EPD filing — read by section

Item 1. Financial Statements

ITEM 1. FINANCIAL STATEMENTS. 
 
 ENTERPRISE PRODUCTS PARTNERS L.P. 
 UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS 
 (Dollars in millions) 
 
 June 30,
2025 December 31,
2024 
 ASSETS 
 Current assets: 
 Cash and cash equivalents $ 870 $ 583 
 Restricted cash 226 255 
 Accounts receivable – trade, net of allowance for credit losses of $ 37 at June 30, 2025 and $ 38 at December 31, 2024 
 7,560 9,236 
 Accounts receivable – related parties 2 4 
 Inventories (see Note 3) 3,969 3,955 
 Derivative assets (see Note 14) 689 534 
 Prepaid and other current assets 844 566 
 Total current assets 14,160 15,133 
 Property, plant and equipment, net (see Note 4) 
 50,495 49,062 
 Investments in unconsolidated affiliates (see Note 5) 
 2,221 2,259 
 Intangible assets, net (see Note 6) 
 3,902 4,005 
 Goodwill (see Note 6) 
 5,712 5,712 
 Other assets 952 997 
 Total assets $ 77,442 $ 77,168 
 
 LIABILITIES AND EQUITY 
 Current liabilities: 
 Current maturities of debt (see Note 7) $ 1,623 $ 1,150 
 Accounts payable – trade 1,326 1,227 
 Accounts payable – related parties 128 198 
 Accrued product payables 9,721 10,777 
 Accrued interest 520 536 
 Derivative liabilities (see Note 14) 627 471 
 Other current liabilities 812 818 
 Total current liabilities 14,757 15,177 
 Long-term debt (see Note 7) 
 31,110 30,746 
 Deferred tax liabilities (see Note 16 ) 
 672 656 
 Other long-term liabilities 934 950 
 Commitments and contingent liabilities (see Note 17) 
 
 Redeemable preferred limited partner interests: (see Note 8) 
 
 Series A cumulative convertible preferred units (“preferred units”) ( 50,879 units outstanding at June 30, 2025 and 50,687 units outstanding at December 31, 2024) 
 50 50 
 Equity: (see Note 8) 
 
 Partners’ equity: 
 Common limited partner interests ( 2,165,556,485 units issued and outstanding at June 30, 2025, 2,165,699,962 units issued and outstanding at December 31, 2024) 
 30,127 29,793 
 Treasury units, at cost ( 1,297 ) ( 1,297 ) 
 Accumulated other comprehensive income 236 236 
 Total partners’ equity 29,066 28,732 
 Noncontrolling interests in consolidated subsidiaries 853 857 
 Total equity 29,919 29,589 
 Total liabilities, preferred units, and equity $ 77,442 $ 77,168 

 See Notes to Unaudited Condensed Consolidated Financial Statements. 
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 ENTERPRISE PRODUCTS PARTNERS L.P. 
 UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS 
 (Dollars in millions, except per unit amounts) 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Revenues: 
 Third parties $ 11,352 $ 13,472 $ 26,756 $ 28,217 
 Related parties 11 11 24 26 
 Total revenues (see Note 9) 11,363 13,483 26,780 28,243 
 Costs and expenses: 
 Operating costs and expenses: 
 Third party and other costs 9,188 11,400 22,486 24,011 
 Related parties 404 362 796 725 
 Total operating costs and expenses 9,592 11,762 23,282 24,736 
 General and administrative costs: 
 Third party and other costs 26 17 53 44 
 Related parties 42 40 75 79 
 Total general and administrative costs 68 57 128 123 
 Total costs and expenses (see Note 10) 9,660 11,819 23,410 24,859 
 Equity in income of unconsolidated affiliates 92 101 186 203 
 Operating income 1,795 1,765 3,556 3,587 
 Other income (expense): 
 Interest expense ( 332 ) ( 332 ) ( 672 ) ( 663 ) 
 Interest income 6 4 14 17 
 Other, net 1 – 2 – 
 Total other expense, net ( 325 ) ( 328 ) ( 656 ) ( 646 ) 
 Income before income taxes 1,470 1,437 2,900 2,941 
 Provision for income taxes (see Note 16) ( 16 ) ( 15 ) ( 40 ) ( 36 ) 
 Net income 1,454 1,422 2,860 2,905 
 Net income attributable to noncontrolling interests ( 18 ) ( 16 ) ( 30 ) ( 42 ) 
 Net income attributable to preferred units ( 1 ) ( 1 ) ( 2 ) ( 2 ) 
 Net income attributable to common unitholders $ 1,435 $ 1,405 $ 2,828 $ 2,861 
 
 Earnings per unit: (see Note 11) 
 
 Basic earnings per common unit 
 $ 0.66 $ 0.64 $ 1.29 $ 1.31 
 Diluted earnings per common unit 
 $ 0.66 $ 0.64 $ 1.29 $ 1.30 

 
 
 
 
 See Notes to Unaudited Condensed Consolidated Financial Statements. 
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 ENTERPRISE PRODUCTS PARTNERS L.P. 
 UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED 
 COMPREHENSIVE INCOME 
 (Dollars in millions) 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 
 Net income $ 1,454 $ 1,422 $ 2,860 $ 2,905 
 Other comprehensive income (loss): 
 Cash flow hedges: (see Note 14) 
 Commodity hedging derivative instruments: 
 Changes in fair value of cash flow hedges – 79 22 ( 83 ) 
 Reclassification of gains to net income ( 59 ) ( 45 ) ( 33 ) ( 47 ) 
 Interest rate hedging derivative instruments: 
 Changes in fair value of cash flow hedges 12 – 14 2 
 Reclassification of gains to net income ( 2 ) ( 1 ) ( 3 ) ( 3 ) 
 Total cash flow hedges ( 49 ) 33 – ( 131 ) 
 Total other comprehensive income (loss) ( 49 ) 33 – ( 131 ) 
 Comprehensive income 1,405 1,455 2,860 2,774 
 Comprehensive income attributable to noncontrolling interests ( 18 ) ( 16 ) ( 30 ) ( 42 ) 
 Comprehensive income attributable to preferred units ( 1 ) ( 1 ) ( 2 ) ( 2 ) 
 Comprehensive income attributable to common unitholders $ 1,386 $ 1,438 $ 2,828 $ 2,730 

 
 
 
 
 See Notes to Unaudited Condensed Consolidated Financial Statements. 
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 ENTERPRISE PRODUCTS PARTNERS L.P. 
 UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS 
 (Dollars in millions) 
 
 For the Six Months
Ended June 30, 
 2025 2024 
 Operating activities: 
 Net income $ 2,860 $ 2,905 
 Reconciliation of net income to net cash flow provided by operating activities: 
 Depreciation and accretion 1,030 981 
 Amortization of intangible assets 104 101 
 Amortization of major maintenance costs for reaction-based plants 31 27 
 Other amortization expense 114 118 
 Impairment of assets other than goodwill 21 24 
 Equity in income of unconsolidated affiliates ( 186 ) ( 203 ) 
 Distributions received from unconsolidated affiliates attributable to earnings 189 204 
 Net losses (gains) attributable to asset sales and related matters ( 9 ) 5 
 Deferred income tax expense 16 14 
 Change in fair market value of derivative instruments ( 10 ) ( 8 ) 
 Non-cash expense related to long-term operating leases (see Note 17) 55 43 
 Net effect of changes in operating accounts (see Note 18) 153 ( 527 ) 
 Other operating activities 7 1 
 Net cash flow provided by operating activities 4,375 3,685 
 Investing activities: 
 Capital expenditures ( 2,361 ) ( 2,311 ) 
 Investments in unconsolidated affiliates 
 ( 1 ) – 
 Distributions received from unconsolidated affiliates attributable to the return of capital 35 39 
 Proceeds from asset sales and other matters 15 6 
 Other investing activities ( 9 ) ( 15 ) 
 Net cash flow used in investing activities ( 2,321 ) ( 2,281 ) 
 Financing activities: 
 Borrowings under debt agreements 49,565 38,281 
 Repayments of debt ( 48,720 ) ( 36,685 ) 
 Debt issuance costs ( 25 ) ( 19 ) 
 Monetization of interest rate derivative instruments 14 ( 29 ) 
 Cash distributions paid to common unitholders (see Note 8) ( 2,319 ) ( 2,235 ) 
 Cash payments made in connection with distribution equivalent rights ( 22 ) ( 21 ) 
 Cash distributions paid to noncontrolling interests ( 39 ) ( 63 ) 
 Cash contributions from noncontrolling interests 5 25 
 Repurchase of common units under 2019 Buyback Program ( 170 ) ( 80 ) 
 Acquisition of noncontrolling interests – ( 400 ) 
 Other financing activities ( 85 ) ( 64 ) 
 Net cash flow used in financing activities ( 1,796 ) ( 1,290 ) 
 Net change in cash and cash equivalents, including restricted cash 258 114 
 Cash and cash equivalents, including restricted cash, at beginning of period 838 320 
 Cash and cash equivalents, including restricted cash, at end of period $ 1,096 $ 434 

 
 
 
 
 
 
 See Notes to Unaudited Condensed Consolidated Financial Statements. 
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 ENTERPRISE PRODUCTS PARTNERS L.P. 
 UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY 
 FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2025 
 (Dollars in millions) 
 
 Partners’ Equity 
 Common
Limited
Partner
Interests Treasury
Units Accumulated
Other
Comprehensive
Income (Loss) Noncontrolling
Interests in
Consolidated
Subsidiaries Total 
 Balance, March 31, 2025 $ 29,927 $ ( 1,297 ) $ 285 $ 860 $ 29,775 
 Net income 1,435 – – 18 1,453 
 Cash distributions paid to common unitholders ( 1,160 ) – – – ( 1,160 ) 
 Cash payments made in connection with distribution equivalent rights ( 11 ) – – – ( 11 ) 
 Cash distributions paid to noncontrolling interests – – – ( 26 ) ( 26 ) 
 Cash contributions from noncontrolling interests – – – 1 1 
 Repurchase and cancellation of common units under 2019 Buyback Program ( 110 ) – – – ( 110 ) 
 Amortization of fair value of equity-based awards 49 – – – 49 
 Cash flow hedges – – ( 49 ) – ( 49 ) 
 Other, net ( 3 ) – – – ( 3 ) 
 Balance, June 30, 2025 $ 30,127 $ ( 1,297 ) $ 236 $ 853 $ 29,919 
 
 
 Partners’ Equity 
 Common
Limited
Partner
Interests Treasury
Units Accumulated
Other
Comprehensive
Income (Loss) Noncontrolling
Interests in
Consolidated
Subsidiaries Total 
 Balance, December 31, 2024 $ 29,793 $ ( 1,297 ) $ 236 $ 857 $ 29,589 
 Net income 2,828 – – 30 2,858 
 Cash distributions paid to common unitholders ( 2,319 ) – – – ( 2,319 ) 
 Cash payments made in connection with distribution equivalent rights ( 22 ) – – – ( 22 ) 
 Cash distributions paid to noncontrolling interests – – – ( 39 ) ( 39 ) 
 Cash contributions from noncontrolling interests – – – 5 5 
 Repurchase and cancellation of common units under 2019 Buyback Program ( 170 ) – – – ( 170 ) 
 Amortization of fair value of equity-based awards 98 – – – 98 
 Cash flow hedges – – – – – 
 Other, net ( 81 ) – – – ( 81 ) 
 Balance, June 30, 2025 $ 30,127 $ ( 1,297 ) $ 236 $ 853 $ 29,919 

 
 
 
 
 
 
 
 
 
 
 See Notes to Unaudited Condensed Consolidated Financial Statements. For information regarding Unit History, 
 Accumulated Other Comprehensive Income (Loss), see Note 8 . 
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 ENTERPRISE PRODUCTS PARTNERS L.P. 
 UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY 
 FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2024 
 (Dollars in millions) 
 
