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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2025
or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-32740
ENERGY TRANSFER LP
(Exact name of registrant as specified in its charter)

Delaware |  | 30-0108820
(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)

8111 Westchester Drive, Suite 600, Dallas, Texas 75225
(Address of principal executive offices) (zip code)
(214) 981-0700
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:

Title of each class |  | Trading Symbol(s) |  | Name of each exchange on which registered
Common Units |  | ET |  | New York Stock Exchange
9.250% Series I Fixed Rate Perpetual Preferred Units |  | ETprI |  | New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer | ý |  | Accelerated filer | ☐
Non-accelerated filer | ¨ |  | Smaller reporting company | ☐
|  |  | 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. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ý
At October 31, 2025, the registrant had 3,433,386,854 Common Units outstanding.

FORM 10-Q
ENERGY TRANSFER LP AND SUBSIDIARIES
TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (unaudited) |
Consolidated Balance Sheets | 4
Consolidated Statements of Operations | 6
Consolidated Statements of Comprehensive Income | 7
Consolidated Statements of Equity | 8
Consolidated Statements of Cash Flows | 10
Notes to Consolidated Financial Statements | 11
1. Organization and Basis of Presentation | 11
2. Acquisitions | 12
3. Cash and Cash Equivalents | 13
4. Inventories | 13
5. Fair Value Measures | 14
6. Net Income per Common Unit | 17
7. Debt Obligations | 17
8. Redeemable Noncontrolling Interests | 19
9. Equity | 20
10. Regulatory Matters, Commitments, Contingencies and Environmental Liabilities | 22
11. Revenue | 34
12. Derivative Assets and Liabilities | 35
13. Reportable Segments | 38
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 44
Recent Developments | 44
Results of Operations | 48
Liquidity and Capital Resources | 61
Cash Distributions | 66
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 70
ITEM 4. CONTROLS AND PROCEDURES | 71
PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS | 72
ITEM 1A. RISK FACTORS | 72
ITEM 6. EXHIBITS | 75
SIGNATURE | 76

2

Table of Contents
Definitions
References to the “Partnership” or “Energy Transfer” refer to Energy Transfer LP. In addition, the following is a list of certain acronyms and terms used throughout this document:

/d |  | per day
AOCI |  | accumulated other comprehensive income
Bakken Pipeline |  | Refers collectively to Dakota Access and Energy Transfer Crude Oil Pipeline and/or Energy Transfer Crude Oil Company, LLC, a non-wholly owned subsidiary of Energy Transfer
BBtu |  | billion British thermal units
Citrus |  | Citrus, LLC, a 50/50 joint venture which owns Florida Gas Transmission Company, LLC, which owns the Florida Gas Transmission Pipeline
Dakota Access |  | Dakota Access, LLC, a non-wholly owned subsidiary of Energy Transfer and/or Dakota Access Pipeline
Energy Transfer Preferred Units |  | Collectively, the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units, Series G Preferred Units, Series H Preferred Units and Series I Preferred Units
Energy Transfer R&M |  | Energy Transfer (R&M), LLC (formerly Sunoco (R&M), LLC)
ETC Sunoco |  | ETC Sunoco Holdings LLC (formerly Sunoco, Inc.), a wholly owned subsidiary of Energy Transfer
ETO |  | Energy Transfer Operating, L.P., formerly a non-wholly owned subsidiary of Energy Transfer until its merger into the Partnership in April 2021
ET-S Permian |  | ET-S Permian Holdings Company LP, a joint venture between Energy Transfer and Sunoco LP, which owns crude oil and water gathering pipelines and storage assets in the Permian Basin
Exchange Act |  | Securities Exchange Act of 1934, as amended
Explorer |  | Explorer Pipeline Company
FERC |  | Federal Energy Regulatory Commission
GAAP |  | accounting principles generally accepted in the United States of America
General Partner |  | LE GP, LLC, the general partner of Energy Transfer
IFERC |  | Inside FERC’s Gas Market Report
J.C. Nolan |  | collectively, J.C. Nolan Terminal Co., LLC and J.C. Nolan Pipeline Co., LLC, both of which are joint ventures between Energy Transfer and Sunoco LP, which own a diesel fuel storage terminal in Midland, Texas and a 500-mile diesel fuel pipeline
LIFO |  | last-in, first-out
MBbls |  | thousand barrels
MEP |  | Midcontinent Express Pipeline LLC
NGA |  | Natural Gas Act of 1938
NGL |  | natural gas liquid, such as propane, butane and natural gasoline
NuStar |  | NuStar Energy L.P.
NYMEX |  | New York Mercantile Exchange
OTC |  | over-the-counter
Panhandle |  | Panhandle Eastern Pipe Line and/or Panhandle Eastern Pipe Line Company, LP, a wholly owned subsidiary of Energy Transfer
Parkland |  | Parkland Corporation
Partnership Agreement |  | Energy Transfer’s Fourth Amended and Restated Agreement of Limited Partnership, as amended to date
PHMSA |  | Pipeline and Hazardous Materials Safety Administration
Rover |  | Rover Pipeline and/or Rover Pipeline LLC, a non-wholly owned subsidiary of Energy Transfer
SEC |  | Securities and Exchange Commission
Series A Preferred Units |  | Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series B Preferred Units |  | Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series C Preferred Units |  | Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series D Preferred Units |  | Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series E Preferred Units |  | Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series F Preferred Units |  | Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Series G Preferred Units |  | Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Series H Preferred Units |  | Series H Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Series I Preferred Units |  | Series I Fixed-Rate Perpetual Preferred Units
SESH |  | Southeast Supply Header, LLC
SPLP |  | Sunoco Pipeline L.P., a wholly owned subsidiary of Energy Transfer
Transwestern |  | Transwestern Pipeline and/or Transwestern Pipeline Company, LLC, a wholly owned subsidiary of Energy Transfer
USAC |  | USA Compression Partners, LP, a publicly traded partnership and consolidated subsidiary of Energy Transfer
White Cliffs |  | White Cliffs Pipeline, L.L.C.

3

Table of Contents
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(unaudited)

| September 30, 2025 |  | December 31, 2024
ASSETS
Current assets: |  |  |
Cash and cash equivalents | $ | 3,574 |  |  | $ | 312 |
Accounts receivable, net | 9,886 |  |  | 10,191 |
Accounts receivable from related companies | 148 |  |  | 87 |
Inventories | 3,269 |  |  | 3,070 |
Income taxes receivable | 6 |  |  | 56 |
Derivative assets | 20 |  |  | 9 |
Other current assets | 539 |  |  | 477 |
Total current assets | 17,442 |  |  | 14,202 |
Property, plant and equipment | 133,835 |  |  | 129,242 |
Accumulated depreciation and depletion | (37,806) |  |  | (34,030) |
Property, plant and equipment, net | 96,029 |  |  | 95,212 |
Investments in unconsolidated affiliates | 3,269 |  |  | 3,266 |
Lease right-of-use assets, net | 880 |  |  | 809 |
Other non-current assets, net | 2,148 |  |  | 2,017 |
Intangible assets, net | 5,660 |  |  | 5,971 |
Goodwill | 3,903 |  |  | 3,903 |
Total assets | $ | 129,331 |  |  | $ | 125,380 |

The accompanying notes are an integral part of these consolidated financial statements.
4

Table of Contents
ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Dollars in millions)
(unaudited)

| September 30, 2025 |  | December 31, 2024
LIABILITIES AND EQUITY
Current liabilities: |  |  |
Accounts payable | $ | 7,299 |  |  | $ | 8,306 |
Accounts payable to related companies | 37 |  |  | 19 |
Derivative liabilities | 15 |  |  | 15 |
Operating lease current liabilities | 67 |  |  | 67 |
Accrued and other current liabilities | 4,984 |  |  | 4,241 |
Current maturities of long-term debt | 8 |  |  | 8 |
Total current liabilities | 12,410 |  |  | 12,656 |
Long-term debt, less current maturities | 63,096 |  |  | 59,752 |
Non-current operating lease liabilities | 803 |  |  | 730 |
Deferred income taxes | 4,263 |  |  | 4,190 |
Other non-current liabilities | 1,615 |  |  | 1,618 |
Commitments and contingencies |  |  |
Redeemable noncontrolling interests | 1,800 |  |  | 417 |
Equity: |  |  |
Limited Partners: |  |  |
Preferred Unitholders | 3,388 |  |  | 3,852 |
Common Unitholders | 31,223 |  |  | 31,195 |
General Partner | (2) |  |  | (2) |
Accumulated other comprehensive income | 68 |  |  | 73 |
Total partners’ capital | 34,677 |  |  | 35,118 |
Noncontrolling interests | 10,667 |  |  | 10,899 |
Total equity | 45,344 |  |  | 46,017 |
Total liabilities and equity | $ | 129,331 |  |  | $ | 125,380 |

The accompanying notes are an integral part of these consolidated financial statements.
5

Table of Contents
ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)
(unaudited)

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
REVENUES: |  |  |  |  |  |  |
Refined product sales | $ | 5,849 |  |  | $ | 5,566 |  |  | $ | 15,987 |  |  | $ | 17,066 |
Crude sales | 5,296 |  |  | 6,476 |  |  | 15,769 |  |  | 19,872 |
NGL sales | 4,285 |  |  | 4,707 |  |  | 14,427 |  |  | 14,336 |
Gathering, transportation and other fees | 3,126 |  |  | 3,105 |  |  | 9,211 |  |  | 9,031 |
Natural gas sales | 1,015 |  |  | 505 |  |  | 3,654 |  |  | 1,820 |
Other | 383 |  |  | 413 |  |  | 1,168 |  |  | 1,005 |
Total revenues | 19,954 |  |  | 20,772 |  |  | 60,216 |  |  | 63,130 |
COSTS AND EXPENSES: |  |  |  |  |  |  |
Cost of products sold | 14,562 |  |  | 15,612 |  |  | 44,079 |  |  | 47,818 |
Operating expenses | 1,532 |  |  | 1,358 |  |  | 4,174 |  |  | 3,723 |
Depreciation, depletion and amortization | 1,440 |  |  | 1,324 |  |  | 4,191 |  |  | 3,791 |
Selling, general and administrative | 268 |  |  | 297 |  |  | 813 |  |  | 889 |
Impairment losses | 1 |  |  | — |  |  | 8 |  |  | 50 |
Total costs and expenses | 17,803 |  |  | 18,591 |  |  | 53,265 |  |  | 56,271 |
OPERATING INCOME | 2,151 |  |  | 2,181 |  |  | 6,951 |  |  | 6,859 |
OTHER INCOME (EXPENSE): |  |  |  |  |  |  |
Interest expense, net of interest capitalized | (890) |  |  | (828) |  |  | (2,564) |  |  | (2,318) |
Equity in earnings of unconsolidated affiliates | 116 |  |  | 102 |  |  | 313 |  |  | 285 |
Losses on extinguishments of debt | (12) |  |  | — |  |  | (31) |  |  | (11) |
Gain (loss) on interest rate derivative | — |  |  | (6) |  |  | — |  |  | 6 |
Gain on sale of Sunoco LP West Texas assets | — |  |  | — |  |  | — |  |  | 598 |
Other, net | 14 |  |  | 74 |  |  | 8 |  |  | 104 |
INCOME BEFORE INCOME TAX EXPENSE | 1,379 |  |  | 1,523 |  |  | 4,677 |  |  | 5,523 |
Income tax expense | 87 |  |  | 89 |  |  | 207 |  |  | 405 |
NET INCOME | 1,292 |  |  | 1,434 |  |  | 4,470 |  |  | 5,118 |
Less: Net income attributable to noncontrolling interests | 259 |  |  | 238 |  |  | 918 |  |  | 1,337 |
Less: Net income attributable to redeemable noncontrolling interests | 14 |  |  | 13 |  |  | 47 |  |  | 44 |
NET INCOME ATTRIBUTABLE TO PARTNERS | 1,019 |  |  | 1,183 |  |  | 3,505 |  |  | 3,737 |
General Partner’s interest in net income | 1 |  |  | 1 |  |  | 3 |  |  | 3 |
Preferred Unitholders’ interest in net income | 59 |  |  | 67 |  |  | 189 |  |  | 294 |
Loss on redemption of preferred units | — |  |  | — |  |  | 8 |  |  | 54 |
Common Unitholders’ interest in net income | $ | 959 |  |  | $ | 1,115 |  |  | $ | 3,305 |  |  | $ | 3,386 |
NET INCOME PER COMMON UNIT: |  |  |  |  |  |  |
Basic | $ | 0.28 |  |  | $ | 0.33 |  |  | $ | 0.96 |  |  | $ | 1.00 |
Diluted | $ | 0.28 |  |  | $ | 0.32 |  |  | $ | 0.96 |  |  | $ | 0.99 |

The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
(unaudited)

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Net income | $ | 1,292 |  |  | $ | 1,434 |  |  | $ | 4,470 |  |  | $ | 5,118 |
Other comprehensive income (loss), net of tax: |  |  |  |  |  |  |
Change in value of available-for-sale securities | 5 |  |  | 4 |  |  | 7 |  |  | 7 |
Actuarial gain (loss) related to pension and other postretirement benefit plans | 1 |  |  | — |  |  | (5) |  |  | 8 |
Foreign currency translation adjustments | (2) |  |  | (5) |  |  | 3 |  |  | (6) |
Change in other comprehensive income from unconsolidated affiliates | (1) |  |  | (5) |  |  | (4) |  |  | (3) |
| 3 |  |  | (6) |  |  | 1 |  |  | 6 |
Comprehensive income | 1,295 |  |  | 1,428 |  |  | 4,471 |  |  | 5,124 |
Less: Comprehensive income attributable to noncontrolling interests | 259 |  |  | 238 |  |  | 918 |  |  | 1,337 |
Less: Comprehensive income attributable to redeemable noncontrolling interests | 14 |  |  | 13 |  |  | 47 |  |  | 44 |
Comprehensive income attributable to partners | $ | 1,022 |  |  | $ | 1,177 |  |  | $ | 3,506 |  |  | $ | 3,743 |

The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Dollars in millions)
(unaudited)

| Common Unitholders |  | Preferred Unitholders |  | General Partner |  | AOCI |  | Noncontrolling Interests |  | Total
Balance, December 31, 2024 | $ | 31,195 |  |  | $ | 3,852 |  |  | $ | (2) |  |  | $ | 73 |  |  | $ | 10,899 |  |  | $ | 46,017 |
Distributions to partners | (1,105) |  |  | (27) |  |  | (1) |  |  | — |  |  | — |  |  | (1,133) |
Distributions to noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | (455) |  |  | (455) |
Capital contributions from noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | 2 |  |  | 2 |
Other comprehensive loss, net of tax | — |  |  | — |  |  | — |  |  | (3) |  |  | — |  |  | (3) |
Other, net | 19 |  |  | — |  |  | — |  |  | (6) |  |  | 14 |  |  | 27 |
Net income, excluding amounts attributable to redeemable noncontrolling interests | 1,255 |  |  | 67 |  |  | 1 |  |  | — |  |  | 384 |  |  | 1,707 |
Balance, March 31, 2025 | 31,364 |  |  | 3,892 |  |  | (2) |  |  | 64 |  |  | 10,844 |  |  | 46,162 |
Distributions to partners | (1,113) |  |  | (107) |  |  | (1) |  |  | — |  |  | — |  |  | (1,221) |
Distributions to noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | (479) |  |  | (479) |
Capital contributions from noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | 3 |  |  | 3 |
Other comprehensive income, net of tax | — |  |  | — |  |  | — |  |  | 1 |  |  | — |  |  | 1 |
Redemption of Series F Preferred Units | — |  |  | (500) |  |  | — |  |  | — |  |  | — |  |  | (500) |
Conversion of USAC preferred to USAC common units | — |  |  | — |  |  | — |  |  | — |  |  | 93 |  |  | 93 |
Other, net | 10 |  |  | 8 |  |  | — |  |  | — |  |  | 19 |  |  | 37 |
Net income, excluding amounts attributable to redeemable noncontrolling interests | 1,099 |  |  | 63 |  |  | 1 |  |  | — |  |  | 275 |  |  | 1,438 |
Balance, June 30, 2025 | 31,360 |  |  | 3,356 |  |  | (2) |  |  | 65 |  |  | 10,755 |  |  | 45,534 |
Distributions to partners | (1,122) |  |  | (27) |  |  | (1) |  |  | — |  |  | — |  |  | (1,150) |
Distributions to noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | (376) |  |  | (376) |
Capital contributions from noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | 22 |  |  | 22 |
Other comprehensive income, net of tax | — |  |  | — |  |  | — |  |  | 3 |  |  | — |  |  | 3 |
Other, net | 26 |  |  | — |  |  | — |  |  | — |  |  | 7 |  |  | 33 |
Net income, excluding amounts attributable to redeemable noncontrolling interests | 959 |  |  | 59 |  |  | 1 |  |  | — |  |  | 259 |  |  | 1,278 |
Balance, September 30, 2025 | $ | 31,223 |  |  | $ | 3,388 |  |  | $ | (2) |  |  | $ | 68 |  |  | $ | 10,667 |  |  | $ | 45,344 |

