility. Other Sunoco LP Acquisitions In the first and second quarters of 2026, Sunoco LP completed other acquisitions for total cash consideration of approximately $50 million and $22 million, respectively, plus working capital. These transactions were accounted for as asset acquisitions. On August 5, 2026, Sunoco LP entered into a definitive agreement to acquire a U.S.-based fuel distribution network in an all-cash transaction valued at approximately $600 million. The transaction is expected to close in the fourth quarter of 2026, subject to customary closing conditions. J-W Power Company Acquisition by USAC 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 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 USAC. The J-W Power Acquisition added approximately 0.8 million active horsepower and 1.0 million total horsepower to USAC’s fleet across key regions including the Northeast, Mid-Con, Rockies, Gulf Coast, Bakken and Permian Basin. J‑W Power also owns and operates specialized manufacturing facilities that support its internal compression requirements and those of third‑party customers. Quarterly Cash Distribution In July 2026, Energy Transfer announced a quarterly distribution of $0.3400 per unit ($1.36 annualized) on Energy Transfer common units for the quarter ended June 30, 2026. 43 Table of Contents 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 ratemaking-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 return 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-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. Circuit, and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the 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. 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. 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, 44 Table of Contents 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. 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. 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. Pipeline Certification The FERC issued a Notice of Inquiry (“NOI”) on April 19, 2018, thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. 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 Natural Gas Act of 1938. 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 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. On September 12, 2025, the FERC issued an order withdrawing the draft 2022 Certificate Policy Statement and terminating the proceeding. Interstate Common Carrier Regulation Liquids pipelines transporting in interstate commerce are regulated by FERC as common carriers under the Interstate Commerce Act (“ICA”). Under the ICA, the FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. Many existing pipelines utilize the FERC liquids index to change transportation rates annually. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’s indexing methodology is subject to review every five years. 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 45 Table of Contents 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. On November 20, 2025, FERC withdrew the Supplemental NOPR and confirmed that the PPI-FG-0.78% index established in its December 17, 2020 order will remain in effect through June 30, 2026. On the same day, FERC issued an Order Denying Rehearing of the Reinstatement Order and Granting Remedial Relief (“Remedial Relief Order”), which granted remedial relief to liquids pipelines for the period of March 1, 2022 to September 17, 2024 (the “Locked-In Period”), when the lower index was effective under the order vacated by the D.C. Circuit in LEPA v. FERC, 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. Those requests and appeals remain pending. 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. On December 18, 2025, the Commission issued an Order Denying Petition for Emergency Relief (“Emergency Relief Order Denial”), which denied a petition requesting emergency relief from invoices issued by a liquid pipeline company to recover amounts of indexed rates for the Locked-In Period and explained that, consistent with the Remedial Relief Order, pipelines that charged the maximum rates permitted under the Commission’s now-vacated January 20, 2022 rehearing order during the Locked-In Period may invoice shippers to recover the amounts that would have been chargeable under the December 17, 2020 order. In January 2026, multiple shippers have filed petitions for review at the D.C. Circuit challenging FERC’s November 20, 2025 orders, including, the (i) Remedial Relief Order, (ii) Order Terminating Supplemental NOPR, and (iii) Emergency Relief Order Denial. These appeals are pending. On April 24, 2026, the FERC issued an order setting the indexed rate at PPI-FG minus 0.55% during the five-year period commencing July 1, 2026 through June 30, 2031 (“Index Order”). Following issuance of the final rule on April 24, 2026, shippers and other parties filed petitions for review with the D.C. Circuit challenging the Index Order. Those petitions are pending. Separately, on December 15, 2022, the FERC had issued a Proposed Policy Statement on Oil Pipeline Affiliate Committed Service, which addressed 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. The proposed policy statement would have created a rebuttable presumption that affiliate contracts are unduly discriminatory and not just and reasonable in certain circumstances and required a pipeline to produce additional evidentiary support for affiliate contracts rates and terms. On February 19, 2026, the FERC withdrew 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. On May 21, 2026, the FERC issued a notice of proposed rulemaking to revise its blanket certificate regulations to expand the scope and scale of projects that interstate natural gas pipelines may construct without a case-specific authorization order and to increase the cost limits for such projects, among other changes. Air Quality Standards In 2023, the 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 United States Supreme Court, or by the administrative stay issued by the EPA in October 2024. On June 18, 2025, the 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. 46 Table of Contents 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. Additionally, on April 4, 2026, the EPA published a final rule finalizing revisions to certain aspects of Subparts OOOOb/OOOOc under the Clean Air Act that provide greater flexibility in venting and flaring from oil and gas operations. The EPA continues to develop proposals to revise other aspects of Subparts OOOOb/OOOOc. 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 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. OECD Pillar Two Global Minimum Tax 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 during the 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 into law. 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 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 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 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. 