EPD 10-Q Quarterly Report Sept. 30, 2025

ENTERPRISE PRODUCTS PARTNERS L.P.

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PROXIES

DEF 14A	Filed on Nov. 22, 2022
DEF 14A	Filed on Oct. 24, 2022
DEF 14A	Filed on Aug. 26, 2013

epd-20250930

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2025

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___ to ___.

Commission file number: 1-14323

ENTERPRISE PRODUCTS PARTNERS L.P.

(Exact Name of Registrant as Specified in Its Charter)


Delaware						76-0568219
(State or Other Jurisdiction of Incorporation or Organization)						(I.R.S. Employer Identification No.)


1100 Louisiana Street, 10th Floor
Houston , Texas 77002
(Address of Principal Executive Offices, including Zip Code)
( 713 ) 381-6500
(Registrant’s Telephone Number, including Area Code)

Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:


Title of Each Class	Trading Symbol(s)	Name of Each Exchange On Which Registered
Common Units	EPD	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


Large Accelerated Filer ☑			Accelerated filer ☐
Non-accelerated filer ☐			Smaller reporting company ☐
Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

There were 2,163,321,050 common units of Enterprise Products Partners L.P. outstanding at the close of business on October 31, 2025 .

Table of Contents

ENTERPRISE PRODUCTS PARTNERS L.P.

TABLE OF CONTENTS


		Page No.
PART I. FINANCIAL INFORMATION.
Item 1.	Financial Statements.
	Unaudited Condensed Consolidated Balance Sheets	2
	Unaudited Condensed Statements of Consolidated Operations	3
	Unaudited Condensed Statements of Consolidated Comprehensive Income	4
	Unaudited Condensed Statements of Consolidated Cash Flows	5
	Unaudited Condensed Statements of Consolidated Equity	6
	Notes to Unaudited Condensed Consolidated Financial Statements:
	1. Partnership Organization and Operations	9
	2. Summary of Significant Accounting Policies	9
	3. Inventories	10
	4. Property, Plant and Equipment	11
	5. Investments in Unconsolidated Affiliates	12
	6. Intangible Assets and Goodwill	13
	7. Debt Obligations	14
	8. Capital Accounts	16
	9. Revenues	19
	10. Business Segments and Related Information	21
	11. Earnings Per Unit	28
	12. Acquisitions	28
	13. Equity-Based Awards	30
	14. Hedging Activities and Fair Value Measurements	31
	15. Related Party Transactions	37
	16. Income Taxes	38
	17. Commitments and Contingent Liabilities	40
	18. Supplemental Cash Flow Information	42

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	43
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	69
Item 4.	Controls and Procedures.	71

PART II. OTHER INFORMATION.
Item 1.	Legal Proceedings.	72
Item 1A.	Risk Factors.	73
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	74
Item 3.	Defaults Upon Senior Securities.	75
Item 4.	Mine Safety Disclosures.	75
Item 5.	Other Information.	75
Item 6.	Exhibits.	75

Signatures		82

Table of Contents

PART I. FINANCIAL INFORMATION.

ITEM 1. FINANCIAL STATEMENTS.

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)


	September 30, 2025		December 31, 2024
ASSETS
Current assets:
Cash and cash equivalents	$	206	$	583
Restricted cash	226		255
Accounts receivable – trade, net of allowance for credit losses of $ 37 at September 30, 2025 and $ 38 at December 31, 2024	7,515		9,236
Accounts receivable – related parties	1		4
Inventories (see Note 3)	4,160		3,955
Derivative assets (see Note 14)	452		534
Prepaid and other current assets	677		566
Total current assets	13,237		15,133
Property, plant and equipment, net (see Note 4)	51,511		49,062
Investments in unconsolidated affiliates (see Note 5)	2,201		2,259
Intangible assets, net (see Note 6)	4,207		4,005
Goodwill (see Note 6)	5,712		5,712
Other assets	954		997
Total assets	$	77,822	$	77,168

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt (see Note 7)	$	2,464	$	1,150
Accounts payable – trade	1,359		1,227
Accounts payable – related parties	161		198
Accrued product payables	9,532		10,777
Accrued interest	288		536
Derivative liabilities (see Note 14)	398		471
Other current liabilities	848		818
Total current liabilities	15,050		15,177
Long-term debt (see Note 7)	31,114		30,746
Deferred tax liabilities (see Note 16 )	655		656
Other long-term liabilities	903		950
Commitments and contingent liabilities (see Note 17)
Redeemable preferred limited partner interests: (see Note 8)
Series A cumulative convertible preferred units (“preferred units”) ( 50,978 units outstanding at September 30, 2025 and 50,687 units outstanding at December 31, 2024)	50		50
Equity: (see Note 8)
Partners’ equity:
Common limited partner interests ( 2,163,126,578 units issued and outstanding at September 30, 2025, 2,165,699,962 units issued and outstanding at December 31, 2024)	30,242		29,793
Treasury units, at cost	( 1,297 )		( 1,297 )
Accumulated other comprehensive income	264		236
Total partners’ equity	29,209		28,732
Noncontrolling interests in consolidated subsidiaries	841		857
Total equity	30,050		29,589
Total liabilities, preferred units, and equity	$	77,822	$	77,168

See Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(Dollars in millions, except per unit amounts)


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Revenues:
Third parties	$	12,009	$	13,759	$	38,765	$	41,976
Related parties	14		16		38		42
Total revenues (see Note 9)	12,023		13,775		38,803		42,018
Costs and expenses:
Operating costs and expenses:
Third party and other costs	9,956		11,661		32,442		35,672
Related parties	410		372		1,206		1,097
Total operating costs and expenses	10,366		12,033		33,648		36,769
General and administrative costs:
Third party and other costs	24		19		77		63
Related parties	37		42		112		121
Total general and administrative costs	61		61		189		184
Total costs and expenses (see Note 10)	10,427		12,094		33,837		36,953
Equity in income of unconsolidated affiliates	90		99		276		302
Operating income	1,686		1,780		5,242		5,367
Other income (expense):
Interest expense	( 354 )		( 343 )		( 1,026 )		( 1,006 )
Interest income	9		14		23		31
Other, net	2		–		4		–
Total other expense, net	( 343 )		( 329 )		( 999 )		( 975 )
Income before income taxes	1,343		1,451		4,243		4,392
Benefit from (provision for) income taxes (see Note 16)	13		( 19 )		( 27 )		( 55 )
Net income	1,356		1,432		4,216		4,337
Net income attributable to noncontrolling interests	( 17 )		( 14 )		( 47 )		( 56 )
Net income attributable to preferred units	( 1 )		( 1 )		( 3 )		( 3 )
Net income attributable to common unitholders	$	1,338	$	1,417	$	4,166	$	4,278

