Energy Transfer LP

Previous wording

In addition, we own investments in other businesses, including Sunoco LP and USAC, both of which are master limited partnerships.

Current wording

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

Previous wording

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.

Current wording

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 U.S. Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income 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 D.C. Circuit issued an opinion upholding the FERC’s decision denying a separate master limited partnership recovery of an income tax allowance and its decision not to require the master limited partnership to refund accumulated deferred income tax balances. In light of the rehearing order’s clarification regarding an individual entity’s ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impact of the FERC’s policy on the treatment of income taxes on the rates we can charge for FERC-regulated transportation services is unknown at this time.

Previous wording

Even without application of the FERC’s rate making-related policy statements and rulemakings, the FERC or our shippers may challenge the cost-of-service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, including ROE and tax-related components, but also other pipeline costs that will continue to affect FERC’s determination of just and reasonable cost-of-service rates. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost-of-service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as Tiger Pipeline, Midcontinent Express Pipeline and Fayetteville Express Pipeline, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as Florida Gas Transmission Pipeline, Transwestern and Panhandle, have a mix of tariff rate, discount rate and negotiated rate agreements. The revenues we receive from natural gas transportation services we provide pursuant to cost-of-service based rates may decrease in the future as a result of changes to FERC policies, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost-of-service rates, if any, will depend on a detailed review of all of our cost-of-service components and the outcomes of any challenges to our rates by the FERC or our shippers.

Current wording

Even without application of the FERC’s rate making-related policy statements and rulemakings, the FERC or our shippers may challenge the cost-of-service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, including 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.

Previous wording

On July 18, 2018, the FERC issued a final rule establishing procedures to evaluate rates charged by the FERC-jurisdictional gas pipelines in light of the Tax Act and the FERC’s Revised Policy Statement. By an order issued on January 16, 2019, the FERC initiated a review of Panhandle’s then existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the Natural Gas Act. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021, and on December 16, 2022, the FERC issued its order on the initial decision. On January 17, 2023, Panhandle and the Michigan Public Service Commission each filed a request for rehearing of FERC’s order on the initial decision, which were denied by operation of law as of February 17, 2023. On March 23, 2023, Panhandle appealed these orders to the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”), and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the Court of Appeals consolidated Panhandle’s and Michigan Public Service Commission’s appeals and stayed the consolidated appeal proceeding while the FERC further considered the requests for rehearing of its December 16, 2022 order. On September 25, 2023, the FERC issued its order addressing arguments raised on rehearing and compliance, which denied our requests for rehearing. Panhandle filed its Petition for Review with the Court of Appeals regarding the September 25, 2023 order. On October 25, 2023, Panhandle filed a limited request for rehearing of the September 25 order addressing arguments raised on rehearing and compliance, which was subsequently denied by operation of law on November 27, 2023. On November 17, 2023, Panhandle provided refunds to shippers and on November 30, 2023, Panhandle submitted a refund report regarding the consolidated rate proceedings, which was protested by several parties. On January 5, 2024, the FERC issued a second order addressing arguments raised on rehearing in which it modified certain discussion from its September 25, 2023 order and sustained its prior conclusions. Panhandle has timely filed its Petition for Review with the Court of Appeals regarding the January 5, 2024 order. On May 28, 2024, the FERC issued an order rejecting Panhandle’s refund report. On June 27, 2024, Panhandle filed a revised refund report in compliance with the FERC’s May 28, 2024 order rejecting Panhandle’s refund report and a request for rehearing of the FERC’s May 28, 2024 order rejecting Panhandle’s refund report, and provided revised refunds to shippers, or in the case of shippers whose revised refunds are less than the original amounts refunded, n…

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Current wording

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, 2024 order rejecting Panhandle’s refund report, and provided revised refunds to shippers, or in the case of shippers whose revised refunds are less than the original amounts refunded, notices of upcoming debits. One party protested Panhandle’s revised refund report, and Panhandle submitted a response to the protest on July 24, 2024. By notice issued July 29, 2024, Panhandle’s rehearing request was deemed denied. In an ordered issued September 9, 2024, FERC addressed arguments raised on rehearing, modified the discussion in the May 28, 2024 order and continued to reach the same result. On September 18, 2024, Panhandle petitioned the 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 iss…

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Previous wording

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. The FERC has taken no further action on the 2022 Certificate Policy Statement. We are unable to predict what, if any, changes may be proposed as a result of the 2022 Certificate Policy Statement that might affect our natural gas pipeline or LNG facility projects, or when such new policy, if any, might become effective. We do not expect that any change in this policy statement would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.