47 Table of Contents Consolidated Results Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Change 2026 2025 Change Segment Adjusted EBITDA: Intrastate transportation and storage $ 377 $ 284 $ 93 $ 814 $ 628 $ 186 Interstate transportation and storage 481 470 11 1,000 982 18 Midstream 884 768 116 1,771 1,693 78 NGL and refined products transportation and services 1,308 1,033 275 2,471 2,011 460 Crude oil transportation and services 834 732 102 1,703 1,474 229 Investment in Sunoco LP 982 454 528 1,840 912 928 Investment in USAC 194 149 45 382 299 83 All other 6 (24) 30 22 (35) 57 Adjusted EBITDA (consolidated) $ 5,066 $ 3,866 $ 1,200 $ 10,003 $ 7,964 $ 2,039 Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Change 2026 2025 Change Reconciliation of net income to Adjusted EBITDA: Net income $ 2,530 $ 1,458 $ 1,072 $ 4,506 $ 3,178 $ 1,328 Depreciation, depletion and amortization 1,575 1,384 191 3,158 2,751 407 Interest expense, net of interest capitalized 934 865 69 1,881 1,674 207 Income tax expense 194 79 115 329 120 209 Impairment losses — 3 (3) — 7 (7) Non-cash compensation expense 46 33 13 88 70 18 Unrealized (gains) losses on commodity risk management activities (396) (100) (296) 140 (31) 171 Inventory valuation adjustments (Sunoco LP) 18 40 (22) (426) (21) (405) Losses on extinguishments of debt — 17 (17) 7 19 (12) Adjusted EBITDA related to unconsolidated affiliates 196 182 14 392 349 43 Equity in earnings of unconsolidated affiliates (108) (105) (3) (218) (197) (21) Other, net 77 10 67 146 45 101 Adjusted EBITDA (consolidated) $ 5,066 $ 3,866 $ 1,200 $ 10,003 $ 7,964 $ 2,039 Net Income. For the three and six months ended June 30, 2026 compared to the same periods last year, net income increased $1.07 billion and $1.33 billion, respectively, primarily due to higher segment margin from all our segments. The most significant increases were in (i) our intrastate transportation and storage segment, where segment margin was favorably impacted by wider basis differentials and early volumes from 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 volumes and (v) 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.” 48 Table of Contents Adjusted EBITDA (consolidated). For the three and six months ended June 30, 2026 compared to the same periods last year, Adjusted EBITDA increased by $1.20 billion and $2.04 billion, respectively, primarily due to increases in our intrastate transportation and storage segment, midstream segment, NGL and refined products transportation and services segment, crude oil and transportation and services segment, and our investment in Sunoco LP segment. Additional information on changes impacting net income and Adjusted EBITDA is available below and in “Segment Operating Results.” Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased for the three and six months ended June 30, 2026 compared to the same periods 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 June 30, 2026 compared to the same periods 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. Income Tax Expense. For the three and six months ended June 30, 2026 compared to the same periods last year, income tax expense increased primarily due to increased corporate earnings from recent acquisitions. Some of the recent acquisitions have subsidiaries that operate in foreign jurisdictions where those subsidiaries are subject to statutory income tax rates that are higher than the U.S. federal corporate income tax rate. Additionally, the income tax expense from those recent acquisitions was further increased due to the non-deductibility of a portion of foreign currency exchange losses in certain Canadian subsidiaries and losses incurred in certain foreign subsidiaries that operate in foreign jurisdictions that do not impose a corporate income tax. Impairment Losses. For the three and six months ended June 30, 2025, the impairment losses were 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 June 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 inventory valuation adjustments of $426 million and $21 million, respectively, which increased net income. Losses on Extinguishments of Debt. For the three and six months ended June 30, 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. Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operating Results.” Other, Net. Other, net primarily includes the amortization of regulatory assets and other income and expense amounts. 49 Table of Contents Supplemental Information on Unconsolidated Affiliates The following table presents financial information related to unconsolidated affiliates: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Change 2026 2025 Change Equity in earnings of unconsolidated affiliates: Citrus $ 38 $ 40 $ (2) $ 76 $ 73 $ 3 MEP 20 18 2 42 35 7 White Cliffs 7 5 2 11 8 3 Explorer 5 7 (2) 11 14 (3) SESH 14 14 — 30 28 2 Other 24 21 3 48 39 9 Total equity in earnings of unconsolidated affiliates $ 108 $ 105 $ 3 $ 218 $ 197 $ 21 Adjusted EBITDA related to unconsolidated affiliates (1): Citrus $ 87 $ 88 $ (1) $ 173 $ 167 $ 6 MEP 28 26 2 59 52 7 White Cliffs 12 10 2 21 18 3 Explorer 9 12 (3) 19 23 (4) SESH 15 15 — 32 30 2 Other 45 31 14 88 59 29 Total Adjusted EBITDA related to unconsolidated affiliates $ 196 $ 182 $ 14 $ 392 $ 349 $ 43 Distributions received from unconsolidated affiliates: Citrus $ 33 $ 36 $ (3) $ 33 $ 66 $ (33) MEP 30 29 1 59 55 4 White Cliffs 11 9 2 20 18 2 Explorer 5 10 (5) 12 15 (3) SESH 17 15 2 30 23 7 Other 30 25 5 50 44 6 Total distributions received from unconsolidated affiliates $ 126 $ 124 $ 2 $ 204 $ 221 $ (17) (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 gain or loss 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 50 Table of Contents in Segment Adjusted EBITDA; therefore, the unrealized loss is added back and the unrealized gain is 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. 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. The following analysis of segment operating results includes a measure of segment margin. 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. Intrastate Transportation and Storage Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Change 2026 2025 Change Natural gas transported (BBtu/d) 13,814 14,229 (415) 13,798 14,224 (426) Withdrawals from storage natural gas inventory (BBtu) 4,020 — 4,020 23,698 8,225 15,473 Revenues $ 596 $ 931 $ (335) $ 1,752 $ 2,225 $ (473) Cost of products sold 132 561 (429) 842 1,525 (683) Segment margin 464 370 94 910 700 210 Unrealized (gains) losses on commodity risk management activities (6) (21) 15 57 55 2 Operating expenses, excluding non-cash compensation expense (75) (61) (14) (140) (118) (22) Selling, general and administrative expenses, excluding non-cash compensation expense (15) (10) (5) (28) (24) (4) Adjusted EBITDA related to unconsolidated affiliates 8 5 3 13 11 2 Other 1 1 — 2 4 (2) Segment Adjusted EBITDA $ 377 $ 284 $ 93 $ 814 $ 628 $ 186 Volumes. For the three and six months ended June 30, 2026 compared to the same periods 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. 