Earnings per unit: (see Note 11)
Basic earnings per common unit	$	0.61	$	0.65	$	1.91	$	1.95
Diluted earnings per common unit	$	0.61	$	0.65	$	1.90	$	1.95

See Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED

COMPREHENSIVE INCOME

(Dollars in millions)


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024

Net income	$	1,356	$	1,432	$	4,216	$	4,337
Other comprehensive income (loss):
Cash flow hedges: (see Note 14)
Commodity hedging derivative instruments:
Changes in fair value of cash flow hedges	65		210		87		127
Reclassification of gains to net income	( 35 )		( 77 )		( 68 )		( 124 )
Interest rate hedging derivative instruments:
Changes in fair value of cash flow hedges	–		( 4 )		14		( 2 )
Reclassification of gains to net income	( 2 )		( 2 )		( 5 )		( 5 )
Total cash flow hedges	28		127		28		( 4 )
Total other comprehensive income (loss)	28		127		28		( 4 )
Comprehensive income	1,384		1,559		4,244		4,333
Comprehensive income attributable to noncontrolling interests	( 17 )		( 14 )		( 47 )		( 56 )
Comprehensive income attributable to preferred units	( 1 )		( 1 )		( 3 )		( 3 )
Comprehensive income attributable to common unitholders	$	1,366	$	1,544	$	4,194	$	4,274

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 Nine Months Ended September 30,
	2025		2024
Operating activities:
Net income	$	4,216	$	4,337
Reconciliation of net income to net cash flow provided by operating activities:
Depreciation and accretion	1,561		1,479
Amortization of intangible assets	159		155
Amortization of major maintenance costs for reaction-based plants	49		42
Other amortization expense	170		169
Impairment of assets other than goodwill	38		51
Equity in income of unconsolidated affiliates	( 276 )		( 302 )
Distributions received from unconsolidated affiliates attributable to earnings	280		303
Net losses (gains) attributable to asset sales and related matters	( 13 )		5
Deferred income tax expense (benefit)	( 1 )		23
Change in fair market value of derivative instruments	24		( 11 )
Non-cash expense related to long-term operating leases (see Note 17)	82		68
Net effect of changes in operating accounts (see Note 18)	( 169 )		( 563 )
Other operating activities	( 7 )		1
Net cash flow provided by operating activities	6,113		5,757
Investing activities:
Capital expenditures	( 4,319 )		( 3,485 )
Investments in unconsolidated affiliates	( 1 )		–
Distributions received from unconsolidated affiliates attributable to the return of capital	56		64
Proceeds from asset sales and other matters	21		11
Other investing activities	( 13 )		( 23 )
Net cash flow used in investing activities	( 4,256 )		( 3,433 )
Financing activities:
Borrowings under debt agreements	71,034		52,456
Repayments of debt	( 69,349 )		( 49,271 )
Debt issuance costs	( 29 )		( 44 )
Monetization of interest rate derivative instruments	14		( 33 )
Cash distributions paid to common unitholders (see Note 8)	( 3,499 )		( 3,374 )
Cash payments made in connection with distribution equivalent rights	( 33 )		( 32 )
Cash distributions paid to noncontrolling interests	( 68 )		( 84 )
Cash contributions from noncontrolling interests	5		33
Repurchase of common units under 2019 Buyback Program	( 250 )		( 156 )
Acquisition of noncontrolling interests	–		( 400 )
Other financing activities	( 88 )		( 66 )
Net cash flow used in financing activities	( 2,263 )		( 971 )
Net change in cash and cash equivalents, including restricted cash	( 406 )		1,353
Cash and cash equivalents, including restricted cash, at beginning of period	838		320
Cash and cash equivalents, including restricted cash, at end of period	$	432	$	1,673

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 NINE MONTHS ENDED SEPTEMBER 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, June 30, 2025	$	30,127	$	( 1,297 )	$	236	$	853	$	29,919
Net income	1,338		–		–		17		1,355
Cash distributions paid to common unitholders	( 1,180 )		–		–		–		( 1,180 )
Cash payments made in connection with distribution equivalent rights	( 11 )		–		–		–		( 11 )
Cash distributions paid to noncontrolling interests	–		–		–		( 29 )		( 29 )

Repurchase and cancellation of common units under 2019 Buyback Program	( 80 )		–		–		–		( 80 )
Amortization of fair value of equity-based awards	49		–		–		–		49
Cash flow hedges	–		–		28		–		28
Other, net	( 1 )		–		–		–		( 1 )
Balance, September 30, 2025	$	30,242	$	( 1,297 )	$	264	$	841	$	30,050


	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	4,166		–		–		47		4,213
Cash distributions paid to common unitholders	( 3,499 )		–		–		–		( 3,499 )
Cash payments made in connection with distribution equivalent rights	( 33 )		–		–		–		( 33 )
Cash distributions paid to noncontrolling interests	–		–		–		( 68 )		( 68 )
Cash contributions from noncontrolling interests	–		–		–		5		5
Repurchase and cancellation of common units under 2019 Buyback Program	( 250 )		–		–		–		( 250 )
Amortization of fair value of equity-based awards	147		–		–		–		147
Cash flow hedges	–		–		28		–		28
Other, net	( 82 )		–		–		–		( 82 )
Balance, September 30, 2025	$	30,242	$	( 1,297 )	$	264	$	841	$	30,050

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 NINE MONTHS ENDED SEPTEMBER 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, June 30, 2024	$	29,110	$	( 1,297 )	$	176	$	808	$	28,797
Net income	1,417		–		–		14		1,431
Cash distributions paid to common unitholders	( 1,139 )		–		–		–		( 1,139 )
Cash payments made in connection with distribution equivalent rights	( 11 )		–		–		–		( 11 )
Cash distributions paid to noncontrolling interests	–		–		–		( 21 )		( 21 )
Cash contributions from noncontrolling interests	–		–		–		8		8
Repurchase and cancellation of common units under 2019 Buyback Program	( 76 )		–		–		–		( 76 )
Amortization of fair value of equity-based awards	44		–		–		–		44

Cash flow hedges	–		–		127		–		127
Other, net	( 2 )		–		–		–		( 2 )
Balance, September 30, 2024	$	29,343	$	( 1,297 )	$	303	$	809	$	29,158


	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	4,278		–		–		56		4,334
Cash distributions paid to common unitholders	( 3,374 )		–		–		–		( 3,374 )
Cash payments made in connection with distribution equivalent rights	( 32 )		–		–		–		( 32 )
Cash distributions paid to noncontrolling interests	–		–		–		( 84 )		( 84 )
Cash contributions from noncontrolling interests	–		–		–		33		33
Repurchase and cancellation of common units under 2019 Buyback Program	( 156 )		–		–		–		( 156 )
Amortization of fair value of equity-based awards	144		–		–		–		144
Acquisition of noncontrolling interests	( 118 )		–		–		( 282 )		( 400 )
Cash flow hedges	–		–		( 4 )		–		( 4 )
Other, net	( 62 )		–		–		–		( 62 )
Balance, September 30, 2024	$	29,343	$	( 1,297 )	$	303	$	809	$	29,158

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 32.5% of the Partnership’s common units outstanding at September 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 nine months ended September 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.