 Partners’ Equity 
 Common
Limited
 Partner
Interests Treasury
Units Accumulated
Other
Comprehensive
Income (Loss) Noncontrolling
Interests in
Consolidated
Subsidiaries Total 
 Balance, March 31, 2024 $ 28,831 $ ( 1,297 ) $ 143 $ 800 $ 28,477 
 Net income 1,405 – – 16 1,421 
 Cash distributions paid to common unitholders ( 1,118 ) – – – ( 1,118 ) 
 Cash payments made in connection with distribution equivalent rights ( 11 ) – – – ( 11 ) 
 Cash distributions paid to noncontrolling interests – – – ( 25 ) ( 25 ) 
 Cash contributions from noncontrolling interests – – – 17 17 
 Repurchase and cancellation of common units under 2019 Buyback Program ( 40 ) – – – ( 40 ) 
 Amortization of fair value of equity-based awards 44 – – – 44 
 
 Cash flow hedges – – 33 – 33 
 Other, net ( 1 ) – – – ( 1 ) 
 Balance, June 30, 2024 $ 29,110 $ ( 1,297 ) $ 176 $ 808 $ 28,797 
 
 
 Partners’ Equity 
 Common
Limited
 Partner
Interests Treasury
Units Accumulated
Other
Comprehensive
Income (Loss) Noncontrolling
Interests in
Consolidated
Subsidiaries Total 
 Balance, December 31, 2023 $ 28,663 $ ( 1,297 ) $ 307 $ 1,086 $ 28,759 
 Net income 2,861 – – 42 2,903 
 Cash distributions paid to common unitholders ( 2,235 ) – – – ( 2,235 ) 
 Cash payments made in connection with distribution equivalent rights ( 21 ) – – – ( 21 ) 
 Cash distributions paid to noncontrolling interests – – – ( 63 ) ( 63 ) 
 Cash contributions from noncontrolling interests – – – 25 25 
 Repurchase and cancellation of common units under 2019 Buyback Program ( 80 ) – – – ( 80 ) 
 Amortization of fair value of equity-based awards 100 – – – 100 
 Acquisition of noncontrolling interests ( 118 ) – – ( 282 ) ( 400 ) 
 Cash flow hedges – – ( 131 ) – ( 131 ) 
 Other, net ( 60 ) – – – ( 60 ) 
 Balance, June 30, 2024 $ 29,110 $ ( 1,297 ) $ 176 $ 808 $ 28,797 

 
 
 
 
 
 
 
 
 
 
 See Notes to Unaudited Condensed Consolidated Financial Statements. For information regarding Unit History, 
 Accumulated Other Comprehensive Income (Loss), see Note 8 . 
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 ENTERPRISE PRODUCTS PARTNERS L.P. 
 NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 
 KEY REFERENCES USED IN THESE 
 NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 
 Unless the context requires otherwise, references to “we,” “us” or “our” within these Notes to Unaudited Condensed Consolidated Financial Statements are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. 
 References to the “Partnership” or “Enterprise” mean Enterprise Products Partners L.P. on a standalone basis. 
 References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of the Partnership, and its consolidated subsidiaries, through which the Partnership conducts its business. We are managed by our general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company. 
 The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors of Enterprise GP (the “Board”); (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board; and (iii) W. Randall Fowler, who is also a director and a Co-Chief Executive Officer of Enterprise GP. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC. 
 References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO; and (iii) Mr. Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO. 
 We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. EPCO, together with its privately held affiliates, owned approximately 32.4% of the Partnership’s common units outstanding at June 30, 2025 . 
 With the exception of per unit amounts, or as noted within the context of each disclosure, 
 the dollar amounts presented in the tabular data within these disclosures are 
 stated in millions of dollars. 
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 ENTERPRISE PRODUCTS PARTNERS L.P. 
 NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 

 Note 1 . Partnership Organization and Operations 
 We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Our preferred units are not publicly traded. We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership. We conduct substantially all of our business operations through EPO and its consolidated subsidiaries. 
 Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations include: 
 • natural gas gathering, treating, processing, transportation and storage; 
 • NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases (“LPG”) and ethane); 
 • crude oil gathering, transportation, storage, and marine terminals; 
 • propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities; 
 • petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”)); and 
 • a marine transportation business that operates on key U.S. inland and intracoastal waterway systems. 
 Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers. See Note 15 for information regarding related party matters. 
 Our results of operations for the six months ended June 30, 2025 are not necessarily indicative of results expected for the full year of 2025 . In our opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments consisting of normal recurring accruals necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). 
 These Unaudited Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the Audited Consolidated Financial Statements and Notes thereto included in our annual report on Form 10-K for the year ended December 31, 2024 (the “ 2024 Form 10-K”) filed with the SEC on February 28, 2025. 
 
 Note 2 . Summary of Significant Accounting Policies 
 Apart from those matters described in this footnote, there have been no updates to our significant accounting policies since those reported under Note 2 of the 2024 Form 10-K. 
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 ENTERPRISE PRODUCTS PARTNERS L.P. 
 NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 

 Cash, Cash Equivalents and Restricted Cash 
 The following table provides a reconciliation of cash and cash equivalents, and restricted cash reported within the Unaudited Condensed Consolidated Balance Sheets that sum to the total of the amounts shown in the Unaudited Condensed Statements of Consolidated Cash Flows. 
 
 June 30,
2025 December 31,
2024 
 Cash and cash equivalents $ 870 $ 583 
 Restricted cash 226 255 
 Total cash, cash equivalents and restricted cash shown in the Unaudited Condensed Statements of Consolidated Cash Flows 
 $ 1,096 $ 838 

 Restricted cash primarily represents amounts held in segregated bank accounts by our clearing brokers as margin in support of our commodity derivative instruments portfolio and related physical purchases and sales of natural gas, NGLs, crude oil, petrochemicals, refined products and power. Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or margin requirements change. See Note 14 for information regarding our derivative instruments and hedging activities. 
 
 Note 3 . Inventories 
 Our inventory amounts by product type were as follows at the dates indicated: 
 
 June 30,
2025 December 31,
2024 
 NGLs $ 3,026 $ 2,768 
 Petrochemicals and refined products 638 652 
 Crude oil 299 523 
 Natural gas 6 12 
 Total $ 3,969 $ 3,955 

 Due to fluctuating commodity prices, we recognize lower of cost or net realizable value adjustments when the carrying value of our available-for-sale inventories exceeds their net realizable value. The following table presents our total cost of sales amounts and lower of cost or net realizable value adjustments for the periods indicated: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Cost of sales (1) $ 7,899 $ 10,184 $ 19,904 $ 21,589 
 Lower of cost or net realizable value adjustments recognized in cost of sales 2 1 4 2 
 

 (1) Cost of sales is a component of “Operating costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations. Fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities. 
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 ENTERPRISE PRODUCTS PARTNERS L.P. 
 NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 

 Note 4 . Property, Plant and Equipment 
 The historical costs of our property, plant and equipment and related balances were as follows at the dates indicated: 
 
 Estimated
Useful Life
in Years June 30,
2025 December 31,
2024 
 Plants, pipelines and facilities (1)(5) 3 - 45 
 $ 62,321 $ 60,716 
 Underground and other storage facilities (2)(6) 5 - 40 
 4,753 4,704 
 Transportation equipment (3) 3 - 10 
 283 272 
 Marine vessels (4) 15 - 30 
 956 949 
 Land 424 424 
 Construction in progress 4,900 4,138 
 Subtotal 73,637 71,203 
 Less accumulated depreciation 23,305 22,330 
 Subtotal property, plant and equipment, net 50,332 48,873 
 Capitalized major maintenance costs for reaction-based plants, net of accumulated amortization (7) 
 163 189 
 Property, plant and equipment, net $ 50,495 $ 49,062 
 

 (1) Plants, pipelines and facilities include distillation-based and reaction-based plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; buildings; office furniture and equipment; laboratory and shop equipment and related assets. 
 (2) Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets. 
 (3) Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations. 
 (4) Marine vessels include tow boats, barges and related equipment used in our marine transportation business. 
 (5) In general, the estimated useful lives of major assets within this category are: distillation-based and reaction-based plants, 20 - 35 years; pipelines and related equipment, 5 - 45 years; terminal facilities, 10 - 35 years; buildings, 20 - 40 years; office furniture and equipment, 3 - 20 years; and laboratory and shop equipment, 5 - 35 years. 
 (6) In general, the estimated useful lives of assets within this category are: underground storage facilities, 5 - 35 years; storage tanks, 10 - 40 years; and water wells, 5 - 35 years. 
 (7) For reaction-based plants, we use the deferral method when accounting for major maintenance activities. Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. On a weighted-average basis, the expected remaining amortization period for these costs is 2.9 years. 
 Property, plant and equipment at both June 30, 2025 and December 31, 2024 includes $ 134 million of asset retirement costs capitalized as an increase in the associated long-lived asset. 
 The following table presents information regarding our asset retirement obligations, or AROs, since December 31, 2024 : 
 
 ARO liability balance, December 31, 2024 $ 265 
 Liabilities incurred (1) – 
 Revisions in estimated cash flows (2) 2 
 Liabilities settled (3) ( 3 ) 
 Accretion expense (4) 12 
 ARO liability balance, June 30, 2025 $ 276 
 

 (1) Represents the initial recognition of estimated ARO liabilities during the period. 
 (2) Represents subsequent adjustments to estimated ARO liabilities during the period. 
 (3) Represents cash payments to settle ARO liabilities during the period. 
 (4) Represents the net change in ARO liability balance attributable to the passage of time and other adjustments, including true-up amounts associated with revised closure estimates. 
 Of the $ 276 million total ARO liability recorded at June 30, 2025 , $ 6 million was reflected as a current liability and $ 270 million as a long-term liability. 
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 ENTERPRISE PRODUCTS PARTNERS L.P. 
 NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 

 The following table summarizes our depreciation expense and capitalized interest amounts for the periods indicated: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Depreciation expense (1) $ 512 $ 491 $ 1,018 $ 976 
 Capitalized interest (2) 53 26 98 51 
 

 (1) Depreciation expense is a component of “Costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations. 
 (2) We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life as a component of depreciation expense. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise. 
 
 Note 5 . Investments in Unconsolidated Affiliates 
 The following table presents our investments in unconsolidated affiliates by business segment at the dates indicated. We account for these investments using the equity method. 
 
