Energy Transfer LP
11/06/2025 | Press release | Distributed by Public on 11/06/2025 12:37
Quarterly Report for Quarter Ending September 30, 2025 (Form 10-Q)
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(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, 2024 filed with the SEC on February 14, 2025. 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, 2024 filed with the SEC on February 14, 2025 and in "Part II - Item 1A. Risk Factors" of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2025 filed with the SEC on May 8, 2025. 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
Parkland Acquisition by Sunoco LP
On October 31, 2025, Sunoco LP completed the previously announced acquisition of Parkland whereby Sunoco LP acquired all the outstanding shares of Parkland, in exchange for SunocoCorp LLC ("SunocoCorp") units that were contributed by SunocoCorp to Sunoco LP at the close of the acquisition. Under the terms of the agreement, Parkland shareholders received 0.295 SunocoCorp units and C$19.80 for each Parkland share. Parkland shareholders could elect, in the alternative, to receive C$44.00 per Parkland share in cash or 0.536 SunocoCorp units for each Parkland share, subject to proration to ensure that the aggregate consideration payable in connection with the transaction would not exceed C$19.80 in cash per Parkland share outstanding as of immediately before close and 0.295 SunocoCorp units per Parkland share outstanding as of immediately before close.
TanQuid Acquisition by Sunoco LP
In March 2025, Sunoco LP entered into an agreement to acquire TanQuid GmbH & Co. KG ("TanQuid") for approximately €500 million (approximately $587 million as of September 30, 2025), including approximately €300 million of assumed debt. TanQuid owns and operates 15 fuel terminals in Germany and one fuel terminal in Poland. The transaction is expected to close in the fourth quarter of 2025, subject to customary closing conditions, and Sunoco LP will fund it using cash on hand and amounts available under its revolving credit facility.
Other Acquisitions
In the first quarter of 2025, Sunoco LP acquired fuel equipment, motor fuel inventory and supply agreements in two separate transactions for total consideration of approximately $17 million. Aggregate consideration included $12 million in cash and 91,776 newly issued Sunoco LP common units, which had an aggregate acquisition-date fair value of approximately $5 million.
In the second quarter of 2025, Sunoco LPacquired a total of 151 fuel distribution consignment sites in three separate transactions for total consideration of approximately $105 million plus working capital. Aggregate consideration included $92 million in cash and 251,646 newly issued Sunoco LP common units which had an aggregate acquisition-date fair value of approximately $13 million.
In the third quarter of 2025, Sunoco LP acquired approximately 70 fuel distribution consignment sites and 100 supply agreements in five separate transactions for total cash consideration of approximately $85 million, plus working capital.
In the third quarter of 2025, Energy Transfer completed the acquisition of two terminal facilities for total cash consideration of approximately $176 million.
Quarterly Cash Distribution
In October 2025, Energy Transfer announced a quarterly distribution of $0.3325 per unit ($1.33 annualized) on Energy Transfer common units for the quarter ended September 30, 2025.
Regulatory Update
One Big Beautiful Bill Act
On July 4, 2025, the One Big Beautiful Bill Act ("OBBBA") was signed into law. The OBBBA permanently reinstates 100% bonus depreciation on qualified property and modifies the calculation of the business interest expense limitation for U.S. federal income tax purposes. We anticipate the OBBBA will defer the payment of a significant portion of the Partnership's corporate subsidiaries' U.S. federal income taxes in future periods. All effects of changes in tax law are recognized in the consolidated financial statements during the period of enactment. As such, the effects of the OBBBA are reflected in our provision for income taxes as of and for the three and nine months ended September 30, 2025. Because the income tax provisions of the Partnership's corporate subsidiaries include both current and deferred income taxes, income tax expense for the period was not significantly impacted, and we currently do not anticipate a significant impact to the Partnership's overall income tax expense in future periods.
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 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.
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.
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 were 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 U.S. Court of Appeals for 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, 2023 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 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 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 the consolidated cases remain 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 with Panhandle's initial brief being due on November 10, 2025.
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 NGA. A technical conference was held on November 19, 2021, and post-technical conference comments were submitted to the FERC on January 7, 2022.
On February 18, 2022, the FERC issued two new policy statements: (1) an Updated Policy Statement on the Certification of New Interstate Natural Gas Facilities ("2022 Certificate Policy Statement") and (2) a Policy Statement on the Consideration of 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.
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. FERCthat 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 Notice of Proposed Rulemaking ("Supplemental NOPR") that proposes a reduction to the currently effective index by one percent. The Supplemental NOPR, which remains pending before FERC, could result in the reimplementation through a notice-and-comment rulemaking of the same rulings that were vacated by the D.C. Circuit in LEPA v. FERC.
On October 20, 2022, the FERC issued a policy statement on the Standard Applied to Complaints Against Oil Pipeline Index Rate Changes to establish guidelines regarding how the FERC will evaluate shipper complaints against oil pipeline index rate increases. Specifically, the policy statement adopted the proposal in the FERC's earlier Notice of Inquiry issued on March 25, 2020 to eliminate the "Substantially Exacerbate Test" as the preliminary screen applied to complaints against index rate increases and instead adopt the proposal to apply the "Percentage Comparison Test" as the preliminary screen for both protests and complaints against index rate increases. At this time, we cannot determine the effect of a change in the FERC's preliminary screen for complaints against index rate changes, however, a revised screen would result in a threshold aligned with the existing threshold for protests against index rate increases. Any complaint or protest raised by a shipper could materially and adversely affect our financial condition, results of operations or cash flows.
Air Quality Standards
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.
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 we cannot predict with any certainty the substance of any such proposed rule or the potential impacts on the Partnership.
The Partnership currently estimates that the existing final rule would require retrofitting or replacement of approximately 192 engines in its interstate and intrastate natural gas transportation and storage operations. The Partnership is involved in challenging application of the Plan in the nine states impacted within its footprint. Compliance with the Plan (if implementation is not stayed or otherwise delayed) will still require substantial capital expenditures which could adversely affect our business in future periods. However, at this time, we are still assessing the potential costs of this rule and, given uncertainties resulting from the multiple legal challenges filed against the Plan in various states, in the 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.
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 affiliates 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.
