Energy Transfer LP 8-K, filed Feb 17, 2026
Energy Transfer LP (ET)
8-K
2026-02-17
For: 2026-02-17
View Original
Added on
April 06, 2026
About this 8-K
Energy Transfer LP filed this 8-K on February 17, 2026.
Items reported
- Item 2.02: Financial results
- Item 9.01: Financial statements and exhibits
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
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Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
Securities registered pursuant to Section 12(b) of the Act:
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Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Item 2.02. Results of Operations and Financial Condition.
On February 17, 2026, Energy Transfer LP (the “Partnership”) issued a press release announcing its financial and operating results for the fiscal year and fourth fiscal quarter ended December 31, 2025. A copy of this press release is furnished as Exhibit 99.1 to this report and is incorporated herein by reference.
In accordance with General Instruction B.2 of Form 8-K, the information set forth in this Item 2.02 and in the attached exhibit shall be deemed to be “furnished” and not be deemed to be “filed” for purposes of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
Item 9.01. Financial Statements and Exhibits.
(d) Exhibits. In accordance with General Instruction B.2 of Form 8-K, the information set forth in the attached Exhibit 99.1 is deemed to be “furnished” and shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act.
| Exhibit Number | Description of the Exhibit | |||||||
| 104 | Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101) | |||||||
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| ENERGY TRANSFER LP | |||||||||||
| By: | LE GP, LLC, its general partner | ||||||||||
| Date: | February 17, 2026 | By: | /s/ Dylan A. Bramhall | ||||||||
| Dylan A. Bramhall | |||||||||||
| Executive Vice President and Group Chief Financial Officer | |||||||||||
ENERGY TRANSFER REPORTS FOURTH QUARTER 2025 RESULTS
Dallas – February 17, 2026 – Energy Transfer LP (NYSE:ET) (“Energy Transfer” or the “Partnership”) today reported financial results for the quarter and year ended December 31, 2025.
Energy Transfer reported net income attributable to partners for the three months ended December 31, 2025 of $928 million compared to $1.08 billion for the same period last year. For the three months ended December 31, 2025, net income per common unit (basic) was $0.25.
Adjusted EBITDA for the three months ended December 31, 2025 was $4.18 billion compared to $3.88 billion for the same period last year, an increase of 8%.
Distributable Cash Flow attributable to partners, as adjusted, for the three months ended December 31, 2025 was $2.04 billion compared to $1.98 billion for the same period last year.
Growth capital expenditures in the fourth quarter of 2025 were $1.40 billion; maintenance capital expenditures were $355 million.
Operational Highlights
•Energy Transfer’s volumes continued to grow during the fourth quarter of 2025 compared to the fourth quarter of 2024.
◦NGL and refined product terminals volumes were up 12%.
◦NGL transportation volumes were up 5%.
◦NGL fractionation volumes were up 3%, setting a new Partnership record.
◦NGL exports were up 12%.
◦Crude oil transportation volumes were up 6%, setting a new Partnership record.
◦Midstream gathered volumes were up 4%.
◦Interstate natural gas transportation volumes were up 4%.
◦Intrastate natural gas transportation volumes were up 3%.
•Construction is underway on Mustang Draw II, a new 275 MMcf/d processing plant and related facilities in the Midland Basin. The plant is fully contracted and is expected to be in service in the fourth quarter 2026.
•In January 2026, Energy Transfer commenced natural gas deliveries to Oracle’s data center near Abilene, Texas under the first of multiple long-term agreements to supply an aggregate of approximately 900 MMcf/d of natural gas to three Oracle data centers, two of which are located in Texas.
Strategic Highlights
•In January 2026, Florida Gas Transmission (“FGT”), a joint venture pipeline which Energy Transfer operates, held an Open Season on two projects to meet growing demand across Florida. Both projects are supported by long-term, binding agreements from anchor customers.
◦The FGT Phase IX Project is designed to expand capacity to multiple locations across FGT’s market area for existing customers. The project includes the construction of up to 82 miles of pipeline looping, along with new and upgraded compression station facilities. Energy Transfer’s share of the project costs, excluding AFUDC, is expected to be up to $535 million. The project is expected to be in-service in the fourth quarter of 2028.
◦The South Florida Project includes the construction of a new 37-mile pipeline lateral and related facilities which are designed to enhance system reliability and efficiency in South Florida. Energy Transfer’s share of the project costs, excluding AFUDC, is expected to be $110 million. The project is expected to be in-service in the first quarter of 2030.
•In December 2025, Energy Transfer increased the transportation capacity of Transwestern Pipeline’s planned Desert Southwest expansion project to meet additional customer demand. The project’s main line pipeline diameter will be
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upsized from 42 inches to 48 inches, which increases the project’s capacity to up to 2.3 Bcf/d and the cost up to approximately $5.6 billion. The project is supported by long-term contracts to serve continued population growth and positive economic momentum throughout Arizona and New Mexico. Natural gas for this project will be sourced from Energy Transfer’s premier asset base in the prolific Permian Basin.
•In December 2025, Energy Transfer suspended development of the Lake Charles LNG export project in order to focus on allocating capital to its significant backlog of natural gas pipeline infrastructure projects that Energy Transfer believes provide superior risk/return profiles.