51 Table of Contents Segment Margin. The components of our intrastate transportation and storage segment margin were as follows: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Change 2026 2025 Change Transportation fees $ 222 $ 217 $ 5 $ 452 $ 441 $ 11 Natural gas sales and other (excluding unrealized gains and losses) 215 102 113 398 233 165 Retained fuel (excluding unrealized gains and losses) 8 7 1 23 18 5 Storage margin (excluding unrealized gains and losses and fair value inventory adjustments) 13 23 (10) 94 63 31 Unrealized losses on commodity risk management activities and fair value inventory adjustments 6 21 (15) (57) (55) (2) Total segment margin $ 464 $ 370 $ 94 $ 910 $ 700 $ 210 Segment Adjusted EBITDA. For the three months ended June 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 $113 million in realized natural gas sales and other primarily due to wider basis differentials, as well as a $21 million increase from early volumes during the commissioning of the Hugh Brinson Pipeline; and •an increase of $5 million in transportation fees due to higher reservation revenues on long-term third-party contracts; partially offset by •a decrease of $10 million in storage margin due to unfavorable storage optimization; •an increase of $14 million in operating expenses primarily due to a $4 million increase in maintenance 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 from various other operating expenses; and •an increase of $5 million in selling, general and administrative expenses primarily due to higher legal fees. For the six months ended June 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 $165 million in realized natural gas sales and other primarily due to wider basis differentials, as well as a $21 million increase from early volumes during the commissioning of the Hugh Brinson Pipeline; •an increase of $31 million in storage margin due to favorable impacts from increased price volatility; •an increase of $11 million in transportation fees primarily due to higher reservation revenues on long-term third-party contracts; and •an increase of $5 million in retained fuel margin due to favorable gas pricing; partially offset by •an increase of $22 million in operating expenses primarily due to an $8 million increase from the commissioning of the Huge Brinson pipeline, a $7 million increase in maintenance and project related expenses, a $3 million increase in employee costs, and increases totaling $5 million from various other operating expenses; and •an increase of $4 million in selling, general and administrative expenses primarily due to legal fees. 52 Table of Contents Interstate Transportation and Storage Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Change 2026 2025 Change Natural gas transported (BBtu/d) 17,988 18,153 (165) 18,053 18,178 (125) Natural gas sold (BBtu/d) 19 30 (11) 34 32 2 Revenues $ 609 $ 590 $ 19 $ 1,243 $ 1,211 $ 32 Cost of products sold 4 3 1 7 5 2 Segment margin 605 587 18 1,236 1,206 30 Operating expenses, excluding non-cash compensation, amortization and accretion expenses (230) (221) (9) (445) (410) (35) Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses (34) (26) (8) (64) (63) (1) Adjusted EBITDA related to unconsolidated affiliates 130 130 — 263 249 14 Other 10 — 10 10 — 10 Segment Adjusted EBITDA $ 481 $ 470 $ 11 $ 1,000 $ 982 $ 18 Volumes. For the three and six months ended June 30, 2026 compared to the same periods last year, transported volumes decreased primarily due to lower utilization on our Trunkline, Gulf Run and Mississippi River systems due to lower demand. Segment Adjusted EBITDA. For the three months ended June 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 $18 million in segment margin primarily due to a $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 and higher utilization, partially offset by a $4 million decrease in operational gas sales; and •an increase of $10 million in other income primarily due to the realization of proceeds from a shipper bankruptcy settlement; partially offset by •an increase of $9 million in operating expenses primarily due to a $4 million increase in maintenance projects, a $3 million increase in employee costs and a $1 million increase in new or renegotiated leases; and •an increase of $8 million in selling, general and administrative expenses primarily due to higher allocated costs, excise taxes and insurance expense. For the six months ended June 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 $30 million in segment margin primarily due to a $33 million increase in transportation revenue from several of our interstate pipeline systems due to higher contracted volumes and higher utilization, and a $5 million increase in storage and liquids revenue, partially offset by a $7 million decrease in operational gas sales; •an increase of $14 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to a $7 million increase from MEP due to higher revenue and lower operating expenses, a $6 million increase from Citrus due to higher revenue and lower operating expenses, and a $2 million increase from SESH due to higher revenue; and •an increase of $10 million in other income primarily due to the realization of proceeds from a shipper bankruptcy settlement; partially offset by •an increase of $35 million in operating expenses primarily due to a $9 million increase in employee costs, an $8 million increase in intercompany transportation expenses, an aggregate $6 million increase in maintenance projects, a $6 million increase from one-time expenses and allocated costs, and a $6 million increase in other direct costs. 53 Table of Contents Midstream Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Change 2026 2025 Change Gathered volumes (BBtu/d) 22,142 21,329 813 21,912 20,872 1,040 NGLs produced (MBbls/d) 1,243 1,181 62 1,201 1,135 66 Equity NGLs (MBbls/d) 72 64 8 68 62 6 Revenues $ 2,821 $ 3,135 $ (314) $ 5,865 $ 6,791 $ (926) Cost of products sold 1,392 1,911 (519) 3,066 4,171 (1,105) Segment margin 1,429 1,224 205 2,799 2,620 179 Operating expenses, excluding non-cash compensation expense (513) (416) (97) (959) (837) (122) Selling, general and administrative expenses, excluding non-cash compensation expense (52) (47) (5) (106) (103) (3) Adjusted EBITDA related to unconsolidated affiliates 5 6 (1) 10 11 (1) Other 15 1 14 27 2 25 Segment Adjusted EBITDA $ 884 $ 768 $ 116 $ 1,771 $ 1,693 $ 78 Volumes. For the three and six months ended June 30, 2026 compared to the same periods 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 from new and existing plants. Segment Adjusted EBITDA. For the three months ended June 30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impact of the following: •an increase of $205 million in segment margin primarily due to higher NGL prices of $88 million, a positive impact of $11 million from natural gas prices, and an $83 million increase due to higher gathered and processed volumes from increased processing capacity and operational efficiencies; and •an increase of $14 million in other income due to the realization of proceeds from a shipper bankruptcy settlement; partially offset by •an increase of $97 million in operating expenses primarily due to a $46 million increase related to environmental reserves, a $39 million increase related to the adjustment of certain estimates