The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY (continued)
(Dollars in millions)
(unaudited)

| Common Unitholders |  | Preferred Unitholders |  | General Partner |  | AOCI |  | Noncontrolling Interests |  | Total
Balance, December 31, 2023 | $ | 30,197 |  |  | $ | 6,459 |  |  | $ | (2) |  |  | $ | 28 |  |  | $ | 7,257 |  |  | $ | 43,939 |
Distributions to partners | (1,039) |  |  | (88) |  |  | (1) |  |  | — |  |  | — |  |  | (1,128) |
Distributions to noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | (421) |  |  | (421) |
Capital contributions from noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | 637 |  |  | 637 |
Other comprehensive income, net of tax | — |  |  | — |  |  | — |  |  | 13 |  |  | — |  |  | 13 |
Redemption of Series C and Series D Preferred Units | — |  |  | (895) |  |  | — |  |  | — |  |  | — |  |  | (895) |
Conversion of USAC preferred to USAC common units | — |  |  | — |  |  | — |  |  | — |  |  | 38 |  |  | 38 |
Other, net | — |  |  | 21 |  |  | — |  |  | — |  |  | (87) |  |  | (66) |
Net income, excluding amounts attributable to redeemable noncontrolling interests | 1,110 |  |  | 129 |  |  | 1 |  |  | — |  |  | 436 |  |  | 1,676 |
Balance, March 31, 2024 | 30,268 |  |  | 5,626 |  |  | (2) |  |  | 41 |  |  | 7,860 |  |  | 43,793 |
Distributions to partners | (1,049) |  |  | (155) |  |  | (1) |  |  | — |  |  | — |  |  | (1,205) |
Distributions to noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | (496) |  |  | (496) |
Other comprehensive loss, net of tax | — |  |  | — |  |  | — |  |  | (1) |  |  | — |  |  | (1) |
Redemption of Series A and Series E Preferred Units | — |  |  | (1,750) |  |  | — |  |  | — |  |  | — |  |  | (1,750) |
Conversion of USAC preferred to USAC common units | — |  |  | — |  |  | — |  |  | — |  |  | 263 |  |  | 263 |
NuStar acquisition | — |  |  | — |  |  | — |  |  | — |  |  | 3,651 |  |  | 3,651 |
Redemption of NuStar preferred units | — |  |  | — |  |  | — |  |  | — |  |  | (784) |  |  | (784) |
Other, net | (20) |  |  | 33 |  |  | — |  |  | 8 |  |  | 3 |  |  | 24 |
Net income, excluding amounts attributable to redeemable noncontrolling interests | 1,215 |  |  | 98 |  |  | 1 |  |  | — |  |  | 663 |  |  | 1,977 |
Balance, June 30, 2024 | 30,414 |  |  | 3,852 |  |  | (2) |  |  | 48 |  |  | 11,160 |  |  | 45,472 |
Distributions to partners | (1,072) |  |  | (27) |  |  | (1) |  |  | — |  |  | — |  |  | (1,100) |
Distributions to noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | (462) |  |  | (462) |
Other comprehensive loss, net of tax | — |  |  | — |  |  | — |  |  | (6) |  |  | — |  |  | (6) |
WTG Midstream acquisition | 833 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 833 |
Other, net | 18 |  |  | — |  |  | — |  |  | — |  |  | 4 |  |  | 22 |
Net income, excluding amounts attributable to redeemable noncontrolling interests | 1,115 |  |  | 67 |  |  | 1 |  |  | — |  |  | 238 |  |  | 1,421 |
Balance, September 30, 2024 | $ | 31,308 |  |  | $ | 3,892 |  |  | $ | (2) |  |  | $ | 42 |  |  | $ | 10,940 |  |  | $ | 46,180 |

The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
(unaudited)

| Nine Months Ended September 30,
| 2025 |  | 2024
OPERATING ACTIVITIES: |  |  |
Net income | $ | 4,470 |  |  | $ | 5,118 |
Reconciliation of net income to net cash provided by operating activities: |  |  |
Depreciation, depletion and amortization | 4,191 |  |  | 3,791 |
Deferred income tax expense | 68 |  |  | 165 |
Inventory valuation adjustments | (31) |  |  | 99 |
Non-cash compensation expense | 110 |  |  | 113 |
Impairment losses | 8 |  |  | 50 |
Other non-cash | 3 |  |  | 39 |
Equity in earnings of unconsolidated affiliates | (313) |  |  | (285) |
Gain on sale of Sunoco LP West Texas assets | — |  |  | (598) |
Losses on extinguishments of debt | 31 |  |  | 11 |
Distributions from unconsolidated affiliates | 236 |  |  | 263 |
Distributions on unvested awards | (39) |  |  | (40) |
Net change in operating assets and liabilities, net of effects of acquisitions and divestitures | (483) |  |  | 190 |
Net cash provided by operating activities | 8,251 |  |  | 8,916 |
INVESTING ACTIVITIES: |  |  |
Cash paid for WTG Midstream acquisition, net of cash received | — |  |  | (2,174) |
Cash paid by Sunoco LP for acquisitions, net of cash received | (189) |  |  | (182) |
Cash paid for Edwards Lime Gathering, LLC noncontrolling interest | — |  |  | (84) |
Cash paid for other acquisitions, net of cash received | (176) |  |  | (219) |
Capital expenditures, excluding allowance for equity funds used during construction | (4,180) |  |  | (2,692) |
Contributions in aid of construction costs | 27 |  |  | 57 |
Contributions to unconsolidated affiliates | (5) |  |  | (205) |
Distributions from unconsolidated affiliates in excess of cumulative earnings | 77 |  |  | 60 |
Proceeds from sale of Sunoco LP West Texas assets | — |  |  | 990 |
Other, net | 19 |  |  | 14 |
Net cash used in investing activities | (4,427) |  |  | (4,435) |
FINANCING ACTIVITIES: |  |  |
Proceeds from borrowings | 26,875 |  |  | 26,583 |
Repayments of debt | (23,467) |  |  | (22,345) |
USAC investments in government securities in connection with the legal defeasance of senior notes | — |  |  | (749) |
Sunoco LP Series A preferred units issuance | 1,473 |  |  | — |
Redemption of Energy Transfer preferred units | (500) |  |  | (2,645) |
Sunoco LP redemption of NuStar preferred units | — |  |  | (784) |
Redemption of Crestwood Niobrara LLC preferred units | — |  |  | (37) |
Capital contributions from noncontrolling interests | 27 |  |  | 637 |
Capital contributions from redeemable noncontrolling interests | — |  |  | 2 |
Distributions to partners | (3,504) |  |  | (3,433) |
Distributions to noncontrolling interests | (1,310) |  |  | (1,379) |
Distributions to redeemable noncontrolling interests | (45) |  |  | (51) |
Debt issuance costs | (111) |  |  | (142) |
Net cash used in financing activities | (562) |  |  | (4,343) |
Increase in cash and cash equivalents | 3,262 |  |  | 138 |
Cash and cash equivalents, beginning of period | 312 |  |  | 161 |
Cash and cash equivalents, end of period | $ | 3,574 |  |  | $ | 299 |

The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar and unit amounts, except per unit data, are in millions)
(unaudited)
1.ORGANIZATION AND BASIS OF PRESENTATION
Organization
The consolidated financial statements presented herein contain the results of Energy Transfer LP and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “Energy Transfer”).
Basis of Presentation
The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements 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. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.
The consolidated financial statements of the Partnership presented herein include the results of operations of our controlled subsidiaries, including Sunoco LP and USAC. The Partnership owns the general partner interest, incentive distribution rights and 28.5 million common units of Sunoco LP, and the general partner interests and 46.1 million common units of USAC.
The operations of certain pipelines and terminals in which we own an undivided interest are proportionately consolidated in the accompanying consolidated financial statements.
Certain prior period amounts have been reclassified to conform to the current period presentation. These reclassifications had no impact on net income or total equity.
Use of Estimates
The unaudited consolidated financial statements have been prepared in conformity with GAAP, which requires the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and the accrual for and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.
Recent Accounting Pronouncements
In November 2024, Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2024-03, Income Statement–Reporting Comprehensive Income–Expense Disaggregation Disclosures (Subtopic 220-40). ASU 2024-03 requires disclosure of specified information about certain costs and expenses in the notes to the consolidated financial statements. ASU 2024-03 is effective for annual periods beginning after December 15, 2026, and interim periods within annual periods beginning after December 15, 2027, with early adoption permitted. ASU 2024-03 is to be applied on a prospective basis, with retrospective application permitted. We are currently evaluating the impact, if any, of ASU 2024-03 on our consolidated financial statements and related disclosures.
In December 2023, FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. ASU 2023-09 improves and enhances income tax disclosure requirements, including new disclosures related to tax rate reconciliation and income taxes paid. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, and interim periods within annual periods beginning after December 15, 2025, with early adoption permitted. ASU 2023-09 is to be applied on a prospective basis, with retrospective application permitted. We expect to include additional disclosures beginning with the annual financial statements for the period ending December 31, 2025, to comply with the requirements of ASU 2023-09.
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2.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.
Parkland is a leading international fuel distributor, marketer and convenience retailer with operations in 26 countries across the Americas. Parkland’s functional currency is the Canadian dollar, and its consolidated structure includes subsidiaries with multiple other functional currencies.
Sunoco LP has engaged a third-party specialist to assist in the initial purchase price allocation in accordance with FASB ASC Topic 805; however, as of the date of this Form 10-Q filing, the initial accounting for this business combination is incomplete due to the timing of the close of the acquisition and the complexity of the acquired business.
As part of the transaction, Sunoco LP repurposed and renamed an existing subsidiary as SunocoCorp. Prior to the Parkland acquisition, SunocoCorp did not have any significant assets, liabilities or operations; in connection with the Parkland acquisition, Sunoco LP deconsolidated SunocoCorp and SunocoCorp became a publicly traded entity classified as a corporation for U.S. federal income tax purposes. SunocoCorp remains a consolidated subsidiary of Energy Transfer. SunocoCorp's common units began trading on the New York Stock Exchange effective November 6, 2025. Subsequent to the Parkland acquisition, SunocoCorp holds limited partnership units of Sunoco LP that are generally economically equivalent to Sunoco LP’s publicly traded common units on the basis of one Sunoco LP common unit for each outstanding SunocoCorp unit. For a period of two years following closing of the transaction, Sunoco LP will ensure that SunocoCorp unitholders receive distributions on a per unit basis that are equivalent to the per unit distributions to Sunoco LP unitholders.
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 LP acquired 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.
These transactions were accounted for as asset acquisitions, and the purchase price was primarily allocated to property, plant and equipment, other non-current assets, net and inventories.
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3.CASH AND CASH EQUIVALENTS
Cash and cash equivalents include all cash on hand, demand deposits and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. The Partnership’s consolidated balance sheets did not include any material amounts of restricted cash as of September 30, 2025 or December 31, 2024.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
The net change in operating assets and liabilities, net of effects of acquisitions and divestitures, included in cash flows from operating activities is comprised as follows:

| Nine Months Ended September 30,
| 2025 |  | 2024
Accounts receivable | $ | 305 |  |  | $ | (415) |
Accounts receivable from related companies | (61) |  |  | (44) |
Inventories | (200) |  |  | (177) |
Other current assets | (11) |  |  | 82 |
Other non-current assets, net | (27) |  |  | (99) |
Accounts payable | (1,016) |  |  | 224 |
Accounts payable to related companies | 32 |  |  | 1 |
Accrued and other current liabilities | 510 |  |  | 711 |
Other non-current liabilities | (4) |  |  | (128) |
Derivative assets and liabilities, net | (11) |  |  | 35 |
Net change in operating assets and liabilities, net of effects of acquisitions and divestitures | $ | (483) |  |  | $ | 190 |

Non-cash investing and financing activities were as follows:

| Nine Months Ended September 30,
| 2025 |  | 2024
Accrued capital expenditures | $ | 914 |  |  | $ | 585 |
Lease assets obtained in exchange for new lease liabilities | 99 |  |  | 3 |
Distribution reinvestment | 33 |  |  | 66 |
USAC exercise and conversion of preferred units into common units | 93 |  |  | 301 |
USAC government securities transferred in connection with the legal defeasance of USAC senior notes due 2026 | — |  |  | 749 |
Legal defeasance of USAC senior notes due 2026 | — |  |  | 725 |
Sunoco LP common units (noncontrolling interest) issued in connection with acquisitions | 18 |  |  | 2,850 |

4.INVENTORIES
Inventories consisted of the following:

| September 30, 2025 |  | December 31, 2024
Natural gas, NGLs and refined products | $ | 2,422 |  |  | $ | 1,989 |
Crude oil | 105 |  |  | 400 |
Spare parts and other | 742 |  |  | 681 |
Total inventories | $ | 3,269 |  |  | $ | 3,070 |

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Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method, except as described below.
Sunoco LP’s fuel inventories are stated at the lower of cost or market using the LIFO method. As of September 30, 2025 and December 31, 2024, Sunoco LP’s fuel inventory balance included lower of cost or market reserves of $285 million and $316 million, respectively. For the three and nine months ended September 30, 2025 and 2024, the Partnership’s consolidated income statements did not include any material amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory. 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 sales included unfavorable inventory valuation adjustments of $197 million and $99 million, respectively, which decreased net income.
5.FAIR VALUE MEASURES
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.
Commodity derivatives, excluding those designated as normal purchases or normal sales, are recognized as assets or liabilities at fair value on our consolidated balance sheets. Fair value is determined using the highest level of observable inputs available, in accordance with the fair value hierarchy.
Exchange-traded contracts, such as futures, swaps and options, are valued using quoted market prices from exchanges including the New York Mercantile Exchange, Intercontinental Exchange or similar platforms. These are classified as Level 1.
Over-the-counter (OTC) swaps, options and physical forward contracts that are comparable to actively traded instruments are valued using third-party broker quotes, pricing services or relevant exchange data. This category also includes OTC options valued using an option pricing model based on observable market inputs. These instruments are classified as Level 2.
Less liquid instruments, including non-standard term OTC swaps and options, as well as long-dated contracts, are valued using internally developed models based on historical industry practices. These models incorporate forward price curves, volatility assumptions, time value and other relevant economic factors. These are classified as Level 3.
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The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2025 and December 31, 2024 based on inputs used to derive their fair values:

|  |  | Fair Value Measurements at September 30, 2025
| Fair Value Total |  | Level 1 |  | Level 2 |  | Level 3
Assets: |  |  |  |  |  |  |
Commodity derivatives: |  |  |  |  |  |  |
Natural Gas: |  |  |  |  |  |  |
Basis Swaps IFERC/NYMEX | $ | 12 |  |  | $ | 12 |  |  | $ | — |  |  | $ | — |
Swing Swaps IFERC | 4 |  |  | 4 |  |  | — |  |  | — |
Fixed Swaps/Futures | 46 |  |  | 46 |  |  | — |  |  | — |
Power: |  |  |  |  |  |  |
Forwards | 42 |  |  | — |  |  | 42 |  |  | — |
Futures | 29 |  |  | 29 |  |  | — |  |  | — |
Options – Calls | 1 |  |  | 1 |  |  | — |  |  | — |
NGLs – Forwards/Swaps | 215 |  |  | 195 |  |  | 20 |  |  | — |
Refined Products – Futures | 8 |  |  | 8 |  |  | — |  |  | — |
Crude – Forwards/Swaps | 27 |  |  | 22 |  |  | 5 |  |  | — |
Total commodity derivatives | 384 |  |  | 317 |  |  | 67 |  |  | — |
Other non-current assets | 215 |  |  | 215 |  |  | — |  |  | — |
Total assets | $ | 599 |  |  | $ | 532 |  |  | $ | 67 |  |  | $ | — |
Liabilities: |  |  |  |  |  |  |
Commodity derivatives: |  |  |  |  |  |  |
Natural Gas: |  |  |  |  |  |  |
Basis Swaps IFERC/NYMEX | $ | (20) |  |  | $ | (20) |  |  | $ | — |  |  | $ | — |
Swing Swaps IFERC | (3) |  |  | (3) |  |  | — |  |  | — |
Fixed Swaps/Futures | (4) |  |  | (4) |  |  | — |  |  | — |
Power: |  |  |  |  |  |  |
Forwards | (41) |  |  | — |  |  | (41) |  |  | — |
Futures | (29) |  |  | (29) |  |  | — |  |  | — |
Options – Calls | (1) |  |  | (1) |  |  | — |  |  | — |
NGLs – Forwards/Swaps | (159) |  |  | (154) |  |  | (5) |  |  | — |
Refined Products – Futures | (18) |  |  | (18) |  |  | — |  |  | — |
Crude – Forwards/Swaps | (30) |  |  | (25) |  |  | (5) |  |  | — |
Total commodity derivatives | (305) |  |  | (254) |  |  | (51) |  |  | — |
Total liabilities | $ | (305) |  |  | $ | (254) |  |  | $ | (51) |  |  | $ | — |