Consolidated Results
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Three Months Ended September 30, |
Nine Months Ended September 30, |
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| 2025 | 2024 | Change | 2025 | 2024 | Change | ||||||||||||||||||||||||||||||
| Segment Adjusted EBITDA: | |||||||||||||||||||||||||||||||||||
| Intrastate transportation and storage | $ | 230 | $ | 329 | $ | (99) | $ | 858 | $ | 1,095 | $ | (237) | |||||||||||||||||||||||
| Interstate transportation and storage | 431 | 460 | (29) | 1,413 | 1,335 | 78 | |||||||||||||||||||||||||||||
| Midstream | 751 | 816 | (65) | 2,444 | 2,205 | 239 | |||||||||||||||||||||||||||||
| NGL and refined products transportation and services | 1,054 | 1,012 | 42 | 3,065 | 3,071 | (6) | |||||||||||||||||||||||||||||
| Crude oil transportation and services | 746 | 768 | (22) | 2,220 | 2,417 | (197) | |||||||||||||||||||||||||||||
| Investment in Sunoco LP | 489 | 456 | 33 | 1,401 | 1,018 | 383 | |||||||||||||||||||||||||||||
| Investment in USAC | 160 | 146 | 14 | 459 | 429 | 30 | |||||||||||||||||||||||||||||
| All other | (23) | (28) | 5 | (58) | 29 | (87) | |||||||||||||||||||||||||||||
| Adjusted EBITDA (consolidated) | $ | 3,838 | $ | 3,959 | $ | (121) | $ | 11,802 | $ | 11,599 | $ | 203 | |||||||||||||||||||||||
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
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| 2025 | 2024 | Change | 2025 | 2024 | Change | ||||||||||||||||||||||||||||||
| Reconciliation of net income to Adjusted EBITDA: | |||||||||||||||||||||||||||||||||||
| Net income | $ | 1,292 | $ | 1,434 | $ | (142) | $ | 4,470 | $ | 5,118 | $ | (648) | |||||||||||||||||||||||
| Depreciation, depletion and amortization | 1,440 | 1,324 | 116 | 4,191 | 3,791 | 400 | |||||||||||||||||||||||||||||
| Interest expense, net of interest capitalized | 890 | 828 | 62 | 2,564 | 2,318 | 246 | |||||||||||||||||||||||||||||
| Income tax expense | 87 | 89 | (2) | 207 | 405 | (198) | |||||||||||||||||||||||||||||
| Impairment losses | 1 | - | 1 | 8 | 50 | (42) | |||||||||||||||||||||||||||||
| (Gain) loss on interest rate derivative | - | 6 | (6) | - | (6) | 6 | |||||||||||||||||||||||||||||
| Non-cash compensation expense | 40 | 37 | 3 | 110 | 113 | (3) | |||||||||||||||||||||||||||||
| Unrealized (gains) losses on commodity risk management activities | (1) | (53) | 52 | (32) | 50 | (82) | |||||||||||||||||||||||||||||
| Inventory valuation adjustments (Sunoco LP) | (10) | 197 | (207) | (31) | 99 | (130) | |||||||||||||||||||||||||||||
| Losses on extinguishments of debt | 12 | - | 12 | 31 | 11 | 20 | |||||||||||||||||||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 193 | 181 | 12 | 542 | 522 | 20 | |||||||||||||||||||||||||||||
| Equity in earnings of unconsolidated affiliates | (116) | (102) | (14) | (313) | (285) | (28) | |||||||||||||||||||||||||||||
| Gain on sale of West Texas assets (Sunoco LP) | - | - | - | - | (598) | 598 | |||||||||||||||||||||||||||||
| Other, net | 10 | 18 | (8) | 55 | 11 | 44 | |||||||||||||||||||||||||||||
| Adjusted EBITDA (consolidated) | $ | 3,838 | $ | 3,959 | $ | (121) | $ | 11,802 | $ | 11,599 | $ | 203 | |||||||||||||||||||||||
Net Income. For the three months ended September 30, 2025 compared to the same period last year, net income decreased $142 million, or 10%, primarily due to a $121 million decrease in Adjusted EBITDA, a $116 million increase in depreciation, depletion and amortization, a $62 million increase in interest expense, net of interest capitalized, and a $52 million unfavorable impact from unrealized gains and losses on commodity risk management activities, partially offset by a $207 million favorable impact from inventory valuation adjustments.
For the nine months ended September 30, 2025 compared to the same period last year, net income decreased $648 million, or 13%, primarily due to a $598 million gain recognized by Sunoco LP on its sale of West Texas assets in the prior period, a $400 million increase in depreciation, depletion and amortization and a $246 million increase in interest expense, net of interest capitalized, partially offset by a $203 million increase in Adjusted EBITDA, a $198 million decrease in income tax expense and a $130 million favorable impact from inventory valuation adjustments.
These changes are discussed in more detail below and in "Segment Operating Results."
Adjusted EBITDA (consolidated).For the three months ended September 30, 2025 compared to the same period last year, Adjusted EBITDA decreased $121 million, or 3%, primarily due to lower segment margin and higher operating expenses in multiple reportable segments.
For the nine months ended September 30, 2025 compared to the same period last year, Adjusted EBITDA increased $203 million, or 2%, primarily due to higher segment margin in our midstream segment and in 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.
Additional discussion on the changes impacting Adjusted EBITDA is available in "Segment Operating Results."
Depreciation, Depletion and Amortization.Depreciation, depletion and amortization increased for the three and nine months ended September 30, 2025 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 nine months ended September 30, 2025 compared to the same periods last year primarily due to an increase in aggregate debt balances following the acquisitions of NuStar and WTG Midstream Holdings LLC and the refinancing of certain preferred units with long-term debt.
Income Tax Expense.For the three and nine months ended September 30, 2025 compared to the same periods 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.
Impairment Losses. For the three and nine months ended September 30, 2025, impairment losses were primarily related to USAC's evaluation of the future deployment of its idle fleet under current market conditions. For the nine months ended September 30, 2024, impairment losses were primarily related to Sunoco LP's termination of a lease in June 2024.
(Gain) Loss on Interest Rate Derivative.For the three and nine months ended September 30, 2024, the gain and loss on interest rate derivative resulted from changes in forward interest rates, which caused USAC's interest rate swap to change in value. This interest rate derivative was terminated by USAC in August 2024.
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 unrealized gains and losses 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 and nine months ended September 30, 2025, the Partnership's cost of products sold included favorable inventory valuation adjustments of $10 million and $31 million, respectively, which increased net income. For the three and nine months ended September 30, 2024, the Partnership's cost of products sold included unfavorable inventory adjustments of $197 million and $99 million, respectively, which decreased net income.
Losses on Extinguishments of Debt. For the three and nine months ended September 30, 2025, the loss on extinguishment of debt was primarily related to Sunoco LP's termination of bridge financing related to the Parkland acquisition. For the nine months ended September 30, 2024, losses on extinguishment of debt included amounts recognized upon debt redemptions by Energy Transfer, Sunoco LP and USAC.
Adjusted EBITDA Related to Unconsolidated Affiliates andEquity in Earnings of Unconsolidated Affiliates.See additional information in "Supplemental Information on Unconsolidated Affiliates" and "Segment Operating Results."
Gain on Sale of West Texas Assets. The gain on sale of West Texas assets was recognized by Sunoco LP in April 2024 on its sale of 204 convenience stores located in West Texas, New Mexico and Oklahoma to 7-Eleven, Inc.
Other, Net.Other, net primarily includes the amortization of regulatory assets and other income and expense amounts.
Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated affiliates:
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
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| 2025 | 2024 | Change | 2025 | 2024 | Change | ||||||||||||||||||||||||||||||
| Equity in earnings of unconsolidated affiliates: | |||||||||||||||||||||||||||||||||||
| Citrus | $ | 41 | $ | 41 | $ | - | $ | 114 | $ | 105 | $ | 9 | |||||||||||||||||||||||
| MEP | 19 | 16 | 3 | 54 | 47 | 7 | |||||||||||||||||||||||||||||
| White Cliffs | 5 | 4 | 1 | 13 | 14 | (1) | |||||||||||||||||||||||||||||
| Explorer | 8 | 11 | (3) | 22 | 26 | (4) | |||||||||||||||||||||||||||||
| SESH | 14 | 12 | 2 | 42 | 32 | 10 | |||||||||||||||||||||||||||||
| Other | 29 | 18 | 11 | 68 | 61 | 7 | |||||||||||||||||||||||||||||
| Total equity in earnings of unconsolidated affiliates | $ | 116 | $ | 102 | $ | 14 | $ | 313 | $ | 285 | $ | 28 | |||||||||||||||||||||||
|
Adjusted EBITDA related to unconsolidated affiliates(1):
|
|||||||||||||||||||||||||||||||||||
| Citrus | $ | 88 | $ | 89 | $ | (1) | $ | 255 | $ | 252 | $ | 3 | |||||||||||||||||||||||
| MEP | 28 | 25 | 3 | 80 | 73 | 7 | |||||||||||||||||||||||||||||
| White Cliffs | 10 | 9 | 1 | 28 | 28 | - | |||||||||||||||||||||||||||||
| Explorer | 12 | 17 | (5) | 35 | 41 | (6) | |||||||||||||||||||||||||||||
| SESH | 15 | 13 | 2 | 45 | 39 | 6 | |||||||||||||||||||||||||||||
| Other | 40 | 28 | 12 | 99 | 89 | 10 | |||||||||||||||||||||||||||||
| Total Adjusted EBITDA related to unconsolidated affiliates | $ | 193 | $ | 181 | $ | 12 | $ | 542 | $ | 522 | $ | 20 | |||||||||||||||||||||||
| Distributions received from unconsolidated affiliates: | |||||||||||||||||||||||||||||||||||
| Citrus | $ | 10 | $ | - | $ | 10 | $ | 76 | $ | 94 | $ | (18) | |||||||||||||||||||||||
| MEP | 26 | 16 | 10 | 81 | 63 | 18 | |||||||||||||||||||||||||||||
| White Cliffs | 9 | 9 | - | 27 | 30 | (3) | |||||||||||||||||||||||||||||
| Explorer | 8 | 11 | (3) | 23 | 29 | (6) | |||||||||||||||||||||||||||||
| SESH | 15 | 15 | - | 38 | 47 | (9) | |||||||||||||||||||||||||||||
| Other | 24 | 20 | 4 | 68 | 60 | 8 | |||||||||||||||||||||||||||||
| Total distributions received from unconsolidated affiliates | $ | 92 | $ | 71 | $ | 21 | $ | 313 | $ | 323 | $ | (10) | |||||||||||||||||||||||
(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 andselling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.