in the prior period and a $15 million increase in employee costs; and •an increase of $5 million in selling, general, and administrative expenses primarily due to higher corporate allocations. For the six months ended June 30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impact of the following: •an increase of $179 million in segment margin primarily due to a $168 million increase due to higher gathered and processed volumes from increased processing capacity and operational efficiencies, higher NGL prices of $66 million, a positive impact of $8 million from natural gas prices, a $39 million increase due to an intercompany imbalance that is completely offset within our NGL and refined products transportation and services segment, and a $14 million increase due to reduced third-party NGL transportation and fractionation costs from our Oklahoma processing facilities, partially offset by a $160 million decrease attributable to the non-recurring recognition of certain amounts associated with Winter Storm Uri in the prior period; and •an increase of $25 million in other income due to $15 million in proceeds from a shipper bankruptcy settlement and $11 million from the recognition of proceeds from a business interruption claim; partially offset by •an increase of $122 million in operating expenses due to a $44 million increase in environmental reserves, a $39 million increase related to the adjustment of certain estimates in the prior period, a $34 million increase in employee costs, and a $6 million increase related to assets placed in service; and •an increase of $3 million in selling, general, and administrative expenses primarily due to higher legal fees and insurance premiums. 54 Table of Contents NGL and Refined Products Transportation and Services Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Change 2026 2025 Change NGL transportation volumes (MBbls/d) 2,641 2,331 310 2,534 2,254 280 Refined products transportation volumes (MBbls/d) 574 599 (25) 581 587 (6) NGL and refined products terminal volumes (MBbls/d) 1,864 1,553 311 1,795 1,503 292 NGL fractionation volumes (MBbls/d) 1,188 1,150 38 1,197 1,120 77 Revenues $ 7,719 $ 5,941 $ 1,778 $ 14,392 $ 12,850 $ 1,542 Cost of products sold 5,927 4,635 1,292 11,411 10,276 1,135 Segment margin 1,792 1,306 486 2,981 2,574 407 Unrealized (gains) losses on commodity risk management activities (185) (34) (151) 103 (60) 163 Operating expenses, excluding non-cash compensation expense (284) (230) (54) (582) (477) (105) Selling, general and administrative expenses, excluding non-cash compensation expense (48) (41) (7) (96) (89) (7) Adjusted EBITDA related to unconsolidated affiliates 31 32 (1) 62 63 (1) Other 2 — 2 3 — 3 Segment Adjusted EBITDA $ 1,308 $ 1,033 $ 275 $ 2,471 $ 2,011 $ 460 Volumes. For the three and six months ended June 30, 2026 compared to the same periods last year, NGL transportation, fractionation, and terminal throughput volumes increased due to higher volumes from the Permian region, as well as increased NGL exports. Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Change 2026 2025 Change Transportation margin $ 724 $ 696 $ 28 $ 1,345 $ 1,318 $ 27 Fractionators and refinery services margin 256 244 12 534 462 72 Terminal services margin 322 251 71 582 484 98 Storage margin 87 75 12 176 156 20 Marketing margin 218 6 212 447 94 353 Unrealized gains (losses) on commodity risk management activities 185 34 151 (103) 60 (163) Total segment margin $ 1,792 $ 1,306 $ 486 $ 2,981 $ 2,574 $ 407 Segment Adjusted EBITDA. For the three months ended June 30, 2026 compared to the same period last 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 $212 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to $140 million from higher premiums from the sale of NGLs for export and for domestic supply and a $70 million increase in refined product margins as a result of higher spreads and prices; •an increase of $71 million in terminal services margin primarily due to a $63 million increase in fees from loading increased volumes at higher rates for export at our Nederland and Marcus Hook terminals, and an $8 million increase from higher throughput and storage at our refined product terminals; 55 Table of Contents •an increase of $28 million in transportation margin due to a $40 million increase related to higher y-grade and NGL throughput, partially offset by a $4 million decrease due to lower refined product transportation volumes due to third-party refinery issues; •an increase of $12 million in storage margin primarily due to an increase in fees generated from export volumes, as well as increases related to blending activity due to a more favorable pricing environment; and •an increase of $12 million in fractionators and refinery services margin primarily due to higher throughput; partially offset by •an increase of $54 million in operating expenses primarily due to a $28 million increase from certain one-time credits recognized in the prior period, a $14 million increase in utilities costs driven by higher volumes across our system, a $6 million increase in employee costs, and increases totaling $5 million from various other operating expenses; and •an increase of $7 million in selling, general and administrative expenses primarily due to higher overhead costs and legal fees. For the six months ended June 30, 2026 compared to the same period last 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 $353 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to $212 million from higher premiums from the sale of NGLs for export and for domestic supply, $65 million in hedge-related gains during the first quarter of 2026 which offset physical losses realized during the fourth quarter of 2025, and a $77 million increase in refined product margins as result of higher spreads and prices; •an increase of $98 million in terminal services margin primarily due to a $79 million increase in fees from loading higher volumes for export at our Nederland and Marcus Hook terminals and a $17 million increase from higher throughput and storage at our refined product terminals; •an increase of $72 million in fractionators and refinery services margin primarily due to higher throughput; •an increase of $27 million in transportation margin due to an $81 million increase related to higher y-grade throughput, partially offset by a $39 million intercompany imbalance that is completely offset within our midstream segment, a $12 million decrease from lower NGL throughput on our Mariner East system due to a weather related demand decrease, and a $3 million decrease due to lower refined product transport volumes due to third party refinery issues; and •an increase of $20 million in storage margin primarily due to an increase in fees generated from export volumes, as well as increases related to blending activity due to a more favorable pricing environment; partially offset by •an increase of $105 million in operating expenses primarily due to a $42 million increase in costs driven by higher volumes across our system, a $28 million increase from certain one-time credits recognized in the prior period, a $15 million