	September 30, 2025		December 31, 2024
Cash and cash equivalents	$	206	$	583
Restricted cash	226		255
Total cash, cash equivalents and restricted cash shown in the Unaudited Condensed Statements of Consolidated Cash Flows	$	432	$	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:


	September 30, 2025		December 31, 2024
NGLs	$	3,129	$	2,768
Petrochemicals and refined products	603		652
Crude oil	424		523
Natural gas	4		12
Total	$	4,160	$	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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Cost of sales (1)	$	8,590	$	10,387	$	28,494	$	31,976
Lower of cost or net realizable value adjustments recognized in cost of sales	4		3		8		5

(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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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	September 30, 2025		December 31, 2024
Plants, pipelines and facilities (1)(5)	3 - 45	$	64,078	$	60,716
Underground and other storage facilities (2)(6)	5 - 40	4,792		4,704
Transportation equipment (3)	3 - 10	290		272
Marine vessels (4)	15 - 30	953		949
Land		425		424
Construction in progress		4,581		4,138
Subtotal		75,119		71,203
Less accumulated depreciation		23,807		22,330
Subtotal property, plant and equipment, net		51,312		48,873
Capitalized major maintenance costs for reaction-based plants, net of accumulated amortization (7)		199		189
Property, plant and equipment, net		$	51,511	$	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 2.7 years.

Property, plant and equipment at both September 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)	1
Revisions in estimated cash flows (2)	2
Liabilities settled (3)	( 5 )
Accretion expense (4)	16
ARO liability balance, September 30, 2025	$	279

(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 $ 279 million total ARO liability recorded at September 30, 2025, $ 4 million was reflected as a current liability and $ 275 million as a long-term liability.

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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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Depreciation expense (1)	$	527	$	495	$	1,545	$	1,471
Capitalized interest (2)	49		31		147		82

(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.


	September 30, 2025		December 31, 2024
NGL Pipelines & Services	$	573	$	598
Crude Oil Pipelines & Services	1,595		1,628
Natural Gas Pipelines & Services	31		30
Petrochemical & Refined Products Services	2		3
Total	$	2,201	$	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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
NGL Pipelines & Services	$	21	$	27	$	59	$	84
Crude Oil Pipelines & Services	68		70		212		212
Natural Gas Pipelines & Services	2		2		4		5
Petrochemical & Refined Products Services	( 1 )		–		1		1
Total	$	90	$	99	$	276	$	302

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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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:


	September 30, 2025						December 31, 2024
	Gross Value		Accumulated Amortization		Carrying Value		Gross Value		Accumulated Amortization		Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	449	$	( 286 )	$	163	$	449	$	( 276 )	$	173
Contract-based intangibles	1,050		( 167 )		883		754		( 141 )		613
Segment total	1,499		( 453 )		1,046		1,203		( 417 )		786
Crude Oil Pipelines & Services:
Customer relationship intangibles	2,195		( 689 )		1,506		2,195		( 627 )		1,568
Contract-based intangibles	283		( 279 )		4		283		( 278 )		5
Segment total	2,478		( 968 )		1,510		2,478		( 905 )		1,573
Natural Gas Pipelines & Services:
Customer relationship intangibles	1,351		( 691 )		660		1,351		( 663 )		688
Contract-based intangibles	1,146		( 254 )		892		1,081		( 227 )		854
Segment total	2,497		( 945 )		1,552		2,432		( 890 )		1,542
Petrochemical & Refined Products Services:
Customer relationship intangibles	181		( 97 )		84		181		( 92 )		89
Contract-based intangibles	45		( 30 )		15		45		( 30 )		15
Segment total	226		( 127 )		99		226		( 122 )		104
Total intangible assets	$	6,700	$	( 2,493 )	$	4,207	$	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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
NGL Pipelines & Services	$	13	$	12	$	36	$	33
Crude Oil Pipelines & Services	21		27		63		78
Natural Gas Pipelines & Services	19		13		55		39
Petrochemical & Refined Products Services	2		2		5		5
Total	$	55	$	54	$	159	$	155

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
$	59	$	231	$	225	$	214	$	214

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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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:


	September 30, 2025		December 31, 2024
EPO senior debt obligations:
Commercial Paper Notes, variable-rates	$	840	$	–
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	31,615		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	33,897		32,207
Other, non-principal amounts	( 319 )		( 311 )
Less current maturities of debt	( 2,464 )		( 1,150 )
Total long-term debt	$	31,114	$	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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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 nine months ended September 30, 2025:


	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
Commercial Paper Notes	4.23 % to 4.68 %	4.54 %
EPO Junior Subordinated Notes C	7.21 % to 7.51 %	7.38 %
EPO Junior Subordinated Notes D	7.43 % to 7.73 %	7.58 %

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 September 30, 2025 for the next five years, and in total thereafter:


			Scheduled Maturities of Debt
	Total		Remainder of 2025		2026		2027		2028		2029		Thereafter
Commercial Paper Notes	$	840	$	840	$	–	$	–	$	–	$	–	$	–
Senior Notes	30,775		–		1,625		1,575		1,500		1,250		24,825
Junior Subordinated Notes	2,282		–		–		–		–		–		2,282
Total	$	33,897	$	840	$	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 September 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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ENTERPRISE PRODUCTS PARTNERS L.P.

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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

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 September 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 September 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
Common unit repurchases under 2019 Buyback Program			( 2,543,004 )
Common units issued in connection with the vesting of phantom unit awards, net			113,097
Common units outstanding at September 30, 2025			2,163,126,578

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.

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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 nine months ended September 30, 2025. The Partnership’s capacity to issue additional common units under the ATM program remains at $ 2.5 billion as of September 30, 2025.

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 nine months ended September 30, 2025, the Partnership repurchased 2,543,004 and 7,913,198 common units, respectively, under the 2019 Buyback Program. The total cost of these repurchases, including commissions and fees, was $ 80 million and $ 250 million, respectively. During the three and nine months ended September 30, 2024, the Partnership repurchased 2,646,351 and 5,452,767 common units, respectively, under the 2019 Buyback Program. The total cost of these repurchases, including commissions and fees, was $ 76 million and $ 156 million, respectively. Common units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition. At September 30, 2025, the remaining available capacity under the 2019 Buyback Program was $ 613 million.