•Unrealized gains and losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.
•Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. 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 September 30, |
Nine Months Ended September 30, |
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| 2025 | 2024 | Change | 2025 | 2024 | Change | ||||||||||||||||||||||||||||||
|
Natural gas transported (BBtu/d)
|
13,861 | 13,214 | 647 | 14,102 | 13,510 | 592 | |||||||||||||||||||||||||||||
| Withdrawals from storage natural gas inventory (BBtu) | - | 2,325 | (2,325) | 8,225 | 10,555 | (2,330) | |||||||||||||||||||||||||||||
|
Revenues
|
$ | 869 | $ | 678 | $ | 191 | $ | 3,094 | $ | 2,233 | $ | 861 | |||||||||||||||||||||||
|
Cost of products sold
|
546 | 272 | 274 | 2,071 | 964 | 1,107 | |||||||||||||||||||||||||||||
|
Segment margin
|
323 | 406 | (83) | 1,023 | 1,269 | (246) | |||||||||||||||||||||||||||||
| Unrealized (gains) losses on commodity risk management activities | (16) | (11) | (5) | 39 | 24 | 15 | |||||||||||||||||||||||||||||
|
Operating expenses, excluding non-cash compensation expense
|
(72) | (61) | (11) | (190) | (180) | (10) | |||||||||||||||||||||||||||||
|
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(12) | (11) | (1) | (36) | (37) | 1 | |||||||||||||||||||||||||||||
|
Adjusted EBITDA related to unconsolidated affiliates
|
6 | 6 | - | 17 | 18 | (1) | |||||||||||||||||||||||||||||
|
Other
|
1 | - | 1 | 5 | 1 | 4 | |||||||||||||||||||||||||||||
|
Segment Adjusted EBITDA
|
$ | 230 | $ | 329 | $ | (99) | $ | 858 | $ | 1,095 | $ | (237) | |||||||||||||||||||||||
Volumes. For the three and nine months ended September 30, 2025 compared to the same periods last year, transported volumes of gas on our Texas intrastate pipelines increased primarily due to more third-party transportation. For the nine months ended September 30, 2025 compared to the same period last year, the increase was partially offset by lower 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.
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.
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
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| 2025 | 2024 | Change | 2025 | 2024 | Change | ||||||||||||||||||||||||||||||
|
Transportation fees
|
$ | 218 | $ | 208 | $ | 10 | $ | 659 | $ | 655 | $ | 4 | |||||||||||||||||||||||
|
Natural gas sales and other (excluding unrealized gains and losses)
|
67 | 168 | (101) | 300 | 567 | (267) | |||||||||||||||||||||||||||||
| Retained fuel (excluding unrealized gains and losses) | 8 | 4 | 4 | 26 | 17 | 9 | |||||||||||||||||||||||||||||
| Storage margin (excluding unrealized gains and losses and fair value inventory adjustments) | 14 | 15 | (1) | 77 | 54 | 23 | |||||||||||||||||||||||||||||
| Unrealized gains (losses) on commodity risk management activities and fair value inventory adjustments | 16 | 11 | 5 | (39) | (24) | (15) | |||||||||||||||||||||||||||||
|
Total segment margin
|
$ | 323 | $ | 406 | $ | (83) | $ | 1,023 | $ | 1,269 | $ | (246) | |||||||||||||||||||||||
Segment Adjusted EBITDA. For the three months ended September 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment decreased due to the net impact of the following:
•a decrease of $101 million in realized natural gas sales and other primarily due to lower optimization volumes with shifts to long-term third-party contracts from the Permian and narrower price spreads; and
•an increase of $11 million in operating expenses primarily due to increases in ad valorem taxes and maintenance project costs; partially offset by
•an increase of $10 million in transportation fees primarily due to the volume shift to long-term third party contracts from our optimization group on our Texas system; and
•an increase of $4 million in retained fuel margin primarily due to higher gas prices.
For the nine months ended September 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment decreased due to the net impact of the following:
•a decrease of $267 million in realized natural gas sales and other primarily due to lower pipeline optimization as a result of lower volatility in natural gas prices, lower optimization volumes with shifts to long-term third-party contracts from the Permian and narrower price spreads; and
•an increase of $10 million in operating expenses primarily due to increases in ad valorem taxes and employee costs; partially offset by
•an increase of $23 million in storage margin primarily due to higher storage optimization;
•an increase of $9 million in retained fuel margin primarily due to higher gas prices;
•an increase of $4 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 the recovery in the prior period of certain disputed fees on our Texas system; and
•a decrease of $1 million in selling, general and administrative expenses primarily due to lower legal fees.
Interstate Transportation and Storage
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
||||||||||||||||||||||||||||||||||
| 2025 | 2024 | Change | 2025 | 2024 | Change | ||||||||||||||||||||||||||||||
| Natural gas transported (BBtu/d) | 18,013 | 16,616 | 1,397 | 18,123 | 16,826 | 1,297 | |||||||||||||||||||||||||||||
| Natural gas sold (BBtu/d) | 43 | 39 | 4 | 35 | 27 | 8 | |||||||||||||||||||||||||||||
| Revenues | $ | 603 | $ | 575 | $ | 28 | $ | 1,814 | $ | 1,696 | $ | 118 | |||||||||||||||||||||||
| Cost of products sold | 3 | 3 | - | 8 | 6 | 2 | |||||||||||||||||||||||||||||
| Segment margin | 600 | 572 | 28 | 1,806 | 1,690 | 116 | |||||||||||||||||||||||||||||
| Operating expenses, excluding non-cash compensation, amortization and accretion expenses | (271) | (203) | (68) | (681) | (616) | (65) | |||||||||||||||||||||||||||||
| Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses | (29) | (34) | 5 | (92) | (99) | 7 | |||||||||||||||||||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 129 | 125 | 4 | 378 | 361 | 17 | |||||||||||||||||||||||||||||
| Other | 2 | - | 2 | 2 | (1) | 3 | |||||||||||||||||||||||||||||
| Segment Adjusted EBITDA | $ | 431 | $ | 460 | $ | (29) | $ | 1,413 | $ | 1,335 | $ | 78 | |||||||||||||||||||||||
Volumes.For the three and nine months ended September 30, 2025 compared to the same periods last year, transported volumes increased primarily due to more capacity sold and higher utilization on several of our systems due to increased demand.
Segment Adjusted EBITDA. For the three months ended September 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impact of the following:
•an increase of $68 million in operating expenses primarily due to a $43 million increase related to the resolution of a prior period ad valorem tax obligation on our Rover system, an $11 million increase in transportation expense and an aggregate $15 million increase in other items, primarily including ad valorem taxes, maintenance projects and revaluation of system gas; partially offset by
•an increase of $28 million in segment margin primarily due to a $25 million increase in transportation revenue from several of our interstate pipeline systems due to higher contracted volumes and a $6 million increase in operational gas sales. These increases were partially offset by a $4 million decrease in interruptible usage and parking revenue.
For the nine months ended September 30, 2025 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 $116 million in segment margin primarily due to a $63 million increase in transportation revenue from several of our interstate pipeline systems due to higher contracted volumes, a $35 million negative impact in the prior period related to the conclusion of a rate case on our Panhandle system and a $19 million increase in operational gas sales; and
•an increase of $17 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to a $7 million increase from our Midcontinent Express Pipeline joint venture, a $6 million increase from our Southeast Supply Header pipeline joint venture and a $3 million increase from our Citrus joint venture; partially offset by
•an increase of $65 million in operating expenses primarily due to a $43 million increase from the resolution of a prior period ad valorem tax obligation on our Rover system, a $26 million increase in transportation expense and a $17 million increase in direct costs, primarily including ad valorem taxes, employee costs and electricity costs, partially offset by a $15 million decrease in maintenance projects and a $6 million decrease in revaluation of system gas and storage expense.