•In November 2025, Energy Transfer signed a 20-year natural gas firm transportation agreement with Entergy Louisiana for natural gas capacity to support new economic development in North Louisiana. The project includes expanding Energy Transfer’s Tiger Pipeline with the construction of a 12-mile lateral, which is expected to have a capacity of 250,000 MMBtu/d. Natural gas supply for this project will be sourced from Energy Transfer’s extensive pipeline network, which is connected to all the major producing basins in the U.S.
Financial Highlights
•In January 2026, Energy Transfer announced a quarterly cash distribution of $0.3350 per common unit ($1.34 annualized) for the quarter ended December 31, 2025, which is an increase of more than 3% compared to the fourth quarter of 2024.
•As of December 31, 2025, the Partnership’s revolving credit facility had an aggregate $2.12 billion of available borrowing capacity.
•Energy Transfer now expects its 2026 Adjusted EBITDA to range between $17.45 and $17.85 billion, compared to the previous range of between $17.3 and $17.7 billion. Energy Transfer’s updated Adjusted EBITDA estimate is solely attributable to USA Compression’s acquisition of J-W Power Company, which closed on January 12, 2026. The Partnership continues to expect to invest $5.0 billion to $5.5 billion in growth capital for 2026, primarily on projects enhancing its natural gas network.
Energy Transfer benefits from a portfolio of assets with exceptional product and geographic diversity. The Partnership’s multiple segments generate high-quality, balanced earnings with no single business segment contributing more than one-third of the Partnership’s consolidated Adjusted EBITDA for the three months or full year ended December 31, 2025. In addition, Energy Transfer generates approximately 40% of its Adjusted EBITDA from natural gas-related assets. The vast majority of the Partnership’s segment margins are fee-based and therefore have limited commodity price sensitivity.
Conference call information:
The Partnership has scheduled a conference call for 8:00 a.m. Central Time/9:00 a.m. Eastern Time on Tuesday, February 17, 2026 to discuss its fourth quarter 2025 results and provide an update on the Partnership. The conference call will be broadcast live via an internet webcast, which can be accessed through www.energytransfer.com and will also be available for replay on the Partnership’s website for a limited time.
Energy Transfer LP (NYSE: ET) owns and operates one of the largest and most diversified portfolios of energy assets in the United States, with approximately 140,000 miles of pipeline and associated energy infrastructure. Energy Transfer’s strategic network spans 44 states with assets in all of the major U.S. production basins. Energy Transfer is a publicly traded limited partnership with core operations that include complementary natural gas midstream, intrastate and interstate transportation and storage assets; crude oil, natural gas liquids (“NGL”) and refined product transportation and terminalling assets; and NGL fractionation. Energy Transfer also owns the general partner interests, the incentive distribution rights and approximately 28 million common units (representing 15% of the aggregate outstanding common units and Class D units) of Sunoco LP (NYSE: SUN), and the general partner interests and approximately 46 million common units (representing 32% of the outstanding common units) of USA Compression Partners, LP (NYSE: USAC). For more information, visit the Energy Transfer LP website at www.energytransfer.com.
Sunoco LP (NYSE: SUN) is a leading energy infrastructure and fuel distribution master limited partnership operating across 32 countries and territories in North America, the Greater Caribbean, and Europe. SUN's midstream operations include an extensive network of approximately 14,000 miles of pipeline and over 160 terminals. This critical infrastructure complements SUN's fuel distribution operations, which distribute over 15 billion gallons annually to approximately 11,000 Sunoco and partner-branded locations, as well as independent dealers and commercial customers. SUN's general partner is owned by Energy Transfer LP (NYSE: ET). For more information, visit the Sunoco LP website at www.sunocolp.com.
SunocoCorp LLC (NYSE: SUNC) is a publicly traded limited liability company that owns a direct limited partner interest in Sunoco LP. For more information, visit the Sunoco LP website at www.sunocolp.com.
USA Compression Partners, LP (NYSE: USAC) is one of the nation’s largest independent providers of natural gas compression services in terms of total compression fleet horsepower. USAC partners with a broad customer base composed of
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producers, processors, gatherers, and transporters of natural gas and crude oil. USAC focuses on providing midstream natural gas compression services to infrastructure applications primarily in high-volume gathering systems, processing facilities, and transportation applications. For more information, visit the USAC website at www.usacompression.com.
Forward-Looking Statements
This news release may include certain statements concerning expectations for the future that are forward-looking statements as defined by federal law. Such forward-looking statements are subject to a variety of known and unknown risks, uncertainties, and other factors that are difficult to predict and many of which are beyond management’s control. An extensive list of factors that can affect future results, including Adjusted EBITDA, and impact current projections, including capital expenditures, are discussed in the Partnership’s Annual Report on Form 10-K and other documents filed from time to time with the Securities and Exchange Commission. The Partnership undertakes no obligation to update or revise any forward-looking statement to reflect new information or events.