In October 2025, we announced that the Board approved an increase to the authorized maximum aggregate purchase price (excluding fees, commissions and other ancillary expenses) of the Partnership’s common units that may be repurchased under the 2019 Buyback Program from $ 2.0 billion to $ 5.0 billion. After giving effect to this increase, the remaining available capacity under the 2019 Buyback Program is $ 3.6 billion.

Common Units Issued in Connection With the Vesting of Phantom Unit Awards

After taking into account tax withholding requirements, the Partnership issued 5,323,416 new common units to employees in connection with the vesting of phantom unit awards during the nine months ended September 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 nine months ended September 30, 2025, agents of the Partnership purchased 3,529,782 common units on the open market and delivered them to participants in the DRIP and EUPP. Apart from $ 3 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 November 14, 2025.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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
Paid in-kind distribution to third party			99
Preferred units outstanding at September 30, 2025			50,978

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 nine months ended September 30, 2025, the Partnership made quarterly cash distributions to its preferred unitholders of $ 2 million and paid-in-kind distributions of 291 new preferred units valued at less than $ 1 million.

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	87		14		–		101
Reclassification of losses (gains) to net income during period	( 68 )		( 5 )		–		( 73 )
Total other comprehensive income (loss) for period	19		9		–		28
Accumulated Other Comprehensive Income (Loss), September 30, 2025	$	110	$	152	$	2	$	264


	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	127		( 2 )		–		125
Reclassification of losses (gains) to net income during period	( 124 )		( 5 )		–		( 129 )
Total other comprehensive income (loss) for period	3		( 7 )		–		( 4 )
Accumulated Other Comprehensive Income (Loss), September 30, 2024	$	157	$	144	$	2	$	303

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 September 30,				For the Nine Months Ended September 30,
Losses (gains) on cash flow hedges:	Location	2025		2024		2025		2024
Interest rate derivatives	Interest expense	$	( 2 )	$	( 2 )	$	( 5 )	$	( 5 )
Commodity derivatives	Revenue	( 47 )		( 96 )		( 100 )		( 176 )
Commodity derivatives	Operating costs and expenses	12		19		32		52
Total		$	( 37 )	$	( 79 )	$	( 73 )	$	( 129 )

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For information regarding our interest rate and commodity derivative instruments, see Note 14.

Cash Distributions

On October 7, 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 third quarter of 2025. The quarterly distribution is payable on November 14, 2025 to unitholders of record as of the close of business on October 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.

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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
NGL Pipelines & Services:
Sales of NGLs and related products	$	2,736	$	4,134	$	10,110	$	12,115
Segment midstream services:
Natural gas processing and fractionation	341		315		989		1,009
Transportation	314		293		934		835
Storage and terminals	74		89		238		277
Total segment midstream services	729		697		2,161		2,121
Total NGL Pipelines & Services	3,465		4,831		12,271		14,236
Crude Oil Pipelines & Services:
Sales of crude oil	5,087		4,952		14,391		15,672
Segment midstream services:
Transportation	202		194		586		577
Storage and terminals	107		105		323		305
Total segment midstream services	309		299		909		882
Total Crude Oil Pipelines & Services	5,396		5,251		15,300		16,554
Natural Gas Pipelines & Services:
Sales of natural gas	476		243		1,893		987
Segment midstream services:
Transportation	456		406		1,331		1,128
Total segment midstream services	456		406		1,331		1,128
Total Natural Gas Pipelines & Services	932		649		3,224		2,115
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products	1,919		2,751		7,020		8,105
Segment midstream services:
Fractionation and isomerization	70		65		257		276
Transportation, including marine logistics	156		157		488		498
Storage and terminals	85		71		243		234
Total segment midstream services	311		293		988		1,008
Total Petrochemical & Refined Products Services	2,230		3,044		8,008		9,113
Total consolidated revenues	$	12,023	$	13,775	$	38,803	$	42,018

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 30, 2025:


Contract Asset	Location	Balance
Unbilled revenue (current amount)	Prepaid and other current assets	$	7
Total		$	7


Contract Liability	Location	Balance
Deferred revenue (current amount)	Other current liabilities	$	158
Deferred revenue (noncurrent)	Other long-term liabilities	253
Total		$	411

The following table presents significant changes in our unbilled revenue and deferred revenue balances for the nine months ended September 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 )		( 164 )
Amount recorded during period (2)	65		585
Amounts recorded during period transferred to other accounts (1)	( 58 )		( 463 )
Other changes	–		1
Balance at September 30, 2025	$	7	$	411

(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 September 30, 2025.


Period	Fixed Consideration
Three months ended December 31, 2025	$	1,103
One year ended December 31, 2026	4,407
One year ended December 31, 2027	4,076
One year ended December 31, 2028	3,607
One year ended December 31, 2029	2,752
Thereafter	11,061
Total	$	27,006

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

• 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.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Total segment gross operating margin	$	2,383	$	2,448	$	7,318	$	7,382
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)	( 625 )		( 586 )		( 1,837 )		( 1,749 )
Asset impairment charges in operating costs and expenses	( 17 )		( 27 )		( 38 )		( 51 )
Net gains (losses) attributable to asset sales and related matters in operating costs and expenses	4		–		13		( 5 )
General and administrative costs	( 61 )		( 61 )		( 189 )		( 184 )
Non-refundable payments received from shippers attributable to make-up rights (2)	–		( 13 )		( 43 )		( 56 )
Subsequent recognition of revenues attributable to make-up rights (3)	2		19		18		30
Total other expense, net (4)	( 343 )		( 329 )		( 999 )		( 975 )
Income before income taxes	$	1,343	$	1,451	$	4,243	$	4,392

(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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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 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	$	3,463	$	5,389	$	927	$	2,230	$	12,009
Revenues from related parties	2		7		5		–		14
Intersegment and intrasegment revenues	17,583		11,504		235		4,019		33,341
Total segment revenues	21,048		16,900		1,167		6,249		45,364
Significant segment expenses:
Cost of sales	19,093		16,450		616		5,484		41,643
Variable operating costs and expenses (1)	219		36		21		118		394
Fixed operating costs and expenses (2)	456		116		194		282		1,048
Total significant segment expenses	19,768		16,602		831		5,884		43,085
Other segment income:
Equity in income of unconsolidated affiliates	21		68		2		( 1 )		90
Other segment items (3)	2		5		1		6		14
Total other segment income	23		73		3		5		104
Total segment gross operating margin	$	1,303	$	371	$	339	$	370	$	2,383

Other financial information:
Capital expenditures	$	1,097	$	35	$	674	$	152	$	1,958