increase in outside services, a $14 million increase in employee costs, and increases totaling $6 million from various other operating expenses; and •an increase of $7 million in selling, general and administrative expenses primarily due to higher legal fees. 56 Table of Contents Crude Oil Transportation and Services Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Change 2026 2025 Change Crude oil transportation volumes (MBbls/d) 7,336 7,049 287 7,312 6,885 427 Crude oil terminal volumes (MBbls/d) 4,911 4,633 278 4,719 4,596 123 Revenues $ 11,051 $ 5,748 $ 5,303 $ 18,809 $ 11,956 $ 6,853 Cost of products sold 9,766 4,725 5,041 16,558 9,939 6,619 Segment margin 1,285 1,023 262 2,251 2,017 234 Unrealized gains on commodity risk management activities (181) (25) (156) (63) (25) (38) Operating expenses, excluding non-cash compensation expense (231) (237) 6 (454) (450) (4) Selling, general and administrative expenses, excluding non-cash compensation expense (45) (38) (7) (46) (82) 36 Adjusted EBITDA related to unconsolidated affiliates 6 8 (2) 15 14 1 Other — 1 (1) — — — Segment Adjusted EBITDA $ 834 $ 732 $ 102 $ 1,703 $ 1,474 $ 229 Volumes. For the three and six months ended June 30, 2026 compared to the same periods last year, crude oil transportation volumes were higher due to higher volumes on our Texas pipeline system, our Permian and Bakken gathering systems, partially offset by lower volume on our Mid-continent pipelines. Crude oil terminal volumes were higher due to higher customer throughput related to strategic petroleum reserve releases and crude export demand at our Gulf Coast terminals. Beginning in the current period, the Partnership has updated its approach for calculating crude oil terminal volumes to be consistent across all terminals; volumes reported for prior periods have been revised accordingly. Segment Adjusted EBITDA. For the three months ended June 30, 2026 compared to the same period last 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 $106 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $62 million increase in optimization gains from more favorable market conditions and higher refined product margins, a $19 million increase in crude gathering revenues, a $17 million increase in transportation revenue, and a $6 million increase from higher crude oil terminal volumes; and •a decrease of $6 million in operating expenses primarily due to lower maintenance project related expenses; partially offset by •an increase of $7 million in selling, general and administrative expenses due primarily to higher expenses associated with a litigation related contingency. For the six months ended June 30, 2026 compared to the same period last 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 $196 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) due to a $133 million increase in optimization gains from more favorable market conditions and higher refined product margins, a $14 million increase in transportation revenue, and a $52 million increase in gathering revenues; •a decrease of $36 million in selling, general and administrative expenses primarily due to an adjustment to the accrual for a litigation contingency; and •an increase of $1 million in Adjusted EBITDA related to unconsolidated affiliates due to higher volumes and crude prices; partly offset by •an increase of $4 million in operating expenses primarily due to an $11 million increase in employee-related expenses and a $9 million increase in volume-driven expenses, partially offset by an $8 million decrease in outside service expenses and a $7 million decrease from maintenance project related expenses. 57 Table of Contents Investment in Sunoco LP Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Change 2026 2025 Change Revenues $ 14,259 $ 5,390 $ 8,869 $ 24,949 $ 10,569 $ 14,380 Cost of products sold 12,795 4,821 7,974 21,796 9,347 12,449 Segment margin 1,464 569 895 3,153 1,222 1,931 Unrealized (gains) losses on commodity risk management activities (6) (7) 1 50 (8) 58 Operating expenses, excluding non-cash compensation expense (434) (162) (272) (815) (320) (495) Selling, general and administrative expenses, excluding non-cash compensation expense (155) (47) (108) (306) (83) (223) Adjusted EBITDA related to unconsolidated affiliates 75 51 24 144 101 43 Inventory valuation adjustments 18 40 (22) (426) (21) (405) Other 20 10 10 40 21 19 Segment Adjusted EBITDA $ 982 $ 454 $ 528 $ 1,840 $ 912 $ 928 The investment in Sunoco LP segment reflects the consolidated results of Sunoco LP. Segment Adjusted EBITDA. For the three months ended June 30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment increased due to the net impact of the following: •an increase of $874 million in segment margin (excluding unrealized gains and losses on commodity risk management activities and inventory valuation adjustments) primarily due to recent acquisitions; and •an increase of $24 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to the Parkland acquisition and ET-S Permian joint venture; partially offset by •an increase of $272 million in operating expenses primarily due to increased costs resulting from recently acquired businesses; and •an increase of $108 million in selling, general and administrative expenses primarily due to increased costs resulting from recently acquired businesses, along with one-time transaction-related expenses associated with those acquisitions. For the six months ended June 30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment increased due to the net impact of the following: •an increase of $1.58 billion in segment margin (excluding unrealized gains and losses on commodity risk management activities and inventory valuation adjustments) primarily due to recent acquisitions, as well as a $102 million favorable impact from a one-time gain on sale of inventory in the current period; and •an increase of $43 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to the Parkland acquisition and ET-S Permian joint venture; partially offset by •an increase of $495 million in operating expenses primarily due to increased costs resulting from recently acquired businesses; and •an increase of $223 million in selling, general and administrative expenses primarily due to increased costs resulting from recently acquired businesses, along with one-time transaction-related expenses associated with those acquisitions. 