Midstream
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
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| 2025 | 2024 | Change | 2025 | 2024 | Change | ||||||||||||||||||||||||||||||
|
Gathered volumes (BBtu/d)
|
21,581 | 21,027 | 554 | 21,111 | 20,132 | 979 | |||||||||||||||||||||||||||||
|
NGLs produced (MBbls/d)
|
1,149 | 1,094 | 55 | 1,140 | 980 | 160 | |||||||||||||||||||||||||||||
|
Equity NGLs (MBbls/d)
|
67 | 65 | 2 | 64 | 58 | 6 | |||||||||||||||||||||||||||||
|
Revenues
|
$ | 2,992 | $ | 2,758 | $ | 234 | $ | 9,783 | $ | 8,039 | $ | 1,744 | |||||||||||||||||||||||
|
Cost of products sold
|
1,746 | 1,551 | 195 | 5,917 | 4,727 | 1,190 | |||||||||||||||||||||||||||||
|
Segment margin
|
1,246 | 1,207 | 39 | 3,866 | 3,312 | 554 | |||||||||||||||||||||||||||||
|
Operating expenses, excluding non-cash compensation expense
|
(459) | (411) | (48) | (1,296) | (1,055) | (241) | |||||||||||||||||||||||||||||
|
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(48) | (57) | 9 | (151) | (144) | (7) | |||||||||||||||||||||||||||||
|
Adjusted EBITDA related to unconsolidated affiliates
|
11 | 6 | 5 | 22 | 18 | 4 | |||||||||||||||||||||||||||||
|
Other
|
1 | 71 | (70) | 3 | 74 | (71) | |||||||||||||||||||||||||||||
|
Segment Adjusted EBITDA
|
$ | 751 | $ | 816 | $ | (65) | $ | 2,444 | $ | 2,205 | $ | 239 | |||||||||||||||||||||||
Volumes.For the three and nine months ended September 30, 2025 compared to the same periods last 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 in the Northeast and Ark-La-Tex regions. NGL production increased primarily due to recently acquired assets and increased Permian plant utilization.
Segment Adjusted EBITDA. For the three months ended September 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impact of the following:
•a decrease of $70 million in other income due to the recognition of proceeds from a business interruption claim in September 2024;
•an increase of $48 million in operating expenses primarily due to recently acquired assets and assets placed in service, as well as the impact of certain estimates recorded in the prior period which were subsequently adjusted. The increase also included a $9 million increase in ad valorem taxes and a $6 million increase related to increased volumes and repairs in the Permian region; and
•a decrease of $2 million in segment margin due to lower dry gas volumes in the Northeast and Ark-La-Tex regions; partially offset by
•an increase of $34 million in segment margin primarily due to recently acquired assets and higher volumes in the Permian region;
•an increase of $7 million in segment margin due to higher natural gas prices of $32 million, partially offset by lower NGL prices of $25 million;
•a decrease of $9 million in selling, general and administrative expenses due to a $3 million decrease resulting from one-time expenses in the prior period, as well as a $3 million decrease in legal fees and a $2 million decrease in insurance expenses; and
•an increase of $5 million in Adjusted EBITDA related to unconsolidated affiliates due to the one-time recognition of fee credits associated with a contract restructuring.
For the nine months ended September 30, 2025 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 $393 million in segment margin primarily due to recently acquired assets and higher volumes in the Permian region;
•an increase of $160 million in segment margin due to the non-recurring recognition of certain amounts associated with Winter Storm Uri in 2021, which represents the remainder of midstream segment margin from Winter Storm Uri that had not already been recognized;
•an increase of $46 million in segment margin due to higher natural gas prices of $105 million, partially offset by lower NGL prices of $59 million; and
•an increase of $4 million in Adjusted EBITDA related to unconsolidated affiliates due to the one-time recognition of fee credits associated with a contract restructuring; partially offset by
•an increase of $241 million in operating expenses primarily due to recently acquired assets and assets placed in service, as well as the impact of certain estimates recorded in the prior period which were subsequently adjusted. The increase also included a $22 million increase in employee costs and a $6 million increase related to increased volumes and repairs in the Permian region;
•a decrease of $71 million in other income due to the recognition of proceeds from a business interruption claim in September 2024;
•a decrease of $45 million in segment margin due to lower dry gas volumes in the Northeast and Ark-La-Tex regions; and
•an increase of $7 million in selling, general, and administrative expenses primarily due to higher corporate allocations.
NGL and Refined Products Transportation and Services
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
||||||||||||||||||||||||||||||||||
| 2025 | 2024 | Change | 2025 | 2024 | Change | ||||||||||||||||||||||||||||||
| NGL transportation volumes (MBbls/d) | 2,487 | 2,237 | 250 | 2,333 | 2,187 | 146 | |||||||||||||||||||||||||||||
| Refined products transportation volumes (MBbls/d) | 601 | 574 | 27 | 591 | 583 | 8 | |||||||||||||||||||||||||||||
| NGL and refined products terminal volumes (MBbls/d) | 1,660 | 1,505 | 155 | 1,556 | 1,470 | 86 | |||||||||||||||||||||||||||||
| NGL fractionation volumes (MBbls/d) | 1,123 | 1,152 | (29) | 1,121 | 1,099 | 22 | |||||||||||||||||||||||||||||
| Revenues | $ | 5,853 | $ | 5,853 | $ | - | $ | 18,703 | $ | 18,174 | $ | 529 | |||||||||||||||||||||||
| Cost of products sold | 4,493 | 4,527 | (34) | 14,769 | 14,358 | 411 | |||||||||||||||||||||||||||||
| Segment margin | 1,360 | 1,326 | 34 | 3,934 | 3,816 | 118 | |||||||||||||||||||||||||||||
| Unrealized gains on commodity risk management activities | (4) | (64) | 60 | (64) | (22) | (42) | |||||||||||||||||||||||||||||
| Operating expenses, excluding non-cash compensation expense | (294) | (243) | (51) | (771) | (703) | (68) | |||||||||||||||||||||||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (41) | (42) | 1 | (130) | (118) | (12) | |||||||||||||||||||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 33 | 35 | (2) | 96 | 98 | (2) | |||||||||||||||||||||||||||||
| Segment Adjusted EBITDA | $ | 1,054 | $ | 1,012 | $ | 42 | $ | 3,065 | $ | 3,071 | $ | (6) | |||||||||||||||||||||||
Volumes.For the three and nine months ended September 30, 2025 compared to the same periods last year, NGL transportation volumes increased primarily due to higher volumes from the Permian region.
For the three months ended September 30, 2025 compared to the same period last year, fractionated volumes were slightly lower due to maintenance at our Mont Belvieu fractionation complex in the current period. For the nine months ended September 30, 2025 compared to the same period last year, the increase in transportation volumes discussed above also led to higher fractionated volumes.
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.