(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 – 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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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	For the Nine Months Ended September 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	$	12,265	$	15,281	$	3,211	$	8,008	$	38,765
Revenues from related parties	6		19		13		–		38
Intersegment and intrasegment revenues	51,604		31,450		669		17,011		100,734
Total segment revenues	63,875		46,750		3,893		25,019		139,537
Significant segment expenses:
Cost of sales	58,013		45,417		2,159		22,799		128,388
Variable operating costs and expenses (1)	622		105		63		331		1,121
Fixed operating costs and expenses (2)	1,321		305		566		859		3,051
Total significant segment expenses	59,956		45,827		2,788		23,989		132,560
Other segment income:
Equity in income of unconsolidated affiliates	59		212		4		1		276
Other segment items (3)	40		13		4		8		65
Total other segment income	99		225		8		9		341
Total segment gross operating margin	$	4,018	$	1,148	$	1,113	$	1,039	$	7,318

Other financial information:
Capital expenditures	$	2,557	$	83	$	1,304	$	375	$	4,319

(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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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	For the Three Months Ended September 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	$	4,828	$	5,241	$	646	$	3,044	$	13,759
Revenues from related parties	3		10		3		–		16
Intersegment and intrasegment revenues	11,044		13,678		166		6,944		31,832
Total segment revenues	15,875		18,929		815		9,988		45,607
Significant segment expenses:
Cost of sales	13,946		18,463		279		9,281		41,969
Variable operating costs and expenses (1)	190		30		15		87		322
Fixed operating costs and expenses (2)	425		103		174		259		961
Total significant segment expenses	14,561		18,596		468		9,627		43,252
Other segment income:
Equity in income of unconsolidated affiliates	27		70		2		–		99
Other segment items (3)	( 6 )		( 2 )		–		2		( 6 )
Total other segment income	21		68		2		2		93
Total segment gross operating margin	$	1,335	$	401	$	349	$	363	$	2,448

Other financial information:
Capital expenditures	$	629	$	52	$	246	$	247	$	1,174

(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:

• 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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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	For the Nine Months Ended September 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	$	14,227	$	16,530	$	2,106	$	9,113	$	41,976
Revenues from related parties	9		24		9		–		42
Intersegment and intrasegment revenues	34,157		42,547		481		18,982		96,167
Total segment revenues	48,393		59,101		2,596		28,095		138,185
Significant segment expenses:
Cost of sales	42,713		57,679		1,106		25,866		127,364
Variable operating costs and expenses (1)	531		102		54		266		953
Fixed operating costs and expenses (2)	1,254		310		492		756		2,812
Total significant segment expenses	44,498		58,091		1,652		26,888		131,129
Other segment income (expense):
Equity in income of unconsolidated affiliates	84		212		5		1		302
Other segment items (3)	21		7		5		( 9 )		24
Total other segment income (expense), net	105		219		10		( 8 )		326
Total segment gross operating margin	$	4,000	$	1,229	$	954	$	1,199	$	7,382

Other financial information:
Capital expenditures	$	1,835	$	133	$	696	$	821	$	3,485

(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:

• 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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Segment revenues:
NGL Pipelines & Services	$	21,048	$	15,875	$	63,875	$	48,393
Crude Oil Pipelines & Services	16,900		18,929		46,750		59,101
Natural Gas Pipelines & Services	1,167		815		3,893		2,596
Petrochemical & Refined Products Services	6,249		9,988		25,019		28,095
Total segment revenues	45,364		45,607		139,537		138,185
Elimination of intersegment and intrasegment revenues	( 33,341 )		( 31,832 )		( 100,734 )		( 96,167 )
Total consolidated revenues	$	12,023	$	13,775	$	38,803	$	42,018

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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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents our segment assets, together with a reconciliation to our consolidated total assets, at the dates indicated:


	September 30, 2025		December 31, 2024
NGL Pipelines & Services	$	23,394	$	21,900
Crude Oil Pipelines & Services	11,168		11,390
Natural Gas Pipelines & Services	13,036		12,260
Petrochemical & Refined Products Services	11,452		11,350
Total segment assets	59,050		56,900
Construction in progress	4,581		4,138
Current assets	13,237		15,133
Other assets	954		997
Consolidated total assets	$	77,822	$	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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Consolidated revenues:
NGL Pipelines & Services	$	3,465	$	4,831	$	12,271	$	14,236
Crude Oil Pipelines & Services	5,396		5,251		15,300		16,554
Natural Gas Pipelines & Services	932		649		3,224		2,115
Petrochemical & Refined Products Services	2,230		3,044		8,008		9,113
Total consolidated revenues	$	12,023	$	13,775	$	38,803	$	42,018

Consolidated costs and expenses
Operating costs and expenses:
Cost of sales	$	8,590	$	10,387	$	28,494	$	31,976
Other operating costs and expenses (1)	1,120		1,018		3,243		2,946
Depreciation, amortization and accretion	643		601		1,886		1,791
Asset impairment charges	17		27		38		51
Net losses (gains) attributable to asset sales and related matters	( 4 )		–		( 13 )		5
General and administrative costs	61		61		189		184
Total consolidated costs and expenses	$	10,427	$	12,094	$	33,837	$	36,953

(1) Represents the cost of operating our plants, pipelines and other fixed assets excluding depreciation, amortization and accretion charges; asset impairment charges; and net losses (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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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
BASIC EARNINGS PER COMMON UNIT
Net income attributable to common unitholders	$	1,338	$	1,417	$	4,166	$	4,278
Earnings allocated to phantom unit awards (1)	( 12 )		( 14 )		( 39 )		( 41 )
Net income allocated to common unitholders	$	1,326	$	1,403	$	4,127	$	4,237

Basic weighted-average number of common units outstanding	2,164		2,169		2,166		2,170

Basic earnings per common unit	$	0.61	$	0.65	$	1.91	$	1.95

DILUTED EARNINGS PER COMMON UNIT
Net income attributable to common unitholders	$	1,338	$	1,417	$	4,166	$	4,278
Net income attributable to preferred units	1		1		3		3
Net income attributable to limited partners	$	1,339	$	1,418	$	4,169	$	4,281

Diluted weighted-average number of units outstanding:
Distribution-bearing common units	2,164		2,169		2,166		2,170
Phantom units (2)	20		21		21		21
Preferred units (2)	2		2		2		2
Total	2,186		2,192		2,189		2,193

Diluted earnings per common unit	$	0.61	$	0.65	$	1.90	$	1.95

(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. Acquisitions

Acquisition of Oxy Natural Gas Gathering Affiliate

In July 2025, we entered into definitive agreements to acquire an affiliate of Occidental Petroleum Corporation (“Oxy”) that owns approximately 200 miles of natural gas gathering pipelines in the Midland Basin and to provide natural gas gathering and processing services to Oxy for production from approximately 73,000 dedicated acres across four counties in the Midland Basin.

This acquisition, which closed on August 22, 2025, did not meet the definition of a business under ASC 805, Business Combinations , and was therefore accounted for as an asset acquisition. Asset acquisitions require, among other considerations, that the total cost of the acquisition be allocated to the assets acquired and liabilities assumed on a relative fair value basis. Additionally, transaction costs incurred in connection with an asset acquisition are capitalized as part of the total cost of the acquired assets.