58 Table of Contents Investment in USAC Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Change 2026 2025 Change Revenues $ 342 $ 250 $ 92 $ 673 $ 495 $ 178 Cost of products sold 33 40 (7) 62 78 (16) Segment margin 309 210 99 611 417 194 Operating expenses, excluding non-cash compensation expense (91) (47) (44) (180) (90) (90) Selling, general and administrative expenses, excluding non-cash compensation expense (27) (14) (13) (60) (28) (32) Other 3 — 3 11 — 11 Segment Adjusted EBITDA $ 194 $ 149 $ 45 $ 382 $ 299 $ 83 The investment in USAC segment reflects the consolidated results of USAC. Segment Adjusted EBITDA. For the three months ended June 30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to the net impact of the following: •an increase of $99 million in segment margin primarily due to the J-W Power Acquisition and increases in USAC’s legacy business; partially offset by •an increase of $57 million in operating expense and selling, general and administrative expense primarily related to the J-W Power Acquisition, as well as increased expenses in outside services and professional fees. For the six months ended June 30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to the net impact of the following: •an increase of $194 million in segment margin primarily due to the J-W Power Acquisition and increases in USAC’s legacy business; partially offset by •an increase of $122 million in operating expense and selling, general and administrative expense primarily related to the J-W Power Acquisition, as well as increased expenses in outside services and professional fees. All Other Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Change 2026 2025 Change Revenues $ 565 $ 936 $ (371) $ 1,619 $ 1,931 $ (312) Cost of products sold 502 909 (407) 1,496 1,904 (408) Segment margin 63 27 36 123 27 96 Unrealized (gains) losses on commodity risk management activities (18) (14) (4) (7) 6 (13) Operating expenses, excluding non-cash compensation expense (6) — (6) (13) (1) (12) Selling, general and administrative expenses, excluding non-cash compensation expense (13) (13) — (17) (26) 9 Adjusted EBITDA related to unconsolidated affiliates 2 2 — 3 2 1 Other and eliminations (22) (26) 4 (67) (43) (24) Segment Adjusted EBITDA $ 6 $ (24) $ 30 $ 22 $ (35) $ 57 Amounts reflected in our all other segment primarily include: •our natural gas marketing operations; •our wholly owned natural gas compression operations; and 59 Table of Contents •our natural resources business. Segment Adjusted EBITDA. For the three months ended June 30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment increased due to the net impact of the following: •an increase of $49 million in our natural gas marketing business driven by favorable spreads and gains on residue gas sales; partially offset by •a decrease of $11 million due to an increase in the intersegment elimination of Sunoco LP’s 32.5% share of ET-S Permian, 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; and •a decrease of $13 million in our dual drive compression business. For the six months ended June 30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment increased due to the net impact of the following: •an increase of $84 million in our natural gas marketing business driven by favorable spreads and gains on residue gas sales; partially offset by •a decrease of $18 million due to an increase in the intersegment elimination of Sunoco LP’s 32.5% share of ET-S Permian, 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. LIQUIDITY AND CAPITAL RESOURCES Overview Our ability to satisfy obligations and pay distributions to unitholders will depend on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control. 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 currently expect capital expenditures in 2026 to be approximately as follows (including capitalized interest and overhead and only our proportionate share for joint ventures, but excluding capital expenditures related to our investments in Sunoco LP and USAC): Growth Maintenance Intrastate transportation and storage $ 1,475 $ 80 Interstate transportation and storage 850 265 Midstream 1,500 385 NGL and refined products transportation and services 1,250 165 Crude oil transportation and services 425 170 All other (including eliminations) 250 85 Total capital expenditures $ 5,750 $ 1,150 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, including as a result of the recent governmental action on tariffs, and other factors beyond our control. However, we have included these factors in our anticipated growth capital expenditures for each year. We generally fund capital expenditures and distributions with cash flows from operating activities. Sunoco LP currently expects to spend between $400 million and $450 million in maintenance capital expenditures and at least $600 million in growth capital for the full year 2026. USAC currently plans to invest between $60 million and $70 million in maintenance capital expenditures and between $230 million and $250 million in expansion capital expenditures for the full year 2026. 60 Table of Contents 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 for our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions and other factors. Operating Activities Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations”), 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 acquisition 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 estimated 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 we have 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 price risk management assets and liabilities, the timing of accounts receivable collection, the timing of payments on accounts payable, the timing of purchase and sales of inventories and the timing of advances and deposits received from customers. Six months ended June 30, 2026 compared to six months ended June 30, 2025. Cash provided by operating activities during 2026 was $7.65 billion compared to $5.68 billion for 2025, and net income was $4.51 billion for 2026 and $3.18 billion for 2025. The difference between net income and net cash provided by operating activities for the six months ended June 30, 2026 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions) of $228 million and other items totaling $2.82 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 2026 and 2025 consisted primarily of depreciation, depletion and amortization of $3.16 billion and $2.75 billion, respectively, deferred income tax expense of $167 million and $7 million, respectively, favorable inventory valuation adjustments of $426 million and $21 million, respectively, and non-cash compensation expense of $88 million and $70 million, respectively. For 2026 and 2025, net income also included equity in earnings of unconsolidated affiliates of $218 million and $197 million, respectively, losses on extinguishments of debt of $7 million and $19 million, respectively, and in 2025, impairment losses of $7 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 $125 million in 2026 and $165 million in 2025. Cash paid for interest, net of interest capitalized, was $1.74 billion and $1.56 billion for the six months ended June 30, 2026 and 2025, respectively. Interest capitalized was $120 million and $55 million for the six months ended June 30, 2026 and 2025, respectively. Investing Activities Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash contributions to our joint ventures and cash proceeds from sales or contributions of assets or businesses. In addition, distributions from equity investees are included in cash flows from investing activities if the distributions are deemed to be a return of the Partnership’s investment. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects. Six months ended June 30, 2026 compared to six months ended June 30, 2025. Cash used in investing activities during 2026 was $4.13 billion compared to $2.90 billion for 2025. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2026 were $3.45 billion compared to $2.86 billion for 2025. Additional detail related to our capital expenditures is provided in the table below. In 2026, USAC paid $445 million, net of cash acquired, for the acquisition of J-W Energy Company and Sunoco LP paid $194 million, net of cash acquired, for the TanQuid acquisition and $75 million, net of cash acquired, for the Delta acquisition. Additionally, in 2026, Sunoco LP paid $72 million in cash for other acquisitions and in 2025, Sunoco LP paid $104 million in cash for acquisitions of fuel equipment, motor fuel inventory and supply agreements. In 2026 and 2025, we received cash distributions from unconsolidated affiliates in excess of cumulative earnings of $79 million and $56 million, respectively, and we paid cash contributions to unconsolidated affiliates of $30 million and $4 million, respectively. 61 Table of Contents The following is a summary of capital expenditures (including only our proportionate share for joint ventures, net of contributions in aid of construction costs) on an accrual basis for the six months ended June 30, 2026: Capital Expenditures Recorded During Period Growth Maintenance Total Intrastate transportation and storage $ 880 $ 32 $ 912 Interstate transportation and storage 342 111 453 Midstream 632 153 785 NGL and refined products transportation and services 544 65 609 Crude oil transportation and services 146 68 214 Investment in Sunoco LP 231 170 401 Investment in USAC 73 26 99 All other (including eliminations) 79 53 132 Total capital expenditures $ 2,927 $ 678 $ 3,605 Financing Activities Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures. Distributions increase between the periods based on increases in the number of common units outstanding or increases in the distribution rate. Six months ended June 30, 2026 compared to six months ended June 30, 2025. Cash used in financing activities during 2026 was $3.77 billion compared to $2.85 billion for 2025. During 2026, we had a net decrease in our debt level of $231 million compared to a net increase of $1.02 billion for 2025. In 2026 and 2025, we paid debt issuance costs of $49 million and $53 million, respectively. In 2025, we paid $500 million in cash for the redemption of our Series F Preferred Units. In 2026 and 2025, we paid distributions of $2.41 billion and $2.35 billion, respectively, to our partners, we paid distributions of $1.07 billion and $934 million, respectively, to noncontrolling interests, and we paid distributions of $17 million and $34 million, respectively, to redeemable noncontrolling interests. In 2026 and 2025, we received capital contributions of $1 million and $5 million, respectively, in cash from noncontrolling interests. In 2026, we received capital contributions of $6 million in cash from redeemable noncontrolling interests. 62 Table of Contents Description of Indebtedness Our outstanding consolidated indebtedness was as follows: June 30, 2026 December 31, 2025 Energy Transfer indebtedness: Notes and debentures(1) (2) $ 50,270 $ 48,870 Five-Year Credit Facility(2) 1,212 2,856 Subsidiary indebtedness: Transwestern senior notes 75 75 Bakken Project senior notes 850 850 Sunoco LP senior notes, bonds and lease-related obligations(1)(2) 13,400 13,470 USAC senior notes 1,750 1,750 Sunoco LP credit facility — — USAC credit facility 1,211 795 Other long-term debt 17 19 Net unamortized premiums, discounts and fair value adjustments 18 32 Deferred debt issuance costs (398) (384) Total debt 68,405 68,333 Less: current maturities of long-term debt 12 25 Long-term debt, less current maturities $ 68,393 $ 68,308 (1)As of June 30, 2026, these balances included approximately $4.40 billion aggregate principal amount due on or before June 30, 2027, 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.” Recent Transactions Energy Transfer Notes Issuances and Redemptions In January 2026, the Partnership issued $1.00 billion aggregate principal amount of 4.55% senior notes due 2031, $1.00 billion aggregate principal amount of 5.35% senior notes due 2036 and $1.00 billion aggregate principal amount of 6.30% senior notes due 2056. The Partnership used the net proceeds to refinance existing indebtedness, including to repay commercial paper and borrowings under its Five-Year Credit Facility. In January 2026, the Partnership redeemed its $1.00 billion aggregate principal amount of 4.75% senior notes due January 2026 using cash on hand and commercial paper borrowings. In February 2026, the Partnership redeemed its $600 million aggregate principal amount of 5.625% senior notes due May 2027 using cash on hand and commercial paper borrowings. In July 2026, the Partnership issued $650 million aggregate principal amount of its Series 2026A Junior Subordinated Notes due 2057 (the “Series 2026A notes”) and $1.10 billion aggregate principal amount of its Series 2026B Junior Subordinated Notes due 2057 (the “Series 2026B notes”). Initially, the Series 2026A notes will bear interest at an annual rate of 6.550% and the Series 2026B notes will bear interest at an annual rate of 6.700%. The Partnership intends to use the net proceeds to redeem the Series H Preferred Units, to repay borrowings under its Five-Year Credit Facility and for general partnership purposes. Sunoco LP Senior Notes Issuances and Redemption In March 2026, Sunoco LP issued $600 million aggregate principal amount of 5.375% senior notes due 2031 and $600 million aggregate principal amount of 5.625% senior notes due 2034. These notes will mature on July 15, 2031 and July 15, 2034, respectively, and interest is payable semi-annually on January 15 and July 15 of each year, commencing on July 15, 2026. Sunoco LP used a portion of the net proceeds from this private offering to redeem in full its $500 million aggregate principal amount of 6.000% senior notes due 2026 and its $600 million aggregate principal amount of 6.000% senior notes due 2027. In March 2026, Sunoco LP redeemed Parkland’s remaining senior notes. In June 2026, Sunoco LP redeemed all of its outstanding 3.875% CAD senior notes due 2026. 63 Table of Contents Credit Facilities and Commercial Paper Five-Year Credit Facility As of June 30, 2026, the Five-Year Credit Facility had $1.21 billion of outstanding borrowings, $1.12 billion of which consisted of commercial paper. The amount available for future borrowings was $3.76 billion, after accounting for outstanding letters of credit in the amount of $24 million. The weighted average interest rate on the total amount outstanding as of June 30, 2026 was 4.00%. Sunoco LP Credit Facility As of June 30, 2026, Sunoco LP’s credit facility, which matures in June 2030, had no outstanding borrowings and $183 million in standby letters of credit. The unused availability on Sunoco LP’s revolving credit facility as of June 30, 2026 was $2.32 billion. The weighted average interest rate on the total amount outstanding as of June 30, 2026 was 5.46%. Sunoco LP Receivables Financing Agreement Upon the closing of Sunoco LP’s acquisition of NuStar, 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 June 30, 2026, this facility had no outstanding borrowings. USAC Credit Facility As of June 30, 2026, USAC’s credit facility, which matures in August 2030, had $1.21 billion of outstanding borrowings and $2 million outstanding letters of credit. As of June 30, 2026, USAC’s credit facility had $537 million of remaining unused availability. The weighted average interest rate on the total amount outstanding as of June 30, 2026 was 5.59%. Compliance with our Covenants We and our subsidiaries were in compliance with all requirements, tests, limitations and covenants related to our debt agreements as of June 30, 2026. 