 June 30,
2025 December 31,
2024 
 NGL Pipelines & Services $ 578 $ 598 
 Crude Oil Pipelines & Services 1,610 1,628 
 Natural Gas Pipelines & Services 32 30 
 Petrochemical & Refined Products Services 1 3 
 Total $ 2,221 $ 2,259 

 The following table presents our equity in income of unconsolidated affiliates by business segment for the periods indicated: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 NGL Pipelines & Services $ 18 $ 26 $ 38 $ 57 
 Crude Oil Pipelines & Services 72 73 144 142 
 Natural Gas Pipelines & Services – 1 2 3 
 Petrochemical & Refined Products Services 2 1 2 1 
 Total $ 92 $ 101 $ 186 $ 203 

 In June 2025, we sold our 25 % membership interest in Transport 4, L.L.C. (“Transport 4”) to third parties for cash proceeds of $ 8 million and recorded a $ 6 million gain. 
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 ENTERPRISE PRODUCTS PARTNERS L.P. 
 NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 

 Note 6 . Intangible Assets and Goodwill 
 Identifiable Intangible Assets 
 The following table summarizes our intangible assets by business segment at the dates indicated: 
 
 June 30, 2025 December 31, 2024 
 Gross
Value Accumulated
Amortization Carrying
Value Gross
Value Accumulated
Amortization Carrying
Value 
 NGL Pipelines & Services: 
 Customer relationship intangibles $ 449 $ ( 282 ) $ 167 $ 449 $ ( 276 ) $ 173 
 Contract-based intangibles 754 ( 158 ) 596 754 ( 141 ) 613 
 Segment total 1,203 ( 440 ) 763 1,203 ( 417 ) 786 
 Crude Oil Pipelines & Services: 
 Customer relationship intangibles 2,195 ( 669 ) 1,526 2,195 ( 627 ) 1,568 
 Contract-based intangibles 283 ( 278 ) 5 283 ( 278 ) 5 
 Segment total 2,478 ( 947 ) 1,531 2,478 ( 905 ) 1,573 
 Natural Gas Pipelines & Services: 
 Customer relationship intangibles 1,351 ( 682 ) 669 1,351 ( 663 ) 688 
 Contract-based intangibles 1,082 ( 244 ) 838 1,081 ( 227 ) 854 
 Segment total 2,433 ( 926 ) 1,507 2,432 ( 890 ) 1,542 
 Petrochemical & Refined Products Services: 
 Customer relationship intangibles 181 ( 95 ) 86 181 ( 92 ) 89 
 Contract-based intangibles 45 ( 30 ) 15 45 ( 30 ) 15 
 Segment total 226 ( 125 ) 101 226 ( 122 ) 104 
 Total intangible assets $ 6,340 $ ( 2,438 ) $ 3,902 $ 6,339 $ ( 2,334 ) $ 4,005 

 The following table presents the amortization expense of our intangible assets by business segment for the periods indicated: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 NGL Pipelines & Services $ 12 $ 11 $ 23 $ 21 
 Crude Oil Pipelines & Services 21 26 42 51 
 Natural Gas Pipelines & Services 18 13 36 26 
 Petrochemical & Refined Products Services 1 1 3 3 
 Total $ 52 $ 51 $ 104 $ 101 

 The following table presents our forecast of amortization expense associated with existing intangible assets for the periods indicated: 
 
 Remainder
of 2025 2026 2027 2028 2029 
 $ 111 $ 216 $ 209 $ 198 $ 199 

 Goodwill 
 Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction. There has been no change in our goodwill amounts since those reported in our 2024 Form 10-K. 
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 ENTERPRISE PRODUCTS PARTNERS L.P. 
 NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 

 Note 7 . Debt Obligations 
 The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated: 
 
 June 30,
2025 December 31,
2024 
 EPO senior debt obligations: 
 Commercial Paper Notes, variable-rates $ – $ – 
 Senior Notes MM, 3.75 % fixed-rate, due February 2025 
 – 1,150 
 Senior Notes FFF, 5.05 % fixed-rate, due January 2026 
 750 750 
 Senior Notes PP, 3.70 % fixed-rate, due February 2026 
 875 875 
 March 2025 $ 1.5 Billion 364 -Day Revolving Credit Agreement, variable-rate, due March 2026 (1) 
 – – 
 Senior Notes HHH, 4.60 % fixed-rate, due January 2027 
 1,000 1,000 
 Senior Notes SS, 3.95 % fixed-rate, due February 2027 
 575 575 
 Senior Notes LLL, 4.30 % fixed-rate, due June 2028 
 500 – 
 Senior Notes WW, 4.15 % fixed-rate, due October 2028 
 1,000 1,000 
 Senior Notes YY, 3.125 % fixed-rate, due July 2029 
 1,250 1,250 
 Senior Notes AAA, 2.80 % fixed-rate, due January 2030 
 1,250 1,250 
 March 2023 $ 2.7 Billion Multi-Year Revolving Credit Agreement, variable-rate, due March 2030 (2) 
 – – 
 Senior Notes MMM, 4.60 % fixed-rate, due January 2031 
 750 – 
 Senior Notes GGG, 5.35 % fixed-rate, due January 2033 
 1,000 1,000 
 Senior Notes D, 6.875 % fixed-rate, due March 2033 
 500 500 
 Senior Notes III, 4.85 % fixed-rate, due January 2034 
 1,000 1,000 
 Senior Notes H, 6.65 % fixed-rate, due October 2034 
 350 350 
 Senior Notes JJJ 4.95 % fixed-rate, due February 2035 
 1,100 1,100 
 Senior Notes J, 5.75 % fixed-rate, due March 2035 
 250 250 
 Senior Notes NNN, 5.20 % fixed-rate, due January 2036 
 750 – 
 Senior Notes W, 7.55 % fixed-rate, due April 2038 
 400 400 
 Senior Notes R, 6.125 % fixed-rate, due October 2039 
 600 600 
 Senior Notes Z, 6.45 % fixed-rate, due September 2040 
 600 600 
 Senior Notes BB, 5.95 % fixed-rate, due February 2041 
 750 750 
 Senior Notes DD, 5.70 % fixed-rate, due February 2042 
 600 600 
 Senior Notes EE, 4.85 % fixed-rate, due August 2042 
 750 750 
 Senior Notes GG, 4.45 % fixed-rate, due February 2043 
 1,100 1,100 
 Senior Notes II, 4.85 % fixed-rate, due March 2044 
 1,400 1,400 
 Senior Notes KK, 5.10 % fixed-rate, due February 2045 
 1,150 1,150 
 Senior Notes QQ, 4.90 % fixed-rate, due May 2046 
 975 975 
 Senior Notes UU, 4.25 % fixed-rate, due February 2048 
 1,250 1,250 
 Senior Notes XX, 4.80 % fixed-rate, due February 2049 
 1,250 1,250 
 Senior Notes ZZ, 4.20 % fixed-rate, due January 2050 
 1,250 1,250 
 Senior Notes BBB, 3.70 % fixed-rate, due January 2051 
 1,000 1,000 
 Senior Notes DDD, 3.20 % fixed-rate, due February 2052 
 1,000 1,000 
 Senior Notes EEE, 3.30 % fixed-rate, due February 2053 
 1,000 1,000 
 Senior Notes NN, 4.95 % fixed-rate, due October 2054 
 400 400 
 Senior Notes KKK, 5.55 % fixed-rate, due February 2055 
 1,400 1,400 
 Senior Notes CCC, 3.95 % fixed-rate, due January 2060 
 1,000 1,000 
 Total principal amount of senior debt obligations 30,775 29,925 
 EPO Junior Subordinated Notes C, variable-rate, due June 2067 (3) 
 232 232 
 EPO Junior Subordinated Notes D, variable-rate, due August 2077 (4) 
 350 350 
 EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 (5) 
 1,000 1,000 
 EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 (6) 
 700 700 
 Total principal amount of senior and junior debt obligations 33,057 32,207 
 Other, non-principal amounts ( 324 ) ( 311 ) 
 Less current maturities of debt ( 1,623 ) ( 1,150 ) 
 Total long-term debt $ 31,110 $ 30,746 
 

 (1) Under the terms of the agreement, EPO may borrow up to $ 1.5 billion (which may be increased by up to $ 200 million to $ 1.7 billion at EPO’s election provided certain conditions are met). 
 (2) Under the terms of the agreement, EPO may borrow up to $ 2.7 billion (which may be increased by up to $ 500 million to $ 3.2 billion at EPO’s election provided certain conditions are met). 
 (3) Variable rate is reset quarterly and based on 3-month Chicago Mercantile Exchange (“CME”) Term Secured Overnight Financing Rate (“SOFR”) plus (a) a 0.26161 % tenor spread adjustment and (b) 2.778 %. 
 (4) Variable rate is reset quarterly and based on 3-month CME Term SOFR plus (a) a 0.26161 % tenor spread adjustment and (b) 2.986 %. 
 (5) Fixed rate of 5.250 % through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month CME Term SOFR plus (a) a 0.26161 % tenor spread adjustment and (b) 3.033 %. 
 (6) Fixed rate of 5.375 % through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month CME Term SOFR plus (a) a 0.26161 % tenor spread adjustment and (b) 2.57 %. 
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 Variable Interest Rates 
 The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the six months ended June 30, 2025 : 
 
 Range of Interest
Rates Paid Weighted-Average
Interest Rate Paid 
 Commercial Paper Notes 4.50 % to 4.68 % 
 4.57 % 
 EPO Junior Subordinated Notes C 7.36 % to 7.51 % 
 7.41 % 
 EPO Junior Subordinated Notes D 7.57 % to 7.73 % 
 7.61 % 

 Amounts borrowed under EPO’s March 2025 $ 1.5 Billion 364 -Day Revolving Credit Agreement and March 2023 $ 2.7 Billion Multi-Year Revolving Credit Agreement bear interest, at EPO’s election, equal to: (i) SOFR, plus an additional variable spread; or (ii) an alternate base rate, which is the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 0.5 % , or (c) Adjusted Term SOFR, for an interest period of one month in effect on such day plus 1 % , and a variable spread. The applicable spreads are determined based on EPO’s debt ratings. 
 Scheduled Maturities of Debt 
 The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at June 30, 2025 for the next five years, and in total thereafter: 
 
 Scheduled Maturities of Debt 
 Total Remainder
of 2025 2026 2027 2028 2029 Thereafter 
 
 Senior Notes $ 30,775 $ – $ 1,625 $ 1,575 $ 1,500 $ 1,250 $ 24,825 
 Junior Subordinated Notes 2,282 – – – – – 2,282 
 Total $ 33,057 $ – $ 1,625 $ 1,575 $ 1,500 $ 1,250 $ 27,107 

 March 2025 $ 1.5 Billion 364 -Day Revolving Credit Agreement 
 In March 2025 , EPO entered into a new 364 -Day Revolving Credit Agreement (the “March 2025 $ 1.5 Billion 364 -Day Revolving Credit Agreement”) that replaced its prior 364 -day revolving credit agreement. As of June 30, 2025 , there were no principal amounts outstanding under the March 2025 $ 1.5 Billion 364 -Day Revolving Credit Agreement. 
 Under the terms of the March 2025 $ 1.5 Billion 364 -Day Revolving Credit Agreement, EPO may borrow up to $ 1.5 billion (which may be increased by up to $ 200 million to $ 1.7 billion at EPO’s election, provided certain conditions are met) at a variable interest rate for a term of up to 364 days, subject to the terms and conditions set forth therein. The March 2025 $ 1.5 Billion 364 -Day Revolving Credit Agreement matures in March 2026. To the extent that principal amounts are outstanding at the maturity date, EPO may elect to have the entire principal balance then outstanding continued as non-revolving term loans for a period of one additional year, payable in March 2027. Borrowings under the March 2025 $ 1.5 Billion 364 -Day Revolving Credit Agreement may be used for working capital, capital expenditures, acquisitions and general company purposes. 
 The March 2025 $ 1.5 Billion 364 -Day Revolving Credit Agreement contains customary representations, warranties, covenants (affirmative and negative) and events of default, the occurrence of which would permit the lenders to accelerate the maturity date of any amounts borrowed under this credit agreement. The March 2025 $ 1.5 Billion 364 -Day Revolving Credit Agreement also restricts EPO’s ability to pay cash distributions to the Partnership, if an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid or would result therefrom. 
 EPO’s obligations under the March 2025 $ 1.5 Billion 364 -Day Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by the Partnership. 
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 Amendment to the March 2023 $ 2.7 Billion Multi-Year Revolving Credit Agreement 
 In March 2025 , we amended our March 2023 $ 2.7 Billion Multi-Year Revolving Credit Agreement to extend its maturity date from March 2028 to March 2030. The remaining material terms of the March 2023 $ 2.7 Billion Multi-Year Revolving Credit Agreement, as amended, are consistent with those reported in our 2024 Form 10-K. 
 Issu an ce of $ 2.0 Billion of Senior Notes in June 2025 
 
 
 In June 2025, EPO issued $ 2.0 billion aggregate principal amount of senior notes comprised of (i) $ 500 million principal amount of senior notes due June 2028 (“Senior Notes LLL”), (ii) $ 750 million principal amount of senior notes due January 2031 (“Senior Notes MMM”) and (iii) $ 750 million principal amount of senior notes due January 2036 (“Senior Notes NNN”). Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including amounts outstanding under our commercial paper program). 
 
 
 Senior Notes LLL were issued at 99.869 % of their principal amount and have a fixed interest rate of 4.30 % per year. Senior Notes MMM were issued at 99.816 % of their principal amount and have a fixed interest rate of 4.60 % per year. Senior Notes NNN were issued at 99.665 % of their principal amount and have a fixed interest rate of 5.20 % per year. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis. 
 