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|  |  | Fair Value Measurements at December 31, 2024
| Fair Value Total |  | Level 1 |  | Level 2 |  | Level 3
Assets: |  |  |  |  |  |  |
Commodity derivatives: |  |  |  |  |  |  |
Natural Gas: |  |  |  |  |  |  |
Basis Swaps IFERC/NYMEX | $ | 6 |  |  | $ | 6 |  |  | $ | — |  |  | $ | — |
Swing Swaps IFERC | 4 |  |  | 4 |  |  | — |  |  | — |
Fixed Swaps/Futures | 10 |  |  | 10 |  |  | — |  |  | — |
Power: |  |  |  |  |  |  |
Forwards | 39 |  |  | 39 |  |  | — |  |  | — |
Futures | 10 |  |  | 10 |  |  | — |  |  | — |
NGLs – Forwards/Swaps | 166 |  |  | 166 |  |  | — |  |  | — |
Refined Products – Futures | 3 |  |  | 3 |  |  | — |  |  | — |
Crude – Forwards/Swaps | 25 |  |  | 25 |  |  | — |  |  | — |
Total commodity derivatives | 263 |  |  | 263 |  |  | — |  |  | — |
Other non-current assets | 212 |  |  | 212 |  |  | — |  |  | — |
Total assets | $ | 475 |  |  | $ | 475 |  |  | $ | — |  |  | $ | — |
Liabilities: |  |  |  |  |  |  |
Commodity derivatives: |  |  |  |  |  |  |
Natural Gas: |  |  |  |  |  |  |
Basis Swaps IFERC/NYMEX | $ | (11) |  |  | $ | (11) |  |  | $ | — |  |  | $ | — |
Swing Swaps IFERC | (11) |  |  | (11) |  |  | — |  |  | — |
Fixed Swaps/Futures | (9) |  |  | (9) |  |  | — |  |  | — |
Power: |  |  |  |  |  |  |
Forwards | (38) |  |  | (38) |  |  | — |  |  | — |
Futures | (10) |  |  | (10) |  |  | — |  |  | — |
NGLs – Forwards/Swaps | (170) |  |  | (170) |  |  | — |  |  | — |
Refined Products – Futures | (9) |  |  | (9) |  |  | — |  |  | — |
Crude – Forwards/Swaps | (35) |  |  | (35) |  |  | — |  |  | — |
Total commodity derivatives | (293) |  |  | (293) |  |  | — |  |  | — |
Total liabilities | $ | (293) |  |  | $ | (293) |  |  | $ | — |  |  | $ | — |

The aggregate estimated fair value and carrying amount of our consolidated debt obligations as of September 30, 2025 were $63.55 billion and $63.10 billion, respectively. As of December 31, 2024, the aggregate fair value and carrying amount of our consolidated debt obligations were $59.01 billion and $59.76 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the respective debt obligations’ observable inputs for similar liabilities.
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6.NET INCOME PER COMMON UNIT
A reconciliation of income or loss and weighted average units used in computing basic and diluted income per common unit is as follows:

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Net income | $ | 1,292 |  |  | $ | 1,434 |  |  | $ | 4,470 |  |  | $ | 5,118 |
Less: Net income attributable to noncontrolling interests | 259 |  |  | 238 |  |  | 918 |  |  | 1,337 |
Less: Net income attributable to redeemable noncontrolling interests | 14 |  |  | 13 |  |  | 47 |  |  | 44 |
Net income, net of noncontrolling interests | 1,019 |  |  | 1,183 |  |  | 3,505 |  |  | 3,737 |
Less: General Partner’s interest in net income | 1 |  |  | 1 |  |  | 3 |  |  | 3 |
Less: Preferred Unitholders’ interest in net income | 59 |  |  | 67 |  |  | 189 |  |  | 294 |
Less: Loss on redemption of preferred units | — |  |  | — |  |  | 8 |  |  | 54 |
Common Unitholders’ interest in net income | $ | 959 |  |  | $ | 1,115 |  |  | $ | 3,305 |  |  | $ | 3,386 |
Basic Income per Common Unit: |  |  |  |  |  |  |
Weighted average common units | 3,433.0 |  |  | 3,415.2 |  |  | 3,432.2 |  |  | 3,384.9 |
Basic income per common unit | $ | 0.28 |  |  | $ | 0.33 |  |  | $ | 0.96 |  |  | $ | 1.00 |
Diluted Income per Common Unit: |  |  |  |  |  |  |
Common Unitholders’ interest in net income | $ | 959 |  |  | $ | 1,115 |  |  | $ | 3,305 |  |  | $ | 3,386 |
Dilutive effect of equity-based compensation of subsidiaries (1) | — |  |  | — |  |  | — |  |  | 1 |
Diluted income attributable to Common Unitholders | $ | 959 |  |  | $ | 1,115 |  |  | $ | 3,305 |  |  | $ | 3,385 |
Weighted average common units | 3,433.0 |  |  | 3,415.2 |  |  | 3,432.2 |  |  | 3,384.9 |
Dilutive effect of unvested restricted unit awards (1) | 23.1 |  |  | 26.0 |  |  | 23.9 |  |  | 25.8 |
Weighted average common units, assuming dilutive effect of unvested restricted unit awards | 3,456.1 |  |  | 3,441.2 |  |  | 3,456.1 |  |  | 3,410.7 |
Diluted income per common unit | $ | 0.28 |  |  | $ | 0.32 |  |  | $ | 0.96 |  |  | $ | 0.99 |

(1)Dilutive effects are excluded from the calculation for periods where the impact would have been antidilutive.
7.DEBT OBLIGATIONS
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.
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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 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%.
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Sunoco LP Credit Facilities
Sunoco LP’s revolving credit facility, which previously was $1.50 billion and increased to approximately $2.46 billion upon the closing of the Parkland acquisition, matures on June 17, 2030, which date may be extended in accordance with the terms of Sunoco LP’s revolving credit facility. Sunoco LP’s revolving credit facility can be increased from time to time upon Sunoco LP’s written request, subject to certain conditions, up to an aggregate amount of $3.50 billion. As of September 30, 2025, Sunoco LP’s revolving credit facility had no 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. For the quarter ended September 30, 2025, the Partnership’s leverage ratio, as calculated pursuant to the covenant related to its Five-Year Credit Facility, was 3.24x.
8.REDEEMABLE NONCONTROLLING INTERESTS
Certain redeemable noncontrolling interests in the Partnership’s subsidiaries were reflected as mezzanine equity on the consolidated balance sheets.
Redeemable noncontrolling interests consisted of the following:

| September 30, 2025 |  | December 31, 2024
Crestwood Niobrara LLC preferred units | $ | 225 |  |  | $ | 225 |
USAC Series A preferred units | 73 |  |  | 169 |
Sunoco LP Series A preferred units | 1,477 |  |  | — |
Other (1) | 25 |  |  | 23 |
Total redeemable noncontrolling interests | $ | 1,800 |  |  | $ | 417 |

(1) Relates to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership.
Sunoco LP Series A Preferred Units
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.
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Distributions on the Sunoco LP Series A Preferred Units will be cumulative from the date of original issuance and will be payable semi-annually in arrears commencing on March 18, 2026, when, as, and if declared by Sunoco LP’s general partner out of legally available funds for such purpose. An initial distribution on the Sunoco LP Series A Preferred Units will be paid on March 18, 2026 in an amount equal to approximately $39.38 per Sunoco LP Series A Preferred Unit.
The Sunoco LP Series A Preferred Units were originally subject to a special mandatory redemption, which was eliminated upon closing of the Parkland acquisition. Prior to the closing, the special mandatory redemption was contingent on conditions that were not entirely within the control of the Partnership; therefore, the Series A Preferred Units were reflected as redeemable noncontrolling interest on the Partnership’s consolidated balance sheet as of September 30, 2025.
Subsequent to the closing of the Parkland acquisition, the Sunoco LP Series A Preferred Units will be reflected as noncontrolling interest within equity on the Partnership's consolidated balance sheet.
USAC Preferred Unit Conversion
On June 3, 2025, the holders of USAC preferred units elected to convert 100,000 preferred units into 4,997,126 common units.
9.EQUITY
Energy Transfer Common Units
Changes in Energy Transfer common units during the nine months ended September 30, 2025 were as follows:

| Number of Units
Number of common units at December 31, 2024 | 3,431.0 |
Common units issued under the distribution reinvestment plan | 1.8 |
Common units vested under equity incentive plans and other | 0.6 |
Number of common units at September 30, 2025 | 3,433.4 |

Energy Transfer Repurchase Program
During the nine months ended September 30, 2025, Energy Transfer did not repurchase any of its common units under its current buyback program. As of September 30, 2025, $880 million remained available to repurchase under the current program.
Energy Transfer Distribution Reinvestment Program
During the nine months ended September 30, 2025, distributions of $33 million were reinvested under the distribution reinvestment program. As of September 30, 2025, a total of 37.1 million Energy Transfer common units remained available to be issued under currently effective registration statements in connection with the distribution reinvestment program.
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 |

Energy Transfer Preferred Units
As of September 30, 2025 and December 31, 2024, Energy Transfer’s outstanding preferred units included 550,000 Series B Preferred Units, 1,484,780 Series G Preferred Units, 900,000 Series H Preferred Units and 41,464,179 Series I Preferred Units. As of December 31, 2024, Energy Transfer’s outstanding preferred units also included 500,000 Series F Preferred
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Units, which were redeemed in May 2025. Energy Transfer’s Series A Preferred Units, Series C Preferred Units and Series E Preferred Units were previously redeemed as indicated in the tables below.
The following table summarizes changes in the Energy Transfer Preferred Units:

| Preferred Unitholders |  |
| Series B |  | Series F |  | Series G |  | Series H |  | Series I |  | Total
Balance, December 31, 2024 | $ | 556 |  |  | $ | 496 |  |  | $ | 1,488 |  |  | $ | 893 |  |  | $ | 419 |  |  | $ | 3,852 |
Distributions to partners | (18) |  |  | — |  |  | — |  |  | — |  |  | (9) |  |  | (27) |
Net income | 9 |  |  | 8 |  |  | 26 |  |  | 15 |  |  | 9 |  |  | 67 |
Balance, March 31, 2025 | 547 |  |  | 504 |  |  | 1,514 |  |  | 908 |  |  | 419 |  |  | 3,892 |
Distributions to partners | — |  |  | (16) |  |  | (53) |  |  | (29) |  |  | (9) |  |  | (107) |
Redemption of preferred units | — |  |  | (500) |  |  | — |  |  | — |  |  | — |  |  | (500) |
Other, net | — |  |  | 8 |  |  | — |  |  | — |  |  | — |  |  | 8 |
Net income | 9 |  |  | 4 |  |  | 27 |  |  | 14 |  |  | 9 |  |  | 63 |
Balance, June 30, 2025 | 556 |  |  | — |  |  | 1,488 |  |  | 893 |  |  | 419 |  |  | 3,356 |
Distributions to partners | (18) |  |  | — |  |  | — |  |  | — |  |  | (9) |  |  | (27) |
Net income | 9 |  |  | — |  |  | 27 |  |  | 15 |  |  | 8 |  |  | 59 |
Balance, September 30, 2025 | $ | 547 |  |  | $ | — |  |  | $ | 1,515 |  |  | $ | 908 |  |  | $ | 418 |  |  | $ | 3,388 |

| Preferred Unitholders |  |
| Series A |  | Series B |  | Series C |  | Series D |  | Series E |  | Series F |  | Series G |  | Series H |  | Series I |  | Total
Balance, December 31, 2023 | $ | 948 |  |  | $ | 556 |  |  | $ | 438 |  |  | $ | 435 |  |  | $ | 786 |  |  | $ | 496 |  |  | $ | 1,488 |  |  | $ | 893 |  |  | $ | 419 |  |  | $ | 6,459 |
Distributions to partners | (24) |  |  | (18) |  |  | (11) |  |  | (11) |  |  | (15) |  |  | — |  |  | — |  |  | — |  |  | (9) |  |  | (88) |
Redemption of preferred units | — |  |  | — |  |  | (450) |  |  | (445) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (895) |
Other, net | — |  |  | — |  |  | 11 |  |  | 10 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 21 |
Net income | 23 |  |  | 9 |  |  | 12 |  |  | 11 |  |  | 15 |  |  | 8 |  |  | 27 |  |  | 15 |  |  | 9 |  |  | 129 |
Balance, March 31, 2024 | 947 |  |  | 547 |  |  | — |  |  | — |  |  | 786 |  |  | 504 |  |  | 1,515 |  |  | 908 |  |  | 419 |  |  | 5,626 |
Distributions to partners | (32) |  |  | — |  |  | — |  |  | — |  |  | (15) |  |  | (17) |  |  | (53) |  |  | (29) |  |  | (9) |  |  | (155) |
Redemption of preferred units | (950) |  |  | — |  |  | — |  |  | — |  |  | (800) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (1,750) |
Other, net | 13 |  |  | — |  |  | — |  |  | — |  |  | 20 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 33 |
Net income | 22 |  |  | 9 |  |  | — |  |  | — |  |  | 9 |  |  | 9 |  |  | 26 |  |  | 14 |  |  | 9 |  |  | 98 |
Balance, June 30, 2024 | — |  |  | 556 |  |  | — |  |  | — |  |  | — |  |  | 496 |  |  | 1,488 |  |  | 893 |  |  | 419 |  |  | 3,852 |
Distributions to partners | — |  |  | (18) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (9) |  |  | (27) |
Net income | — |  |  | 9 |  |  | — |  |  | — |  |  | — |  |  | 8 |  |  | 26 |  |  | 15 |  |  | 9 |  |  | 67 |
Balance, September 30, 2024 | $ | — |  |  | $ | 547 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 504 |  |  | $ | 1,514 |  |  | $ | 908 |  |  | $ | 419 |  |  | $ | 3,892 |

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
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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.
Noncontrolling Interests
The Partnership’s consolidated financial statements also include noncontrolling interests in 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.
Sunoco LP Cash Distributions
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 |

USAC Cash Distributions
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 |

Accumulated Other Comprehensive Income
The following table presents the components of AOCI, net of tax:

| September 30, 2025 |  | December 31, 2024
Available-for-sale securities | $ | 27 |  |  | $ | 20 |
Foreign currency translation adjustment | (9) |  |  | (6) |
Actuarial gains related to pensions and other postretirement benefits | 40 |  |  | 45 |
Investments in unconsolidated affiliates, net | 10 |  |  | 14 |
Total AOCI included in partners’ capital, net of tax | $ | 68 |  |  | $ | 73 |