Current wording

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.

Previous wording

On December 17, 2020, FERC issued an order establishing a new index of PPI-FG plus 0.78%. The FERC received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG minus 0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period July 1, 2022 to June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the January 20 order with FERC, which was denied by FERC on May 6, 2022. Certain parties appealed the January 20 and May 6 orders. On July 26, 2024, the D.C. Circuit ruled in LEPA v. FERC that FERC violated the Administrative Procedure Act because the January 20 order modified the index without following notice and comment. As a result, the D.C. Circuit vacated the January 20 order and on September 17, 2024, the Commission reinstated the index level established by its original December 17 order, directed pipelines to file an informational filing to show their recomputed ceiling levels reflecting the reinstated index level and stated that pipelines may file to prospectively increase their indexed rates to their recomputed levels. On October 17, 2024, FERC issued a Supplemental NOPR that proposes a reduction to the currently effective index by one percent. The Supplemental NOPR, which remains pending before FERC, could result in the reimplementation through a notice-and-comment rulemaking of the same rulings that were vacated by the D.C. Circuit in LEPA v. FERC.

Current wording

On December 17, 2020, FERC issued an order establishing a new index of PPI-FG plus 0.78%. The FERC received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG minus 0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period July 1, 2022 to June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the January 20 order with FERC, which was denied by FERC on May 6, 2022. Certain parties appealed the January 20 and May 6 orders. On July 26, 2024, the D.C. Circuit ruled in LEPA v. FERC that FERC violated the Administrative Procedure Act because the January 20 order modified the index without following notice and comment. As a result, the D.C. Circuit vacated the January 20 order and on September 17, 2024, the FERC reinstated the index level established by its original December 17 order, directed pipelines to file an informational filing to show their recomputed ceiling levels reflecting the reinstated index level and stated that pipelines may file to prospectively increase their indexed rates to their recomputed levels. On October 17, 2024, the FERC issued a Supplemental NOPR that proposes a reduction to the currently effective index by one percent. On November 20, 2025, the FERC withdrew the Supplemental NOPR and confirmed that the PPI-FG-0.78% index established in December 2020 will remain in place through June 30, 2026. On the same day, the FERC approved limited relief for pipelines. Oil pipelines with index-based rates may recover applicable rate differences from March 1, 2022 to September 17, 2024 but only if such pipelines charged the maximum rate allowed under the applicable index ceiling during the relevant time period. Parties have since filed requests for clarification or rehearing, as well as court appeals, to determine whether pipelines may recover rate differences in other scenarios. Also on November 20, 2025, the FERC issued a Notice of Proposed Rulemaking for the Five-Year Review of the Oil Pipeline Index proposing an index level of Producer Price Index for Finished Goods (PPI-FG) minus 1.42% for the period from July 1, 2026 to June 30, 2031.

Previous wording

In 2023, the United States Environmental Protection Agency (“EPA”) finalized its Good Neighbor Plan (the “Plan”) which seeks to reduce nitrogen oxide pollution from power plants and other industrial facilities from 23 upwind states which the EPA determined is contributing to National Ambient Air Quality Standards (NAAQS) nonattainment and interfering with maintenance of the 2015 ozone NAAQS in downwind states. 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.

Current wording

In 2023, the U.S. Environmental Protection Agency (“EPA”) finalized its Good Neighbor Plan (the “Plan”) which seeks to reduce nitrogen oxide pollution from power plants and other industrial facilities from 23 upwind states which the EPA determined is contributing to National Ambient Air Quality Standards (NAAQS) nonattainment and interfering with maintenance of the 2015 ozone NAAQS in downwind states. As part of the Plan, the EPA announced that it would be issuing prescriptive emission standards for several sectors, including certain new and existing internal combustion engines of a certain size used in pipeline transportation of natural gas. The EPA’s final rule was to become effective on August 4, 2023, and the prescribed emission standards were scheduled to be effective in 2026. However, on March 12, 2025, the EPA announced plans to end the Plan.