 
 Letters of Credit 
 At June 30, 2025 , EPO had $ 35 million of letters of credit outstanding primarily related to our insurance program. 
 Lender Financial Covenants 
 We were in compliance with the financial covenants of our consolidated debt agreements at June 30, 2025 . 
 Parent-Subsidiary Guarantor Relationships 
 The Partnership acts as guarantor of the consolidated debt obligations of EPO. If EPO were to default on any of its guaranteed debt, the Partnership would be responsible for full and unconditional repayment of such obligations. 
 
 Note 8 . Capital Accounts 
 Common Limited Partner Interests 
 The following table summarizes changes in the number of our common units outstanding since December 31, 2024 : 
 
 Common units outstanding at December 31, 2024 2,165,699,962 
 Common unit repurchases under 2019 Buyback Program ( 1,803,215 ) 
 Common units issued in connection with the vesting of phantom unit awards, net 4,989,490 
 Other 16,398 
 Common units outstanding at March 31, 2025 2,168,902,635 
 Common unit repurchases under 2019 Buyback Program ( 3,566,979 ) 
 Common units issued in connection with the vesting of phantom unit awards, net 220,829 
 Common units outstanding at June 30, 2025 2,165,556,485 

 Registration Statements 
 We have a universal shelf registration statement on file with the SEC which allows the Partnership and EPO (each on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. 
 In addition, the Partnership has a registration statement on file with the SEC covering the issuance of up to $ 2.5 billion of its common units in amounts, at prices and on terms based on market conditions and other factors at the time of such offerings (referred to as the Partnership’s at-the-market (“ATM”) program). The Partnership did not issue any common units under its ATM program during the six months ended June 30, 2025 . The Partnership’s capacity to issue additional common units under the ATM program remains at $ 2.5 billion as of June 30, 2025 . 
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 We may issue additional equity and debt securities to assist us in meeting our future liquidity requirements, including those related to capital investments. 
 Common Unit Repurchases Under 2019 Buyback Program 
 In January 2019, we announced that the Board had approved a $ 2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides the Partnership with an additional method to return capital to investors. The 2019 Buyback Program authorizes the Partnership to repurchase its common units from time to time, including through open market purchases and negotiated transactions. No time limit has been set for completion of the program, and it may be suspended or discontinued at any time. 
 During the three and six months ended June 30, 2025 , the Partnership repurchased 3,566,979 and 5,370,194 common units, respectively, under the 2019 Buyback Program through open market purchases. The total cost of these repurchases, including commissions and fees, was $ 110 million and $ 170 million , respectively. During the three and six months ended June 30, 2024 , the Partnership repurchased 1,419,581 and 2,806,416 common units, respectively, under the 2019 Buyback Program through open market purchases. The total cost of these repurchases, including commissions and fees, was $ 40 million and $ 80 million, respectively. Common units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition. At June 30, 2025 , the remaining available capacity under the 2019 Buyback Program was $ 692 million. 
 Common Units Issued in Connection With the Vesting of Phantom Unit Awards 
 After taking into account tax withholding requirements, the Partnership issued 5,210,319 new common units to employees in connection with the vesting of phantom unit awards during the six months ended June 30, 2025 . See Note 13 for information regarding our phantom unit awards. 
 Common Units Delivered Under DRIP and EUPP 
 The Partnership has registration statements on file with the SEC in connection with its distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”). In July 2019, the Partnership announced that, beginning with the quarterly distribution payment paid in August 2019, it would use common units purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP. This election is subject to change in future quarters depending on the Partnership’s need for equity capital. 
 During the six months ended June 30, 2025 , agents of the Partnership purchased 2,366,556 common units on the open market and delivered them to participants in the DRIP and EUPP. Apart from $ 2 million attributable to the plan discount available to all participants in the EUPP, the funds used to effect these purchases were sourced from the DRIP and EUPP participants. No other Partnership funds were used to satisfy these obligations. We plan to use open market purchases to satisfy DRIP and EUPP reinvestments in connection with the distribution expected to be paid on August 14, 2025 . 
 Preferred Units 
 The following table summarizes changes in the number of our Series A Cumulative Convertible Preferred Units (“preferred units”) outstanding since December 31, 2024 . 
 
 Preferred units outstanding at December 31, 2024 50,687 
 Paid in-kind distribution to third party 95 
 Preferred units outstanding at March 31, 2025 50,782 
 Paid in-kind distribution to third party 97 
 Preferred units outstanding at June 30, 2025 50,879 

 We present the capital accounts attributable to our preferred unitholders as mezzanine equity on our consolidated balance sheets since the terms of the preferred units allow for cash redemption by such unitholders in the event of a Change of Control (as defined in our partnership agreement), without regard to the likelihood of such an event. 
 During the six months ended June 30, 2025 , the Partnership made quarterly cash distributions to its preferred unitholders of $ 2 million and paid-in-kind distributions of 192 new preferred units valued at less than $ 1 million . 
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 Accumulated Other Comprehensive Income (Loss) 
 The following tables present the components of accumulated other comprehensive income (loss) as reported on our Unaudited Condensed Consolidated Balance Sheets at the dates indicated: 
 
 Cash Flow Hedges Other Total 
 Commodity
Derivative
Instruments Interest Rate
Derivative
Instruments 
 Accumulated Other Comprehensive Income (Loss), December 31, 2024 $ 91 $ 143 $ 2 $ 236 
 Other comprehensive income (loss) for period, before reclassifications 22 14 – 36 
 Reclassification of losses (gains) to net income during period ( 33 ) ( 3 ) – ( 36 ) 
 Total other comprehensive income (loss) for period ( 11 ) 11 – – 
 Accumulated Other Comprehensive Income (Loss), June 30, 2025 $ 80 $ 154 $ 2 $ 236 

 
 Cash Flow Hedges 
 Commodity
Derivative
Instruments Interest Rate
Derivative
Instruments Other Total 
 Accumulated Other Comprehensive Income (Loss), December 31, 2023 $ 154 $ 151 $ 2 $ 307 
 Other comprehensive income (loss) for period, before reclassifications ( 83 ) 2 – ( 81 ) 
 Reclassification of losses (gains) to net income during period ( 47 ) ( 3 ) – ( 50 ) 
 Total other comprehensive income (loss) for period ( 130 ) ( 1 ) – ( 131 ) 
 Accumulated Other Comprehensive Income (Loss), June 30, 2024 $ 24 $ 150 $ 2 $ 176 

 The following table presents reclassifications of (income) loss out of accumulated other comprehensive income (loss) into net income during the periods indicated: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 Losses (gains) on cash flow hedges: Location 2025 2024 2025 2024 
 Interest rate derivatives Interest expense $ ( 2 ) $ ( 1 ) $ ( 3 ) $ ( 3 ) 
 Commodity derivatives Revenue ( 67 ) ( 61 ) ( 53 ) ( 80 ) 
 Commodity derivatives Operating costs and expenses 8 16 20 33 
 Total $ ( 61 ) $ ( 46 ) $ ( 36 ) $ ( 50 ) 

 For information regarding our interest rate and commodity derivative instruments, see Note 14 . 
 Cash Distributions 
 On July 8, 2025, we announced that the Board declared a quarterly cash distribution of $ 0.545 per common unit, or $ 2.18 per common unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the second quarter of 2025 . The quarterly distribution is payable on August 14, 2025 to unitholders of record as of the close of business on July 31, 2025 . The total amount to be paid is $ 1.19 billion, which includes $ 11 million for distribution equivalent rights (“DERs”) on phantom unit awards. 
 The payment of quarterly cash distributions is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and Board approval. Management will evaluate any future increases in cash distributions on a quarterly basis. 
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 Note 9 . Revenues 
 We classify our revenues into sales of products and midstream services. Product sales relate primarily to our various marketing activities whereas midstream services represent our other integrated businesses (i.e., gathering, processing, transportation, fractionation, storage and terminaling). The following table presents our revenues by business segment, and further by revenue type, for the periods indicated: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 NGL Pipelines & Services: 
 Sales of NGLs and related products $ 2,723 $ 3,581 $ 7,374 $ 7,981 
 Segment midstream services: 
 Natural gas processing and fractionation 296 336 648 694 
 Transportation 308 263 620 542 
 Storage and terminals 79 85 164 188 
 Total segment midstream services 683 684 1,432 1,424 
 Total NGL Pipelines & Services 3,406 4,265 8,806 9,405 
 Crude Oil Pipelines & Services: 
 Sales of crude oil 4,479 5,598 9,304 10,720 
 Segment midstream services: 
 Transportation 195 190 384 383 
 Storage and terminals 109 100 216 200 
 Total segment midstream services 304 290 600 583 
 Total Crude Oil Pipelines & Services 4,783 5,888 9,904 11,303 
 Natural Gas Pipelines & Services: 
 Sales of natural gas 632 241 1,417 744 
 Segment midstream services: 
 Transportation 439 371 875 722 
 Total segment midstream services 439 371 875 722 
 Total Natural Gas Pipelines & Services 1,071 612 2,292 1,466 
 Petrochemical & Refined Products Services: 
 Sales of petrochemicals and refined products 1,775 2,389 5,101 5,354 
 Segment midstream services: 
 Fractionation and isomerization 84 85 187 211 
 Transportation, including marine logistics 157 163 332 341 
 Storage and terminals 87 81 158 163 
 Total segment midstream services 328 329 677 715 
 Total Petrochemical & Refined Products Services 2,103 2,718 5,778 6,069 
 Total consolidated revenues $ 11,363 $ 13,483 $ 26,780 $ 28,243 

 Substantially all of our revenues are derived from contracts with customers as defined within Accounting Standards Codification (“ASC”) 606, Revenue from Contracts with Customers. 
 Unbilled Revenue and Deferred Revenue 
 The following tables provide information regarding our contract assets and contract liabilities at June 30, 2025 : 
 
 Contract Asset Location Balance 
 Unbilled revenue (current amount) Prepaid and other current assets $ 8 
 Total $ 8 

 
 Contract Liability Location Balance 
 Deferred revenue (current amount) Other current liabilities $ 184 
 Deferred revenue (noncurrent) Other long-term liabilities 260 
 Total $ 444 

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 The following table presents significant changes in our unbilled revenue and deferred revenue balances for the six months ended June 30, 2025 : 
 
 Unbilled
Revenue Deferred
Revenue 
 Balance at December 31, 2024 $ 9 $ 452 
 Amount included in opening balance transferred to other accounts during period (1) ( 9 ) ( 148 ) 
 Amount recorded during period (2) 45 439 
 Amounts recorded during period transferred to other accounts (1) ( 37 ) ( 297 ) 
 Other changes – ( 2 ) 
 Balance at June 30, 2025 $ 8 $ 444 
 

 (1) Unbilled revenues are transferred to accounts receivable once we have an unconditional right to consideration from the customer. Deferred revenues are recognized as revenue upon satisfaction of our performance obligation to the customer. 
 (2) Unbilled revenue represents revenue that has been recognized upon satisfaction of a performance obligation, but cannot be contractually invoiced (or billed) to the customer at the balance sheet date until a future period. Deferred revenue is recorded when payment is received from a customer prior to our satisfaction of the associated performance obligation. 
 Remaining Performance Obligations 
 The following table presents estimated fixed future consideration from revenue contracts that contain minimum volume commitments, deficiency and similar fees and the term of the contracts exceeds one year. These amounts represent the revenues we expect to recognize in future periods from these contracts as of June 30, 2025 . 
 