10.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
FERC Proceedings
Rover – FERC – Stoneman House
In late 2016, FERC Enforcement Staff began a non-public investigation related to Rover’s purchase and removal of a potentially historic home (known as the Stoneman House) while Rover’s application for permission to construct the new 711-mile interstate natural gas pipeline and related facilities was pending. On March 18, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN19-4-000), ordering Rover to explain why it should not pay a $20 million civil penalty for alleged violations of FERC regulations requiring certificate holders to be forthright in their
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submissions of information to the FERC. Rover filed its answer and denial to the order on June 21, 2021, and a surreply on September 15, 2021. FERC issued an order on January 20, 2022, setting the matter for hearing before an administrative law judge. The hearing was set to commence on March 6, 2023; as explained below, this FERC proceeding has been stayed.
On February 1, 2022, Energy Transfer and Rover filed a Complaint for Declaratory Relief in the U.S. District Court for the Northern District of Texas (the “Federal District Court”) seeking an order declaring that FERC must bring its enforcement action in federal district court (instead of before an administrative law judge). Also on February 1, 2022, Energy Transfer and Rover filed an expedited request to stay the proceedings before the FERC administrative law judge pending the outcome of the Federal District Court case. On May 24, 2022, the Federal District Court ordered a stay of the FERC’s enforcement case and the Federal District Court case pending the resolution of two cases pending before the U.S. Supreme Court. Arguments were heard in those cases on November 7, 2022. On April 14, 2023, the U.S. Supreme Court held against the government in both cases, finding that the federal district courts had jurisdiction to hear those suits and to resolve the parties’ constitutional challenges. The cases were remanded to the federal district courts for further proceedings.
On September 13, 2023, the Federal District Court ordered that the Federal District Court case would be stayed pending the resolution of another case pending before the U.S. Supreme Court and that the FERC enforcement case would remain stayed. On November 13, 2023, the FERC appealed the Federal District Court order to the U.S. Court of Appeals for the Fifth Circuit. On December 11, 2023, FERC filed a motion to withdraw that appeal, which the Fifth Circuit granted on December 12, 2023. The FERC and the Federal District Court proceedings were stayed pending resolution of the case pending before the U.S. Supreme Court. The Supreme Court issued a decision in that case on June 27, 2024. The FERC and Federal District Court proceedings remain stayed at this time. Energy Transfer and Rover intend to vigorously defend against this claim.
Rover – FERC – Tuscarawas
In mid-2017, FERC Enforcement Staff began a non-public investigation regarding allegations that diesel fuel may have been included in the drilling mud at the Tuscarawas River horizontal directional drilling (“HDD”) operations. Rover and the Partnership are cooperating with the investigation. In 2019, Enforcement Staff provided Rover with a notice pursuant to Section 1b.19 of the FERC regulations that Enforcement Staff intended to recommend that the FERC pursue an enforcement action against Rover and the Partnership. On December 16, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN17-4-000), ordering Rover and Energy Transfer to show cause why they should not be found to have violated Section 7(e) of the NGA, Section 157.20 of FERC’s regulations, and the Rover Pipeline Certificate Order, and assessed civil penalties of $40 million.
Rover and Energy Transfer filed their answer to this order on March 21, 2022, and Enforcement Staff filed a reply on April 20, 2022. Rover and Energy Transfer filed their surreply to this order on May 13, 2022. FERC has taken no further action on the case since that time.
The primary contractor (and one of the subcontractors) responsible for the HDD operations of the Tuscarawas River site have agreed to indemnify Rover and the Partnership for any and all losses, including any fines and penalties from government agencies, resulting from their actions in conducting such HDD operations. Given the stage of the proceedings, the Partnership is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any; however, the Partnership believes the indemnity described above will be applicable to the penalty proposed by Enforcement Staff and intends to vigorously defend itself against the subject claims.
Other FERC Proceedings
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 District of Columbia Circuit (“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
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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 placed the consolidated cases in abeyance pending further order of the D.C. Circuit. On August 12, 2025, the D.C. Circuit issued an order returning all cases to the court’s active docket and issued a briefing schedule with Panhandle’s initial brief being due on November 10, 2025.
Commitments
In the normal course of business, Energy Transfer purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. Energy Transfer believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on the Partnership’s financial position or results of operations.
Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon the unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
We have certain non-cancelable rights-of-way (“ROW”) commitments which require fixed payments and either expire upon our chosen abandonment or at various dates in the future. The following table reflects ROW expense included in operating expenses in the accompanying consolidated statements of operations:

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
ROW expense | $ | 27 |  |  | $ | 23 |  |  | $ | 62 |  |  | $ | 50 |