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
||||||||||||||||||||||||||||||||||
| 2025 | 2024 | Change | 2025 | 2024 | Change | ||||||||||||||||||||||||||||||
| Transportation margin | $ | 743 | $ | 651 | $ | 92 | $ | 2,062 | $ | 1,930 | $ | 132 | |||||||||||||||||||||||
| Fractionators and refinery services margin | 230 | 239 | (9) | 692 | 704 | (12) | |||||||||||||||||||||||||||||
| Terminal services margin | 271 | 260 | 11 | 755 | 718 | 37 | |||||||||||||||||||||||||||||
| Storage margin | 81 | 79 | 2 | 237 | 233 | 4 | |||||||||||||||||||||||||||||
| Marketing margin | 30 | 33 | (3) | 123 | 209 | (86) | |||||||||||||||||||||||||||||
| Unrealized gains on commodity risk management activities | 5 | 64 | (59) | 65 | 22 | 43 | |||||||||||||||||||||||||||||
| Total segment margin | $ | 1,360 | $ | 1,326 | $ | 34 | $ | 3,934 | $ | 3,816 | $ | 118 | |||||||||||||||||||||||
Segment Adjusted EBITDA. For the three months ended September 30, 2025 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 $92 million in transportation margin primarily due to higher throughput and contractual rate escalations on our Mariner East and our Gulf Coast pipeline systems; and
•an increase of $11 million in terminal services margin primarily due to a $6 million increase in fees from loading volumes for export at our Nederland and Marcus Hook terminals and a $5 million increase from higher throughput and storage at our refined product terminals; partially offset by
•an increase of $51 million in operating expenses primarily due to $17 million in one-time investigation and remediation costs, a $19 million increase in costs driven by higher volumes across our NGL system, a $6 million increase from the timing of project related expenses, a $4 million increase in ad valorem taxes on assets placed in service and a $4 million increase in employee costs;
•a decrease of $9 million in fractionators and refinery services margin primarily due to lower throughput due to more downtime; and
•a decrease of $3 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to the timing of the gains from the optimization of hedged NGL and refined product inventories.
For the nine months ended September 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment decreased due to the net impact of the following:
•a decrease of $86 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to lower gains from gasoline blending activities due to less favorable market conditions, and lower gains from the optimization of hedged NGL and refined product inventories;
•an increase of $68 million in operating expenses primarily due to $30 million in one-time investigation and remediation costs, a $19 million increase in costs driven by higher volumes across our system, a $15 million increase in employee costs and increases totaling $4 million from various other operating expenses;
•an increase of $12 million in selling, general and administrative expenses primarily due to increased costs from recently acquired assets; and
•a decrease of $12 million in fractionators and refinery services margin, despite higher throughput, due to lower fees for fractionation services and more downtime for certain fractionation assets during the 2025 period; partially offset by
•an increase of $132 million in transportation margin primarily due to higher throughput and contractual rate escalations on our Mariner East and our Gulf Coast pipeline systems; and
•an increase of $37 million in terminal services margin primarily due to a $29 million increase in fees from loading volumes for export at our Nederland and Marcus Hook terminals and an $8 million increase from higher throughput and storage at our refined product terminals.
Crude Oil Transportation and Services
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
||||||||||||||||||||||||||||||||||
| 2025 | 2024 | Change | 2025 | 2024 | Change | ||||||||||||||||||||||||||||||
| Crude oil transportation volumes (MBbls/d) | 7,023 | 7,025 | (2) | 6,932 | 6,540 | 392 | |||||||||||||||||||||||||||||
| Crude oil terminal volumes (MBbls/d) | 3,195 | 3,533 | (338) | 3,245 | 3,356 | (111) | |||||||||||||||||||||||||||||
| Revenues | $ | 6,043 | $ | 7,309 | $ | (1,266) | $ | 17,999 | $ | 22,319 | $ | (4,320) | |||||||||||||||||||||||
| Cost of products sold | 5,047 | 6,297 | (1,250) | 14,986 | 19,200 | (4,214) | |||||||||||||||||||||||||||||
| Segment margin | 996 | 1,012 | (16) | 3,013 | 3,119 | (106) | |||||||||||||||||||||||||||||
| Unrealized (gains) losses on commodity risk management activities | 18 | 20 | (2) | (7) | 20 | (27) | |||||||||||||||||||||||||||||
| Operating expenses, excluding non-cash compensation expense | (243) | (231) | (12) | (693) | (635) | (58) | |||||||||||||||||||||||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (36) | (39) | 3 | (118) | (111) | (7) | |||||||||||||||||||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 11 | 6 | 5 | 25 | 22 | 3 | |||||||||||||||||||||||||||||
| Other | - | - | - | - | 2 | (2) | |||||||||||||||||||||||||||||
| Segment Adjusted EBITDA | $ | 746 | $ | 768 | $ | (22) | $ | 2,220 | $ | 2,417 | $ | (197) | |||||||||||||||||||||||
Volumes.For the nine months ended September 30, 2025 compared to the same period last year, crude oil transportation volumes were higher due to continued growth on our Texas pipeline system, gathering systems and from the ET-S Permian joint venture with Sunoco LP, partially offset by lower volumes on our Bakken Pipeline. Volumes on our Bayou Bridge system were also lower for the three months ended September 30, 2025 due to higher Gulf Coast refinery maintenance. For the three and nine months ended September 30, 2025 compared to the same periods last year, crude terminal volumes were lower primarily due to Gulf Coast refinery maintenance and lower volumes received from our Bakken Pipeline system.
Segment Adjusted EBITDA. For the three months ended September 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment decreased due to the net impact of the following:
•a decrease of $18 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) due to decreased transportation revenue, primarily from our Bakken Pipeline and Bayou Bridge systems; and
•an increase of $12 million in operating expenses primarily due to a $4 million increase in maintenance project costs, a $4 million increase in materials costs, a $3 million increase in ad valorem taxes and a $3 million increase in employee costs due to higher headcount; partially offset by
•a decrease of $3 million in selling, general and administrative expenses primarily due to lower insurance expenses.
For the nine months ended September 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment decreased due to the net impact of the following:
•a decrease of $133 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) due to decreased transportation revenue, primarily from our Bakken Pipeline system, and optimization revenues from existing assets, partially offset by a $90 million increase from gathering fees from assets related to our ET-S Permian joint venture;
•an increase of $58 million in operating expenses primarily due to a $20 million increase from assets contributed upon the formation of ET-S Permian, a $14 million increase in employee costs due to higher headcount, a $7 million increase in materials costs, a $9 million increase in maintenance project costs, a $7 million increase in right-of-way lease and maintenance expenses and a $3 million increase in utilities; and
•an increase of $7 million in selling, general and administrative expenses primarily due to costs associated with ET-S Permian.
Investment in Sunoco LP
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
||||||||||||||||||||||||||||||||||
| 2025 | 2024 | Change | 2025 | 2024 | Change | ||||||||||||||||||||||||||||||
| Revenues | $ | 6,032 | $ | 5,751 | $ | 281 | $ | 16,601 | $ | 17,424 | $ | (823) | |||||||||||||||||||||||
| Cost of products sold | 5,386 | 5,327 | 59 | 14,733 | 15,951 | (1,218) | |||||||||||||||||||||||||||||
| Segment margin | 646 | 424 | 222 | 1,868 | 1,473 | 395 | |||||||||||||||||||||||||||||
| Unrealized losses on commodity risk management activities | 15 | 1 | 14 | 7 | 8 | (1) | |||||||||||||||||||||||||||||
| Operating expenses, excluding non-cash compensation expense | (180) | (168) | (12) | (500) | (423) | (77) | |||||||||||||||||||||||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (47) | (52) | 5 | (130) | (216) | 86 | |||||||||||||||||||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 58 | 47 | 11 | 159 | 53 | 106 | |||||||||||||||||||||||||||||
| Inventory valuation adjustments | (10) | 197 | (207) | (31) | 99 | (130) | |||||||||||||||||||||||||||||
| Other | 7 | 7 | - | 28 | 24 | 4 | |||||||||||||||||||||||||||||
| Segment Adjusted EBITDA | $ | 489 | $ | 456 | $ | 33 | $ | 1,401 | $ | 1,018 | $ | 383 | |||||||||||||||||||||||
The investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Segment Adjusted EBITDA.For the three months ended September 30, 2025 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 $29 million in segment margin (excluding unrealized gains and losses on commodity risk management activities and inventory valuation adjustments) primarily due to increased fuel volumes and increased margin from transmix and blending activities;
•an increase of $11 million in Adjusted EBITDA related to unconsolidated affiliates related to ET-S Permian; and
•a decrease of $5 million in selling, general and administrative expenses, excluding non-cash compensation expense, primarily due to one-time NuStar acquisition costs incurred in 2024; partially offset by
•an increase of $12 million in operating expenses, excluding non-cash compensation expenses, due to an increase in operating expenses from the timing of the acquisitions of NuStar and Zenith European terminals.