The information contained in this press release is available on our website at www.energytransfer.com.
| Investor Relations: | Media Relations: | |||||||
| Bill Baerg, Brent Ratliff, Lyndsay Hannah, 214-981-0795 | Vicki Granado, 214-840-5820 | |||||||
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ENERGY TRANSFER LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(unaudited)
| December 31, 2025 | December 31, 2024 | ||||||||||
| ASSETS | |||||||||||
| Current assets | $ | 18,233 | $ | 14,202 | |||||||
| Property, plant and equipment, net | 102,142 | 95,212 | |||||||||
| Investments in unconsolidated affiliates | 3,589 | 3,266 | |||||||||
Lease right-of-use assets, net | 1,841 | 809 | |||||||||
| Other non-current assets, net | 2,591 | 2,017 | |||||||||
| Intangible assets, net | 7,438 | 5,971 | |||||||||
| Goodwill | 5,452 | 3,903 | |||||||||
| Total assets | $ | 141,286 | $ | 125,380 | |||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities | $ | 14,955 | $ | 12,656 | |||||||
| Long-term debt, less current maturities | 68,308 | 59,752 | |||||||||
Non-current operating lease liabilities | 1,515 | 730 | |||||||||
| Deferred income taxes | 5,307 | 4,190 | |||||||||
| Other non-current liabilities | 1,941 | 1,618 | |||||||||
| Commitments and contingencies | |||||||||||
| Redeemable noncontrolling interests | 250 | 417 | |||||||||
| Equity: | |||||||||||
| Limited Partners: | |||||||||||
| Preferred Unitholders | 3,356 | 3,852 | |||||||||
| Common Unitholders | 30,930 | 31,195 | |||||||||
| General Partner | (2) | (2) | |||||||||
| Accumulated other comprehensive income | 82 | 73 | |||||||||
| Total partners’ capital | 34,366 | 35,118 | |||||||||
| Noncontrolling interests | 14,644 | 10,899 | |||||||||
| Total equity | 49,010 | 46,017 | |||||||||
| Total liabilities and equity | $ | 141,286 | $ | 125,380 | |||||||
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ENERGY TRANSFER LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data)
(unaudited)
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| REVENUES | $ | 25,320 | $ | 19,541 | $ | 85,536 | $ | 82,671 | |||||||||||||||
| COSTS AND EXPENSES: | |||||||||||||||||||||||
| Cost of products sold | 19,416 | 14,157 | 63,495 | 61,975 | |||||||||||||||||||
| Operating expenses | 1,693 | 1,441 | 5,867 | 5,164 | |||||||||||||||||||
| Depreciation, depletion and amortization | 1,491 | 1,374 | 5,682 | 5,165 | |||||||||||||||||||
| Selling, general and administrative | 367 | 288 | 1,180 | 1,177 | |||||||||||||||||||
| Impairment losses | 277 | 2 | 285 | 52 | |||||||||||||||||||
| Total costs and expenses | 23,244 | 17,262 | 76,509 | 73,533 | |||||||||||||||||||
| OPERATING INCOME | 2,076 | 2,279 | 9,027 | 9,138 | |||||||||||||||||||
| OTHER INCOME (EXPENSE): | |||||||||||||||||||||||
| Interest expense, net of interest capitalized | (910) | (807) | (3,474) | (3,125) | |||||||||||||||||||
| Equity in earnings of unconsolidated affiliates | 106 | 94 | 419 | 379 | |||||||||||||||||||
| Losses on extinguishments of debt | (3) | (1) | (34) | (12) | |||||||||||||||||||
| Gain (loss) on sale of Sunoco LP West Texas assets | — | (12) | — | 586 | |||||||||||||||||||
| Other, net | 112 | 30 | 120 | 140 | |||||||||||||||||||
| INCOME BEFORE INCOME TAX EXPENSE | 1,381 | 1,583 | 6,058 | 7,106 | |||||||||||||||||||
| Income tax expense | 143 | 136 | 350 | 541 | |||||||||||||||||||
| NET INCOME | 1,238 | 1,447 | 5,708 | 6,565 | |||||||||||||||||||
| Less: Net income attributable to noncontrolling interests | 290 | 355 | 1,208 | 1,692 | |||||||||||||||||||
| Less: Net income attributable to redeemable noncontrolling interests | 20 | 15 | 67 | 59 | |||||||||||||||||||
| NET INCOME ATTRIBUTABLE TO PARTNERS | 928 | 1,077 | 4,433 | 4,814 | |||||||||||||||||||
| General Partner’s interest in net income | 1 | 1 | 4 | 4 | |||||||||||||||||||
| Preferred Unitholders’ interest in net income | 59 | 68 | 248 | 362 | |||||||||||||||||||
| Loss on redemption of preferred units | — | — | 8 | 54 | |||||||||||||||||||
| Common Unitholders’ interest in net income | $ | 868 | $ | 1,008 | $ | 4,173 | $ | 4,394 | |||||||||||||||
| NET INCOME PER COMMON UNIT: | |||||||||||||||||||||||
| Basic | $ | 0.25 | $ | 0.29 | $ | 1.22 | $ | 1.29 | |||||||||||||||
| Diluted | $ | 0.25 | $ | 0.29 | $ | 1.21 | $ | 1.28 | |||||||||||||||
| WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING: | |||||||||||||||||||||||
| Basic | 3,434.8 | 3,425.6 | 3,432.9 | 3,395.1 | |||||||||||||||||||
| Diluted | 3,449.3 | 3,449.9 | 3,449.5 | 3,420.5 | |||||||||||||||||||
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ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION
(Dollars and units in millions)