Previous wording

Operators and industry groups have challenged the Plan in the D.C. Circuit, as well as the legal predicates to the individual upwind states’ inclusion in the Plan in the regional circuits. The effectiveness of the rule is currently stayed in the nine states within the Partnership’s footprint, by nature of judicial stays of the legal predicate to the Plan, by judicial stay of the Plan itself by the U.S. Supreme Court, or by the administrative stay issued by the EPA in October 2024. Proceedings as to both on the merits are ongoing. In the challenge to the Plan in the D.C. Circuit, oral argument is expected in early 2025 and a decision could take several months, projected late 2025.

Current wording

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

Previous wording

The Partnership currently estimates that the final rule would require retrofitting or replacement of approximately 192 engines in its interstate and intrastate natural gas transportation and storage operations. The Partnership is involved in challenging application of the Plan in the nine states impacted within its footprint. Compliance with the Plan (if implementation is not stayed or otherwise delayed) will still require substantial capital expenditures which could adversely affect our business in future periods. However, at this time, we are still assessing the potential costs of this rule and, given uncertainties resulting from the multiple legal challenges filed against the Plan in various states, in the DC Circuit and the U.S. Supreme Court, we cannot predict with any certainty what the final costs of compliance for the Plan for the Partnership ultimately may be.

Current wording

The Partnership currently estimates that the existing final rule would require retrofitting or replacement of approximately 192 engines in its interstate and intrastate natural gas transportation and storage operations. The Partnership is involved in challenging application of the Plan in the nine states impacted within its footprint. Compliance with the Plan (if implementation is not stayed or otherwise delayed) will still require substantial capital expenditures which could adversely affect our business in future periods. However, at this time, we are still assessing the potential costs of this rule and, given uncertainties resulting from the multiple legal challenges filed against the Plan in various states, in the D.C. Circuit and the U.S. Supreme Court, we cannot predict with any certainty what the final costs of compliance for the Plan for the Partnership ultimately may be.

Previous wording

For 2025 and beyond, we expect increased demand from new data centers, power plants and LNG exports to support increased production, while increased global demand for petrochemicals and NGL feedstocks is expected to support higher volumes of NGL production and exports on existing assets and assets currently being developed or under construction. In addition, in the United States, we expect a more constructive regulatory environment under the new presidential administration, which we anticipate being favorable for project development and our operations in general.

Current wording

For 2026 and beyond, we expect continued increasing demand from new data centers, power plants and LNG exports to support increased production, while increased global demand for petrochemicals and NGL feedstocks is expected to support higher volumes of NGL production and exports on existing assets and assets currently being developed or under construction. In addition, in the United States, we expect a constructive regulatory environment, which we anticipate being favorable for project development and our operations in general.

Previous wording

Ultimately, the extent to which our business will be impacted by future market developments depends on factors beyond our control, which are highly uncertain and cannot be predicted. In response to market volatility and other uncertainties, we have reduced growth capital spending in recent years. While we anticipate a healthy capital expenditure program in 2025 and beyond, we expect to continue to be prudent going forward as we allocate capital across our business segments. See “Liquidity and Capital Resources” for additional information on our capital expenditures over the last two years and our forecasted capital expenditures for 2025.

Current wording

Ultimately, the extent to which our business will be impacted by future market developments depends on factors beyond our control, which are highly uncertain and cannot be predicted. Our previously announced outlook includes an expected increase in growth capital expenditures up to a range of $5.0 billion to $5.5 billion in 2026, primarily on projects enhancing the Partnership’s natural gas and NGL networks. While we anticipate a healthy capital expenditure program in 2026 and beyond, we expect to continue to be prudent going forward as we allocate capital across our business segments. See “Liquidity and Capital Resources” for additional information on our capital expenditures over the last two years and our forecasted capital expenditures for 2026.

Previous wording

We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total Partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items, as well as certain non-recurring gains and losses. Inventory adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at LIFO. These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.

Current wording

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, certain foreign currency transaction gains and losses and other non-operating income or expense items, as well as certain non- recurring gains and losses. Inventory valuation adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at LIFO. These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.