For the nine months ended September 30, 2025 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 $264 million in segment margin (excluding unrealized gains and losses on commodity risk management activities and inventory valuation adjustments) primarily due to the acquisitions of NuStar and Zenith European terminals. NuStar was acquired in May 2024, and the prior period only reflected five months of results as well as an increase in fuel volumes and increased volume from transmix and blending activities. These increases were partially offset by a decrease of $50 million from Sunoco LP's deconsolidation of certain of NuStar's assets in connection with the formation of ET-S Permian effective July 1, 2024.
•an increase of $106 million in Adjusted EBITDA related to unconsolidated affiliates related to ET-S Permian; and
•a decrease of $86 million in selling, general and administrative expenses, excluding non-cash compensation expense, related to one-time NuStar acquisition costs in 2024; partially offset by
•an increase of $77 million in operating expenses due to increased costs from the acquisition of NuStar acquisition, which was acquired in May 2024 and therefore is only reflected for five months in the prior period. This increase was partially offset by a decrease of $6 million from Sunoco LP's deconsolidation of certain of NuStar's assets in connection with the formation of ET-S Permian effective July 1, 2024.
Investment in USAC
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
||||||||||||||||||||||||||||||||||
| 2025 | 2024 | Change | 2025 | 2024 | Change | ||||||||||||||||||||||||||||||
|
Revenues
|
$ | 251 | $ | 240 | $ | 11 | $ | 746 | $ | 705 | $ | 41 | |||||||||||||||||||||||
|
Cost of products sold
|
34 | 38 | (4) | 112 | 110 | 2 | |||||||||||||||||||||||||||||
|
Segment margin
|
217 | 202 | 15 | 634 | 595 | 39 | |||||||||||||||||||||||||||||
|
Operating expenses, excluding non-cash compensation expense
|
(43) | (43) | - | (133) | (125) | (8) | |||||||||||||||||||||||||||||
|
Selling, general and administrative expenses, excluding non-cash compensation expense
|
(14) | (13) | (1) | (42) | (42) | - | |||||||||||||||||||||||||||||
| Other | - | - | - | - | 1 | (1) | |||||||||||||||||||||||||||||
|
Segment Adjusted EBITDA
|
$ | 160 | $ | 146 | $ | 14 | $ | 459 | $ | 429 | $ | 30 | |||||||||||||||||||||||
The investment in USAC segment reflects the consolidated results of USAC.
Segment Adjusted EBITDA.For the three months ended September 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to an increase in segment margin primarily due to higher market-based and CPI-based rates.
For the nine months ended September 30, 2025 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 $39 million in segment margin primarily due to higher market-based and CPI-based rates; partially offset by
•an increase of $8 million in operating expenses primarily due to an increase in employee costs associated with increased revenue-generating horsepower.
All Other
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
||||||||||||||||||||||||||||||||||
| 2025 | 2024 | Change | 2025 | 2024 | Change | ||||||||||||||||||||||||||||||
| Revenues | $ | 923 | $ | 379 | $ | 544 | $ | 2,854 | $ | 1,140 | $ | 1,714 | |||||||||||||||||||||||
| Cost of products sold | 895 | 369 | 526 | 2,799 | 1,107 | 1,692 | |||||||||||||||||||||||||||||
| Segment margin | 28 | 10 | 18 | 55 | 33 | 22 | |||||||||||||||||||||||||||||
| Unrealized (gains) losses on commodity risk management activities | (13) | 1 | (14) | (7) | 20 | (27) | |||||||||||||||||||||||||||||
| Operating expenses, excluding non-cash compensation expense | (17) | (20) | 3 | (18) | (28) | 10 | |||||||||||||||||||||||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (11) | (23) | 12 | (37) | (43) | 6 | |||||||||||||||||||||||||||||
|
Adjusted EBITDA related to unconsolidated affiliates
|
2 | 2 | - | 4 | 4 | - | |||||||||||||||||||||||||||||
| Other and eliminations | (12) | 2 | (14) | (55) | 43 | (98) | |||||||||||||||||||||||||||||
| Segment Adjusted EBITDA | $ | (23) | $ | (28) | $ | 5 | $ | (58) | $ | 29 | $ | (87) | |||||||||||||||||||||||
Amounts reflected in our all other segment primarily include:
•our natural gas marketing operations;
•our wholly owned natural gas compression operations; and
•our natural resources business.
Segment Adjusted EBITDA.For the three months ended September 30, 2025 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 $8 million due to lower acquisition-related expenses;
•an increase of $7 million in lease income on recently acquired assets; and
•an increase of $5 million in our dual drive compression business due to higher service fee revenue; partially offset by
•a decrease of $11 million due to an increase in the intersegment elimination from increased earnings of Sunoco LP's 32.5% share of ET-S Permian, which is consolidated in our crude oil transportation and services segment and reflected as an unconsolidated affiliate in our investment in Sunoco LP segment; and
•a decrease of $4 million from our compressor packaging business.
For the nine months ended September 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impact of the following:
•a decrease of $106 million due to an increase in the intersegment elimination from increased earnings of Sunoco LP's 32.5% share of ET-S Permian, which is consolidated in our crude oil transportation and services segment and reflected as an unconsolidated affiliate in our investment in Sunoco LP segment; and
•a decrease of $7 million from our natural resources business; partially offset by
•an increase of $9 million in lease income from recently acquired real estate;
•an increase of $8 million in our dual drive compression business due to higher service fees and gas revenue; and
•an increase in $4 million due to higher acquisition-related expenses in the prior period.
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 currently expect capital expenditures in 2025 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 | $ | 1,450 | $ | 85 | |||||||
| Interstate transportation and storage | 175 | 205 | |||||||||
| Midstream | 1,300 | 375 | |||||||||
| NGL and refined products transportation and services | 1,250 | 150 | |||||||||
| Crude oil transportation and services | 225 | 180 | |||||||||
| All other (including eliminations) | 200 | 105 | |||||||||
|
Total capital expenditures
|
$ | 4,600 | $ | 1,100 | |||||||
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 invest approximately $150 million in maintenance capital expenditures and at least $400 million in growth capital for the full year 2025.
USAC currently plans to invest between $38 million and $42 million in maintenance capital expenditures and between $115 million and $125 million in expansion capital expenditures for the full year 2025.
Cash Flows
Our cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price 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.
Nine months ended September 30, 2025 compared to nine months ended September 30, 2024. Cash provided by operating activities during 2025 was $8.25 billion compared to $8.92 billion for 2024, and net income was $4.47 billion for 2025 and $5.12 billion for 2024. The difference between net income and net cash provided by operating activities for the nine months ended September 30, 2025 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions and divestitures) of $483 million and other items totaling $4.07 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 2025 and 2024 consisted primarily of depreciation, depletion and amortization of $4.19 billion and $3.79 billion, respectively, deferred income tax expense of $68 million and $165 million, respectively, favorable inventory valuation adjustments of $31 million and unfavorable inventory valuation adjustments of $99 million, respectively, and non-cash compensation expense of $110 million and $113 million, respectively. For 2025 and 2024, net income also included equity in earnings of unconsolidated affiliates of $313 million and $285 million, respectively, losses on extinguishments of debt of $31 million and $11 million, respectively, and impairment losses of $8 million and $50 million, respectively, as well as a $598 million gain on Sunoco LP's sale of its West Texas assets in 2024.
Cash provided by operating activities includes cash distributions received from unconsolidated affiliates that are deemed to be paid from cumulative earnings, which distributions were $236 million in 2025 and $263 million in 2024.
Cash paid for interest, net of interest capitalized, was $2.05 billion and $1.84 billion for the nine months ended September 30, 2025 and 2024, respectively. Interest capitalized was $98 million and $77 million for the nine months ended September 30, 2025 and 2024, 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.
Nine months ended September 30, 2025 compared to nine months ended September 30, 2024. Cash used in investing activities during 2025 was $4.43 billion compared to $4.44 billion for 2024. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2025 were $4.15 billion compared to $2.64 billion for 2024. Additional detail related to our capital expenditures is provided in the table below.