The total cost of the acquisition was $ 583 million, consisting of $ 581 million in cash consideration and $ 2 million in transaction-related costs. This amount is reflected as a component of “Capital expenditures” on our Unaudited Condensed Consolidated Statements of Consolidated Cash Flows.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the allocation of the total cost to the assets acquired and liabilities assumed:


Recognized amounts of assets acquired and liabilities assumed (1):
Property, plant and equipment	$	223
Contract-based intangible asset	360
Total net assets acquired	$	583

(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 assumed liabilities primarily included accounts payable and asset retirement obligations. None of these amounts were considered individually significant.

The fair value of the acquired property, plant and equipment was determined using the cost approach and consisted of pipelines and related equipment. See Note 4 for additional information regarding our property, plant and equipment.

The contract-based intangible asset represents the estimated value assigned to the long-term gathering and processing services agreement with Oxy, which is expected to renew in approximately 15 years under similar commercial terms. The fair value of the contract-based intangible asset was determined using the income approach, specifically a discounted cash flow analysis, which incorporated Level 3 inputs including management’s long-term forecast of cash flows generated by the gathering and processing services agreement, based on the estimated life of the hydrocarbon resource basin served, resource depletion rates, and expected contract renewals. The intangible asset will be amortized on a straight-line basis over approximately 23 years.

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. This acquisition was accounted for under the acquisition method in accordance with ASC 805, Business Combinations .

The following table presents the final fair value allocation of assets acquired and liabilities assumed in the acquisition at October 28, 2024 (the effective date of the acquisition).


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 nine months ended September 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.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Equity-classified awards:
Phantom unit awards	$	50	$	44	$	149	$	135
Profits interest awards	–		–		–		10
Total	$	50	$	44	$	149	$	145

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	( 7,786,401 )	$	24.45
Forfeited	( 514,233 )	$	28.40
Phantom unit awards at September 30, 2025	20,083,707	$	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.

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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Cash payments made in connection with DERs	$	11	$	11	$	33	$	32
Total intrinsic value of phantom unit awards that vested during period	5		3		261		197

For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $ 267 million at September 30, 2025, of which our share of such cost is currently estimated to be $ 212 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 2.3 years.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

• 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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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes our portfolio of commodity derivative instruments outstanding at September 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)	30.0	22.7	Cash flow hedge
Forecasted sales of NGLs (MMBbls)	2.7	0.2	Cash flow hedge
Octane enhancement:
Forecasted sales of octane enhancement products (MMBbls)	1.9	0.4	Cash flow hedge
Natural gas marketing:
Natural gas storage inventory management activities (Bcf)	1.1	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)	217.0	23.9	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)	217.9	29.2	Cash flow hedge
Refined products marketing:
Forecasted purchases of refined products (MMBbls)	0.6	n/a	Cash flow hedge
Forecasted sales of refined products (MMBbls)	1.8	0.1	Cash flow hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)	15.3	8.1	Cash flow hedge
Forecasted sales of crude oil (MMBbls)	25.2	16.0	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	0.5	Cash flow hedge

Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (3)	48.3	n/a	Mark-to-market
NGL risk management activities (MMBbls) (3)	36.4	6.0	Mark-to-market
Refined products risk management activities (MMBbls) (3)	7.2	n/a	Mark-to-market
Crude oil risk management activities (MMBbls) (3)	50.3	n/a	Mark-to-market
Petrochemical risk management activities (MMBbls) (3)	0.3	n/a	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 2028, December 2025 and December 2027, 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 $ 4 million and $ 11 million at September 30, 2025 and December 31, 2024, respectively.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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
	September 30, 2025			December 31, 2024			September 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	$	258	Current assets	$	210	Current liabilities	$	202	Current liabilities	$	178
Commodity derivatives	Other assets	23		Other assets	22		Other liabilities	19		Other liabilities	4
Total commodity derivatives		281			232			221			182
Total derivatives designated as hedging instruments		$	281		$	232		$	221		$	182

Derivatives not designated as hedging instruments
Commodity derivatives	Current assets	$	194	Current assets	$	324	Current liabilities	$	196	Current liabilities	$	293
Commodity derivatives	Other assets	1		Other assets	19		Other liabilities	1		Other liabilities	20
Total commodity derivatives		195			343			197			313
Total derivatives not designated as hedging instruments		$	195		$	343		$	197		$	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 September 30, 2025:

Commodity derivatives	$	476	$	–	$	476	$	( 417 )	$	( 59 )	$	–	$	–
As of December 31, 2024:
Commodity derivatives	$	575	$	–	$	575	$	( 495 )	$	( 79 )	$	–	$	1

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	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 September 30, 2025:
Commodity derivatives	$	418	$	–	$	418	$	( 417 )	$	–	$	–	$	1
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 September 30,				For the Nine Months Ended September 30,
		2025		2024		2025		2024
Commodity derivatives	Revenue	$	–	$	1	$	4	$	2
Total		$	–	$	1	$	4	$	2


Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Hedged Item
		For the Three Months Ended September 30,				For the Nine Months Ended September 30,
		2025		2024		2025		2024
Commodity derivatives	Revenue	$	( 2 )	$	–	$	( 4 )	$	5
Total		$	( 2 )	$	–	$	( 4 )	$	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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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Interest rate derivatives	$	–	$	( 4 )	$	14	$	( 2 )
Commodity derivatives – Revenue (1)	77		261		114		186
Commodity derivatives – Operating costs and expenses (1)	( 12 )		( 51 )		( 27 )		( 59 )
Total	$	65	$	206	$	101	$	125

(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 September 30,				For the Nine Months Ended September 30,
		2025		2024		2025		2024
Interest rate derivatives	Interest expense	$	2	$	2	$	5	$	5
Commodity derivatives	Revenue	47		96		100		176
Commodity derivatives	Operating costs and expenses	( 12 )		( 19 )		( 32 )		( 52 )
Total		$	37	$	79	$	73	$	129

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 $ 102 million of net gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, with $ 111 million as an increase in revenue and $ 9 million as an increase 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 September 30,				For the Nine Months Ended September 30,
		2025		2024		2025		2024
Commodity derivatives	Revenue	$	( 17 )	$	( 13 )	$	30	$	( 5 )
Commodity derivatives	Operating costs and expenses	( 5 )		( 4 )		( 4 )		( 5 )
Total		$	( 22 )	$	( 17 )	$	26	$	( 10 )

The $ 26 million net gain recognized for the nine months ended September 30, 2025 (as noted in the preceding table) from derivatives not designated as hedging instruments consists of $ 46 million of net realized gains and $ 20 million of net unrealized mark-to-market losses 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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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 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	$	276	$	509	$	–	$	785
Impact of CME Rule 814	( 98 )		( 211 )		–		( 309 )
Total commodity derivatives	178		298		–		476
Total	$	178	$	298	$	–	$	476

Financial liabilities:
Commodity derivatives:
Value before application of CME Rule 814	$	194	$	494	$	1	$	689
Impact of CME Rule 814	( 28 )		( 242 )		( 1 )		( 271 )
Total commodity derivatives	166		252		–		418
Total	$	166	$	252	$	–	$	418


	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 September 30, 2025 was a net derivative asset of $ 96 million prior to the impact of CME Rule 814.