(unaudited)
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (a): | |||||||||||||||||||||||
| Net income | $ | 1,238 | $ | 1,447 | $ | 5,708 | $ | 6,565 | |||||||||||||||
| Depreciation, depletion and amortization | 1,491 | 1,374 | 5,682 | 5,165 | |||||||||||||||||||
| Interest expense, net of interest capitalized | 910 | 807 | 3,474 | 3,125 | |||||||||||||||||||
| Income tax expense | 143 | 136 | 350 | 541 | |||||||||||||||||||
| Losses on interest rate derivatives | — | 6 | — | — | |||||||||||||||||||
| Non-cash compensation expense | 38 | 38 | 148 | 151 | |||||||||||||||||||
| Impairment losses and other | 277 | 2 | 285 | 52 | |||||||||||||||||||
| Unrealized (gains) losses on commodity risk management activities | (98) | 6 | (130) | 56 | |||||||||||||||||||
| Inventory valuation adjustments (Sunoco LP) | 187 | (13) | 156 | 86 | |||||||||||||||||||
| Losses on extinguishments of debt | 3 | 1 | 34 | 12 | |||||||||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 184 | 170 | 726 | 692 | |||||||||||||||||||
| Equity in earnings of unconsolidated affiliates | (106) | (94) | (419) | (379) | |||||||||||||||||||
| (Gain) loss on sale of Sunoco LP West Texas assets | — | 12 | — | (586) | |||||||||||||||||||
| Other, net | (85) | (8) | (30) | 3 | |||||||||||||||||||
| Adjusted EBITDA (consolidated) | 4,182 | 3,884 | 15,984 | 15,483 | |||||||||||||||||||
Adjusted EBITDA related to unconsolidated affiliates (b) | (184) | (170) | (726) | (692) | |||||||||||||||||||
Distributable cash flow from unconsolidated affiliates (b) | 142 | 113 | 510 | 486 | |||||||||||||||||||
| Interest expense, net of interest capitalized | (910) | (807) | (3,474) | (3,125) | |||||||||||||||||||
Preferred unitholders’ distributions (c) | (89) | (71) | (287) | (361) | |||||||||||||||||||
| Current income tax expense | (34) | (24) | (173) | (265) | |||||||||||||||||||
Transaction-related income taxes (d) | — | (2) | — | 179 | |||||||||||||||||||
| Maintenance capital expenditures | (462) | (376) | (1,316) | (1,161) | |||||||||||||||||||
| Other, net | 36 | 16 | 97 | 90 | |||||||||||||||||||
| Distributable Cash Flow (consolidated) | 2,681 | 2,563 | 10,615 | 10,634 | |||||||||||||||||||
Distributable Cash Flow attributable to Sunoco LP and SunocoCorp (e) | (344) | (254) | (1,263) | (946) | |||||||||||||||||||
| Distributions from Sunoco LP | 87 | 63 | 286 | 245 | |||||||||||||||||||
| Distributable Cash Flow attributable to USAC (100%) | (104) | (96) | (386) | (355) | |||||||||||||||||||
| Distributions from USAC | 24 | 24 | 97 | 97 | |||||||||||||||||||
| Distributable Cash Flow attributable to noncontrolling interests in other non-wholly owned consolidated subsidiaries | (305) | (326) | (1,153) | (1,335) | |||||||||||||||||||
| Distributable Cash Flow attributable to the partners of Energy Transfer | 2,039 | 1,974 | 8,196 | 8,340 | |||||||||||||||||||
| Transaction-related adjustments | 2 | 4 | 6 | 23 | |||||||||||||||||||
| Distributable Cash Flow attributable to the partners of Energy Transfer, as adjusted | $ | 2,041 | $ | 1,978 | $ | 8,202 | $ | 8,363 | |||||||||||||||
| Distributions to partners: | |||||||||||||||||||||||
| Limited Partners | $ | 1,152 | $ | 1,115 | $ | 4,551 | $ | 4,384 | |||||||||||||||
| General Partner | 1 | 1 | 4 | 4 | |||||||||||||||||||
| Total distributions to be paid to partners | $ | 1,153 | $ | 1,116 | $ | 4,555 | $ | 4,388 | |||||||||||||||
Common Units outstanding – end of period | 3,440.0 | 3,431.1 | 3,440.0 | 3,431.1 | |||||||||||||||||||
(a) Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of Energy Transfer’s fundamental business activities and should not be considered in isolation or as a substitute for net income, income from operations, cash flows from operating activities or other GAAP measures.
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There are material limitations to using measures such as Adjusted EBITDA and Distributable Cash Flow, including the difficulty associated with using either as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss or cash flows. In addition, our calculations of Adjusted EBITDA and Distributable Cash Flow may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measures that are computed in accordance with GAAP, such as operating income, net income and cash flows from operating activities.
Definition of Adjusted EBITDA
We define Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt, certain foreign currency transaction gains and losses and other non-operating income or expense items. 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 last-in, first-out (“LIFO”). These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.
Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of 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 Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.
Adjusted EBITDA is used by management to determine our operating performance and, along with other financial and volumetric data, as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation.
Definition of Distributable Cash Flow
We define Distributable Cash Flow as net income, adjusted for certain non-cash items, less distributions to preferred unitholders and maintenance capital expenditures. Non-cash items include depreciation, depletion and amortization, non-cash compensation expense, amortization included in interest 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 deferred income taxes. For unconsolidated affiliates, Distributable Cash Flow reflects the Partnership’s proportionate share of the investees’ distributable cash flow.
Distributable Cash Flow is used by management to evaluate our overall performance. Our partnership agreement requires us to distribute all available cash, and Distributable Cash Flow is calculated to evaluate our ability to fund distributions through cash generated by our operations.
On a consolidated basis, Distributable Cash Flow includes 100% of the Distributable Cash Flow of Energy Transfer’s consolidated subsidiaries. However, to the extent that noncontrolling interests exist among our subsidiaries, the Distributable Cash Flow generated by our subsidiaries may not be available to be distributed to our partners. In order to reflect the cash flows available for distributions to our partners, we have reported Distributable Cash Flow attributable to partners, which is calculated by adjusting Distributable Cash Flow (consolidated), as follows:
•For subsidiaries with publicly traded equity interests, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiary, and Distributable Cash Flow attributable to our partners includes distributions to be received by the parent company with respect to the periods presented.
•For consolidated joint ventures or similar entities, where the noncontrolling interest is not publicly traded, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiaries, but Distributable Cash Flow attributable to partners reflects only the amount of Distributable Cash Flow of such subsidiaries that is attributable to our ownership interest.
For Distributable Cash Flow attributable to partners, as adjusted, certain transaction-related adjustments and non-recurring expenses that are included in net income are excluded.
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(b) These amounts exclude Sunoco LP’s Adjusted EBITDA and distributable cash flow related to its investment in the ET-S Permian and J.C. Nolan joint ventures, which amounts are eliminated in the Energy Transfer consolidation.
(c) For the three months ended December 31, 2025, preferred unitholders’ distributions include $30 million of distributions on Sunoco LP’s Series A preferred units, which were issued in September 2025.
(d) For the year ended December 31, 2024, the amount reflected for transaction-related income taxes reflects current income tax expense recognized by Sunoco LP in connection with its April 2024 sale of convenience stores in West Texas, New Mexico and Oklahoma.
(e) Beginning with the three months ended December 31, 2025, this amount includes the distributable cash flow of Sunoco LP and SunocoCorp, eliminating the distributable cash flow of Sunoco LP that is attributable to SunocoCorp.
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ENERGY TRANSFER LP AND SUBSIDIARIES
SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT
(Tabular dollar amounts in millions)
(unaudited)
| Three Months Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Segment Adjusted EBITDA: | |||||||||||
| Intrastate transportation and storage | $ | 355 | $ | 263 | |||||||
| Interstate transportation and storage | 523 | 493 | |||||||||
| Midstream | 720 | 705 | |||||||||
| NGL and refined products transportation and services | 1,078 | 1,108 | |||||||||
| Crude oil transportation and services | 722 | 760 | |||||||||
| Investment in Sunoco LP | 646 | 439 | |||||||||
| Investment in USAC | 154 | 155 | |||||||||
| All other | (16) | (39) | |||||||||
| Adjusted EBITDA (consolidated) | $ | 4,182 | $ | 3,884 | |||||||
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.
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Intrastate Transportation and Storage
| Three Months Ended December 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Natural gas transported (BBtu/d) | 13,482 | 13,145 | ||||||||||||
| Revenues | $ | 902 | $ | 820 | ||||||||||
| Cost of products sold | 454 | 426 | ||||||||||||
| Segment margin | 448 | 394 | ||||||||||||
| Unrealized gains on commodity risk management activities | (24) | (59) | ||||||||||||
| Operating expenses, excluding non-cash compensation expense | (67) | (66) | ||||||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (10) | (13) | ||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 7 | 6 | ||||||||||||
| Other | 1 | 1 | ||||||||||||
| Segment Adjusted EBITDA | $ | 355 | $ | 263 | ||||||||||
Transported volumes of gas on our Texas intrastate pipelines increased primarily due to more third-party transportation. Transported volumes reported above exclude volumes attributable to purchases and sales of gas for our pipelines’ own accounts and the optimization of any unused capacity.
For the three months ended December 31, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impact of the following:
•an increase of $54 million in realized natural gas sales and other primarily due to wider price spreads;
•an increase of $16 million in storage margin due to higher storage optimization;
•an increase of $13 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 $7 million in retained fuel margin due to favorable gas pricing.
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Interstate Transportation and Storage
| Three Months Ended December 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Natural gas transported (BBtu/d) | 17,708 | 17,026 | ||||||||||||
| Natural gas sold (BBtu/d) | 56 | 46 | ||||||||||||
| Revenues | $ | 631 | $ | 600 | ||||||||||
| Cost of products sold | 1 | 3 | ||||||||||||
| Segment margin | 630 | 597 | ||||||||||||
| Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses | (206) | (191) | ||||||||||||
| Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses | (29) | (30) | ||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 129 | 116 | ||||||||||||
| Other | (1) | 1 | ||||||||||||
| Segment Adjusted EBITDA | $ | 523 | $ | 493 | ||||||||||
Transported volumes increased primarily due to more capacity sold and higher utilization across the segment due to increased demand.