In 2025, we paid $176 million in cash for the acquisition of two terminal facilities and Sunoco LP paid $189 million in cash for the acquisitions of fuel equipment, motor fuel inventory, supply agreements and fuel distribution consignment sites. In 2024, we paid $2.17 billion, net of cash received, for the WTG Midstream acquisition, we paid $84 million to acquire the outstanding
noncontrolling interest in Edwards Lime Gathering, LLC, which is now a wholly owned subsidiary, and we also paid $219 million for other acquisitions. In 2024, Sunoco LP paid $182 million in cash for the acquisition of liquid fuels terminals in Amsterdam, Netherlands and Bantry Bay, Ireland from Zenith Energy, net of $27 million in cash received from the NuStar acquisition. Additionally, in 2024, Sunoco LP received cash proceeds of $990 million from its sale of West Texas assets.
In 2025 and 2024, we received cash distributions from unconsolidated affiliates in excess of cumulative earnings of $77 million and $60 million, respectively, and we paid cash contributions to unconsolidated affiliates of $5 million and $205 million, respectively.
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 nine months ended September 30, 2025:
| Capital Expenditures Recorded During Period | |||||||||||||||||
| Growth | Maintenance | Total | |||||||||||||||
| Intrastate transportation and storage | $ | 867 | $ | 63 | $ | 930 | |||||||||||
| Interstate transportation and storage | 101 | 134 | 235 | ||||||||||||||
| Midstream | 902 | 247 | 1,149 | ||||||||||||||
| NGL and refined products transportation and services | 980 | 96 | 1,076 | ||||||||||||||
| Crude oil transportation and services | 153 | 119 | 272 | ||||||||||||||
|
Investment in Sunoco LP
|
310 | 108 | 418 | ||||||||||||||
| Investment in USAC | 78 | 32 | 110 | ||||||||||||||
| All other (including eliminations) | 136 | 52 | 188 | ||||||||||||||
| Total capital expenditures | $ | 3,527 | $ | 851 | $ | 4,378 | |||||||||||
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.
Nine months ended September 30, 2025 compared to nine months ended September 30, 2024.Cash used in financing activities during 2025 was $562 million compared to $4.34 billion for 2024. During 2025, we had a net increase in our debt level of $3.41 billion compared to a net increase of $4.24 billion for 2024. In 2025 and 2024, we paid debt issuance costs of $111 million and $142 million, respectively. In 2025, Sunoco LP received $1.47 billion in cash from the issuance of the Sunoco LP Series A Preferred Units. In 2025, we paid $500 million in cash for the redemption of our Series F Preferred Units and in 2024, we paid $2.65 billion in cash for the redemption of our Series A, Series C, Series D and Series E Preferred Units and paid $37 million in cash to redeem a portion of the outstanding Crestwood Niobrara LLC preferred units. In 2024, USAC paid $749 million in cash for investments in government securities in connection with the legal defeasance of senior notes and Sunoco LP paid $784 million in cash for the redemption of NuStar preferred units.
In 2025 and 2024, we paid distributions of $3.50 billion and $3.43 billion, respectively, to our partners. In 2025 and 2024, we paid distributions of $1.31 billion and $1.38 billion, respectively, to noncontrolling interests. In 2025 and 2024, we paid distributions of $45 million and $51 million, respectively, to our redeemable noncontrolling interests.
In 2025 and 2024, we received capital contributions of $27 million and $637 million, respectively, in cash from noncontrolling interests. In 2024, we received capital contributions of $2 million in cash from redeemable noncontrolling interests.
Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:
|
September 30, 2025 |
December 31, 2024 |
||||||||||
| Energy Transfer indebtedness: | |||||||||||
|
Notes and debentures(1) (2)
|
$ | 48,870 | $ | 46,269 | |||||||
|
Five-Year Credit Facility(2)
|
1,543 | 2,759 | |||||||||
| Subsidiary indebtedness: | |||||||||||
|
Transwestern senior notes
|
75 | 75 | |||||||||
|
Bakken Project senior notes
|
850 | 850 | |||||||||
|
Sunoco LP senior notes, bonds and lease-related obligations(1)
|
9,528 | 7,304 | |||||||||
|
USAC senior notes
|
2,500 | 1,750 | |||||||||
|
Sunoco LP credit facility(2)
|
- | 203 | |||||||||
|
USAC credit facility
|
55 | 772 | |||||||||
| Other long-term debt | 10 | 11 | |||||||||
| Net unamortized premiums, discounts and fair value adjustments | 52 | 77 | |||||||||
| Deferred debt issuance costs | (379) | (310) | |||||||||
| Total debt | 63,104 | 59,760 | |||||||||
|
Less: current maturities of long-term debt
|
8 | 8 | |||||||||
| Long-term debt, less current maturities | $ | 63,096 | $ | 59,752 | |||||||
(1)As of September 30, 2025, these balances included approximately $2.05 billion aggregate principal amount due on or before September 30, 2026, 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 March 2025, the Partnership issued $650 million aggregate principal amount of 5.20% senior notes due April 2030, $1.25 billion aggregate principal amount of 5.70% senior notes due April 2035 and $1.10 billion aggregate principal amount of 6.20% senior notes due April 2055. The Partnership used the net proceeds to refinance existing indebtedness, including to repay commercial paper and borrowings under its Five-Year Credit Facility (described below), and for general partnership purposes.
In March 2025, the Partnership redeemed its $1.00 billion aggregate principal amount of 4.05% senior notes due March 2025 using cash on hand and commercial paper borrowings.
In May 2025, the Partnership redeemed its $1.00 billion aggregate principal amount of 2.90% senior notes due May 2025 using cash on hand and commercial paper borrowings.
In August 2025, the Partnership issued $1.20 billion aggregate principal amount of its Series 2025A junior subordinated notes due 2056 and $800 million aggregate principal amount of its Series 2025B junior subordinated notes due 2056. The Partnership used the net proceeds to repay borrowings under its Five-Year Credit Facility and for general partnership purposes.
In September 2025, the Partnership redeemed its $400 million aggregate principal amount of 5.95% senior notes due December 2025 using cash on hand and commercial paper borrowings.
Sunoco LP Senior Notes Issuances and Redemption
In March 2025, Sunoco LP issued $1.00 billion aggregate principal amount of 6.25% senior notes due 2033 in a private offering. These notes will mature on July 1, 2033 and interest is payable semi-annually on January 1 and July 1 of each year. Sunoco LP used the net proceeds from the private offering to repay its $600 million aggregate principal amount of 5.75% senior notes due 2025 and to repay a portion of the outstanding borrowings under Sunoco LP's revolving credit facility.
In September 2025, Sunoco LP issued $1.00 billion aggregate principal amount of 5.625% senior notes due 2031 and $900 million aggregate principal amount of 5.875%senior notes due 2034 in a private offering. These notes will mature on March 15, 2031 and March 15, 2034, respectively, and interest is payable semi-annually on March 15 and September 15 of each year, commencing on March 15, 2026. Sunoco LP used the net proceeds from this private offering (i) on the closing date of the Parkland acquisition to fund a portion of the cash consideration for the Parkland acquisition and related transaction costs, with the remaining proceeds used for general corporate purposes, and (ii) prior to the closing date of the Parkland acquisition, to temporarily reduce the borrowings outstanding under its revolving credit facility and to pay interest and fees in connection therewith.
The 5.625% senior notes due 2031 and 5.875% senior notes due 2034 were originally subject to a special mandatory redemption requirement, which was eliminated upon closing of the Parkland acquisition.
Sunoco LP - Parkland Senior Note Exchange
In October 2025, in connection with Sunoco LP's Parkland acquisition, Sunoco LP commenced a private offering to exchange C$1.60 billion Canadian dollar denominated notes (collectively, the "PKI CAD Notes") and $2.60 billion U.S. dollar denominated notes (collectively, the "PKI USD Notes"). The exchange offer closed on November 4, 2025, with approximately C$1.47 billion of the PKI CAD Notes and approximately $2.58 billion of the PKI USD Notes being validly tendered and not validly withdrawn.