 Period Fixed
Consideration 
 Six months ended December 31, 2025 
 $ 2,174 
 One year ended December 31, 2026 
 4,288 
 One year ended December 31, 2027 
 3,952 
 One year ended December 31, 2028 
 3,518 
 One year ended December 31, 2029 
 2,703 
 Thereafter 10,856 
 Total $ 27,491 

 
 Note 10 . Business Segments and Related Information 
 Our operations are reported under four business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold. 
 Financial information regarding these segments is evaluated regularly by our co-chief operating decision makers (“CODMs”) in deciding how to allocate resources and in assessing our operating and financial performance. The co-principal executive officers of our general partner have been identified as our CODMs. 
 The following information summarizes the assets and operations of each business segment: 
 • Our NGL Pipelines & Services business segment includes our natural gas processing and related NGL marketing activities, NGL pipelines, NGL fractionation facilities, NGL and related product storage facilities, and NGL marine terminals. 
 • Our Crude Oil Pipelines & Services business segment includes our crude oil pipelines, crude oil storage and marine terminals, and related crude oil marketing activities. 
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 • Our Natural Gas Pipelines & Services business segment includes our natural gas pipeline systems that provide for the gathering, treating and transportation of natural gas. This segment also includes our natural gas marketing activities. 
 • Our Petrochemical & Refined Products Services business segment includes our (i) propylene production facilities, which include propylene fractionation units and PDH facilities, and related pipelines and marketing activities, (ii) butane isomerization complex and related deisobutanizer operations, (iii) octane enhancement, iBDH and HPIB production facilities, (iv) refined products pipelines, terminals and related marketing activities, (v) ethylene export terminal and related operations; and (vi) marine transportation business. 
 Our plants, pipelines and other fixed assets are located in the U.S. 
 Segment Gross Operating Margin 
 Our CODMs evaluate segment performance based on our financial measure of gross operating margin. Gross operating margin is an important performance measure of the core profitability of our operations, forms the basis of our internal financial reporting, and is used by our CODMs on a monthly basis to monitor budgeted versus actual results. Our CODMs also consider gross operating margin results, in part, when determining how to allocate resources (e.g., employees and capital investments) to each segment, primarily in the annual budget process. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. Gross operating margin is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests. Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies. 
 The following table presents a reconciliation of total segment gross operating margin to income before income taxes for the periods indicated: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Total segment gross operating margin $ 2,471 $ 2,427 $ 4,935 $ 4,934 
 Adjustments to reconcile total segment gross operating margin to income before income taxes (addition or subtraction indicated by sign): 
 
 Depreciation, amortization and accretion expense in operating costs and expenses (1) ( 610 ) ( 581 ) ( 1,212 ) ( 1,163 ) 
 Asset impairment charges in operating costs and expenses ( 11 ) ( 4 ) ( 21 ) ( 24 ) 
 Net gains (losses) attributable to asset sales and related matters in operating costs and expenses 
 7 ( 5 ) 9 ( 5 ) 
 General and administrative costs ( 68 ) ( 57 ) ( 128 ) ( 123 ) 
 Non-refundable payments received from shippers attributable to make-up rights (2) ( 6 ) ( 18 ) ( 43 ) ( 43 ) 
 Subsequent recognition of revenues attributable to make-up rights (3) 12 3 16 11 
 Total other expense, net (4) ( 325 ) ( 328 ) ( 656 ) ( 646 ) 
 Income before income taxes $ 1,470 $ 1,437 $ 2,900 $ 2,941 
 

 (1) Excludes amortization of major maintenance costs for reaction-based plants and amortization of finance lease right-of-use (“ROU”) assets, which are components of gross operating margin. 
 (2) Since make-up rights entail a future performance obligation by the pipeline to the shipper, these receipts are recorded as deferred revenue for GAAP purposes; however, these receipts are included in gross operating margin in the period of receipt since they are non-refundable to the shipper. 
 (3) As deferred revenues attributable to make-up rights are subsequently recognized as revenue under GAAP, gross operating margin must be adjusted to remove such amounts to prevent duplication since the associated non-refundable payments were previously included in gross operating margin. 
 (4) As presented on our Statements of Consolidated Operations, Total other expense, net is comprised of Interest expense, Interest income and Other, net. 
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 Summarized Segment Financial Information 
 The following tables present segment revenues and significant segment expenses by segment, together with a reconciliation to segment gross operating margin, for the periods indicated: 
 
 For the Three Months Ended June 30, 2025 
 NGL
Pipelines
& Services Crude Oil
Pipelines
& Services Natural Gas
Pipelines
& Services Petrochemical
& Refined
Products
Services Segment
Total 
 Segment revenues: 
 Revenues from third parties $ 3,404 $ 4,777 $ 1,068 $ 2,103 $ 11,352 
 Revenues from related parties 2 6 3 – 11 
 Intersegment and intrasegment revenues 17,004 9,324 202 5,797 32,327 
 Total segment revenues 20,410 14,107 1,273 7,900 43,690 
 Significant segment expenses: 
 Cost of sales 18,487 13,660 644 7,159 39,950 
 Variable operating costs and expenses (1) 204 34 20 107 365 
 Fixed operating costs and expenses (2) 442 88 195 283 1,008 
 Total significant segment expenses 19,133 13,782 859 7,549 41,323 
 Other segment income: 
 Equity in income of unconsolidated affiliates 18 72 – 2 92 
 Other segment items (3) 2 6 3 1 12 
 Total other segment income 20 78 3 3 104 
 Total segment gross operating margin $ 1,297 $ 403 $ 417 $ 354 $ 2,471 
 
 Other financial information: 
 Capital expenditures $ 825 $ 25 $ 327 $ 122 $ 1,299 
 

 (1) Variable operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally fluctuate based on utilization. 
 (2) Fixed operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally remain constant independent of utilization. 
 (3) Other segment items for each segment primarily represent the following: 
 • NGL Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights and other miscellaneous segment items. 
 • Crude Oil Pipelines & Services – Other miscellaneous segment items. 
 • Natural Gas Pipelines & Services – Other miscellaneous segment items. 
 • Petrochemical & Refined Products Services – Other miscellaneous segment items. 
 
 
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 For the Six Months Ended June 30, 2025 
 NGL
Pipelines
& Services Crude Oil
Pipelines
& Services Natural Gas
Pipelines
& Services Petrochemical
& Refined
Products
Services Segment
Total 
 Segment revenues: 
 Revenues from third parties $ 8,802 $ 9,892 $ 2,284 $ 5,778 $ 26,756 
 Revenues from related parties 4 12 8 – 24 
 Intersegment and intrasegment revenues 34,021 19,946 434 12,992 67,393 
 Total segment revenues 42,827 29,850 2,726 18,770 94,173 
 Significant segment expenses: 
 Cost of sales 38,920 28,967 1,543 17,315 86,745 
 Variable operating costs and expenses (1) 403 69 42 213 727 
 Fixed operating costs and expenses (2) 865 189 372 577 2,003 
 Total significant segment expenses 40,188 29,225 1,957 18,105 89,475 
 Other segment income: 
 Equity in income of unconsolidated affiliates 38 144 2 2 186 
 Other segment items (3) 38 8 3 2 51 
 Total other segment income 76 152 5 4 237 
 Total segment gross operating margin $ 2,715 $ 777 $ 774 $ 669 $ 4,935 
 
 Other financial information: 
 Capital expenditures $ 1,460 $ 48 $ 630 $ 223 $ 2,361 
 

 (1) Variable operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally fluctuate based on utilization. 
 (2) Fixed operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally remain constant independent of utilization. 
 (3) Other segment items for each segment primarily represent the following: 
 • NGL Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights and other miscellaneous segment items. 
 • Crude Oil Pipelines & Services – Other miscellaneous segment items. 
 • Natural Gas Pipelines & Services – Other miscellaneous segment items. 
 • Petrochemical & Refined Products Services – Other miscellaneous segment items. 
 
 
 
 
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 For the Three Months Ended June 30, 2024 
 NGL
Pipelines
& Services Crude Oil
Pipelines
& Services Natural Gas
Pipelines
& Services Petrochemical
& Refined
Products
Services Segment
Total 
 Segment revenues: 
 Revenues from third parties $ 4,262 $ 5,883 $ 609 $ 2,718 $ 13,472 
 Revenues from related parties 3 5 3 – 11 
 Intersegment and intrasegment revenues 11,558 15,042 138 5,714 32,452 
 Total segment revenues 15,823 20,930 750 8,432 45,935 
 Significant segment expenses: 
 Cost of sales 13,957 20,467 269 7,710 42,403 
 Variable operating costs and expenses (1) 167 26 24 85 302 
 Fixed operating costs and expenses (2) 404 103 168 248 923 
 Total significant segment expenses 14,528 20,596 461 8,043 43,628 
 Other segment income: 
 
 Equity in income of unconsolidated affiliates 26 73 1 1 101 
 Other segment items (3) 4 10 3 2 19 
 Total other segment income 
 30 83 4 3 120 
 Total segment gross operating margin $ 1,325 $ 417 $ 293 $ 392 $ 2,427 
 
 Other financial information: 
 Capital expenditures $ 629 $ 44 $ 246 $ 345 $ 1,264 
 

 (1) Variable operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally fluctuate based on utilization. 
 (2) Fixed operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally remain constant independent of utilization. 
 (3) Other segment items for each segment primarily represent the following: 
 • NGL Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights and other miscellaneous segment items. 
 • Crude Oil Pipelines & Services – Other miscellaneous segment items. 
 • Natural Gas Pipelines & Services – Other miscellaneous segment items. 
 • Petrochemical & Refined Products Services – Other miscellaneous segment items. 
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 For the Six Months Ended June 30, 2024 
 NGL
Pipelines
& Services Crude Oil
Pipelines
& Services Natural Gas
Pipelines
& Services Petrochemical
& Refined
Products
Services Segment
Total 
 Segment revenues: 
 Revenues from third parties $ 9,399 $ 11,289 $ 1,460 $ 6,069 $ 28,217 
 Revenues from related parties 6 14 6 – 26 
 Intersegment and intrasegment revenues 23,113 28,869 315 12,038 64,335 
 Total segment revenues 32,518 40,172 1,781 18,107 92,578 
 Significant segment expenses: 
 Cost of sales 28,767 39,216 827 16,585 85,395 
 Variable operating costs and expenses (1) 341 72 39 179 631 
 Fixed operating costs and expenses (2) 829 207 318 497 1,851 
 Total significant segment expenses 29,937 39,495 1,184 17,261 87,877 
 Other segment income (expense): 
 Equity in income of unconsolidated affiliates 57 142 3 1 203 
 Other segment items (3) 27 9 5 ( 11 ) 30 
 Total other segment income (expense), net 84 151 8 ( 10 ) 233 
 Total segment gross operating margin $ 2,665 $ 828 $ 605 $ 836 $ 4,934 
 
 Other financial information: 
 Capital expenditures $ 1,206 $ 81 $ 450 $ 574 $ 2,311 
 

 (1) Variable operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally fluctuate based on utilization. 
 (2) Fixed operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally remain constant independent of utilization. 
 (3) Other segment items for each segment primarily represent the following: 
 • NGL Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights and other miscellaneous segment items. 
 • Crude Oil Pipelines & Services – Other miscellaneous segment items. 
 • Natural Gas Pipelines & Services – Other miscellaneous segment items. 
 • Petrochemical & Refined Products Services – Other miscellaneous segment items. 
 Segment revenues include intersegment and intrasegment transactions, which are generally based on transactions made at market-based rates. Our consolidated revenues reflect the elimination of intercompany transactions. The following table reconciles total segment revenues as reported in the preceding tables to consolidated revenues as presented on our Unaudited Condensed Statements of Consolidated Operations: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Segment revenues: 
 NGL Pipelines & Services $ 20,410 $ 15,823 $ 42,827 $ 32,518 
 Crude Oil Pipelines & Services 14,107 20,930 29,850 40,172 
 Natural Gas Pipelines & Services 1,273 750 2,726 1,781 
 Petrochemical & Refined Products Services 7,900 8,432 18,770 18,107 
 Total segment revenues 43,690 45,935 94,173 92,578 
 Elimination of intersegment and intrasegment revenues ( 32,327 ) ( 32,452 ) ( 67,393 ) ( 64,335 ) 
 Total consolidated revenues $ 11,363 $ 13,483 $ 26,780 $ 28,243 