For the three months ended December 31, 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 $33 million in segment margin primarily due to a $16 million increase in transportation revenue from several of our interstate pipeline systems due to higher rates on contracted volumes, a $5 million increase due to higher interruptible utilization, a $5 million negative impact in the prior period related to the conclusion of a rate case on our Panhandle system and a $5 million increase in operational gas sales; and
•an increase of $13 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to an $8 million increase from our Citrus joint venture and a $4 million increase from our Midcontinent Express Pipeline joint venture; partially offset by
•an increase of $15 million in operating expenses primarily due to a $19 million increase in transportation expense on our affiliate pipelines and a $5 million increase in employee costs. These increases were partially offset by a $10 million decrease in ad valorem taxes.
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Midstream
| Three Months Ended December 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Gathered volumes (BBtu/d) | 21,484 | 20,690 | ||||||||||||
| NGLs produced (MBbls/d) | 1,176 | 1,134 | ||||||||||||
| Equity NGLs (MBbls/d) | 64 | 59 | ||||||||||||
| Revenues | $ | 2,720 | $ | 3,160 | ||||||||||
| Cost of products sold | 1,474 | 1,910 | ||||||||||||
| Segment margin | 1,246 | 1,250 | ||||||||||||
| Operating expenses, excluding non-cash compensation expense | (488) | (495) | ||||||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (42) | (55) | ||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 3 | 5 | ||||||||||||
| Other | 1 | — | ||||||||||||
| Segment Adjusted EBITDA | $ | 720 | $ | 705 | ||||||||||
Gathered volumes increased across most regions, primarily due to additional and upgraded plants in the Permian region, as well as higher dry gas gathering volumes in the Northeast and Ark-La-Tex regions. NGL production increased primarily due to increased Permian plant utilization.
For the three months ended December 31, 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 $21 million in segment margin primarily due to higher volumes in the Permian region;
•an increase of $18 million in segment margin due to higher dry gas gathering volumes in the Northeast and Ark-La-Tex regions;
•a decrease of $14 million in selling, general, and administrative expenses primarily due to an $8 million decrease related to a legal settlement and a $5 million decrease in employee costs; and
•a decrease of $8 million in operating expenses primarily due to decreases in ad valorem taxes, retainage credits and tax audit penalties; partially offset by
•a decrease of $28 million in segment margin due to a $14 million decrease on our Jackalope gathering system and a $14 million decrease from intersegment transportation fees related to a regulatory order impacting prior period and current period rates;
•a decrease of $14 million in segment margin due to lower NGL prices of $42 million, partially offset by favorable natural gas prices of $28 million; and
•a decrease of $3 million in Adjusted EBITDA related to unconsolidated affiliates due to a contract restructuring.
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NGL and Refined Products Transportation and Services
| Three Months Ended December 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| NGL transportation volumes (MBbls/d) | 2,364 | 2,262 | ||||||||||||
| Refined products transportation volumes (MBbls/d) | 603 | 570 | ||||||||||||
| NGL and refined products terminal volumes (MBbls/d) | 1,639 | 1,465 | ||||||||||||
| NGL fractionation volumes (MBbls/d) | 1,177 | 1,141 | ||||||||||||
| Revenues | $ | 6,150 | $ | 6,356 | ||||||||||
| Cost of products sold | 4,736 | 5,048 | ||||||||||||
| Segment margin | 1,414 | 1,308 | ||||||||||||
| Unrealized (gains) losses on commodity risk management activities | (29) | 60 | ||||||||||||
| Operating expenses, excluding non-cash compensation expense | (295) | (254) | ||||||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (42) | (42) | ||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 29 | 36 | ||||||||||||
| Other | 1 | — | ||||||||||||
| Segment Adjusted EBITDA | $ | 1,078 | $ | 1,108 | ||||||||||
NGL transportation and fractionation volumes increased primarily due to higher volumes from the Permian region. Terminal volumes also increased as result of recently acquired assets.
For the three months ended December 31, 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 $100 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to the timing of the settlement of NGL and refined product inventory hedges. This timing, which was the result of market price movements on hedged physical product, resulted in the recognition of significant gains in the fourth quarter of 2024, as well as reduced gains in the fourth quarter of 2025, which we anticipate will be recognized during the first quarter of 2026;
•an increase of $41 million in operating expenses primarily due to a $22 million increase in costs driven by higher volumes across our NGL system, a $16 million increase in reserves related to the transportation revenues recognized in connection with a regulatory order impacting prior period and current period rates as discussed below, and a $7 million increase in employee costs, partially offset by a $4 million decrease in ad valorem taxes;
•a decrease of $9 million in terminal services margin primarily due to a $19 million decrease in fees from loading volumes for export at our Nederland and Marcus Hook terminals, inclusive of a $14 million impact from a fog related closure in December 2025 which we expect to make up in the first quarter of 2026, partially offset by a $10 million increase from higher throughput and storage at our refined product terminals; and
•a decrease of $7 million in Adjusted EBITDA related to unconsolidated affiliates due to lower throughput on certain of our joint venture pipelines; partially offset by
•an increase of $96 million in transportation margin primarily due to a $71 million increase related to a regulatory order impacting prior period and current period rates and a $23 million increase from higher throughput and contractual rate escalations on our NGL pipeline systems;
•an increase of $22 million in fractionators and refinery services margin primarily due to higher throughput; and
•an increase of $8 million in storage margin primarily due to timing of deficiency payments and cavern withdrawals.