Sunoco LP GoZone Bonds Remarketing
NuStar Logistics L.P., a wholly owned subsidiary of Sunoco LP, has obligations which include revenue bonds issued by the Parish of St. James, Louisiana pursuant to the Gulf Opportunity Zone Act of 2005 (the "GoZone Bonds"). Sunoco LP recently completed the remarketing of $75 million principal amount of Series 2011 GoZone Bonds, which were previously repurchased on the mandatory purchase date of June 1, 2025 but were not remarketed at that time. The remarketed bonds were issued on October 1, 2025 and have a 3.70% interest rate, a mandatory purchase date of June 1, 2030, and a maturity of August 1, 2041.
USAC Senior Notes Issuance and Redemption
In September 2025, USAC issued $750 million aggregate principal amount of 6.250% senior notes due 2033. USAC used the net proceeds from this issuance, together with borrowings under USAC's credit facility, to redeem its $750 million aggregate principal amount of 6.875% senior notes due 2027 in October 2025.
Credit Facilities and Commercial Paper
Five-Year Credit Facility
The Partnership's revolving credit facility (the "Five-Year Credit Facility") allows for unsecured borrowings up to $5.00 billion until April 11, 2027, and up to $4.84 billion until April 11, 2029. The Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $7.00 billion under certain conditions.
As of September 30, 2025, the Five-Year Credit Facility had $1.54 billion of outstanding borrowings, all of which $1.54 billion consisted of commercial paper. The amount available for future borrowings was $3.44 billion after accounting for outstanding letters of credit in the amount of $21 million. The weighted average interest rate on the total amount outstanding as of September 30, 2025 was 4.33%.
Sunoco LP Credit Facilities
As of September 30, 2025, Sunoco LP's revolving credit facility, which matures in June 2030, had zero outstanding borrowings and $47 million in standby letters of credit outstanding. The unused availability on Sunoco LP's revolving credit facility as of September 30, 2025 was $1.45 billion. The weighted average interest rate on the total amount outstanding as of September 30, 2025 was 6.42%.
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 September 30, 2025, this facility had no outstanding borrowings.
USAC Credit Facility
USAC's credit facility, as amended and restated on August 27, 2025, matures on August 27, 2030, except that (1) if more than $50 million principal amount of USAC's existing 6.875% senior notes due 2027 are outstanding on June 2, 2027, its credit facility will mature on June 2, 2027 and (2) if more than $50 million principal amount of USAC's existing 7.125% senior notes
due 2029 are outstanding on December 14, 2028, its credit facility will mature on December 14, 2028. As of September 30, 2025, USAC's credit facility had $55 million of outstanding borrowings and $1 million outstanding letters of credit. As of September 30, 2025, USAC's credit facility had $1.69 billion of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $1.02 billion was available to be drawn. The weighted average interest rate on the total amount outstanding as of September 30, 2025 was 7.35%.
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 September 30, 2025.
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, 2024 were as follows:
| Quarter Ended | Record Date | Payment Date | Rate | |||||||||||||||||
| December 31, 2024 | February 7, 2025 | February 19, 2025 | $ | 0.3250 | ||||||||||||||||
| March 31, 2025 | May 9, 2025 | May 20, 2025 | 0.3275 | |||||||||||||||||
| June 30, 2025 | August 8, 2025 | August 19, 2025 | 0.3300 | |||||||||||||||||
| September 30, 2025 | November 7, 2025 | November 19, 2025 | 0.3325 | |||||||||||||||||
Cash Distributions on Energy Transfer Preferred Units
Distributions declared on the Energy Transfer Preferred Units were as follows:
| Period Ended |
Record Date (1)
|
Payment Date (1)
|
Series B (2)
|
Series F |
Series G (2)
|
Series H (2)
|
Series I (1)
|
|||||||||||||||||||||||||||||||||||||
| December 31, 2024 | February 3, 2025 | February 17, 2025 | $ | 33.125 | $ | - | $ | - | $ | - | $ | 0.2111 | ||||||||||||||||||||||||||||||||
| March 31, 2025 | May 1, 2025 | May 15, 2025 | - | 33.750 | 35.625 | 32.500 | 0.2111 | |||||||||||||||||||||||||||||||||||||
| June 30, 2025 | August 1, 2025 | August 15, 2025 | 33.125 | - | - | - | 0.2111 | |||||||||||||||||||||||||||||||||||||
| September 30, 2025 | November 4, 2025 | November 14, 2025 | - | - | 35.625 | 32.500 | 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 March 31, 2025, the cash distribution for the Series I Preferred Units was paid on May 15, 2025 to unitholders of record as of the close of business on May 2, 2025. For the period ended June 30, 2025, the cash distribution for the Series I Preferred Units was paid on August 14, 2025 to unitholders of record as of the close of business on August 4, 2025. For the period ended September 30, 2025, the cash distribution for the Series I Preferred Units will be paid on November 14, 2025 to unitholders of record as of the close of business on November 4, 2025.
(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.
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 Sunoco LP and USAC, both of which are master limited partnerships, as well as other non-wholly owned consolidated joint ventures. The following sections describe cash distributions made by our publicly traded subsidiaries, Sunoco LP and USAC, both of which are required by their respective partnership
agreements 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 Sunoco LP
Distributions on Sunoco LP's common units declared and/or paid by Sunoco LP subsequent to December 31, 2024 were as follows:
| Quarter Ended | Payment Date | Rate | ||||||||||||
| December 31, 2024 | February 19, 2025 | $ | 0.8865 | |||||||||||
| March 31, 2025 | May 20, 2025 | 0.8976 | ||||||||||||
| June 30, 2025 | August 19, 2025 | 0.9088 | ||||||||||||
| September 30, 2025 | November 19, 2025 | 0.9202 | ||||||||||||
Cash Distributions Paid by USAC
Distributions on USAC's common units declared and/or paid by USAC subsequent to December 31, 2024 were as follows:
| Quarter Ended | Payment Date | Rate | ||||||||||||
| December 31, 2024 | February 7, 2025 | $ | 0.525 | |||||||||||
| March 31, 2025 | May 9, 2025 | 0.525 | ||||||||||||
| June 30, 2025 | August 8, 2025 | 0.525 | ||||||||||||
| September 30, 2025 | November 7, 2025 | 0.525 | ||||||||||||
Sunoco LP Series A Preferred Units Offering
In September 2025, Sunoco LP closed a private offering of 1.5 million of its 7.875% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units (the "Sunoco LP Series A Preferred Units") at an offering price of $1,000 per unit. Sunoco LP received net proceeds of approximately $1.47 billion from the sale of the Sunoco LP Series A Preferred Units after deducting the initial purchasers' discount and other estimated offering expenses. Sunoco LP used the net proceeds from this private offering (i) on the closing date of the Parkland acquisition, to fund a portion of the cash consideration for the Parkland acquisition, and (ii) prior to the closing date of the Parkland acquisition, to temporarily reduce the borrowings outstanding under Sunoco LP's revolving credit facility and to pay interest and fees in connection therewith.
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 14, 2025. 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 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;
•U.S. and foreign governmental regulation, taxation and tariffs;
•the macroeconomic, regulatory or other potential effects of a prolonged U.S. government shutdown;
•changes to, the application of, and regulation of tariff rates and operational requirements related to our subsidiaries' interstate and intrastate pipelines;
•hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;
•competition from other midstream companies and interstate pipeline companies;
•loss of key personnel;
•loss of key natural gas producers or the providers of fractionation services;
•reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries' pipelines and facilities;
•the effectiveness of risk-management policies and procedures and the ability of our subsidiaries' liquids marketing counterparties to satisfy their financial commitments;
•the nonpayment or nonperformance by our subsidiaries' customers;
•risks related to the development of new infrastructure projects or other growth projects, including failure to make sufficient progress to justify continued development, delays in obtaining customers, increased costs of financing and 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; and
•the costs and effects of legal and administrative proceedings.
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, 2024 filed with the SEC on February 14, 2025 and in "Part II - Item 1A. Risk Factors" of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2025 filed with the SEC on May 8, 2025. 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.
Energy Transfer LP published this content on November 06, 2025, and is solely responsible for the information contained herein. Distributed via Edgar on November 06, 2025 at 18:37 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]