 Segment expenses represent operating costs and expenses exclusive of (i) depreciation, amortization and accretion expenses (excluding amortization of major maintenance costs for reaction-based plants and amortization of finance lease right-of-use assets), (ii) impairment charges, and (iii) gains and losses attributable to asset sales and related matters. Segment expense presented in the tables above include intersegment and intrasegment transactions, which are generally based on transactions made at market-based rates. Additionally, the significant segment expense categories presented align with the manner in which our CODMs evaluate segment results. Our consolidated operating costs and expenses are inclusive of the aforementioned adjustments and reflect the elimination of intercompany transactions. 
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 The following table presents our segment assets, together with a reconciliation to our consolidated total assets, at the dates indicated: 
 
 June 30,
2025 December 31,
2024 
 NGL Pipelines & Services $ 22,457 $ 21,900 
 Crude Oil Pipelines & Services 11,234 11,390 
 Natural Gas Pipelines & Services 12,458 12,260 
 Petrochemical & Refined Products Services 11,281 11,350 
 Total segment assets 57,430 56,900 
 Construction in progress 4,900 4,138 
 Current assets 14,160 15,133 
 Other assets 952 997 
 Consolidated total assets $ 77,442 $ 77,168 

 Supplemental Revenue and Expense Information 
 The following table presents additional information regarding our consolidated revenues and costs and expenses for the periods indicated: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Consolidated revenues: 
 NGL Pipelines & Services $ 3,406 $ 4,265 $ 8,806 $ 9,405 
 Crude Oil Pipelines & Services 4,783 5,888 9,904 11,303 
 Natural Gas Pipelines & Services 1,071 612 2,292 1,466 
 Petrochemical & Refined Products Services 2,103 2,718 5,778 6,069 
 Total consolidated revenues $ 11,363 $ 13,483 $ 26,780 $ 28,243 
 
 Consolidated costs and expenses 
 Operating costs and expenses: 
 Cost of sales $ 7,899 $ 10,184 $ 19,904 $ 21,589 
 Other operating costs and expenses (1) 1,064 974 2,123 1,928 
 Depreciation, amortization and accretion 625 595 1,243 1,190 
 Asset impairment charges 11 4 21 24 
 Net losses (gains) attributable to asset sales and related matters 
 ( 7 ) 5 ( 9 ) 5 
 General and administrative costs 68 57 128 123 
 Total consolidated costs and expenses $ 9,660 $ 11,819 $ 23,410 $ 24,859 
 

 (1) Represents the cost of operating our plants, pipelines and other fixed assets excluding depreciation, amortization and accretion charges; asset impairment charges; and net gains attributable to asset sales and related matters. 
 Fluctuations in our product sales revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. In general, higher energy commodity prices result in an increase in our revenues attributable to product sales; however, these higher commodity prices would also be expected to increase the associated cost of sales as purchase costs are higher. The same type of relationship would be true in the case of lower energy commodity sales prices and purchase costs. 
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 Note 11 . Earnings Per Unit 
 The following table presents our calculation of basic and diluted earnings per common unit for the periods indicated: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 BASIC EARNINGS PER COMMON UNIT 
 Net income attributable to common unitholders $ 1,435 $ 1,405 $ 2,828 $ 2,861 
 Earnings allocated to phantom unit awards (1) ( 14 ) ( 13 ) ( 27 ) ( 27 ) 
 Net income allocated to common unitholders $ 1,421 $ 1,392 $ 2,801 $ 2,834 
 
 Basic weighted-average number of common units outstanding 2,168 2,171 2,167 2,171 
 
 Basic earnings per common unit $ 0.66 $ 0.64 $ 1.29 $ 1.31 
 
 DILUTED EARNINGS PER COMMON UNIT 
 Net income attributable to common unitholders $ 1,435 $ 1,405 $ 2,828 $ 2,861 
 Net income attributable to preferred units 1 1 2 2 
 Net income attributable to limited partners $ 1,436 $ 1,406 $ 2,830 $ 2,863 
 
 Diluted weighted-average number of units outstanding: 
 Distribution-bearing common units 2,168 2,171 2,167 2,171 
 Phantom units (2) 20 21 21 21 
 Preferred units (2) 2 2 2 2 
 Total 2,190 2,194 2,190 2,194 
 
 Diluted earnings per common unit $ 0.66 $ 0.64 $ 1.29 $ 1.30 
 

 (1) Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding our phantom units. 
 (2) We use the “if-converted method” to determine the potential dilutive effect of the vesting of phantom unit awards and the conversion of preferred units outstanding. See Note 13 for information regarding phantom unit awards. See Note 8 for information regarding preferred units. 
 
 Note 12 . Business Combination 
 Acquisition of Pinon Midstream 
 On October 28, 2024, we acquired Pinon Midstream for $ 953 million in cash consideration. We funded this transaction using cash on hand. 
 Pinon Midstream’s assets include 43 miles of natural gas gathering and redelivery pipelines, five 3-stage compressor stations, 270 million cubic feet per day (“MMcf/d”) of hydrogen sulfide and carbon dioxide treating facilities and two high capacity acid gas injection wells. 
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 The following table presents the preliminary fair value allocation of assets acquired and liabilities assumed in the acquisition at October 28, 2024 (the effective date of the acquisition). The allocation is provisional and subject to ongoing efforts to clarify the values assigned to tangible and identifiable intangible assets. 
 
 Purchase price for 100 % interest in Pinon Midstream 
 $ 953 
 Recognized amounts of identifiable assets acquired and liabilities assumed (1): 
 Cash and cash equivalents $ 4 
 Property, plant and equipment 410 
 Contract-based intangible asset 435 
 Total identifiable net assets $ 849 
 Goodwill $ 104 
 

 (1) As part of this transaction, we acquired other assets and assumed liabilities that net to a negligible amount. Acquired other assets primarily included accounts receivable and ROU assets. Assumed liabilities primarily included accounts payable and operating lease liabilities. None of these amounts were considered individually significant. 
 On a historical pro forma basis, our revenues, costs and expenses, operating income, net income attributable to common unitholders and earnings per unit for the three and six months ended June 30, 2024 would not have differed materially from those we actually reported had the acquisition been completed on January 1, 2024 rather than October 28, 2024. 
 
 Note 13 . Equity-Based Awards 
 An allocated portion of the fair value of EPCO’s equity-based awards is charged to us under the ASA. The following table summarizes compensation expense we recognized in connection with equity-based awards for the periods indicated: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Equity-classified awards: 
 Phantom unit awards $ 50 $ 45 $ 99 $ 91 
 Profits interest awards – – – 10 
 Total $ 50 $ 45 $ 99 $ 101 

 The fair value of equity-classified awards is amortized to earnings over the requisite service or vesting period. Equity-classified awards are expected to result in the issuance of the Partnership’s common units upon vesting. 
 Phantom Unit Awards 
 Subject to customary forfeiture provisions, phantom unit awards allow recipients to acquire the Partnership’s common units once a defined vesting period expires (at no cost to the recipient apart from fulfilling required service and other conditions). The following table presents phantom unit award activity for the period indicated: 
 
 Number of
Units Weighted-
Average Grant
Date Fair Value
per Unit (1) 
 Phantom unit awards at December 31, 2024 20,592,251 $ 25.21 
 Granted (2) 7,792,090 $ 33.12 
 Vested ( 7,630,601 ) $ 24.37 
 Forfeited ( 407,883 ) $ 28.32 
 Phantom unit awards at June 30, 2025 20,345,857 $ 28.49 
 

 (1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. 
 (2) The aggregate grant date fair value of phantom unit awards issued during 2025 was $ 258 million based on a grant date market price of the Partnership’s common units ranging from $ 33.12 to $ 33.21 per unit. An estimated annual forfeiture rate of 2.0 % was applied to these awards. 
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 Each phantom unit award includes a DER, which entitles the participant to nonforfeitable cash payments equal to the product of the number of phantom unit awards outstanding for the participant and the cash distribution per common unit paid by the Partnership to its common unitholders. Cash payments made in connection with DERs are charged to partners’ equity when the phantom unit award is expected to result in the issuance of common units; otherwise, such amounts are expensed. 
 The following table presents supplemental information regarding phantom unit awards for the periods indicated: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Cash payments made in connection with DERs $ 11 $ 11 $ 22 $ 21 
 Total intrinsic value of phantom unit awards that vested during period 9 7 256 194 

 For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $ 322 million at June 30, 2025 , of which our share of such cost is currently estimated to be $ 261 million. Due to the graded vesting provisions of these awards, we expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.2 years. 
 
 Note 14 . Hedging Activities and Fair Value Measurements 
 In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with assets, liabilities and certain anticipated future transactions, we use derivative instruments such as futures, forward contracts, swaps, options and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities. 
 Interest Rate Hedging Activities 
 We may utilize interest rate swaps, forward-starting swaps, options to enter into forward-starting swaps (“swaptions”), treasury locks and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain consolidated debt agreements. This strategy may be used in controlling our overall cost of capital associated with such borrowings. 
 Treasury Locks 
 A treasury lock is an agreement that fixes the price (or yield) of a specified U.S. treasury security for an established period of time. We use treasury lock agreements to hedge our exposure to interest rate changes and to reduce the volatility of financing costs on an expected future debt issuance. Each of our treasury lock transactions was designated as a cash flow hedge of interest payments associated with an anticipated debt issuance. 
 During 2025, we entered into four treasury lock transactions to fix the seven-year treasury rate at a weighted-average rate of approximately 3.98 % on an aggregate notional amount of $ 750 million. The purpose of these transactions was to hedge the underlying interest rate risk associated with debt issuances that occurred in June 2025. Upon settlement of these treasury lock transactions in May 2025, we received total cash proceeds of $ 14 million. As cash flow hedges, gains on these derivative instruments are reflected as a component of accumulated other comprehensive income and will be amortized to earnings as a component of interest expense over seven years . 
 Commodity Hedging Activities 
 The prices of natural gas, NGLs, crude oil, petrochemicals and refined products, and power are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control. In order to manage such price risks, we enter into commodity derivative instruments such as physical forward contracts, futures contracts, fixed-for-float swaps and basis swaps. 
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 At June 30, 2025 , our predominant commodity hedging strategies consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities, (ii) hedging natural gas processing margins, (iii) hedging the fair value of commodity products held in inventory and (iv) hedging anticipated future purchases of power for certain operations in Southeast Texas. 
 • The objective of our anticipated future commodity purchases and sales hedging program is to hedge the margins of certain transportation, storage, blending and operational activities by locking in purchase and sale prices through the use of derivative instruments and related contracts. 
 • The objective of our natural gas processing hedging program is to hedge an amount of earnings associated with these activities. We achieve this objective by executing fixed-price sales for a portion of our expected equity production using derivative instruments and related contracts. For certain natural gas processing contracts, the hedging of expected equity NGL production also involves the purchase of natural gas for plant thermal reduction, which is hedged using derivative instruments and related contracts. 
 • The objective of our inventory hedging program is to hedge the fair value of commodity products currently held in inventory by locking in the sales price of the inventory through the use of derivative instruments and related contracts. 
 • The objective of our commercial energy hedging program is to hedge anticipated future purchases of power for certain operations in Southeast Texas by locking in purchase prices through the use of derivative instruments and related contracts. 
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 The following table summarizes our portfolio of commodity derivative instruments outstanding at June 30, 2025 (volume measures as noted): 
 
 Volume (1) Accounting
Treatment 
 Derivative Purpose Current (2) 
 Long-Term (2) 
 