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Crude Oil Transportation and Services
| Three Months Ended December 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Crude oil transportation volumes (MBbls/d) | 7,256 | 6,831 | ||||||||||||
| Crude oil terminal volumes (MBbls/d) | 3,298 | 3,316 | ||||||||||||
| Revenues | $ | 8,479 | $ | 6,220 | ||||||||||
| Cost of products sold | 7,479 | 5,207 | ||||||||||||
| Segment margin | 1,000 | 1,013 | ||||||||||||
| Unrealized gains on commodity risk management activities | (18) | (4) | ||||||||||||
| Operating expenses, excluding non-cash compensation expense | (234) | (217) | ||||||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (34) | (38) | ||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 8 | 6 | ||||||||||||
| Segment Adjusted EBITDA | $ | 722 | $ | 760 | ||||||||||
Crude oil transportation volumes were higher due to continued growth on our Texas pipeline system, our gathering systems, and from the ET-S Permian joint venture with Sunoco LP, partially offset by lower volumes on our Bakken Pipeline. Crude terminal volumes were lower primarily due to Gulf Coast refinery maintenance and lower volumes received from our Bakken Pipeline system.
For the three months ended December 31, 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 $27 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to decreased transportation revenue, primarily from our Bakken Pipeline joint venture, and a legal accrual of $15 million, partially offset by an increase of $30 million from our ET-S Permian joint venture and a $30 million increase related to a regulatory order impacting prior period and current period rates; and
•an increase of $17 million in operating expenses primarily due to a $10 million increase in reserves related to revenues recognized in connection with a regulatory order impacting prior period and current period rates as discussed above, a $10 million increase in employee costs, a $5 million increase in volume-driven expenses, partially offset by a $10 million decrease in property tax expense.
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Investment in Sunoco LP
| Three Months Ended December 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Revenues | $ | 8,600 | $ | 5,269 | ||||||||||
| Cost of products sold | 7,676 | 4,644 | ||||||||||||
| Segment margin | 924 | 625 | ||||||||||||
| Unrealized (gains) losses on commodity risk management activities | (18) | 4 | ||||||||||||
| Operating expenses, excluding non-cash compensation expense | (373) | (188) | ||||||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (153) | (50) | ||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 62 | 48 | ||||||||||||
| Inventory fair value adjustments | 187 | (13) | ||||||||||||
| Other, net | 17 | 13 | ||||||||||||
| Segment Adjusted EBITDA | $ | 646 | $ | 439 | ||||||||||
The investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
For the three months ended December 31, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP increased primarily due to the net impact of the following:
•an increase of $478 million in segment margin (excluding unrealized gains and losses on commodity risk management activities and inventory valuation adjustments) primarily due to the Parkland acquisition, along with favorable margins from transmix and blending activities; and
•an increase of $14 million in Adjusted EBITDA related to unconsolidated affiliates primarily from the ET-S Permian joint venture; partially offset by
•an increase of $185 million in operating expenses primarily due to increased costs resulting from Parkland’s operations; and
•an increase of $103 million in selling, general and administrative expenses primarily due to Parkland’s operations, as well as one-time transaction-related expenses related to the Parkland acquisition.
Investment in USAC
| Three Months Ended December 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Revenues | $ | 252 | $ | 245 | ||||||||||
| Cost of products sold | 36 | 36 | ||||||||||||
| Segment margin | 216 | 209 | ||||||||||||
| Operating expenses, excluding non-cash compensation expense | (48) | (41) | ||||||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (14) | (12) | ||||||||||||
| Other, net | — | (1) | ||||||||||||
| Segment Adjusted EBITDA | $ | 154 | $ | 155 | ||||||||||
The investment in USAC segment reflects the consolidated results of USAC.
For the three months ended December 31, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC increased primarily due to a $9 million increase in contract operations revenues driven by higher average revenue per revenue-generating horsepower and higher revenue-generating horsepower, partially offset by a $2 million decrease in parts and services revenues, as well as higher operating expenses.
15
All Other
| Three Months Ended December 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Revenues | $ | 1,055 | $ | 607 | ||||||||||
| Cost of products sold | 1,022 | 602 | ||||||||||||
| Segment margin | 33 | 5 | ||||||||||||
| Unrealized (gains) losses on commodity risk management activities | (9) | 5 | ||||||||||||
| Operating expenses, excluding non-cash compensation expense | (14) | 8 | ||||||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (16) | (19) | ||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 1 | 2 | ||||||||||||
| Other and eliminations | (11) | (40) | ||||||||||||
| Segment Adjusted EBITDA | $ | (16) | $ | (39) | ||||||||||
For the three months ended December 31, 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 $11 million in our natural gas marketing business driven by residue gas sales;
•an increase of $6 million related to corporate allocations;
•an increase of $4 million in lease income from recently acquired real estate;
•an increase of $2 million from our power-related businesses; and
•an increase of $1 million from gains recognized by our captive insurance company; partially offset by
•a decrease of $8 million due to the intersegment elimination of Sunoco LP’s 32.5% share of ET-S Permian, which is consolidated in our crude oil transportation and services segment and also reflected as an unconsolidated affiliate in our investment in Sunoco LP segment.