Previous wording

Segment Adjusted EBITDA, as reported for each segment in the following table, is analyzed in the section titled “Segment Operating Results.” Adjusted EBITDA is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’s fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures.

Current wording

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.

Previous wording

Net Income. For the year ended December 31, 2024 compared to the prior year, net income increased $1.27 billion, or approximately 24%, primarily due to the recognition of a $586 million gain on Sunoco LP’s sale of its West Texas assets in the current year, as well as the recognition of a $627 million non-operating litigation-related loss in the prior year. The change in net income also reflected higher segment margin from multiple segments, partially offset by increases in operating expenses, selling, general and administrative expenses, depreciation, depletion and amortization, impairment losses, interest expense and income tax expense; these changes are discussed in more detail below and in “Segment Operating Results.”

Current wording

Net Income. For the year ended December 31, 2025 compared to the prior year, net income decreased $857 million, or 13%, primarily due to a $586 million gain recognized by Sunoco LP on its sale of West Texas assets in the prior year, a $517 million increase in depreciation, depletion and amortization and a $349 million increase in interest expense, net of interest capitalized, partially offset by a $501 million increase in Adjusted EBITDA, a $191 million decrease in income tax expense and a $186 million favorable impact from unrealized gains and losses on commodity risk management activities. These changes are discussed in more detail below.

Previous wording

Adjusted EBITDA(consolidated). For the year ended December 31, 2024 compared to the prior year, Adjusted EBITDA increased $1.79 billion, or approximately 13%, primarily due to favorable results in multiple segments. The most significant increases were in our midstream segment, our crude oil transportation and services segment and our Investment in Sunoco LP segment, each of which reflected increases from recently acquired assets. Our midstream segment also reflected increases from higher volumes, as did our NGL and refined products transportation and services segment. Our intrastate transportation and storage segment also reflected increases from higher pipeline optimization.

Current wording

Adjusted EBITDA(consolidated). For the year ended December 31, 2025 compared to the prior year, Adjusted EBITDA increased $501 million, or 3%, primarily due to increases in our midstream segment, our interstate transportation and storage segment and our investment in Sunoco LP segment, partially offset by decreases in our intrastate transportation and storage segment and our crude oil transportation and services segment.

Previous wording

Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, increased primarily due to higher aggregate debt balances and higher interest rates on floating rate and recently refinanced debt.

Current wording

Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, increased primarily due to an increase in aggregate debt balances following the acquisitions of NuStar, Parkland and WTG Midstream Holdings LLC and the refinancing of certain preferred units with long-term debt.

Previous wording

Income Tax Expense. For the year ended December 31, 2024 compared to the same period last year, income tax expense increased due to the taxable gain recognized by a corporate subsidiary of Sunoco LP on its sale of West Texas assets.

Current wording

Income Tax Expense. For the year ended December 31, 2025 compared to the same period last year, income tax expense decreased primarily due to a taxable gain recognized by a corporate subsidiary of Sunoco LP upon its completion of the sale of convenience stores to 7-Eleven, Inc. in 2024.

Previous wording

Impairment Losses and Other. For the year ended December 31, 2024, impairment losses and other were primarily related to Sunoco LP’s termination of a lease in June 2024. For the year ended December 31, 2023 impairment losses and other consisted of impairment losses incurred by USAC primarily related to its compression equipment.

Current wording

Impairment Losses and Other. For the year ended December 31, 2025, impairment losses and other primarily reflected an impairment of the assets associated with the Lake Charles LNG export project due to the suspension of the project. For the year ended December 31, 2024 impairment losses and other were primarily related to Sunoco LP’s termination of a lease in June 2024.

Previous wording

Inventory Valuation Adjustments (Sunoco LP). Inventory valuation adjustments represent changes in lower of cost or market using the last-in, first-out method on Sunoco LP’s inventory. These amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory at the end of the period. For the years ended December 31, 2024 and 2023, decreases in fuel prices caused the lower of cost or market reserve requirements to increase by $86 million and $114 million, respectively, which reduced net income.