 Derivatives designated as hedging instruments: 
 Natural gas processing: 
 Forecasted sales of natural gas (Bcf) 36.5 18.4 Cash flow hedge 
 Forecasted sales of NGLs (MMBbls) 4.6 0.4 Cash flow hedge 
 Octane enhancement: 
 Forecasted sales of octane enhancement products (MMBbls) 2.5 0.1 Cash flow hedge 
 Natural gas marketing: 
 Natural gas storage inventory management activities (Bcf) 2.0 n/a Fair value hedge 
 NGL marketing: 
 Forecasted purchases of NGLs and related hydrocarbon products (MMBbls) 216.3 17.4 Cash flow hedge 
 Forecasted sales of NGLs and related hydrocarbon products (MMBbls) 214.2 19.0 Cash flow hedge 
 Refined products marketing: 
 Forecasted purchases of refined products (MMBbls) 3.4 n/a Cash flow hedge 
 Forecasted sales of refined products (MMBbls) 3.6 n/a Cash flow hedge 
 Crude oil marketing: 
 Forecasted purchases of crude oil (MMBbls) 16.6 7.2 Cash flow hedge 
 Forecasted sales of crude oil (MMBbls) 23.2 14.3 Cash flow hedge 
 Petrochemical marketing: 
 Forecasted sales of petrochemical products (MMBbls) 0.1 n/a Cash flow hedge 
 Commercial energy: 
 Forecasted purchases of power related to asset operations (terawatt hours (“TWh”)) 1.2 0.7 Cash flow hedge 
 
 Derivatives not designated as hedging instruments: 
 Natural gas risk management activities (Bcf) (3) 64.9 n/a Mark-to-market 
 NGL risk management activities (MMBbls) (3) 22.4 11.6 Mark-to-market 
 Refined products risk management activities (MMBbls) (3) 3.5 n/a Mark-to-market 
 Crude oil risk management activities (MMBbls) (3) 90.9 0.5 Mark-to-market 
 Petrochemical risk management activities (MMBbls) (3) 
 0.3 n/a 
 Mark-to-market 
 Commercial energy risk management activities (TWh) (3) n/a 0.1 Mark-to-market 
 

 (1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes. 
 (2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2027, December 2025 and August 2028, respectively. 
 (3) Reflects the use of derivative instruments to manage risks associated with our transportation, processing and storage assets. 
 The carrying amount of our inventories subject to fair value hedges was $ 7 million and $ 11 million at June 30, 2025 and December 31, 2024 , respectively. 
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 Tabular Presentation of Fair Value Amounts, and Gains and Losses on 
 Derivative Instruments and Related Hedged Items 
 The following table provides a balance sheet overview of our derivative assets and liabilities at the dates indicated: 
 
 Asset Derivatives Liability Derivatives 
 June 30, 2025 December 31, 2024 June 30, 2025 December 31, 2024 
 Balance
Sheet
Location Fair
Value Balance
Sheet
Location Fair
Value Balance
Sheet
Location Fair
Value Balance
Sheet
Location Fair
Value 
 Derivatives designated as hedging instruments 
 
 Commodity derivatives Current
assets $ 232 Current
assets $ 210 Current
liabilities $ 209 Current
liabilities $ 178 
 Commodity derivatives Other assets 28 Other assets 22 Other liabilities 19 Other liabilities 4 
 Total commodity derivatives 260 232 228 182 
 Total derivatives designated as hedging instruments $ 260 $ 232 $ 228 $ 182 
 
 Derivatives not designated as hedging instruments 
 Commodity derivatives Current
assets $ 457 Current
assets $ 324 Current
liabilities $ 418 Current
liabilities $ 293 
 Commodity derivatives Other assets 2 Other assets 19 Other liabilities 1 Other liabilities 20 
 Total commodity derivatives 459 343 419 313 
 Total derivatives not designated as hedging instruments $ 459 $ 343 $ 419 $ 313 

 Certain of our commodity derivative instruments are subject to master netting arrangements or similar agreements. The following tables present our derivative instruments subject to such arrangements at the dates indicated: 
 
 Offsetting of Financial Assets and Derivative Assets 
 Gross
Amounts of
Recognized
Assets Gross
Amounts
Offset in the
Balance Sheet Amounts
of Assets
Presented
in the
Balance Sheet Gross Amounts Not Offset
 in the Balance Sheet Amounts That
Would Have
Been Presented
On Net Basis 
 Financial
Instruments Cash
Collateral
Received Cash
Collateral
Paid 
 (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) 
 As of June 30, 2025: 
 
 Commodity derivatives $ 719 $ – $ 719 $ ( 644 ) $ ( 74 ) $ – $ 1 
 As of December 31, 2024: 
 Commodity derivatives $ 575 $ – $ 575 $ ( 495 ) $ ( 79 ) $ – $ 1 

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 Offsetting of Financial Liabilities and Derivative Liabilities 
 Gross
Amounts of
Recognized
Liabilities Gross
Amounts
Offset in the
Balance Sheet Amounts
of Liabilities
Presented
in the
Balance Sheet Gross Amounts Not Offset
 in the Balance Sheet Amounts That
Would Have
Been Presented
On Net Basis 
 Financial
Instruments Cash
Collateral
Received Cash
Collateral
Paid 
 (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) 
 As of June 30, 2025: 
 Commodity derivatives $ 647 $ – $ 647 $ ( 644 ) $ – $ – $ 3 
 As of December 31, 2024: 
 Commodity derivatives $ 495 $ – $ 495 $ ( 495 ) $ – $ – $ – 

 Derivative assets and liabilities recorded on our Unaudited Condensed Consolidated Balance Sheets are presented on a gross-basis and determined at the individual transaction level. The tabular presentation above provides a means for comparing the gross amount of derivative assets and liabilities, excluding associated accounts payable and receivable, to the net amount that would likely be receivable or payable under a default scenario based on the existence of rights of offset in the respective derivative agreements. Any cash collateral paid or received is reflected in these tables, but only to the extent that it represents variation margins. Any amounts associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from these tables. 
 The following tables present the effect of our derivative instruments designated as fair value hedges on our Unaudited Condensed Statements of Consolidated Operations for the periods indicated: 
 
 Derivatives in Fair Value
Hedging Relationships Location Gain (Loss) Recognized in
Income on Derivative 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Commodity derivatives Revenue $ 3 $ – $ 4 $ 1 
 Total $ 3 $ – $ 4 $ 1 

 
 Derivatives in Fair Value
Hedging Relationships Location Gain (Loss) Recognized in
Income on Hedged Item 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Commodity derivatives Revenue $ ( 2 ) $ 1 $ ( 2 ) $ 5 
 Total $ ( 2 ) $ 1 $ ( 2 ) $ 5 

 The gain (loss) corresponding to the hedge ineffectiveness on the fair value hedges was negligible for all periods presented. The remaining gain (loss) for each period presented is primarily attributable to prompt-to-forward month price differentials that were excluded from the assessment of hedge effectiveness. 
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 The following tables present the effect of our derivative instruments designated as cash flow hedges on our Unaudited Condensed Statements of Consolidated Operations and Unaudited Condensed Statements of Consolidated Comprehensive Income for the periods indicated: 
 
 Derivatives in Cash Flow
Hedging Relationships Change in Value Recognized in 
 Other Comprehensive Income (Loss) on Derivative 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Interest rate derivatives $ 12 $ – $ 14 $ 2 
 Commodity derivatives – Revenue (1) 19 74 37 ( 75 ) 
 Commodity derivatives – Operating costs and expenses (1) ( 19 ) 5 ( 15 ) ( 8 ) 
 Total $ 12 $ 79 $ 36 $ ( 81 ) 
 

 (1) The fair value of these derivative instruments will be reclassified to their respective locations on the Unaudited Condensed Statement of Consolidated Operations when the forecasted transactions affect earnings. 
 
 Derivatives in Cash Flow
Hedging Relationships Location Gain (Loss) Reclassified from 
 Accumulated Other Comprehensive Income (Loss) to Income 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Interest rate derivatives Interest expense $ 2 $ 1 $ 3 $ 3 
 Commodity derivatives Revenue 67 61 53 80 
 Commodity derivatives Operating costs and expenses ( 8 ) ( 16 ) ( 20 ) ( 33 ) 
 Total $ 61 $ 46 $ 36 $ 50 

 Over the next twelve months, we expect to reclassify $ 8 million of gains attributable to interest rate derivative instruments from accumulated other comprehensive income to earnings as a decrease in interest expense. Likewise, we expect to reclassify $ 83 million of net gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, with $ 80 million as an increase in revenue and $ 3 million as a decrease in operating costs and expenses. 
 The following table presents the effect of our derivative instruments not designated as hedging instruments on our Unaudited Condensed Statements of Consolidated Operations for the periods indicated: 
 
 Derivatives Not Designated
as Hedging Instruments Location Gain (Loss) Recognized in
Income on Derivative 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Commodity derivatives Revenue $ 68 $ ( 5 ) $ 47 $ 8 
 Commodity derivatives Operating costs and expenses 3 – 1 ( 1 ) 
 Total $ 71 $ ( 5 ) $ 48 $ 7 

 The $ 48 million net gain recognized for the six months ended June 30, 2025 (as noted in the preceding table) from derivatives not designated as hedging instruments consists of $ 35 million of net realized gains and $ 13 million of net unrealized mark-to-market gains attributable to commodity derivatives. 
 Fair Value Measurements 
 The following tables set forth, by level within the Level 1, 2 and 3 fair value hierarchy, the carrying values of our financial assets and liabilities at the dates indicated. These assets and liabilities are measured on a recurring basis and are classified based on the lowest level of input used to estimate their fair value. Our assessment of the relative significance of such inputs requires judgment. 
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 The values for commodity derivatives are presented before and after the application of CME Rule 814, which deems that financial instruments cleared by the CME are settled daily in connection with variation margin payments. As a result of this exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. Derivative transactions cleared on exchanges other than the CME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis. 
 
 At June 30, 2025
Fair Value Measurements Using 
 Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1) Significant
Other
Observable
Inputs
(Level 2) Significant
Unobservable
Inputs
(Level 3) Total 
 Financial assets: 
 
 Commodity derivatives: 
 Value before application of CME Rule 814 $ 564 $ 507 $ 1 $ 1,072 
 Impact of CME Rule 814 ( 147 ) ( 206 ) – ( 353 ) 
 Total commodity derivatives 417 301 1 719 
 Total $ 417 $ 301 $ 1 $ 719 
 
 Financial liabilities: 
 Commodity derivatives: 
 Value before application of CME Rule 814 $ 449 $ 553 $ 1 $ 1,003 
 Impact of CME Rule 814 ( 73 ) ( 283 ) – ( 356 ) 
 Total commodity derivatives 376 270 1 647 
 Total $ 376 $ 270 $ 1 $ 647 

 
 At December 31, 2024
Fair Value Measurements Using 
 Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1) Significant
Other
Observable
Inputs
(Level 2) Significant
Unobservable
Inputs
(Level 3) Total 
 Financial assets: 
 Commodity derivatives: 
 Value before application of CME Rule 814 $ 355 $ 443 $ – $ 798 
 Impact of CME Rule 814 ( 56 ) ( 167 ) – ( 223 ) 
 Total commodity derivatives 299 276 – 575 
 Total $ 299 $ 276 $ – $ 575 
 
 Financial liabilities: 
 Commodity derivatives: 
 Value before application of CME Rule 814 $ 291 $ 404 $ 21 $ 716 
 Impact of CME Rule 814 ( 43 ) ( 157 ) ( 21 ) ( 221 ) 
 Total commodity derivatives 248 247 – 495 
 Total $ 248 $ 247 $ – $ 495 

 In the aggregate, the fair value of our commodity hedging portfolios at June 30, 2025 was a net derivative asset of $ 69 million prior to the impact of CME Rule 814. 
 Financial assets and liabilities recorded on the balance sheet at June 30, 2025 using significant unobservable inputs (Level 3) are not material to the Unaudited Condensed Consolidated Financial Statements. 
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 Other Fair Value Information 
 The carrying amounts of cash and cash equivalents (including restricted cash balances), accounts receivable, commercial paper notes and accounts payable approximate their fair values based on their short-term nature. The estimated total fair value of our fixed-rate debt obligations was $ 30.2 billion and $ 28.9 billion at June 30, 2025 and December 31, 2024 , respectively. The aggregate carrying value of these debt obligations was $ 32.5 billion and $ 31.6 billion at June 30, 2025 and December 31, 2024 , respectively. These values are primarily based on quoted market prices for such debt or debt of similar terms and maturities (Level 2) and our credit standing. Changes in market rates of interest affect the fair value of our fixed-rate debt. The carrying values of our variable-rate long-term debt obligations approximate their fair values since the associated interest rates are market-based. We do not have any long-term investments in debt or equity securities recorded at fair value. 
 