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ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON LIQUIDITY
(In millions)
(unaudited)
The table below provides information on our revolving credit facility. We also have consolidated subsidiaries with revolving credit facilities which are not included in this table.
| Facility Size | Funds Available at December 31, 2025 | Maturity Date | |||||||||||||||
| Five-Year Revolving Credit Facility | $ | 5,000 | $ | 2,123 | April 11, 2029 | ||||||||||||
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ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES
(In millions)
(unaudited)
The table below provides information on an aggregated basis for our unconsolidated affiliates, which are accounted for as equity method investments in the Partnership’s financial statements for the periods presented.
| Three Months Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Equity in earnings of unconsolidated affiliates: | |||||||||||
Citrus | $ | 39 | $ | 31 | |||||||
MEP | 20 | 16 | |||||||||
| White Cliffs | 4 | 5 | |||||||||
| Explorer | 4 | 8 | |||||||||
| SESH | 15 | 13 | |||||||||
Other | 24 | 21 | |||||||||
Total equity in earnings of unconsolidated affiliates | $ | 106 | $ | 94 | |||||||
Adjusted EBITDA related to unconsolidated affiliates: | |||||||||||
Citrus | $ | 86 | $ | 77 | |||||||
MEP | 28 | 25 | |||||||||
| White Cliffs | 9 | 10 | |||||||||
| Explorer | 8 | 12 | |||||||||
| SESH | 17 | 14 | |||||||||
Other | 36 | 32 | |||||||||
Total Adjusted EBITDA related to unconsolidated affiliates | $ | 184 | $ | 170 | |||||||
Distributions received from unconsolidated affiliates: | |||||||||||
Citrus | $ | 52 | $ | 35 | |||||||
MEP | 24 | 23 | |||||||||
| White Cliffs | 10 | 8 | |||||||||
| Explorer | 4 | 7 | |||||||||
| SESH | 14 | 12 | |||||||||
Other | 26 | 23 | |||||||||
Total distributions received from unconsolidated affiliates | $ | 130 | $ | 108 | |||||||
18
ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON NON-WHOLLY OWNED JOINT VENTURE SUBSIDIARIES
(In millions)
(unaudited)
The table below provides information on an aggregated basis for our non-wholly owned joint venture subsidiaries, which are reflected on a consolidated basis in our financial statements. The table below excludes Sunoco LP and USAC, which are non-wholly owned subsidiaries that are publicly traded, as well as Sunoco LP’s 32.5% interest in the ET-S Permian joint venture.
| Three Months Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
Adjusted EBITDA of non-wholly owned subsidiaries (100%) (a) | $ | 598 | $ | 634 | |||||||
Our proportionate share of Adjusted EBITDA of non-wholly owned subsidiaries (b) | 293 | 305 | |||||||||
Distributable Cash Flow of non-wholly owned subsidiaries (100%) (c) | $ | 581 | $ | 614 | |||||||
Our proportionate share of Distributable Cash Flow of non-wholly owned subsidiaries (d) | 276 | 288 | |||||||||
Below is our ownership percentage of certain non-wholly owned subsidiaries:
| Non-wholly owned subsidiary: | Energy Transfer Percentage Ownership (e) | ||||
Bakken Pipeline | 36.4 | % | |||
Bayou Bridge | 60.0 | % | |||
| Maurepas | 51.0 | % | |||
Ohio River System | 75.0 | % | |||
Permian Express Partners | 87.7 | % | |||
Red Bluff Express | 70.0 | % | |||
Rover | 32.6 | % | |||
Others | various | ||||
(a)Adjusted EBITDA of non-wholly owned subsidiaries reflects the total Adjusted EBITDA of our non-wholly owned subsidiaries on an aggregated basis. This is the amount included in our consolidated non-GAAP measure of Adjusted EBITDA.
(b)Our proportionate share of Adjusted EBITDA of non-wholly owned subsidiaries reflects the amount of Adjusted EBITDA of such subsidiaries (on an aggregated basis) that is attributable to our ownership interest.
(c)Distributable Cash Flow of non-wholly owned subsidiaries reflects the total Distributable Cash Flow of our non-wholly owned subsidiaries on an aggregated basis.
(d)Our proportionate share of Distributable Cash Flow of non-wholly owned subsidiaries reflects the amount of Distributable Cash Flow of such subsidiaries (on an aggregated basis) that is attributable to our ownership interest. This is the amount included in our consolidated non-GAAP measure of Distributable Cash Flow attributable to the partners of Energy Transfer.
(e)Our ownership reflects the total economic interest held by us and our subsidiaries. In some cases, this percentage comprises ownership interests held in (or by) multiple entities.
19