Litigation and Contingencies
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Due to the flammable and combustible nature of natural gas and crude oil, the potential exists for personal injury and/or property damage to occur in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.
We or our subsidiaries are parties to various legal proceedings, arbitrations and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine
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that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
As of September 30, 2025 and December 31, 2024, accruals of approximately $313 million and $281 million, respectively, were reflected on our consolidated balance sheets related to contingent obligations that met both the probable and reasonably estimable criteria. In addition, we may recognize additional contingent losses in the future related to (i) contingent matters for which a loss is currently considered reasonably possible but not probable and/or (ii) losses in excess of amounts that have already been accrued for such contingent matters. In some of these cases, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. For such matters where additional contingent losses can be reasonably estimated, the range of additional losses is estimated to be up to approximately $42 million.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts or our estimates of reasonably possible losses prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
The following sections include descriptions of certain matters that could impact the Partnership’s financial position, results of operations and/or cash flows in future periods. The following sections also include updates to certain matters that have previously been disclosed, even if those matters are not anticipated to have a potentially significant impact on future periods. In addition to the matters disclosed in the following sections, the Partnership is also involved in multiple other matters that could impact future periods, including other lawsuits and arbitration related to the Partnership’s commercial agreements. With respect to such matters, contingencies that met both the probable and reasonably estimable criteria have been included in the accruals disclosed above, and the range of additional losses disclosed above also reflects any relevant amounts for such matters.
Dakota Access Pipeline
On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the U.S. District Court for the District of Columbia (“D.C. District Court”) challenging permits issued by the U.S. Army Corps of Engineers (“USACE”) that allowed Dakota Access to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE that allowed the pipeline to cross land owned by the USACE adjacent to the Missouri River. Dakota Access and the Cheyenne River Sioux Tribe (“CRST”) intervened. Separate lawsuits filed by the Oglala Sioux Tribe (“OST”) and the Yankton Sioux Tribe (“YST”) were consolidated with this action and several individual tribal members intervened (collectively, with SRST and CRST, the “Tribes”). On March 25, 2020, the D.C. District Court remanded the case back to the USACE for preparation of an Environment Impact Statement (“EIS”). On July 6, 2020, the D.C. District Court vacated the easement and ordered the Dakota Access Pipeline to be shut down and emptied of oil by August 5, 2020. Dakota Access and the USACE appealed to the D.C. Circuit which granted an administrative stay of the D.C. District Court’s July 6 order and ordered further briefing on whether to fully stay the July 6 order. On August 5, 2020, the D.C. Circuit (1) granted a stay of the portion of the D.C. District Court order that required Dakota Access to shut the pipeline down and empty it of oil, (2) denied a motion to stay the March 25 order pending a decision on the merits by the D.C. Circuit as to whether the USACE would be required to prepare an EIS and (3) denied a motion to stay the D.C. District Court’s order to vacate the easement during this appeal process. The August 5 order also states that the D.C. Circuit expected the USACE to clarify its position with respect to whether the USACE intended to allow the continued operation of the pipeline notwithstanding the vacatur of the easement and that the D.C. District Court may consider additional relief, if necessary.
On August 10, 2020, the D.C. District Court ordered the USACE to submit a status report by August 31, 2020, clarifying its position with regard to its decision-making process with respect to the continued operation of the pipeline. On August 31, 2020, the USACE submitted a status report that indicated that it considered the presence of the pipeline at the Lake Oahe crossing without an easement to constitute an encroachment on federal land, and that it was still considering whether to exercise its enforcement discretion regarding this encroachment. The Tribes subsequently filed a motion seeking an injunction to stop the operation of the pipeline and both the USACE and Dakota Access filed briefs in opposition of the motion for injunction. The motion for injunction was fully briefed as of January 8, 2021.
On January 26, 2021, the D.C. Circuit affirmed the D.C. District Court’s March 25, 2020 order requiring an EIS and its July 6, 2020 order vacating the easement. In this same January 26 order, the D.C. Circuit also overturned the D.C. District Court’s July 6, 2020 order that the pipeline shut down and be emptied of oil. Dakota Access filed for rehearing en banc on April 12, 2021, which the D.C. Circuit denied. On September 20, 2021, Dakota Access filed a petition with the U.S.
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Supreme Court to hear the case. Oppositions were filed by the Solicitor General on December 17, 2021 and by the Tribes on December 16, 2021. Dakota Access filed their reply on January 4, 2022. On February 22, 2022, the U.S. Supreme Court declined to hear the case.
The D.C. District Court scheduled a status conference for February 10, 2021 to discuss the effects of the D.C. Circuit’s January 26, 2021 order on the pending motion for injunctive relief, as well as the USACE’s expectations as to how it will proceed regarding its enforcement discretion regarding the easement. On May 3, 2021, the USACE advised the D.C. District Court that it had not changed its position with respect to its opposition to the Tribes’ motion for injunction. On May 21, 2021, the D.C. District Court denied the Tribes’ request for an injunction. On June 22, 2021, the D.C. District Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice.
On September 8, 2023, the USACE published the Draft EIS. Comments on the Draft EIS were due on December 13, 2023. The USACE anticipates that a Final EIS will be issued in December 2025 and a Record of Decision will be issued in early 2026. The pipeline continues to operate pending completion of the Final EIS. Energy Transfer cannot determine when or how future lawsuits will be resolved or the impact they may have on the Bakken Pipeline; however, Energy Transfer expects that after the law and complete record are fully considered, any such proceeding will be resolved in a manner that will allow the pipeline to continue to operate.
In addition, lawsuits and/or regulatory proceedings or actions of this or a similar nature could result in interruptions to construction or operations of current or future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and results of operations.
Standing Rock Sioux Tribe in Federal Court in District of Columbia
Dakota Access is the subject of litigation in the D.C. District Court. The SRST sued the USACE arguing that the USACE’s alleged failure to stop Dakota Access from operating violates numerous laws, including the Mineral Leasing Act, the Government Acquisition and Streamlining Act, the National Environmental Policy Act, the Clean Water Act, the National Historic Preservation Act, the Administrative Procedure Act as well as the 1868 Fort Laramie Treaty. The SRST requests a permanent injunction or writ of mandamus that would compel the USACE to shut Dakota Access down pending the completion of the USACE’s EIS and decision on whether to grant Dakota Access an easement under the Mineral Leasing Act.
On October 15, 2024, the SRST filed the above referenced complaint. A summons to the USACE was issued on October 17, 2024. Dakota Access, the state of North Dakota and numerous other states have intervened in the lawsuit in support of the USACE.
On January 17, 2025, the USACE, Dakota Access and state intervenors (including North Dakota and thirteen other states) each filed a motion to dismiss all of the claims in the new SRST litigation. Also, on January 17, 2025, the SRST filed a motion for partial summary judgment on certain of their claims. Briefing on the motions to dismiss is complete. The D.C. District Court has held briefing on the motion for partial summary judgment in abeyance pending the D.C. District Court’s decision on the motions to dismiss. On March 28, 2025, the D.C. District Court granted the motions to dismiss. On May 27, 2025, the SRST appealed the dismissal to the D.C. Circuit. Dakota Access intends to vigorously defend against this claim.
Williams Antitrust Litigation
On June 28, 2024, Louisiana Energy Gateway LLC, The Williams Companies, Inc., and Williams Fields Services Group, LLC (collectively, “Williams”) filed a Petition for Damages against Energy Transfer and Gulf Run Transmission, LLC (“Gulf Run”) in the 42nd Judicial District Court, Parish of DeSoto, State of Louisiana (“District Court”), alleging that Energy Transfer and/or Gulf Run have monopolized, conspired to monopolize and/or attempted to monopolize, the relevant product and geographic market for the movement of natural gas from the Haynesville Shale in northwestern Louisiana south to natural gas facilities in the Louisiana Gulf Coast (the “Relevant Market”), engaged in acquisitions that have directly enabled and incentivized to substantially lessen competition, and engaged in unfair methods of competition and unfair trade practices.
On September 16, 2024, Energy Transfer and Gulf Run removed the case to the U.S. District Court for the Western District of Louisiana (“Federal Court”). On October 4, 2024, Williams filed a Motion to Remand with the Federal Court, seeking to remand the case back to the District Court. On October 21, 2024, Energy Transfer and Gulf Run filed a consent to remand based on a subsequent change in circumstances. After the case was remanded, on November 18, 2024, Energy Transfer and Gulf Run filed a Peremptory Exception of No Cause, asserting that Williams failed to state a cause of action. The
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Peremptory Exception was set for hearing on February 10, 2025 and denied. The District Court has set the case for trial on September 14, 2026.
Mont Belvieu Incident
On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu LP’s (“Lone Star,” now known as Energy Transfer Mont Belvieu NGLs LP) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations resumed at the facilities in the fall of 2016, with the exception of one of Lone Star’s storage wells at the North Terminal that has not been returned to service. Lone Star has obtained payment for most of the losses it has submitted to the adjacent operator. Lone Star continues to quantify and seek reimbursement for outstanding losses.
MTBE Litigation
ETC Sunoco and Energy Transfer R&M (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging methyl tertiary butyl ether (“MTBE”) contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws and/or deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.
As of September 30, 2025, Sunoco Defendants are defendants in two cases: one case initiated by the State of Maryland and one by the Commonwealth of Pennsylvania. The actions brought also named as defendants ETO, ETP Holdco Corporation and Sunoco Partners Marketing & Terminals L.P., now known as Energy Transfer Marketing & Terminals L.P. ETP Holdco Corporation and Energy Transfer Marketing & Terminals L.P. are wholly owned subsidiaries of Energy Transfer.
It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.
Rover – State of Ohio
On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants seeking to recover approximately $3 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. The defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Ohio’s Fifth District Court of Appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court. On April 22, 2020, the Ohio Supreme Court granted the review. On March 17, 2022, the Ohio Supreme Court reversed in part and remanded to the Ohio trial court. The Ohio Supreme Court agreed with Rover that the State of Ohio had waived its rights under Section 401 of the Clean Water Act but remanded to the trial court to determine whether any of the allegations fell outside the scope of the waiver.
On remand, the Ohio EPA voluntarily dismissed four of the other five defendants and dismissed one of its counts against Rover. In its Fourth Amended Complaint, the Ohio EPA removed all paragraphs that alleged violations by the four dismissed defendants, including those where the dismissed defendants were alleged to have acted jointly with Rover or others. At a June 2, 2022 status conference, the trial judge set a schedule for Rover and the other remaining defendant to file motions to dismiss the Fourth Amended Complaint. On August 1, 2022, Rover and the other remaining defendant each filed their respective motions. Briefing on those motions was completed on November 4, 2022. By order issued on October 20, 2023, the trial judge dismissed the Ohio EPA’s Fourth Amended Complaint.
On November 17, 2023, the State of Ohio appealed the trial judge’s decision to Ohio’s Fifth District Court of Appeals. The State filed its initial brief on January 8, 2024. Energy Transfer and Rover filed a responsive brief on February 20, 2024. The State filed a reply brief on February 26, 2024. Oral argument on the appeal was held on August 27, 2024. On October 1, 2024, Ohio’s Fifth District Court of Appeals affirmed the trial judge’s decision. The State of Ohio sought permission to appeal this decision from the Ohio Supreme Court. Energy Transfer and Rover have opposed such permission. On January 28, 2025, the Ohio Supreme Court declined to hear the State’s appeal. On April 25, 2025, the State of Ohio filed a Petition for Writ of Certiorari with the U.S. Supreme Court. Rover filed a Brief in Opposition on June 30, 2025. The State of Ohio filed a reply brief on July 11, 2025. On October 6, 2025, the U.S. Supreme Court denied the State of Ohio’s Petition for Writ of Certiorari, concluding this matter.
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Unitholder Litigation Regarding Pipeline Construction
Various purported unitholders of Energy Transfer have filed derivative actions against various past and current officers and members of Energy Transfer’s Board of Directors, LE GP, LLC, and Energy Transfer, as a nominal defendant that assert claims for breach of fiduciary duties, unjust enrichment, waste of corporate assets, breach of Energy Transfer’s Partnership Agreement, tortious interference, abuse of control and gross mismanagement related primarily to matters involving the construction of pipelines in Pennsylvania and Ohio. They also seek damages and changes to Energy Transfer’s corporate governance structure. See Bettiol v. LE GP, Case No. 3:19-cv-02890-X (N.D. Tex.); Davidson v. Kelcy L. Warren, Cause No. DC-20-02322 (44th Judicial District of Dallas County, Texas); Harris v. Kelcy L. Warren, Case No. 2:20-cv-00364-GAM (E.D. Pa.); Barry King v. LE GP, Case No. 3:20-cv-00719-X (N.D. Tex.); Inter-Marketing Group USA, Inc. v. LE GP, et al., Case No. 2022-0139-SG (Del. Ch.); Elliot v. LE GP LLC, Case No. 3:22-cv-01527-B (N.D. Tex.); Chapa v. Kelcy L. Warren, et al., Index No. 611307/2022 (N.Y. Sup. Ct.); Elliott v. LE GP et al, Cause No. DC-22-14194 (Dallas County, Tex.); and Charles King v. LE GP, LLC et al, Cause No. DC-22-14159 (Dallas County, Texas). The Barry King action that was filed in the U.S. District Court for the Northern District of Texas (Case No. 3:20-cv-00719-X) has been consolidated with the Bettiol action. On August 9, 2022, the Elliot action that was filed in the U.S. District Court for the Northern District of Texas (Case No. 3:22-cv-01527-B) was voluntarily dismissed.
Another purported unitholder of Energy Transfer, Allegheny County Employees’ Retirement System (“ACERS”), individually and on behalf of all others similarly situated, filed a suit under the federal securities laws purportedly on behalf of a class, against Energy Transfer and three of Energy Transfer’s directors: Kelcy L. Warren, John W. McReynolds and Thomas E. Long. See Allegheny County Emps.’ Ret. Sys. v. Energy Transfer LP, Case No. 2:20-00200-GAM (E.D. Pa.). On June 15, 2020, ACERS filed an amended complaint and added as additional defendants Energy Transfer directors Marshall S. McCrea and Matthew S. Ramsey, as well as Michael J. Hennigan and Joseph McGinn. The amended complaint asserts claims for violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder related primarily to matters involving the construction of pipelines in Pennsylvania. On August 14, 2020, the defendants filed a motion to dismiss ACERS’ amended complaint. On April 6, 2021, the court granted in part and denied in part the defendants’ motion to dismiss. The court held that ACERS could proceed with its claims regarding certain statements put at issue by the amended complaint while also dismissing claims based on other statements. The court also dismissed without prejudice the claims against defendants McReynolds, McGinn and Hennigan. On August 23, 2022, the court granted in part and denied in part ACERS’ motion for class certification. The court certified a class consisting of those who purchased or otherwise acquired common units of Energy Transfer between February 25, 2017 and November 11, 2019. On January 19, 2024, the defendants filed a motion for summary judgment on all of the claims asserted in ACERS’ amended complaint, and ACERS filed a motion for partial summary judgment. The court heard oral argument on the parties’ motions for summary judgment on July 15, 2024. On August 8, 2024, the court ruled on the parties’ cross motions for summary judgment. The court granted defendants’ motion in part, entering judgment for defendants on loss causation for two categories of challenged statements, thereby significantly reducing the class period and potential damages. The court also granted plaintiffs’ motion for partial summary judgment in part, entering judgment for plaintiffs on the elements of falsity and the scienter of certain individuals as to four of the challenged statements. The parties settled in principle on April 23, 2025. On July 9, 2025, the court entered an Order Preliminarily Approving Settlement and Authorizing Dissemination of Notice of Settlement. The final settlement hearing was held on October 7, 2025.
On June 3, 2022, another purported unitholder of Energy Transfer, Mike Vega, filed suit, purportedly on behalf of a class, against Energy Transfer and Messrs. Warren, Long, McCrea and Whitehurst. See Vega v. Energy Transfer LP et al., Case No. 1:22-cv-4614 (S.D.N.Y.). The action asserts claims for violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder related primarily to statements made in connection with the construction of Rover. On August 10, 2022, the court appointed the New Mexico State Investment Council and Public Employees Retirement Association of New Mexico (the “New Mexico Funds”) as lead plaintiffs. New Mexico Funds filed an amended complaint on September 30, 2022 and added as additional defendants Energy Transfer directors John W. McReynolds and Matthew S. Ramsey. On November 7, 2022, the court granted the defendants’ motion to transfer and transferred this action to the U.S. District Court for the Northern District of Texas. On January 27, 2023, the defendants filed their motion to dismiss the New Mexico Funds’ amended complaint.
The defendants cannot predict the outcome of these lawsuits or any lawsuits that might be filed subsequent to the date of this filing, nor can the defendants predict the amount of time and expense that will be required to resolve these lawsuits. However, the defendants believe that the claims are without merit and intend to vigorously contest them.
Cline Class Action
On July 7, 2017, Perry Cline filed a class action complaint in the Eastern District of Oklahoma (the “Eastern District Court”) against Sunoco, Inc. (R&M), LLC (now known as Energy Transfer R&M) and Energy Transfer Marketing &
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Terminals L.P. (collectively, “ETMT”) that alleged ETMT failed to make timely payments of oil and gas proceeds from Oklahoma wells and to pay statutory interest for those untimely payments. On October 3, 2019, the Eastern District Court certified a class to include all persons who received untimely payments from Oklahoma wells on or after July 7, 2012, and who have not already been paid statutory interest on the untimely payments (the “Class”). Excluded from the Class are those entitled to payments of proceeds that qualify as “minimum pay,” prior period adjustments and pass through payments, as well as governmental agencies and publicly traded oil and gas companies.
After a bench trial, on August 17, 2020, Judge John Gibney (sitting from the Eastern District of Virginia) issued an opinion that awarded the Class actual damages of $75 million for late payment interest for identified and unidentified royalty owners and interest-on-interest. This amount was later amended to $81 million to account for interest accrued from trial (the “Order”). Judge Gibney also awarded punitive damages in the amount of $75 million. The Class is also seeking attorneys’ fees.
On August 27, 2020, ETMT filed its Notice of Appeal with the 10th Circuit Court of Appeals (“10th Circuit”) and appealed the entirety of the Order. The matter was fully briefed, and oral argument was set for November 15, 2021. However, on November 1, 2021, the 10th Circuit dismissed the appeal due to jurisdictional concerns with finality of the Order. En banc rehearing of this decision was denied on November 29, 2021. On December 1, 2021, ETMT filed a Petition for Writ of Mandamus to the 10th Circuit to correct the jurisdictional problems and secure final judgment. On February 2, 2022, the 10th Circuit denied the Petition for Writ of Mandamus, citing that there are other avenues for ETMT to obtain adequate relief. On February 10, 2022, ETMT filed a Motion to Modify the Plan of Allocation Order and Issue a Rule 58 Judgment with the trial court, requesting the Eastern District Court to enter a final judgment in compliance with the Rules. ETMT also filed an injunction with the trial court to enjoin all efforts by plaintiffs to execute on any non-final judgment. On March 31, 2022, Judge Gibney denied the Motion to Modify the Plan of Allocation, reiterating his thoughts that the order constitutes a final judgment. Judge Gibney granted the injunction in part (placing a hold on enforcement efforts for 60 days) and denied the injunction in part. The injunction has since been lifted.
Despite the fact that ETMT has taken the position that the judgment is not final and not subject to execution, the Class engaged in asset discovery and actively tried to collect on the judgment through garnishment proceedings from ETMT’s customers. ETMT unsuccessfully tried to deposit the funds into the Eastern District Court’s Registry. Accordingly, to stop the garnishment proceedings, on December 2, 2022, ETMT wired approximately $161 million to the Plaintiff’s approved Plan Administrator, which represented at the time the full amount of the judgment with attorneys’ fees and post-judgment interest. ETMT did so without waiving its ability to pursue its pending appeal or its right to appeal the merits of the judgment. Plaintiff has since dismissed the garnishment actions.
ETMT appealed the denial of the Motion to Modify to the 10th Circuit in an attempt to get a decision on finality. The appeal was fully briefed, and oral argument was held on March 21, 2023. On August 3, 2023, the 10th Circuit ruled in favor of ETMT and found that the Eastern District Court’s plan of allocation (which was part of the final judgment) did not satisfy all finality requirements. The 10th Circuit held that the Eastern District Court abused its discretion in denying ETMT’s Rule 60(b)(6) Motion to Modify and reversed and remanded for further proceedings. The case was sent back to the trial court so that the Eastern District Court could fix the finality requirements with the judgment. Further, ETMT sought and recovered a return of funds deposited with the Plan Administrator; Class Counsel did not oppose this motion.
At a status hearing on September 28, 2023, Class Counsel indicated that it would seek additional interest up until the date that the final judgment is entered. The Eastern District Court asked for briefing on the issue of additional interest and held a hearing on October 17, 2023 to address this issue further and enter a ruling as to whether additional interest should be added to the judgment total. During the hearing, the Eastern District Court ruled that additional interest should be awarded at the 12% statutory rate from the date of the prior improper judgment up until October 17, 2023. However, the Judge tolled the running of interest for the time period during which the Plan Administrator was in possession of ETMT’s funds (between November 2, 2022 and October 10, 2023). Based on this ruling, the Class calculated that approximately $23 million in additional interest should be added to the final judgment. On October 19, 2023, the Eastern District Court entered the new final judgment with a corrected Plan of Allocation. Both parties agree that this newly entered judgment fixes the finality concerns and will allow an appeal to the 10th Circuit on the merits. With the inclusion of additional interest, the total amount awarded to the Class is approximately $104 million in actual damages and $75 million in punitive damages. ETMT has appealed the entirety of the judgment to the 10th Circuit. Oral argument took place on November 20, 2024 and the parties are awaiting a decision. ETMT cannot predict the outcome of the case, nor can ETMT predict the amount of time and expense that will be required to resolve the appeal.
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Massachusetts Attorney General v. New England Gas Company
On July 7, 2011, the Massachusetts Attorney General (the “MA AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“DPU”) against New England Gas Company (“NEG”) with respect to certain environmental cost recoveries. NEG was an operating division of Southern Union Company (“SUG”), and the NEG assets were acquired in connection with the merger transaction with Energy Transfer in March 2012. Subsequent to the merger, in 2013, SUG sold the NEG assets to Liberty Utilities (“Liberty,” and together with NEG and SUG, “Respondents”) and retained certain potential liabilities, including the environmental cost recoveries with respect to the pending complaint before the DPU. Specifically, the MA AG seeks a refund to NEG’s ratepayers for approximately $18 million in legal fees associated with SUG environmental response activities. The MA AG requests that the DPU initiate an investigation into NEG’s collection and reconciliation of recoverable environmental costs, namely: (1) the legal fees charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005; (2) the legal fees charged by the Bishop, London & Dodds firm and passed through the recovery mechanisms since 2005; and (3) the legal fees passed through the recovery mechanism that the MA AG contends only qualify for a lesser (i.e., 50%) level of recovery. Respondents maintain that, by tariff, these costs are recoverable through rates charged to NEG customers pursuant to the environmental remediation adjustment clause program. After the Respondents answered the complaint and filed a motion to dismiss in 2011, the Hearing Officer deferred decision on the motion to dismiss and issued a stay of discovery pending resolution of a discovery dispute, which it later lifted on June 24, 2013, permitting the case to resume. However, the MA AG failed to take any further steps to prosecute its claims for nearly seven years. The case remained largely dormant until February 2022, when the Hearing Officer denied the motion to dismiss. After receiving input from the parties, the Hearing Officer entered a procedural schedule on March 16, 2022 (which was amended slightly on August 22, 2022). The parties engaged in discovery and the preparation of pre-filed testimony. Respondents submitted their pre-filed testimony on July 11, 2022. The MA AG served three sets of discovery requests on Respondents on September 9, September 12, and September 20, 2022, to which Respondents timely responded. On October 5, 2022, the MA AG requested that the DPU issue a ruling on whether the information that Respondents redacted in their attorneys’ fees invoices is protected by the attorney-client privilege. On the same day, the MA AG also filed a Motion to Stay the Procedural Schedule pending a ruling on the privilege issue. On October 6, 2022, without even affording Respondents the opportunity to respond, the DPU granted the MA AG’s request to stay the procedural schedule. Accordingly, all previous deadlines (including the MA AG’s October 7, 2022 deadline to submit direct pre-filed testimony) are presently stayed. On October 18, 2023, the DPU issued an Order on Attorney General’s Motion to Compel, ruling on issues originally raised in a motion to compel that the MA AG filed in 2013. The October 18, 2023 Order directed NEG to review its redactions again and, to the extent any invoices are completely redacted or heavily redacted, to provide more lightly redacted versions within 30 days. The October 18, 2023 Order also stated that the DPU will set a new procedural schedule in this matter sometime after NEG complies with the directives in the order, which Respondents have completed as of January 17, 2024. The matter remains stayed until the DPU sets a new procedural schedule.
Crestwood Midstream Partners, LP – Linde Litigation
On December 23, 2019, Linde Engineering North America Inc. (“Linde”) filed a lawsuit in the District Court of Harris County, Texas alleging that Arrow Field Services, LLC and Crestwood Midstream Partners LP, our consolidated subsidiaries (collectively, “Crestwood”), breached a contract entered into in March 2018 under which Linde was to provide engineering, procurement and construction services to Crestwood related to the completion of the construction of the Bear Den II cryogenic processing plant.
Trial was held in June 2022, and a final judgment was entered on October 24, 2022. The final judgment includes an award of damages of approximately $21 million, a pre-judgment interest award of approximately $18 million and attorney fees and other costs of approximately $5 million. Crestwood has insurance coverage related to certain pre-judgment interest awards but has not recorded a receivable related to any potential insurance recovery. On January 9, 2023, Crestwood paid approximately $21 million to the Court Registry under protest to mitigate the impact of post-judgment interest. Crestwood filed a Notice of Appeal on January 13, 2023, and filed its Appellate Brief on September 29, 2023. Linde’s response was filed on February 8, 2024. Oral argument was held on September 26, 2024.
On December 17, 2024, the First Court of Appeals in Houston issued its opinion, in which it reversed the trial court judgment in part and affirmed it in part. The appellate court reversed the awards to Linde of $18 million in interest and $5 million for fees and other costs. This reversal reduces the judgment amount by approximately $22 million. The appellate court affirmed the damages award to Linde of $21 million. The appellate court remanded the case to the trial court to recompute the prejudgment interest award. Linde filed its petition for review in the Texas Supreme Court on March 17, 2025; Crestwood filed its cross petition on April 30, 2025. In July 2025, the Texas Supreme Court requested responses to the petitions for review from both Linde and Crestwood. On September 26, 2025, the parties resolved and executed a settlement agreement, concluding this matter.
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Twin Oaks Pipeline Litigation
On March 27, 2025, Daniel and Katherine La Hart (“Plaintiffs”) filed a Class Action Complaint against SPLP, Energy Transfer, and Energy Transfer R&M (collectively, “Defendants”) in the Court of Common Pleas of Philadelphia County, captioned Daniel La Hart and Katherine La Hart v. Sunoco Pipeline L.P., Energy Transfer, and Energy Transfer R&M; Case No. 250303655. The action is related to the release of jet fuel (the “Release”) from the 14” Twin-Oaks to Newark Pipeline (the “Pipeline”) in Upper Makefield Township, Bucks County, Pennsylvania. The putative class was defined in the complaint as all “Pennsylvania citizens who owned, rented, and/or resided” in properties “within a one-mile radius” of the location of the Release from “September 1, 2023, to the present.” Excluded from the class definition are homeowners of six properties which are among those properties which have brought individual actions related to the Release. Plaintiffs asserted causes of action for negligence, gross negligence, negligence per se, strict liability/abnormally dangerous/ultrahazardous activity, public nuisance, private nuisance, trespass, negligent infliction of emotional distress and medical monitoring. Plaintiffs sought compensatory damages, punitive damages, declaratory and injunctive relief, and medical monitoring for their alleged exposure to petroleum constituents at their properties and in groundwater.
Defendants removed the case to the U.S. District Court for the Eastern District of Pennsylvania (the “E.D. Pa.”) on April 24, 2025 and filed a motion to dismiss on May 14, 2025. On May 27, 2025, Plaintiffs moved to remand. On June 4, 2025, Plaintiffs amended their complaint (the “Amended Complaint”), consolidating their negligence, negligence per se and gross negligence claims into a single cause of action. On June 13, 2025, the E.D. Pa. granted Plaintiffs’ motion to remand the case to the Court of Common Pleas of Philadelphia County. Defendants have appealed the remand decision.
On June 25, 2025, Defendants filed their preliminary objections to Plaintiffs’ Amended Complaint which included an objection based on improper venue, and on June 27, 2025, Defendants filed a Motion to Transfer the case to the Court of Common Pleas of Bucks County, Pennsylvania on the grounds of forum non conveniens. On July 9, 2025, Plaintiffs filed a Motion for Preliminary Injunction, seeking inter alia, to enjoin the operation of the Pipeline; which Defendants opposed on July 21, 2025. In connection with the venue issues raised by these filings, the Court of Common Pleas has ordered certain discovery, followed by amended pleadings and/or supplemental briefing. Court conferences in the La Hart putative class action as well as individual actions are set for November 20, 2025. Defendants intend to vigorously defend these claims.
State of Oklahoma Attorney General – Winter Storm Uri
On April 10, 2024, the State of Oklahoma, through Attorney General Gentner Drummond, filed a petition on behalf of Grand River Dam Authority against defendants ET Gathering & Processing LLC, successor by merger to Enable Midstream Partners, LP, Enable Oklahoma Intrastate Transmission, LLC, Enable Gas Transmission, LLC and Enable Energy Resources, LLC arising out of Winter Storm Uri in February 2021. Specifically, plaintiff alleges that defendants violated the Oklahoma Antitrust Reform Act (79 O.S. §201, et. seq.) by acting individually and in concert with each other to unreasonably restrain trade in the natural gas market in Oklahoma during the storm. Plaintiff also alleges causes of action for breach of contract, unjust enrichment, fraud, bad faith, conspiracy and negligence. Plaintiff’s petition seeks actual damages, punitive damages, treble damages and attorneys’ fees and costs. However, the actual amount sought was not specified.
On June 3, 2024, defendants filed a Motion to Dismiss and a Motion to Transfer Venue, along with a Brief in Support. In its Motion to Dismiss, defendants argued that plaintiff’s petition fails to state a claim upon which relief can be granted and also that such claims should be dismissed because collateral estoppel bars plaintiff from bringing allegations inconsistent with earlier agency and judicial findings that the extreme cold weather—not defendants’ conduct—caused the natural gas shortage and resulting high prices during Winter Storm Uri. Defendants also argued that plaintiff’s suit should be dismissed for filing suit in the wrong forum or, alternatively, should be transferred to the correct county of venue (Oklahoma County). Plaintiff filed its response brief on July 12, 2024. A hearing on both motions was held on October 15, 2024. On January 16, 2025, the Judge denied all motions, noting (1) that venue is proper in Osage County, Oklahoma; (2) collateral estoppel does not bar recovery; (3) the plaintiffs can plead inconsistent theories of recovery; and (4) the recovery is public in nature and not foreclosed by statute of limitations. The case will now proceed into the discovery phase.
In a separate matter filed on January 9, 2025, the State of Oklahoma through Gentner Drummond, Attorney General of Oklahoma (“Plaintiff”), filed a petition against ETC Marketing Ltd. and ETC Marketing Inc. (collectively, “ETCM”) and other natural gas marketers in Case No. CJ-25-06 in the District Court of Osage County, Oklahoma, arising out of Winter Storm Uri in February 2021. The Oklahoma Attorney General brought this action on behalf of its state agencies, political subdivisions and the people of the State of Oklahoma. Specifically, Plaintiff alleges that the defendants violated the Oklahoma Antitrust Reform Act (79 O.S. §201, et. seq.) by acting individually and in concert with each other to unreasonably restrain trade in the natural gas market in Oklahoma during the storm. Plaintiff also alleges causes of action for unjust enrichment and violation of the Oklahoma Consumer Protection Act. Plaintiff’s petition seeks damages in excess
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of $75,000, including actual damages, punitive damages, treble damages, and attorneys’ fees and costs. However, the actual amount sought was not specified.
On March 17, 2025, all defendants (including ETCM) jointly filed a motion to dismiss and brief in support. In the joint motion to dismiss, defendants asserted that FERC’s exclusive jurisdiction preempts all the Attorney General’s state-law claims and, alternatively, that the petition does not state a claim under Oklahoma antitrust law. Further, the motion argues that the Oklahoma Consumer Protection Act claims are time-barred and inconsistent with the statute, and that the unjust enrichment claims are barred by Oklahoma law. Finally, the motion alleges that the Attorney General’s unjust enrichment claims fail as a matter of law because defendants sold natural gas pursuant to valid contracts and the individual consumers were not direct purchasers of natural gas from defendants. On August 19, 2025, the court denied the motion without holding oral argument. The case will now proceed into the discovery phase.
Defendants cannot predict the ultimate outcome of this litigation but will vigorously defend against these claims.
Tax Contingencies
Internal Revenue Service Audits
The Partnership’s 2020 U.S. Federal income tax return is currently under examination by the Internal Revenue Service (“IRS”). In general, Energy Transfer and its subsidiaries are no longer subject to examination by the IRS, and most state tax authorities, for the 2019 and prior tax years.
USAC is currently under examination by the IRS for years 2019 and 2020. The IRS has issued preliminary partnership examination changes, resulting in imputed underpayment computations of approximately $30 million, including interest, for the 2019 and 2020 tax years. Under the Bipartisan Budget Act of 2015, there are several procedural steps to complete before a final imputed underpayment, if any, is determined. Based on discussions with the IRS, USAC has accrued $3 million, which USAC believes is a reasonable estimate of the potential loss from the aggregate final imputed underpayment for the years 2019 and 2020. However, USAC’s final imputed underpayment, if any, has not been determined. Once determined, USAC’s general partner may either elect to pay the imputed underpayment, if any, (including any applicable penalties and interest) directly to the IRS or, if eligible, issue a revised information statement to each unitholder, or former unitholder as applicable, of USAC with respect to an audited and adjusted return.
Sunoco LP New York Motor Fuel Excise Tax Audit
New York State issued a motor fuel excise tax assessment to Sunoco LLC, a wholly owned subsidiary of Sunoco LP, in the amount of approximately $20 million, exclusive of penalties and interest, for the periods of March 2017 through May 2020. Sunoco LLC intends to pursue all available avenues of appeal and contest the full amount of the assessment. Sunoco LLC cannot predict the outcome of this matter at this time.
Environmental Matters
Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, natural resource damages, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on our results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
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Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.
Environmental Remediation
Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
•Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of polychlorinated biphenyls (“PCBs”). PCB assessments are ongoing and, in some cases, our subsidiaries could be contractually responsible for contamination caused by other parties.
•Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
•Legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that the Partnership no longer operates, closed and/or sold refineries and other formerly owned sites.
•The Partnership is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of September 30, 2025, the Partnership had been named as a PRP at approximately 31 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. The Partnership is usually one of a number of companies identified as a PRP at a site. The Partnership has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon the Partnership’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.
To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.
The following table reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.