Financial assets and liabilities recorded on the balance sheet at September 30, 2025 using significant unobservable inputs (Level 3) are not material to the Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 $ 30.6 billion and $ 28.9 billion at September 30, 2025 and December 31, 2024, respectively. The aggregate carrying value of these debt obligations was $ 32.5 billion and $ 31.6 billion at September 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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Revenues – related parties:
Unconsolidated affiliates	$	14	$	16	$	38	$	42
Costs and expenses – related parties:
EPCO and its privately held affiliates	$	404	$	367	$	1,200	$	1,085
Unconsolidated affiliates	43		47		118		133
Total	$	447	$	414	$	1,318	$	1,218

The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated:


	September 30, 2025		December 31, 2024
Accounts receivable - related parties:
Unconsolidated affiliates	$	1	$	4

Accounts payable - related parties:
EPCO and its privately held affiliates	$	146	$	180
Unconsolidated affiliates	15		18
Total	$	161	$	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 September 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
702,247,078 common units			32.5 %

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 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 nine months ended September 30, 2025 and 2024, we paid EPCO and its privately held affiliates cash distributions totaling $ 1.1 billion and $ 1.1 billion, 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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Operating costs and expenses	$	364	$	323	$	1,079	$	956
General and administrative expenses	33		37		101		111
Total costs and expenses	$	397	$	360	$	1,180	$	1,067

We lease office space from privately held affiliates of EPCO. For the three months ended September 30, 2025 and 2024, we recognized $ 6 million and $ 7 million, respectively, of related party operating lease expense in connection with these office space leases. For the nine months ended September 30, 2025 and 2024, we recognized $ 18 million and $ 17 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 nine months ended September 30, 2025 and 2024.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Our federal, state and foreign income tax benefit (provision) is summarized below:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Current portion of income tax provision:
Federal	$	( 1 )	$	( 1 )	$	( 2 )	$	( 1 )
State	( 3 )		( 9 )		( 26 )		( 31 )
Total current portion	( 4 )		( 10 )		( 28 )		( 32 )
Deferred portion of income tax provision:
Federal	( 4 )		( 4 )		( 12 )		( 12 )
State	21		( 4 )		13		( 10 )
Foreign	–		( 1 )		–		( 1 )
Total deferred portion	17		( 9 )		1		( 23 )
Total benefit from (provision for) income taxes	$	13	$	( 19 )	$	( 27 )	$	( 55 )

A reconciliation of the benefit from (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 September 30,						For the Nine Months Ended September 30,
	2025			2024			2025			2024
Pre-Tax Net Book Income (“NBI”)	$	1,343		$	1,451		$	4,243		$	4,392

Texas Margin Tax (1)	18			( 13 )			( 12 )			( 40 )
State income tax provision, net of federal benefit	–			( 1 )			( 1 )			( 1 )
Federal income tax provision computed by applying the federal statutory rate to NBI of corporate entities	( 5 )			( 4 )			( 14 )			( 12 )
Other	–			( 1 )			–			( 2 )
Benefit from (provision for) income taxes	$	13		$	( 19 )		$	( 27 )		$	( 55 )

Effective income tax rate	1.0		%	( 1.3 )		%	( 0.6 )		%	( 1.3 )		%

(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:


	September 30, 2025		December 31, 2024
Deferred tax liabilities:
Attributable to investment in OTA (1)	$	485	$	462
Attributable to property, plant and equipment	137		151
Attributable to investments in other entities	4		5
Other	97		98
Total deferred tax liabilities	723		716
Deferred tax assets:
Net operating loss carryovers (2)	65		56
Temporary differences related to Texas Margin Tax	3		4
Total deferred tax assets	68		60
Total net deferred tax liabilities	$	655	$	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 September 30, 2025 has an indefinite carryover period. All losses are subject to limitations on their utilization.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 30, 2025 and December 31, 2024, respectively.

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 $ 33.9 billion and $ 32.2 billion at September 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 September 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	$	180	$	178	8 years	4.5 %
Transportation equipment	34		36		3 years	4.8 %
Office and warehouse space	161		195		11 years	3.3 %
Total operating leases	375		409
Finance leases
Transportation equipment	17		17		4 years	4.8 %
Total finance leases	17		17
Total leases	$	392	$	426

(1) ROU asset amounts are a component of “ Other assets ” on our Unaudited Condensed Consolidated Balance Sheet.

(2) At September 30, 2025, operating lease liabilities of $ 94 million and $ 315 million were included within “ Other current liabilities ” and “ Other long-term liabilities ,” respectively. Additionally at September 30, 2025, finance lease liabilities of $ 3 million and $ 14 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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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table disaggregates our total operating and finance lease expense for the periods indicated:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Long-term leases:
Fixed operating lease expense:
Non-cash lease expense (amortization of ROU assets)	$	27	$	25	$	82	$	68
Related accretion expense on lease liability balances	4		4		13		12
Total fixed operating lease expense	31		29		95		80
Fixed finance lease expense:
Amortization of ROU assets	1		–		2		–
Interest on finance lease liabilities	–		–		1		–
Total fixed finance lease expense	1		–		3		–
Variable lease expense	5		4		14		12
Total long-term lease expense	37		33		112		92
Short-term leases	45		32		118		91
Total lease expense	$	82	$	65	$	230	$	183

Cash paid for operating lease liabilities was $ 31 million and $ 28 million for the three months ended September 30, 2025 and 2024, respectively. For the nine months ended September 30, 2025 and 2024, cash paid for operating lease liabilities was $ 97 million and $ 78 million, respectively. Cash paid for finance leases was $ 1 million and $ 2 million for the three and nine months ended September 30, 2025, respectively.