 Note 15 . Related Party Transactions 
 The following table summarizes our related party transactions for the periods indicated: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Revenues – related parties: 
 Unconsolidated affiliates $ 11 $ 11 $ 24 $ 26 
 Costs and expenses – related parties: 
 EPCO and its privately held affiliates $ 409 $ 362 $ 796 $ 718 
 Unconsolidated affiliates 37 40 75 86 
 Total $ 446 $ 402 $ 871 $ 804 

 The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated: 
 
 June 30,
2025 December 31,
2024 
 Accounts receivable - related parties: 
 Unconsolidated affiliates $ 2 $ 4 
 
 Accounts payable - related parties: 
 EPCO and its privately held affiliates $ 114 $ 180 
 Unconsolidated affiliates 14 18 
 Total $ 128 $ 198 

 We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties. 
 Relationship with EPCO and Affiliates 
 We have an extensive and ongoing relationship with EPCO and its privately held affiliates (including Enterprise GP, our general partner), which are not a part of our consolidated group of companies. 
 At June 30, 2025 , EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us: 
 
 Total Number of Limited Partner Interests Held Percentage of
Common Units
Outstanding 
 702,234,756 common units 32.4 % 

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 Of the total number of Partnership common units held by EPCO and its privately held affiliates, 59,976,464 have been pledged as security under the separate credit facilities of EPCO and its privately held affiliates at June 30, 2025 . These credit facilities contain customary and other events of default, including defaults by us and other affiliates of EPCO. An event of default, followed by a foreclosure on the pledged collateral, could ultimately result in a change in ownership of these units and affect the market price of the Partnership’s common units. 
 The Partnership and Enterprise GP are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are also separate from those of EPCO and its other affiliates. EPCO and its privately held affiliates use cash on hand and cash distributions they receive from us and other investments to fund their other activities and to meet their respective debt obligations, if any. During the six months ended June 30, 2025 and 2024 , we paid EPCO and its privately held affiliates cash distributions totaling $ 727 million and $ 700 million, respectively. 
 We have no employees. All of our administrative and operating functions are provided either by employees of EPCO (pursuant to the ASA) or by other service providers. We and our general partner are parties to the ASA. The following table presents our related party costs and expenses attributable to the ASA with EPCO for the periods indicated: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Operating costs and expenses $ 364 $ 319 $ 715 $ 633 
 General and administrative expenses 39 38 68 74 
 Total costs and expenses $ 403 $ 357 $ 783 $ 707 

 We lease office space from privately held affiliates of EPCO. For the three months ended June 30, 2025 and 2024 , we recognized $ 6 million and $ 4 million , respectively, of related party operating lease expense in connection with these office space leases. For the six months ended June 30, 2025 and 2024 , we recognized $ 12 million and $ 7 million, respectively, of related party operating lease expense in connection with these office space leases. 
 
 Note 16 . Income Taxes 
 Income taxes are accounted for under the asset-and-liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. We recognize the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs. We did not rely on any uncertain tax positions in recording our income tax-related amounts during the three and six months ended June 30, 2025 and 2024 . 
 Our federal, state and foreign income tax benefit (provision) is summarized below: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Current portion of income tax provision: 
 Federal $ – $ – $ ( 1 ) $ – 
 State ( 11 ) ( 10 ) ( 23 ) ( 22 ) 
 Total current portion ( 11 ) ( 10 ) ( 24 ) ( 22 ) 
 Deferred portion of income tax provision: 
 Federal ( 4 ) ( 4 ) ( 8 ) ( 8 ) 
 State ( 1 ) ( 1 ) ( 8 ) ( 6 ) 
 Total deferred portion ( 5 ) ( 5 ) ( 16 ) ( 14 ) 
 Total provision for income taxes $ ( 16 ) $ ( 15 ) $ ( 40 ) $ ( 36 ) 

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 A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Pre-Tax Net Book Income (“NBI”) $ 1,470 $ 1,437 $ 2,900 $ 2,941 
 
 Texas Margin Tax (1) ( 11 ) ( 10 ) ( 30 ) ( 27 ) 
 State income tax provision, net of federal benefit – – ( 1 ) – 
 Federal income tax provision computed by applying the federal statutory rate to NBI of corporate entities ( 5 ) ( 5 ) ( 9 ) ( 8 ) 
 Other – – – ( 1 ) 
 Provision for income taxes $ ( 16 ) $ ( 15 ) $ ( 40 ) $ ( 36 ) 
 
 Effective income tax rate ( 1.1 ) % ( 1.0 ) % ( 1.4 ) % ( 1.2 ) % 
 

 (1) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses. 
 The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated: 
 
 June 30,
2025 December 31,
2024 
 Deferred tax liabilities: 
 Attributable to investment in OTA (1) $ 483 $ 462 
 Attributable to property, plant and equipment 158 151 
 Attributable to investments in other entities 4 5 
 Other 98 98 
 Total deferred tax liabilities 743 716 
 Deferred tax assets: 
 Net operating loss carryovers (2) 68 56 
 Temporary differences related to Texas Margin Tax 3 4 
 Total deferred tax assets 71 60 
 Total net deferred tax liabilities $ 672 $ 656 
 

 (1) Represents the deferred tax liability balance held by our wholly owned subsidiary, OTA Holdings, Inc. (“OTA”), which we acquired in March 2020. 
 (2) The loss amount presented as of June 30, 2025 has an indefinite carryover period. All losses are subject to limitations on their utilization. 
 
 Note 17 . Commitments and Contingent Liabilities 
 Litigation 
 As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from future legal proceedings. We will vigorously defend the Partnership in litigation matters. 
 There were no accruals for litigation contingencies at June 30, 2025 and December 31, 2024 , respectively. 
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 Contractual Obligations 
 Scheduled Maturities of Debt 
 We have long-term and short-term payment obligations under debt agreements. In total, the principal amount of our consolidated debt obligations were $ 33.1 billion and $ 32.2 billion at June 30, 2025 and December 31, 2024 , respectively. See Note 7 for additional information regarding our scheduled future maturities of debt principal. 
 Lease Accounting Matters 
 There has been no significant change in our operating and finance lease obligations since those disclosed in the 2024 Form 10-K. 
 The following table presents information regarding operating and finance leases where we are the lessee at June 30, 2025 : 
 
 Asset Category ROU 
 Asset 
 Carrying 
 Value (1) 
 Lease 
 Liability 
 Carrying 
 Value (2) 
 Weighted-
Average
Remaining
Term Weighted- 
 Average 
 Discount 
 Rate (3) 
 
 Operating leases 
 Storage and pipeline facilities $ 193 $ 191 8 years 4.5 % 
 Transportation equipment 37 38 3 years 4.8 % 
 Office and warehouse space 165 199 11 years 3.3 % 
 Total operating leases 395 428 
 Finance leases 
 Transportation equipment 18 18 4 years 4.8 % 
 Total finance leases 18 18 
 Total leases $ 413 $ 446 
 

 (1) ROU asset amounts are a component of “ Other assets ” on our Unaudited Condensed Consolidated Balance Sheet. 
 (2) At June 30, 2025, operating lease liabilities of $ 99 million and $ 329 million were included within “ Other current liabilities ” and “ Other long-term liabilities ,” respectively. Additionally at June 30, 2025, finance lease liabilities of $ 3 million and $ 15 million were included within “ Other current liabilities” and “ Other long-term liabilities ,” respectively. 
 (3) The discount rate for each category of assets represents the weighted average of either (i) the implicit rate applicable to the underlying leases (where determinable) or (ii) our incremental borrowing rate adjusted for collateralization (if the implicit rate is not determinable). In general, the discount rates are based on either information available at the lease commencement date or January 1, 2019 for leases existing at the adoption date for ASC 842, Leases . 
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 The following table disaggregates our total operating and finance lease expense for the periods indicated: 
 
 For the Three Months
Ended June 30, For the Six Months
Ended June 30, 
 2025 2024 2025 2024 
 Long-term leases: 
 Fixed operating lease expense: 
 Non-cash lease expense (amortization of ROU assets) $ 27 $ 23 $ 55 $ 43 
 Related accretion expense on lease liability balances 5 4 9 8 
 Total fixed operating lease expense 32 27 64 51 
 Fixed finance lease expense: 
 Amortization of ROU assets 1 – 1 – 
 Interest on finance lease liabilities 1 – 1 – 
 Total fixed finance lease expense 2 – 2 – 
 Variable lease expense 4 4 9 8 
 Total long-term lease expense 38 31 75 59 
 Short-term leases 38 30 73 59 
 Total lease expense $ 76 $ 61 $ 148 $ 118 
 

 
 
 Cash paid for operating lease liabilities was $ 32 million and $ 27 million for the three months ended June 30, 2025 and 2024 , respectively. For the six months ended June 30, 2025 and 2024, c ash paid for operating lease liabilities was $ 66 million and $ 57 million, respectively. Cash paid for finance leases was $ 1 million for the three and six months ended June 30, 2025. 
 Operating lease income for each of the three months ended June 30, 2025 and 2024 was $ 3 million . Operating lease income for each of the six months ended June 30, 2025 and 2024 was $ 7 million. 
 Purchase Obligations 
 We have contractual future product purchase commitments for NGLs and crude oil representing enforceable and legally binding agreements as of the reporting date. In the ordinary course of business, we fulfill product purchase commitments with our third party suppliers. Outside of changes related to the ordinary course of business, our consolidated product purchase commitments at June 30, 2025 did not differ materially from those reported in our 2024 Form 10-K. 
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 Note 18 . Supplemental Cash Flow Information 
 The following table provides information regarding the net effect of changes in our operating accounts and cash payments for interest and income taxes for the periods indicated: 
 
 For the Six Months
Ended June 30, 
 2025 2024 
 Decrease (increase) in: 
 Accounts receivable – trade $ 1,680 $ ( 867 ) 
 Accounts receivable – related parties 2 ( 3 ) 
 Inventories 56 ( 11 ) 
 Prepaid and other current assets ( 128 ) ( 110 ) 
 Other assets 47 3 
 Increase (decrease) in: 
 Accounts payable – trade ( 94 ) ( 201 ) 
 Accounts payable – related parties ( 70 ) ( 90 ) 
 Accrued product payables ( 1,131 ) 943 
 Accrued interest ( 16 ) 32 
 Other current liabilities ( 104 ) ( 143 ) 
 Other long-term liabilities ( 89 ) ( 80 ) 
 Net effect of changes in operating accounts $ 153 $ ( 527 ) 
 
 Cash payments for interest, net of $ 98 and $ 51 capitalized during the six months ended June 30, 2025 and 2024, respectively 
 $ 680 $ 623 
 
 Cash payments for federal and state income taxes $ 12 $ 19 

 We incurred liabilities for construction in progress that had not been paid at June 30, 2025 and December 31, 2024 of $ 595 million and $ 490 million, respectively. Such amounts are not included under the caption “Capital expenditures” on the Unaudited Condensed Statements of Consolidated Cash Flows. 
 
 Note 19. Subsequent Event 
 In July 2025, an affiliate of Enterprise agreed to acquire an affiliate of Occidental Petroleum Corporation (“Oxy”), which owns approximately 200 miles of natural gas gathering pipelines in the Midland Basin, in a debt-free transaction for $ 580 million in cash consideration (subject to adjustment in accordance with the agreement). In addition, an affiliate of Enterprise has agreed to provide Oxy with natural gas gathering and processing services, supported by a long-term dedication of approximately 73,000 acres across four counties in the Midland Basin. Completion of the acquisition is subject to customary regulatory approvals and closing conditions. The acquisition is expected to close in the third quarter of 2025. 
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Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.
ENTERPRISE PRODUCTS PARTNERS L.P. 10-Q

Item 1. Financial Statements