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 to provide for future cash requirements. Cash Distributions on Energy Transfer Common Units Distributions declared and/or paid with respect to Energy Transfer common units subsequent to December 31, 2025 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2025 February 6, 2026 February 19, 2026 $ 0.3350 March 31, 2026 May 8, 2026 May 20, 2026 0.3375 June 30, 2026 August 7, 2026 August 19, 2026 0.3400 Cash Distributions on Energy Transfer Preferred Units Distributions declared on the Energy Transfer Preferred Units were as follows: Period Ended Record Date Payment Date Series B (2) Series G (2) Series H (2) Series I (1) December 31, 2025 February 1, 2026 February 15, 2026 $ 33.125 $ — $ — $ 0.2111 March 31, 2026 May 1, 2026 May 15, 2026 — 35.630 32.500 0.2111 June 30, 2026 August 3, 2026 August 17, 2026 33.125 — 16.611 0.2111 (1)The record date and payment date shown above apply to all Energy Transfer Preferred Units, except for the Series I Preferred Units. For the period ended December 31, 2025, the cash distribution on Series I Preferred Units was paid on February 17, 2026 to unitholders of record as of the close of business on February 4, 2026. For the period ended March 31, 2026, the cash distribution on Series I Preferred Units was paid on May 15, 2026 to unitholders of record as of the close of business on May 4, 2026. For the period ended June 30, 2026, the cash distribution on Series I Preferred Units will be paid on August 14, 2026 to unitholders of record as of the close of business on August 4, 2026. 64 Table of Contents (2)Series B, 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. The final distributions on Series H Preferred Units will be paid in conjunction with the Series H Preferred Unit redemption on August 17, 2026. Description of Energy Transfer Preferred Units A summary of the distribution and redemption rights associated with the Energy Transfer Preferred Units is included in Note 9 in “Item 1. Financial Statements.” Cash Distributions Paid by Subsidiaries The Partnership’s consolidated financial statements include SunocoCorp, Sunoco LP and USAC, as well as other non-wholly owned consolidated joint ventures. The following sections describe cash distributions made by our publicly traded subsidiaries, SunocoCorp, Sunoco LP and USAC, all of which are required to distribute all cash on hand (less appropriate reserves determined by the boards of directors of their respective general partners) subsequent to the end of each quarter. Cash Distributions Paid by SunocoCorp Distributions on SunocoCorp’s common units declared and/or paid by SunocoCorp subsequent to December 31, 2025 were as follows: Quarter Ended Payment Date Rate December 31, 2025 February 19, 2026 $ 0.9317 March 31, 2026 May 20, 2026 0.9899 June 30, 2026 August 19, 2026 1.0023 Cash Distributions Paid by Sunoco LP Distributions on Sunoco LP’s common units and Class D Units declared and/or paid by Sunoco LP subsequent to December 31, 2025 were as follows: Quarter Ended Payment Date Rate December 31, 2025 February 19, 2026 $ 0.9317 March 31, 2026 May 20, 2026 0.9899 June 30, 2026 August 19, 2026 1.0023 Distributions on Sunoco LP’s Series A Preferred Units, which are paid semi-annually, were as follows: Record Date Payment Date Rate March 2, 2026 March 18, 2026 $ 39.38 Cash Distributions Paid by USAC Distributions on USAC’s common units declared and/or paid by USAC subsequent to December 31, 2025 were as follows: Quarter Ended Payment Date Rate December 31, 2025 February 6, 2026 $ 0.525 March 31, 2026 May 8, 2026 0.525 June 30, 2026 August 7, 2026 0.525 CRITICAL ACCOUNTING ESTIMATES The Partnership’s critical accounting estimates are described in its Annual Report on Form 10-K filed with the SEC on February 19, 2026. We have not made any changes to the accounting policies involving critical accounting estimates subsequent to the Form 10-K filing. Changes to any of the related estimate amounts are discussed in the notes to consolidated financial statements included in “Item 1. Financial Statements” in this quarterly report on Form 10-Q. FORWARD-LOOKING STATEMENTS This quarterly 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 65 Table of Contents are identified as any statement that does not relate strictly to historical or current facts. When used in this quarterly report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are: •the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition; •the actual amount of cash distributions by our subsidiaries to us; •the volumes transported on our subsidiaries’ pipelines and gathering systems; •the level of throughput in our subsidiaries’ processing and treating facilities; •the fees our subsidiaries charge and the margins they realize for their gathering, treating, processing, storage and transportation services; •the prices and market demand for, and the relationship between, natural gas and NGLs; •energy prices generally; •impacts of world health events; •the possibility of cyber and malware attacks; •the prices of natural gas and NGLs compared to the price of alternative and competing fuels; •the general level of petroleum product demand and the availability and price of NGL supplies; •the level of domestic oil, natural gas and NGL production; •the availability of imported oil, natural gas and NGLs; •actions taken by foreign oil and gas producing nations; •the political and economic stability of petroleum producing nations; •the effect of weather conditions on demand for oil, natural gas and NGLs; •availability of local, intrastate and interstate transportation systems; •the continued ability to find and contract for new sources of natural gas supply; •availability and marketing of competitive fuels; •the impact of energy conservation efforts; •energy efficiencies and technological trends; •governmental regulation, 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; 66 Table of Contents •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 raw materials 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 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 “Part I - Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2025 filed with the SEC on February 19, 2026 and in “Part II - Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2026 filed with the SEC on May 7, 2026. Any forward-looking statement made by us in this Quarterly Report on Form 10-Q 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. 67 Table of Contents