Current wording

Inventory Valuation Adjustments (Sunoco LP). Inventory valuation adjustments represent changes in lower of cost or market using the last-in, first-out method on Sunoco LP’s inventory. These amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory at the end of the period. For the years ended December 31, 2025 and 2024, decreases in fuel prices caused the lower of cost or market reserve requirements to increase by $156 million and $86 million, respectively, which reduced net income.

Previous wording

(Gains) Losses on Extinguishment of Debt. For the year ended December 31, 2024, losses on extinguishment of debt included a $5 million loss on Energy Transfer’s redemption of its $450 million aggregate principal amount of 8.00% senior notes due April 2029 and $500 million aggregate principal amount of 5.75% senior notes due April 2025, a $2 million loss recognized by Sunoco LP and a $5 million loss related to USAC’s redemption of its $725 million aggregate principal amount of 6.875% senior notes due 2026.

Current wording

Losses on Extinguishment of Debt. For the year ended December 31, 2025, losses on extinguishment of debt primarily related to Sunoco LP's termination of bridge financing related to the Parkland acquisition. For year ended December 31, 2024, losses on extinguishment of debt included amounts recognized upon debt redemptions by Energy Transfer, Sunoco LP and USAC.

Previous wording

Gain on Sale of West Texas Assets (Sunoco LP). The gain on sale of West Texas assets relates to the gain recognized by Sunoco LP upon completion of the sale of convenience stores to 7-Eleven Inc. in April 2024. During the fourth quarter of 2024, Sunoco LP recorded a $12 million reduction to the gain to reflect adjustments to the cash proceeds and certain balance sheet accounts associated with the business sold.

Current wording

Gain on Sale of West Texas Assets (Sunoco LP). The gain on sale of West Texas assets relates to the gain recognized by Sunoco LP upon completion of the sale of convenience stores to 7-Eleven, Inc. in April 2024.

Previous wording

Volumes. For the year ended December 31, 2024 compared to the prior year, transported volumes of gas on our Texas and Oklahoma intrastate pipelines decreased primarily due to less third-party transportation and decreased gas production from the Haynesville area. Transported volumes reported above exclude volumes attributable to purchases and sales of gas for our pipelines’ own accounts and the optimization of any unused capacity.

Current wording

Volumes. For the year ended December 31, 2025 compared to the prior year, transported volumes of gas on our Texas intrastate pipelines increased primarily due to more third-party transportation. Transported volumes reported above exclude volumes attributable to purchases and sales of gas for our pipelines’ own accounts and the optimization of any unused capacity.

Previous wording

Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:

Current wording

Segment Margin. The table below represents the components of our intrastate transportation and storage segment margin. Amounts previously reported for transportation fees, natural gas sales and other, and retained fuel revenues have been adjusted to reflect the reclassification of certain amounts to conform to the current period presentation; these changes did not impact total segment margin.

Previous wording

Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impact of the following:

Current wording

Segment Adjusted EBITDA. For the year ended December 31, 2025 compared to the prior year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment decreased due to the net impact of the following:

Previous wording

•a decrease of $34 million in storage margin primarily due to lower storage optimization from settled derivatives.

Current wording

•an increase of $40 million in storage margin primarily due to higher storage optimization;

Previous wording

•an increase of $14 million in transportation fees primarily due to the recovery of certain fees earned in a prior period on our Texas system; partially offset by

Current wording

•an increase of $16 million in transportation fees primarily due to the volume shift to long-term third-party contracts from our optimization group on our Texas system, partially offset by $16 million recognized in the prior period from the recovery of certain disputed fees on our Texas system;

Previous wording

Volumes. For the year ended December 31, 2024 compared to the prior year, transported volumes increased primarily due to more capacity sold and higher utilization on our Panhandle, Trunkline and Gulf Run systems due to increased demand.

Current wording

Volumes. For the year ended December 31, 2025 compared to the prior year, transported volumes increased primarily due to more capacity sold and higher utilization across the segment due to increased demand.