| September 30, 2025 |  | December 31, 2024
Current | $ | 59 |  |  | $ | 51 |
Non-current | 212 |  |  | 227 |
Total environmental liabilities | $ | 271 |  |  | $ | 278 |

We have established a wholly owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
During the nine months ended September 30, 2025 and 2024, the Partnership recorded $26 million and $7 million, respectively, of expenditures related to environmental cleanup programs.
Our pipeline operations are subject to regulation by the U.S. Department of Transportation under PHMSA, pursuant to which PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the results of such testing and assessment could cause us to incur future capital and
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operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
Our operations are also subject to the requirements of the Federal Occupational Safety and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations; however, there is no assurance that such costs will not be material in the future.
11.REVENUE
Disaggregation of Revenue
The Partnership’s consolidated financial statements reflect eight reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure purposes. Note 13 depicts the disaggregation of revenue by segment.
Contract Balances with Customers
The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability.
The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services.
The Partnership recognizes a contract liability if the customer’s payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed minimum fee, but allow customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Additionally, Sunoco LP maintains some franchise agreements requiring dealers to make one-time upfront payments for long-term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license.
The following tables summarize the consolidated activity of our contract liabilities:

| Contract Liabilities
Balance, December 31, 2024 | $ | 759 |
Additions | 838 |
Revenue recognized | (954) |
Balance, September 30, 2025 | $ | 643 |
Balance, December 31, 2023 | $ | 749 |
Additions | 902 |
Revenue recognized | (932) |
Balance, September 30, 2024 | $ | 719 |

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The balances of Sunoco LP’s contract assets and contract liabilities were as follows:

| September 30, 2025 |  | December 31, 2024 |  |
Contract assets | $ | 344 |  |  | $ | 288 |  |  |
Accounts receivable from contracts with customers | 1,246 |  |  | 1,084 |  |  |
Contract liabilities | 37 |  |  | 39 |  |  |

Performance Obligations
At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total contract consideration it expects to be entitled to, to each distinct performance obligation based on a standalone selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component, are considered a single performance obligation. For these types of contacts, only the fixed components of the contracts are included in the following table.
As of September 30, 2025, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $34.22 billion. The Partnership expects to recognize this amount as revenue within the time bands illustrated in the following table:

|  | Years Ending December 31, |  |  |  |
|  | 2025 |  |  |  |  |  |  |  |
|  | (remainder) |  | 2026 |  | 2027 |  | Thereafter |  | Total
Revenue expected to be recognized on contracts with customers existing as of September 30, 2025 |  | $ | 2,035 |  |  | $ | 7,409 |  |  | $ | 5,976 |  |  | $ | 18,804 |  |  | $ | 34,224 |

12.DERIVATIVE ASSETS AND LIABILITIES
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.
We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off-peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.
We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales in our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.
We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of natural gas, refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
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We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. These contracts are not designated as hedges for accounting purposes.
We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our intrastate transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our intrastate transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.
The following table details our outstanding commodity-related derivatives:

| September 30, 2025 |  | December 31, 2024
| Notional Volume |  | Maturity |  | Notional Volume |  | Maturity
Mark-to-Market Derivatives |  |  |  |  |  |  |
Natural Gas (BBtu): |  |  |  |  |  |  |
Fixed Swaps/Futures | (21,270) |  |  | 2025-2027 |  | 6,630 |  |  | 2025-2026
Basis Swaps IFERC/NYMEX | 63,445 |  |  | 2025-2028 |  | 3,490 |  |  | 2025-2027
Swing Swaps | (142,195) |  |  | 2025-2027 |  | (156,820) |  |  | 2025-2027
Power (Megawatt): |  |  |  |  |  |  |
Forwards | 50,800 |  |  | 2025-2029 |  | 6,040 |  |  | 2025-2029
Futures | 62,209 |  |  | 2025-2027 |  | (140,137) |  |  | 2025-2026
Options – Puts | 30,400 |  |  | 2025-2026 |  | (17,600) |  |  | 2025
Options – Calls | (500,000) |  |  | 2025-2026 |  | — |  |  | —
Crude (MBbls): |  |  |  |  |  |  |
Forwards/Swaps | (20,494) |  |  | 2025-2027 |  | (22,512) |  |  | 2025-2026
NGL/Refined Products (MBbls): |  |  |  |  |  |  |
Forward/Swaps | (20,129) |  |  | 2025-2028 |  | (15,063) |  |  | 2025-2027
Options – Puts | 6 |  |  | 2025-2026 |  | (9) |  |  | 2025-2026
Options – Calls | (1) |  |  | 2025-2026 |  | (14) |  |  | 2025-2026
Futures | (5,442) |  |  | 2025-2026 |  | (1,763) |  |  | 2025-2026
Fair Value Hedging Derivatives |  |  |  |  |  |  |
Natural Gas (BBtu): |  |  |  |  |  |  |
Basis Swaps IFERC/NYMEX | (47,840) |  |  | 2025-2026 |  | (47,170) |  |  | 2025
Fixed Swaps/Futures | (47,840) |  |  | 2025-2026 |  | (47,170) |  |  | 2025
Hedged Item – Inventory | 47,840 |  |  | 2025-2026 |  | 44,170 |  |  | 2025

Credit Risk
Credit risk refers to the risk that a counterparty may default on its contractual obligations, resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
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Our natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. In addition to oil and gas producers, the Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily with independent system operators and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments is deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.
Derivative Summary
The following table provides a summary of our derivative assets and liabilities:

|  | Fair Value of Derivative Instruments
|  | Asset Derivatives |  | Liability Derivatives
|  | September 30, 2025 |  | December 31, 2024 |  | September 30, 2025 |  | December 31, 2024
Derivatives designated as hedging instruments: |  |  |  |  |  |  |  |
Commodity derivatives – margin deposits |  | $ | 40 |  |  | $ | 3 |  |  | $ | (17) |  |  | $ | (7) |
|  | 40 |  |  | 3 |  |  | (17) |  |  | (7) |
Derivatives not designated as hedging instruments: |  |  |  |  |  |  |  |
Commodity derivatives – margin deposits |  | 271 |  |  | 209 |  |  | (220) |  |  | (229) |
Commodity derivatives |  | 73 |  |  | 51 |  |  | (68) |  |  | (57) |
|  | 344 |  |  | 260 |  |  | (288) |  |  | (286) |
Total derivatives |  | $ | 384 |  |  | $ | 263 |  |  | $ | (305) |  |  | $ | (293) |

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:

|  |  |  | Asset Derivatives |  | Liability Derivatives
|  | Balance Sheet Location |  | September 30, 2025 |  | December 31, 2024 |  | September 30, 2025 |  | December 31, 2024
Derivatives in offsetting agreements: |  |  |  |  |  |  |  |
OTC contracts |  | Derivative assets (liabilities) |  | $ | 73 |  |  | $ | 51 |  |  | $ | (68) |  |  | $ | (57) |
Broker cleared derivative contracts |  | Other current assets (liabilities) |  | 311 |  |  | 212 |  |  | (237) |  |  | (236) |
Total gross derivatives |  | 384 |  |  | 263 |  |  | (305) |  |  | (293) |
Offsetting agreements: |  |  |  |  |  |  |  |
Counterparty netting |  | Derivative assets (liabilities) |  | (53) |  |  | (42) |  |  | 53 |  |  | 42 |
Counterparty netting |  | Other current assets (liabilities) |  | (233) |  |  | (204) |  |  | 233 |  |  | 204 |
Total net derivatives |  | $ | 98 |  |  | $ | 17 |  |  | $ | (19) |  |  | $ | (47) |

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We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.
The following table summarizes the location and amounts recognized in our consolidated statements of operations with respect to our derivative financial instruments:

| Location of Gain (Loss) Recognized on Income on Derivatives |  | Amount of Gain (Loss) Recognized in Income on Derivatives
|  |  | Three Months Ended September 30, |  | Nine Months Ended September 30,
|  | 2025 |  | 2024 |  | 2025 |  | 2024
Derivatives not designated as hedging instruments: |  |  |  |  |  |  |  |  |
Commodity derivatives | Cost of products sold |  | $ | 10 |  |  | $ | 163 |  |  | $ | 114 |  |  | $ | 148 |
Interest rate derivative(1) | Gain (loss) on interest rate derivative |  | — |  |  | (6) |  |  | — |  |  | 6 |
Total |  |  | $ | 10 |  |  | $ | 157 |  |  | $ | 114 |  |  | $ | 154 |

(1)This interest rate derivative was terminated by USAC in August 2024.
13.REPORTABLE SEGMENTS
Our reportable segments, which conduct their business primarily in the U.S., are as follows:
•intrastate transportation and storage;
•interstate transportation and storage;
•midstream;
•NGL and refined products transportation and services;
•crude oil transportation and services;
•investment in Sunoco LP;
•investment in USAC; and
•all other.
Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.
Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL and refined products transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our crude oil transportation and services segment are primarily reflected in crude sales. Revenues from our investment in Sunoco LP segment are primarily reflected in refined product sales and, subsequent to Sunoco LP’s acquisition of NuStar in May 2024, also in gathering, transportation and other fees. Revenues from our investment in USAC segment are primarily reflected in gathering, transportation and other fees. Revenues from our all other segment are primarily reflected in natural gas sales and gathering, transportation and other fees.
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.
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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.
The following tables present financial information by segment:

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Revenues: |  |  |  |  |  |  |
Intrastate transportation and storage: |  |  |  |  |  |  |
Revenues from external customers | $ | 773 |  |  | $ | 622 |  |  | $ | 2,739 |  |  | $ | 2,010 |
Intersegment revenues | 96 |  |  | 56 |  |  | 355 |  |  | 223 |
| 869 |  |  | 678 |  |  | 3,094 |  |  | 2,233 |
Interstate transportation and storage: |  |  |  |  |  |  |
Revenues from external customers | 595 |  |  | 568 |  |  | 1,792 |  |  | 1,676 |
Intersegment revenues | 8 |  |  | 7 |  |  | 22 |  |  | 20 |
| 603 |  |  | 575 |  |  | 1,814 |  |  | 1,696 |
Midstream: |  |  |  |  |  |  |
Revenues from external customers | 819 |  |  | 1,064 |  |  | 2,560 |  |  | 2,646 |
Intersegment revenues | 2,173 |  |  | 1,694 |  |  | 7,223 |  |  | 5,393 |
| 2,992 |  |  | 2,758 |  |  | 9,783 |  |  | 8,039 |
NGL and refined products transportation and services: |  |  |  |  |  |  |
Revenues from external customers | 4,919 |  |  | 5,017 |  |  | 15,982 |  |  | 15,598 |
Intersegment revenues | 934 |  |  | 836 |  |  | 2,721 |  |  | 2,576 |
| 5,853 |  |  | 5,853 |  |  | 18,703 |  |  | 18,174 |
Crude oil transportation and services: |  |  |  |  |  |  |
Revenues from external customers | 6,043 |  |  | 7,294 |  |  | 17,996 |  |  | 22,294 |
Intersegment revenues | — |  |  | 15 |  |  | 3 |  |  | 25 |
| 6,043 |  |  | 7,309 |  |  | 17,999 |  |  | 22,319 |
Investment in Sunoco LP: |  |  |  |  |  |  |
Revenues from external customers | 6,023 |  |  | 5,738 |  |  | 16,586 |  |  | 17,406 |
Intersegment revenues | 9 |  |  | 13 |  |  | 15 |  |  | 18 |
| 6,032 |  |  | 5,751 |  |  | 16,601 |  |  | 17,424 |
Investment in USAC: |  |  |  |  |  |  |
Revenues from external customers | 234 |  |  | 227 |  |  | 698 |  |  | 680 |
Intersegment revenues | 17 |  |  | 13 |  |  | 48 |  |  | 25 |
| 251 |  |  | 240 |  |  | 746 |  |  | 705 |
All other: |  |  |  |  |  |  |
Revenues from external customers | 548 |  |  | 242 |  |  | 1,863 |  |  | 820 |
Intersegment revenues | 375 |  |  | 137 |  |  | 991 |  |  | 320 |
| 923 |  |  | 379 |  |  | 2,854 |  |  | 1,140 |
Eliminations | (3,612) |  |  | (2,771) |  |  | (11,378) |  |  | (8,600) |
Total revenues | $ | 19,954 |  |  | $ | 20,772 |  |  | $ | 60,216 |  |  | $ | 63,130 |

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| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Cost of products sold: |  |  |  |  |  |  |
Intrastate transportation and storage | $ | 546 |  |  | $ | 272 |  |  | $ | 2,071 |  |  | $ | 964 |
Interstate transportation and storage | 3 |  |  | 3 |  |  | 8 |  |  | 6 |
Midstream | 1,746 |  |  | 1,551 |  |  | 5,917 |  |  | 4,727 |
NGL and refined products transportation and services | 4,493 |  |  | 4,527 |  |  | 14,769 |  |  | 14,358 |
Crude oil transportation and services | 5,047 |  |  | 6,297 |  |  | 14,986 |  |  | 19,200 |
Investment in Sunoco LP | 5,386 |  |  | 5,327 |  |  | 14,733 |  |  | 15,951 |
Investment in USAC | 34 |  |  | 38 |  |  | 112 |  |  | 110 |
All other | 895 |  |  | 369 |  |  | 2,799 |  |  | 1,107 |
Eliminations | (3,588) |  |  | (2,772) |  |  | (11,316) |  |  | (8,605) |
Total cost of products sold | $ | 14,562 |  |  | $ | 15,612 |  |  | $ | 44,079 |  |  | $ | 47,818 |

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses: |  |  |  |  |  |  |
Intrastate transportation and storage | $ | 72 |  |  | $ | 61 |  |  | $ | 190 |  |  | $ | 180 |
Interstate transportation and storage | 271 |  |  | 203 |  |  | 681 |  |  | 616 |
Midstream | 459 |  |  | 411 |  |  | 1,296 |  |  | 1,055 |
NGL and refined products transportation and services | 294 |  |  | 243 |  |  | 771 |  |  | 703 |
Crude oil transportation and services | 243 |  |  | 231 |  |  | 693 |  |  | 635 |
Investment in Sunoco LP | 180 |  |  | 168 |  |  | 500 |  |  | 423 |
Investment in USAC | 43 |  |  | 43 |  |  | 133 |  |  | 125 |
All other | 17 |  |  | 20 |  |  | 18 |  |  | 28 |
Eliminations | (65) |  |  | (47) |  |  | (158) |  |  | (88) |
Total operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses | $ | 1,514 |  |  | $ | 1,333 |  |  | $ | 4,124 |  |  | $ | 3,677 |

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Depreciation, depletion and amortization: |  |  |  |  |  |  |
Intrastate transportation and storage | $ | 52 |  |  | $ | 54 |  |  | $ | 154 |  |  | $ | 161 |
Interstate transportation and storage | 144 |  |  | 145 |  |  | 427 |  |  | 431 |
Midstream | 457 |  |  | 429 |  |  | 1,364 |  |  | 1,252 |
NGL and refined products transportation and services | 249 |  |  | 267 |  |  | 745 |  |  | 779 |
Crude oil transportation and services | 294 |  |  | 252 |  |  | 775 |  |  | 738 |
Investment in Sunoco LP | 159 |  |  | 95 |  |  | 469 |  |  | 216 |
Investment in USAC | 71 |  |  | 67 |  |  | 212 |  |  | 196 |
All other | 14 |  |  | 15 |  |  | 45 |  |  | 18 |
Total depreciation, depletion and amortization | $ | 1,440 |  |  | $ | 1,324 |  |  | $ | 4,191 |  |  | $ | 3,791 |

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| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Selling, general and administrative expenses, excluding non-cash compensation and accretion expenses: |  |  |  |  |  |  |
Intrastate transportation and storage | $ | 12 |  |  | $ | 11 |  |  | $ | 36 |  |  | $ | 37 |
Interstate transportation and storage | 29 |  |  | 34 |  |  | 92 |  |  | 99 |
Midstream | 48 |  |  | 57 |  |  | 151 |  |  | 144 |
NGL and refined products transportation and services | 41 |  |  | 42 |  |  | 130 |  |  | 118 |
Crude oil transportation and services | 36 |  |  | 39 |  |  | 118 |  |  | 111 |
Investment in Sunoco LP | 47 |  |  | 52 |  |  | 130 |  |  | 216 |
Investment in USAC | 14 |  |  | 13 |  |  | 42 |  |  | 42 |
All other | 11 |  |  | 23 |  |  | 37 |  |  | 43 |
Total selling, general and administrative expenses, excluding non-cash compensation and accretion expenses | $ | 238 |  |  | $ | 271 |  |  | $ | 736 |  |  | $ | 810 |

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Equity in earnings of unconsolidated affiliates(1): |  |  |  |  |  |  |
Intrastate transportation and storage | $ | 4 |  |  | $ | 5 |  |  | $ | 12 |  |  | $ | 13 |
Interstate transportation and storage | 73 |  |  | 67 |  |  | 208 |  |  | 180 |
Midstream | 8 |  |  | 2 |  |  | 14 |  |  | 10 |
NGL and refined products transportation and services | 22 |  |  | 22 |  |  | 59 |  |  | 61 |
Crude oil transportation and services | 8 |  |  | 5 |  |  | 17 |  |  | 18 |
All other | 1 |  |  | 1 |  |  | 3 |  |  | 3 |
Total equity in earnings of unconsolidated affiliates | $ | 116 |  |  | $ | 102 |  |  | $ | 313 |  |  | $ | 285 |

(1)Amounts reflected above exclude Sunoco LP’s earnings from the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Other income (expense)(1): |  |  |  |  |  |  |
Intrastate transportation and storage | $ | (9) |  |  | $ | (5) |  |  | $ | 61 |  |  | $ | 43 |
Interstate transportation and storage | 131 |  |  | 125 |  |  | 380 |  |  | 360 |
Midstream | 12 |  |  | 77 |  |  | 25 |  |  | 92 |
NGL and refined products transportation and services | 29 |  |  | (29) |  |  | 32 |  |  | 76 |
Crude oil transportation and services | 29 |  |  | 26 |  |  | 18 |  |  | 44 |
Investment in Sunoco LP | 70 |  |  | 252 |  |  | 163 |  |  | 184 |
Investment in USAC | — |  |  | — |  |  | — |  |  | 1 |
All other | (8) |  |  | 4 |  |  | 5 |  |  | 27 |
Eliminations | (56) |  |  | (47) |  |  | (159) |  |  | (53) |
Total other income | $ | 198 |  |  | $ | 403 |  |  | $ | 525 |  |  | $ | 774 |

(1)Other income and expense include, if applicable to a segment, Adjusted EBITDA related to unconsolidated affiliates, unrealized gains and losses on commodity risk management activities and other items. For the investment in Sunoco LP segment, this also includes inventory valuation adjustments.
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| September 30, 2025 |  | December 31, 2024
Segment assets: |  |  |
Intrastate transportation and storage | $ | 6,840 |  |  | $ | 6,289 |
Interstate transportation and storage | 17,262 |  |  | 17,656 |
Midstream | 27,613 |  |  | 30,473 |
NGL and refined products transportation and services | 26,701 |  |  | 27,445 |
Crude oil transportation and services | 28,525 |  |  | 25,231 |
Investment in Sunoco LP | 17,845 |  |  | 14,375 |
Investment in USAC | 2,659 |  |  | 2,746 |
All other and eliminations | 1,886 |  |  | 1,165 |
Total segment assets | $ | 129,331 |  |  | $ | 125,380 |

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Additions to property, plant and equipment(1): |  |  |  |  |  |  |
Intrastate transportation and storage | $ | 431 |  |  | $ | 4 |  |  | $ | 930 |  |  | $ | 50 |
Interstate transportation and storage | 110 |  |  | 115 |  |  | 235 |  |  | 232 |
Midstream | 416 |  |  | 444 |  |  | 1,149 |  |  | 825 |
NGL and refined products transportation and services | 328 |  |  | 375 |  |  | 1,076 |  |  | 929 |
Crude oil transportation and services | 115 |  |  | 103 |  |  | 272 |  |  | 283 |
Investment in Sunoco LP | 157 |  |  | 93 |  |  | 418 |  |  | 212 |
Investment in USAC | 47 |  |  | 43 |  |  | 110 |  |  | 230 |
All other | 34 |  |  | 42 |  |  | 188 |  |  | 112 |
Total additions to property, plant and equipment | $ | 1,638 |  |  | $ | 1,219 |  |  | $ | 4,378 |  |  | $ | 2,873 |

(1)Amounts are presented on the accrual basis, net of contributions in aid of constructions costs. Amounts exclude acquisitions and include only the Partnership’s proportionate share of capital expenditures related to joint ventures.

| September 30, 2025 |  | December 31, 2024
Investments in unconsolidated affiliates(1): |  |  |
Intrastate transportation and storage | $ | 151 |  |  | $ | 150 |
Interstate transportation and storage | 2,367 |  |  | 2,350 |
Midstream | 133 |  |  | 132 |
NGL and refined products transportation and services | 367 |  |  | 383 |
Crude oil transportation and services | 191 |  |  | 193 |
All other | 60 |  |  | 58 |
Total investments in unconsolidated affiliates | $ | 3,269 |  |  | $ | 3,266 |

(1)Amounts reflected above exclude Sunoco LP’s investments in the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.
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| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Segment Adjusted EBITDA: |  |  |  |  |  |  |
Intrastate transportation and storage | $ | 230 |  |  | $ | 329 |  |  | $ | 858 |  |  | $ | 1,095 |
Interstate transportation and storage | 431 |  |  | 460 |  |  | 1,413 |  |  | 1,335 |
Midstream | 751 |  |  | 816 |  |  | 2,444 |  |  | 2,205 |
NGL and refined products transportation and services | 1,054 |  |  | 1,012 |  |  | 3,065 |  |  | 3,071 |
Crude oil transportation and services | 746 |  |  | 768 |  |  | 2,220 |  |  | 2,417 |
Investment in Sunoco LP | 489 |  |  | 456 |  |  | 1,401 |  |  | 1,018 |
Investment in USAC | 160 |  |  | 146 |  |  | 459 |  |  | 429 |
All other | (23) |  |  | (28) |  |  | (58) |  |  | 29 |
Adjusted EBITDA (consolidated) | $ | 3,838 |  |  | $ | 3,959 |  |  | $ | 11,802 |  |  | $ | 11,599 |

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Reconciliation of net income to Adjusted EBITDA: |  |  |  |  |  |  |
Net income | $ | 1,292 |  |  | $ | 1,434 |  |  | $ | 4,470 |  |  | $ | 5,118 |
Depreciation, depletion and amortization | 1,440 |  |  | 1,324 |  |  | 4,191 |  |  | 3,791 |
Interest expense, net of interest capitalized | 890 |  |  | 828 |  |  | 2,564 |  |  | 2,318 |
Income tax expense | 87 |  |  | 89 |  |  | 207 |  |  | 405 |
Impairment losses | 1 |  |  | — |  |  | 8 |  |  | 50 |
(Gain) loss on interest rate derivative | — |  |  | 6 |  |  | — |  |  | (6) |
Non-cash compensation expense | 40 |  |  | 37 |  |  | 110 |  |  | 113 |
Unrealized (gains) losses on commodity risk management activities | (1) |  |  | (53) |  |  | (32) |  |  | 50 |
Inventory valuation adjustments (Sunoco LP) | (10) |  |  | 197 |  |  | (31) |  |  | 99 |
Losses on extinguishments of debt | 12 |  |  | — |  |  | 31 |  |  | 11 |
Adjusted EBITDA related to unconsolidated affiliates | 193 |  |  | 181 |  |  | 542 |  |  | 522 |
Equity in earnings of unconsolidated affiliates | (116) |  |  | (102) |  |  | (313) |  |  | (285) |
Gain on sale of West Texas assets (Sunoco LP) | — |  |  | — |  |  | — |  |  | (598) |
Other, net | 10 |  |  | 18 |  |  | 55 |  |  | 11 |
Adjusted EBITDA (consolidated) | $ | 3,838 |  |  | $ | 3,959 |  |  | $ | 11,802 |  |  | $ | 11,599 |

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ITEM 2. 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 LP acquired 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.
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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.
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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.
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On December 17, 2020, FERC issued an order establishing a new index of PPI-FG plus 0.78%. The FERC received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG minus 0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period July 1, 2022 to June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the January 20 order with FERC, which was denied by FERC on May 6, 2022. Certain parties appealed the January 20 and May 6 orders. On July 26, 2024, the D.C. Circuit ruled in LEPA v. FERC that FERC violated the Administrative Procedure Act because the January 20 order modified the index without following notice and comment. As a result, the D.C. Circuit vacated the January 20 order and on September 17, 2024, the Commission reinstated the index level established by its original December 17 order, directed pipelines to file an informational filing to show their recomputed ceiling levels reflecting the reinstated index level and stated that pipelines may file to prospectively increase their indexed rates to their recomputed levels. On October 17, 2024, FERC issued a Supplemental 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.
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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

| Three Months Ended September 30, |  |  |  | Nine Months Ended September 30, |  |
| 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 |

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| Three Months Ended September 30, |  |  |  | Nine Months Ended September 30, |  |
| 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.
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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 and Equity 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.
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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, |  |
| 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 and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.
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•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, |  |
| 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.
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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, |  |
| 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.
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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.
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Midstream

| Three Months Ended September 30, |  |  |  | Nine Months Ended September 30, |  |
| 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;
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•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.
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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.
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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.
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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.
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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.
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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.
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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
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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.
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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.
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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
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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
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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;
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•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;
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•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.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II - Item 7A 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, in addition to the accompanying notes and management’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2024. Since December 31, 2024, there have been no material changes to our primary market risk exposures or how those exposures are managed.
Commodity Price Risk
The following table summarizes our commodity-related financial derivative instruments and fair values, including derivatives related to our consolidated subsidiaries, as well as the effect of an assumed hypothetical 10% change in the underlying price of the commodity. Dollar amounts are presented in millions.