Previous wording

Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impact of the following:

Current wording

Segment Adjusted EBITDA. For the year ended December 31, 2025 compared to the prior year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impact of the following:

Previous wording

•a decrease of $19 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to a $23 million decrease from our Midcontinent Express Pipeline joint venture due to capacity sold at lower rates and a $6 million decrease from our Citrus joint venture primarily due to higher operating expenses. These decreases were partially offset by a $10 million increase from our Southeast Supply Header joint venture due to higher contracted volumes;

Current wording

•an increase of $30 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to an $11 million increase from our Citrus joint venture, an $11 million increase from our Midcontinent Express Pipeline joint venture and a $7 million increase from our Southeast Supply Header joint venture; and

Previous wording

Volumes. For the year ended December 31, 2024 compared to the prior year, gathered volumes increased primarily due to recently acquired assets and higher volumes in the Permian region. NGL production increased primarily due to recently acquired assets and increased Permian plant utilization.

Current wording

Volumes. For the year ended December 31, 2025 compared to the prior year, gathered volumes increased primarily due to newly acquired assets, as well as additional and upgraded plants in the Permian region, partially offset by lower dry gas gathering volumes in the Northeast and Ark-La-Tex regions. NGL production increased primarily due to recently acquired assets and increased Permian plant utilization.

Previous wording

•a decrease of $27 million in segment margin due to lower natural gas prices of $59 million, partially offset by higher NGL prices of $32 million.

Current wording

•an increase of $32 million in segment margin due to higher natural gas prices of $133 million, partially offset by lower NGL prices of $101 million;

Previous wording

•an increase of $91 million in Adjusted EBITDA related to unconsolidated affiliates due to the formation of the ET-S Permian joint venture; partially offset by

Current wording

•an increase of $2 million in Adjusted EBITDA related to unconsolidated affiliates due to a contract restructuring; partially offset by

Previous wording

•an increase of $346 million in operating expenses primarily due to a $297 million increase related to recent acquisitions and assets placed in service, a $30 million increase in employee costs and a $10 million increase in expense projects; and

Current wording

•an increase of $234 million in operating expenses due to a $206 million increase related to recently acquired assets and assets placed in service, a $33 million increase in employee costs, and a $10 million increase related to increased volumes and repairs in the Permian region, partially offset by a $13 million decrease primarily due to ad valorem taxes, retainage credits, and tax audit penalties;

Previous wording

•an increase of $69 million in other primarily from the recognition of proceeds from a business interruption claim; and

Current wording

•a decrease of $70 million in other income due to the recognition of proceeds from a business interruption claim in September 2024;

Previous wording

Volumes. For the year ended December 31, 2024 compared to the prior year, NGL transportation volumes increased primarily due to higher volumes from the Permian and Eagle Ford regions and on our Mariner East pipeline system.

Current wording

Volumes. For the year ended December 31, 2025 compared to the prior year, NGL transportation and fractionation volumes increased primarily due to higher volumes from the Permian region. Terminal volumes also increased as result of recently acquired assets.

Previous wording

Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:

Current wording

Segment Margin. The table below presents the components of our NGL and refined products transportation and services segment margin. Certain transportation fees previously reported within marketing margin have been reclassified to transportation margin to conform to the current period presentation; these changes did not impact total segment margin.

Previous wording

Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impact of the following:

Current wording

Segment Adjusted EBITDA. For the year ended December 31, 2025 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment decreased due to the net impact of the following:

Previous wording

•an increase of $3 million in selling, general and administrative expenses primarily due to increased costs from recently acquired assets.

Current wording

•an increase of $12 million in selling, general and administrative expenses primarily due to increased costs from recently acquired assets and legal settlement received in 2024; and

Previous wording

•an increase of $9 million in Adjusted EBITDA related to unconsolidated affiliates due to recently acquired assets and higher volumes on our White Cliffs crude pipeline; partially offset by

Current wording

•a decrease of $9 million in Adjusted EBITDA related to unconsolidated affiliates due to lower throughput on certain of our joint venture pipelines; partially offset by

Previous wording

•an increase of $92 million in terminal services margin primarily due to an $80 million increase in fees from loading volumes for export at our Nederland and Marcus Hook terminals and a $12 million increase from higher throughput and storage at our refined product terminals;

Current wording

•an increase of $29 million in terminal services margin primarily due to a $19 million increase from higher throughput and storage at our refined product terminals and a $24 million increase in fees from loading volumes for export at our Nederland and Marcus Hook terminals. These increases were partially offset by a $14 million decrease due to fog related closures in December 2025, which we expect to make up in the first quarter of 2026.