| September 30, 2025 |  | December 31, 2024
| Notional Volume |  | Fair Value Asset (Liability) |  | Effect of Hypothetical 10% Change |  | Notional Volume |  | Fair Value Asset (Liability) |  | Effect of Hypothetical 10% Change
Mark-to-Market Derivatives |  |  |  |  |  |  |  |  |  |  |
Natural Gas (BBtu): |  |  |  |  |  |  |  |  |  |  |
Fixed Swaps/Futures | (21,270) |  |  | $ | 12 |  |  | $ | 8 |  |  | 6,630 |  |  | $ | 5 |  |  | $ | 3 |
Basis Swaps IFERC/NYMEX | 63,445 |  |  | (2) |  |  | — |  |  | 3,490 |  |  | (6) |  |  | 3 |
Swing Swaps IFERC | (142,195) |  |  | 1 |  |  | 1 |  |  | (156,820) |  |  | (7) |  |  | 1 |
Power (Megawatt): |  |  |  |  |  |  |  |  |  |  |
Forwards | 50,800 |  |  | 1 |  |  | — |  |  | 6,040 |  |  | 1 |  |  | — |
Futures | 62,209 |  |  | — |  |  | 2 |  |  | (140,137) |  |  | 1 |  |  | 1 |
Options – Puts | 30,400 |  |  | — |  |  | — |  |  | (17,600) |  |  | — |  |  | — |
Options – Calls | (500,000) |  |  | — |  |  | 1 |  |  | — |  |  | — |  |  | — |
Crude (MBbls): |  |  |  |  |  |  |  |  |  |  |
Forwards/Swaps | (20,494) |  |  | (3) |  |  | 14 |  |  | (22,512) |  |  | (10) |  |  | 39 |
NGL/Refined Products (MBbls): |  |  |  |  |  |  |  |  |  |  |
Forwards/Swaps | (20,129) |  |  | 56 |  |  | 84 |  |  | (15,063) |  |  | (4) |  |  | 58 |
Options – Puts | 6 |  |  | — |  |  | — |  |  | (9) |  |  | — |  |  | — |
Options – Calls | (1) |  |  | — |  |  | — |  |  | (14) |  |  | — |  |  | — |
Futures | (5,442) |  |  | (10) |  |  | 58 |  |  | (1,763) |  |  | (7) |  |  | 13 |
Fair Value Hedging Derivatives |  |  |  |  |  |  |  |  |  |  |
Natural Gas (BBtu): |  |  |  |  |  |  |  |  |  |  |
Basis Swaps IFERC/NYMEX | (47,840) |  |  | (6) |  |  | 2 |  |  | (47,170) |  |  | 1 |  |  | 2 |
Fixed Swaps/Futures | (47,840) |  |  | 30 |  |  | 17 |  |  | (47,170) |  |  | (4) |  |  | 15 |

The fair values of the commodity-related financial positions have been determined using independent third-party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.
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Interest Rate Risk
As of September 30, 2025, we and our subsidiaries had $2.20 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $22 million annually.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
Under the supervision and with the participation of senior management, including the Co-Chief Executive Officers (Co-Principal Executive Officers) and the Chief Financial Officer (Principal Financial Officer) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Co-Principal Executive Officers and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of September 30, 2025 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including the Co-Principal Executive Officers and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended September 30, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For information regarding legal proceedings, see our Annual Report on Form 10-K filed with the SEC on February 14, 2025 and Note 10 in “Item 1. Financial Statements” in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2025.
Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the following environmental proceedings were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report governmental proceedings if we reasonably believe that such proceedings could result in monetary sanctions in excess of $1 million.
On January 31, 2025, a release of refined products was discovered from the 14-inch Twin-Oaks to Newark Pipeline in Upper Makefield Township, Bucks County, Pennsylvania. The release allegedly impacted certain properties and water wells near the release location. On February 13, 2025, SPLP voluntarily entered into the Pennsylvania remediation program through a Notice of Intent to Remediate, which was revised on March 4, 2025. On March 6, 2025, the Pennsylvania Department of Environmental Protection issued an Administrative Order directing that SPLP conduct the remediation. On May 2, 2025, PHMSA entered a Consent Order, adopting an agreement SPLP entered into with PHMSA on April 30, 2025. Finally, on April 9, 2025, SPLP was advised that the Bucks County District Attorney’s Office has referred the matter to the Pennsylvania Attorney General’s Office, Environmental Crimes Unit. The Attorney General’s Office has accepted the referral and opened an investigation. Potential charges, penalties or damages are not known at this time. PHMSA issued a Warning Letter to the Partnership on September 11, 2025 alleging certain violations of the Consent Order but stating that it would not conduct additional enforcement action at this time.
On February 3, 2022, the State of New Mexico, ex rel. Hector Balderas, Attorney General filed a complaint against ETO, Transwestern, Kinder Morgan, Inc., El Paso Natural Gas L.L.C. and Northwest Pipeline, LLC in Cause No. D-101-CV-2022-00174 in the First Judicial District Court, County of Santa Fe, State of New Mexico, seeking to recover statewide damages for contamination with PCBs used for decades by the oil and gas industry in the operation and maintenance of pipeline infrastructure. The complaint alleged discharge or release of PCBs into the natural environment from compressor stations in connection with the operation of Transwestern. The State sought damages in the range of $50 million to $60 million plus the attorneys’ fees from Transwestern. The parties agreed to a settlement in September 2025.
Pursuant to the instructions to Form 10-Q, matters disclosed in this Part II - Item 1 include any reportable legal proceeding (i) that has been terminated during the period covered by this report, (ii) that became a reportable event during the period covered by this report, or (iii) for which there has been a material development during the period covered by this report.
For additional information required in this Item, see disclosure under the headings “Litigation and Contingencies” and “Environmental Matters” in Note 10 to our consolidated financial statements in “Item 1. Financial Statements,” which information is incorporated by reference into this Item.
ITEM 1A. RISK FACTORS
The following risk factors, certain of which were previously disclosed in our Annual Report on Form 10-K, have been included to reflect updates based on recent developments. These risk factors should be read in conjunction with risk factors described 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.
Sunoco LP’s investment in the Burnaby Refinery is subject to operational risks, including commodity price and pricing pressure and environment, health and safety hazards. If any of the operational risks materialize, our financial condition or results of operations could be materially and adversely affected.
Following the Parkland acquisition, Sunoco LP will own and operate a refinery located in Burnaby, British Columbia (the “Burnaby Refinery”), which produces and supplies fuel within the Lower Mainland in Canada.
Key operational risks at the Burnaby Refinery include: supply disruptions of crude oil and bio-feedstocks, product offtake contract issues or interruptions, operational availability, labor and material shortages, compliance with regulatory requirements and local community opposition. Major accidents could cause significant damage and may result in operational interruptions, loss of licenses, fines, reputational damage, injuries or fatalities. Large amounts of power, heat by way of natural gas and large volumes of water are used to refine crude oil, the supply of which is not in our control, and even a temporary interruption of
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power, natural gas or water could adversely affect continuous operations. Unanticipated costs and delays during maintenance may negatively impact Sunoco LP’s operational results. Scheduled and unscheduled maintenance and repairs at the Burnaby Refinery may reduce revenue and increase Sunoco LP’s operating costs, impacting our financial and operational results.
Additionally, Sunoco LP contracts with third parties for the supply of crude oil and other feedstock to the Burnaby Refinery. Crude oil sourced by the Burnaby Refinery is delivered from Alberta by the Trans Mountain Pipeline (“TMPL”). Interruptions or apportionment on the TMPL’s pipeline system can result in Sunoco LP temporarily ceasing or decreasing processing operations at the Burnaby Refinery and may materially affect our business, financial condition and results of operations. The Burnaby Refinery could see variability in its crude deliveries as the capacity on the pipeline fluctuates from time to time, which can impact committed as well as uncommitted linespace, based on operating conditions and planned and/or unplanned maintenance. In addition to the TMPL line capacity, extreme or unexpected weather events may affect the operation of the TMPL. Significant operational delays, changes in tariffs and unanticipated costs could adversely impact the refinery.
Refining gross margins are primarily driven by commodity prices and are a function of the difference between the costs of feedstock (primarily crude oil) and the market prices for the marketing of finished products (such as gasoline, diesel, jet fuel, lubricants, fuel oil and fuel and lubricant additives). Prices for commodities are determined by global and regional marketplaces and are influenced by many factors, including supply and demand balances, inventory levels, industry refinery operations, import and export balances, currency fluctuations, seasonal demand, political climate, disruptions at the refinery resulting from unplanned outages due to severe weather, fires or other operational events and plant capacity utilization. Sustained low refining margins may have an adverse effect on our revenue, profitability and ability to service debt and pay distributions.
The Burnaby Refinery faces hazards related to hydrocarbon supply and processing, including, but not limited to, fires, explosions, railcar or marine vessel incidents, oil spills, migration of harmful substances, corrosion, vandalism, terrorism and other accidents that may occur at or during transport to or from sites. The consequences of an accidental spill or release at or near any marine terminal used in connection with Sunoco LP’s operations could be significant, given the complexities of addressing releases occurring in marine environments or along populated coastlines. Such incidents could result in significant disruptions to offshore shipping activities and impede Sunoco LP’s ability to operate in any affected areas.
These hazards may interrupt operations, cause injuries or fatalities, cause loss of or damage to equipment, property, information technology or control systems, and data, or result in environmental damage that may include pollution of water, land or air. The consequences could expose Sunoco LP to business interruptions, potential liabilities, modifications to or revocation of existing regulatory approvals, fines and other environmental damages, or reputational impacts.
Sunoco LP faces a variety of risks related to its entry into the refinery business following the completion of the Parkland acquisition.
Entry into a new line of business may also subject Sunoco LP to new laws and regulations with which it is not familiar and may lead to increased litigation and regulatory risk. Further, Sunoco LP’s management team has not engaged in the refinery operations business in recent years, and Sunoco LP’s lack of recent experience may result in delays or further complications to its new business and increases its dependence upon former Parkland employees that have experience in the field. If Sunoco LP is unable to successfully implement the acquired business of Parkland, in particular, the Burnaby Refinery, Sunoco LP’s revenue and profitability may not grow as expected, its competitiveness may be materially and adversely affected, and its reputation and business may be harmed.
Our operations (including Sunoco LP’s) are subject to federal, state and local laws and regulations, in the U.S., in Canada, in Mexico, in the Greater Caribbean and in Europe, relating to the environment, health, safety and security that require it to make substantial expenditures.
Our operations are subject to increasingly stringent international, federal, state and local environmental, health, safety and security laws and regulations, including those relating to: terminals and underground storage tanks; the release or discharge of regulated materials into the air, water and soil; the generation, storage, handling, use, transportation and disposal of hazardous materials; the exposure of persons to regulated materials; and the health and safety of our employees. A violation of, liability under, or noncompliance with these laws and regulations, or any future environmental law or regulation, could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to our unitholders.
Regulations under the Clean Water Act, the Oil Pollution Act of 1990 (“OPA 90”) and state laws impose regulatory burdens on terminal operations. Spill prevention control and countermeasure requirements of federal and state laws require containment to mitigate or prevent contamination of waters in the event of a refined product overflow, rupture, or leak from above-ground pipelines and storage tanks. The Clean Water Act also requires us to maintain spill prevention control and countermeasure plans at our terminal facilities with above-ground storage tanks and pipelines. In addition, OPA 90 requires that most fuel transport and storage companies maintain and update various oil spill prevention and oil spill contingency plans. Facilities that are
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adjacent to water require the engagement of Federally Certified Oil Spill Response Organizations to be available to respond to a spill on water from above-ground storage tanks or pipelines.
Transportation and storage of refined products over and adjacent to water involves risk and potentially subjects us to strict, joint and potentially unlimited liability for removal costs and other consequences of an oil spill where the spill is into navigable waters, along shorelines or in the exclusive economic zone of the United States. In the event of an oil spill into navigable waters, substantial liabilities could be imposed upon us. The Clean Water Act imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters, with the potential of substantial liability for the violation of permits or permitting requirements.
Terminal operations and associated facilities are subject to the Clean Air Act as well as comparable state and local statutes. Under these laws, permits may be required before construction can commence on a new source of potentially significant air emissions, and operating permits may be required for sources that are already constructed. If regulations become more stringent, additional emission control technologies may be required at our facilities. Any such future obligation could require us to incur significant additional capital or operating costs. Additionally, permits or licenses may be difficult to obtain and may include public comment and other public involvement periods, which could affect agency considerations or the decisions reached.
Terminal operations are subject to additional programs and regulations under the Occupational Safety and Health Administration. Liability under, or a violation of compliance with, these laws and regulations, or any future laws or regulations, could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to our unitholders.
Pipeline operations are also subject to a number of environmental and safety programs and regulations. Should our operations fail to comply with applicable Department of Transportation or comparable state regulations regarding pipeline safety, we could be subject to substantial fines and penalties. In addition, the adoption of recently proposed or new laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant.
Certain environmental laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), impose strict, and under certain circumstances, joint and several, liability on the current and former owners and operators of properties for the costs of investigation and removal or remediation of contamination and also impose liability for any related damages to natural resources without regard to fault. Under CERCLA and similar state laws, as persons who arrange for the transportation, treatment and disposal of hazardous substances, we may also be subject to liability at sites where such hazardous substances come to be located. We may be subject to third-party claims alleging property damage and/or personal injury in connection with releases of or exposure to hazardous substances at, from or in the vicinity of our current or former properties or off-site waste disposal sites. Costs associated with the investigation and remediation of contamination, as well as associated third-party claims, could be substantial, and could have a material adverse effect on our business, financial condition, results of operations and our ability to service our outstanding indebtedness. In addition, the presence of, or failure to remediate, identified or unidentified contamination at our properties could materially and adversely affect our ability to sell or rent such property or to borrow money using such property as collateral.
We are required to make financial expenditures to comply with regulations governing underground storage tanks as adopted by federal, state and local regulatory agencies. Compliance with existing and future environmental laws regulating underground storage tank systems of the kind we use may require significant capital expenditures. For example, the EPA has previously published rules that amend existing federal underground storage tank rules, requiring certain upgrades to underground storage tanks and related piping to further ensure the detection, prevention, investigation and remediation of leaks and spills.
We are required to comply with federal and state financial responsibility requirements to demonstrate that we have the ability to pay for cleanups or to compensate third parties for damages incurred as a result of a release of regulated materials from our underground storage tank systems. We seek to comply with these requirements by maintaining insurance that we purchase from private insurers and in certain circumstances, rely on applicable state trust funds, which are funded by underground storage tank registration fees and taxes on wholesale purchases of motor fuels. Coverage afforded by each fund varies and is dependent upon the continued maintenance and solvency of each fund.
We are responsible for investigating and remediating contamination at a number of our current and former properties. We are entitled to reimbursement for certain of these costs under various third-party contractual indemnities and insurance policies, subject to eligibility requirements, deductibles, per incident, annual and aggregate caps. To the extent third parties (including insurers) do not pay for investigation and remediation, and/or insurance is not available, we will be obligated to make these
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additional payments, which could have a material adverse impact on our business, liquidity, results of operations and cash available for distribution to our unitholders.
Our environmental, health and safety program may not identify all environmental liabilities at all of our current and former locations; material environmental or pipeline safety conditions not known to us may exist; existing and future laws, ordinances or regulations may impose material environmental or pipeline safety liability or compliance costs on us; or we may be required to make material expenditures for the remediation of contamination or pipeline integrity and safety matters.
The occurrence of any of the events described above could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to our unitholders.
ITEM 6. EXHIBITS
The exhibits listed on the following exhibit index are filed or furnished, as indicated, as part of this report:

Exhibit Number |  | Description |  |
3.1 |  | Certificate of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.2 of Form S-1 (File No. 333-128097) filed September 2, 2005) |  |
3.2 |  | Certificate of Amendment of Certificate of Limited Partnership of Energy Transfer Equity, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed October 19, 2018) |  |
3.3 |  | Fourth Amended and Restated Agreement of Limited Partnership of Energy Transfer LP, dated November 3, 2023 (incorporated by reference to Exhibit 3.3 of Form 10-Q (File No. 1-32740) filed August 8, 2024) |  |
4.1 |  | Eighth Supplemental Indenture, dated as of August 25, 2025, between Energy Transfer LP, as issuer, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed August 25, 2025) |  |
4.2 |  | Ninth Supplemental Indenture, dated as of August 25, 2025, between Energy Transfer LP, as issuer, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.3 to Form 8-K (File No. 1-32740) filed August 25, 2025) |  |
22.1 |  | Issuers and Guarantors of Registered Securities (incorporated by reference to Exhibit 22.1 of Form 10-Q (File No. 1-32740) filed August 5, 2021) |  |
31.1* |  | Certification of Co-Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |  |
31.2* |  | Certification of Co-Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |  |
31.3* |  | Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |  |
32.1** |  | Certification of Co-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |  |
32.2** |  | Certification of Co-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |  |
32.3** |  | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |  |
101* |  | Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets; (ii) our Consolidated Statements of Operations; (iii) our Consolidated Statements of Comprehensive Income; (iv) our Consolidated Statements of Equity; (v) our Consolidated Statements of Cash Flows; and (vi) the notes to our Consolidated Financial Statements |  |
104 |  | Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101) |  |
* |  | Filed herewith |  |
** |  | Furnished herewith |  |

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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 thereunto duly authorized.

|  | ENERGY TRANSFER LP
|  | By: |  | LE GP, LLC, its general partner
Date: | November 6, 2025 | By: |  | /s/ A. Troy Sturrock
|  |  |  | A. Troy Sturrock
|  |  |  | Group Senior Vice President, Controller and Principal Accounting Officer

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