Operating lease income for each of the three months ended September 30, 2025 and 2024 was $ 4 million. Operating lease income for each of the nine months ended September 30, 2025 and 2024 was $ 11 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 September 30, 2025 did not differ materially from 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 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 Nine Months Ended September 30,
	2025		2024
Decrease (increase) in:
Accounts receivable – trade	$	1,725	$	( 426 )
Accounts receivable – related parties	3		2
Inventories	( 101 )		32
Prepaid and other current assets	( 81 )		( 96 )
Other assets	23		62
Increase (decrease) in:
Accounts payable – trade	26		( 147 )
Accounts payable – related parties	( 37 )		( 62 )
Accrued product payables	( 1,353 )		305
Accrued interest	( 248 )		( 185 )
Other current liabilities	( 17 )		52
Other long-term liabilities	( 109 )		( 100 )
Net effect of changes in operating accounts	$	( 169 )	$	( 563 )

Cash payments for interest, net of $ 147 and $ 82 capitalized during the nine months ended September 30, 2025 and 2024, respectively	$	1,260	$	1,180

Cash payments for federal and state income taxes	$	12	$	19

We incurred liabilities for construction in progress that had not been paid at September 30, 2025 and December 31, 2024 of $ 571 million and $ 490 million, respectively. Such amounts are not included under the caption “Capital expenditures” on the Unaudited Condensed Statements of Consolidated Cash Flows.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS.

For the Three and Nine Months Ended September 30, 2025 and 2024

The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying Notes included in this quarterly report on Form 10-Q and the Audited Consolidated Financial Statements and related Notes, together with our discussion and analysis of financial position and results of operations, included in our annual report on Form 10-K for the year ended December 31, 2024 (the “ 2024 Form 10-K”), as filed on February 28, 2025 with the U.S. Securities and Exchange Commission (“SEC”). Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”).

Cautionary Statement Regarding Forward-Looking Information

This quarterly report on Form 10-Q for the three and nine months ended September 30, 2025 (our “quarterly report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “scheduled,” “pending,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we and our general partner believe that our expectations reflected in such forward-looking statements (including any forward-looking statements/expectations of third parties referenced in this quarterly report) are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct.

Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of our 2024 Form 10-K and within Part II, Item 1A of this quarterly report. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. The forward-looking statements in this quarterly report speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

Key References Used in this Management’s Discussion and Analysis

Unless the context requires otherwise, references to “we,” “us” or “our” within this quarterly report 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.

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As generally used in the energy industry and in this quarterly report, the acronyms below have the following meanings:

per day

MMBPD

million barrels per day

BBtus

billion British thermal units

MMBtus

million British thermal units

Bcf

billion cubic feet

MMcf

million cubic feet

BPD

barrels per day

MWac

megawatts, alternating current

MBPD

thousand barrels per day

MWdc

megawatts, direct current

MMBbls

million barrels

TBtus

trillion British thermal units

As used in this quarterly report, the phrase “quarter-to-quarter” means the third quarter of 2025 compared to the third quarter of 2024 . Likewise, the phrase “period-to-period” means the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024 .

Overview of Business

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 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;

• 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.

The safe operation of our assets is a top priority. We are committed to protecting the environment and the health and safety of the public and those working on our behalf by conducting our business activities in a safe and environmentally responsible manner. For additional information, see “ Environmental, Safety and Conservation ” within the Regulatory Matters section of Part I, Items 1 and 2 of the 2024 Form 10-K.

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Our financial position, results of operations and cash flows are subject to certain risks. For information regarding such risks, see “ Risk Factors ” included under Part I, Item 1A of the 2024 Form 10-K and Part II, Item 1A of this quarterly report.

We provide investors access to additional information regarding the Partnership and our consolidated businesses, including information relating to governance procedures and principles, through our website, www.enterpriseproducts.com.

Recent Developments

Enterprise Announces Increase to 2019 Buyback Program

In October 2025, we announced that the Board approved an increase to the authorized maximum aggregate purchase price (excluding fees, commissions and other ancillary expenses) of the Partnership’s common units that may be repurchased under the 2019 Buyback Program from $2.0 billion to $5.0 billion. After giving effect to this increase, the remaining available capacity under the 2019 Buyback Program is $3.6 billion.

Enterprise Acquires Oxy Affiliate, Enters into Service Agreements, and Expands Midland Basin Processing Capacity

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 $581 million in cash consideration. In addition, an affiliate of Enterprise 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. This transaction closed on August 22, 2025.

In order to accommodate this production growth in the Midland Basin, we also announced plans to expand our natural gas gathering and processing capabilities in the Midland Basin with the construction of a ninth natural gas processing train (“Athena”) and further expansion of our Midland Basin gathering system. This natural gas processing train, which will have the capacity to process approximately 300 MMcf/d of natural gas and extract up to 40 MBPD of NGLs, is expected to begin service in the fourth quarter of 2026.

Enterprise Begins Initial Service at Neches River Ethane / Propane Export Facility

In July 2025, we placed into service the first phase of our new ethane / propane export facility located on the Neches River in Orange County, Texas (“Neches River Ethane / Propane Export Facility”). This phase included the completion of a loading dock and an ethane refrigeration train with a nameplate capacity of 120 MBPD. The second phase of the project, which will add a second refrigeration train capable of loading up to 180 MBPD of ethane, 360 MBPD of propane, or a combination thereof, is expected to begin service in the first half of 2026.

Enterprise Begins Service at Mentone West 1 and Orion

In July 2025, we placed our first natural gas processing train at our Mentone West location in the Delaware Basin (“Mentone West 1”) and our eighth Midland Basin natural gas processing train (“Orion”) into commercial service. Both Mentone West 1 and Orion are capable of processing over 300 MMcf/d of natural gas and extracting more than 40 MBPD of NGLs and are supported by long-term acreage dedication agreements and minimum volume commitments.

Issuance of $2.0 Billion of Senior Notes in June 2025

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.

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Selected Energy Commodity Price Data

The following table presents selected average index prices for natural gas and selected NGL and petrochemical products for the periods indicated:


	Natural Gas, $/MMBtu	Ethane, $/gallon	Propane, $/gallon	Normal Butane, $/gallon	Isobutane, $/gallon	Natural Gasoline, $/gallon	Polymer Grade Propylene, $/pound	Refinery Grade Propylene, $/pound	Indicative Gas Processing Gross Spread $/gallon
	(1)	(2)	(2)	(2)	(2)	(2)	(3)	(3)	(4)
2024 by quarter:
1st Quarter	$2.25	$0.19	$0.84	$1.03	$1.14	$1.54	$0.55	$0.18	$0.43
2nd Quarter	$1.89	$0.19	$0.75	$0.90	$1.26	$1.55	$0.47	$0.21	$0.43
3rd Quarter	$2.15	$0.16	$0.73	$0.97	$1.08	$1.48	$0.53	$0.28	$0.39
4th Quarter	$2.79	$0.22	$0.78	$1.13	$1.12	$1.50	$0.42	$0.24	$0.39
2024 Averages	$2.27	$0.19	$0.78	$1.01	$1.15	$1.52	$0.49	$0.23	$0.41

2025 by quarter:
1st Quarter	$3.65	$0.27	$0.90	$1.06	$1.07	$1.53	$0.45	$0.33	$0.37
2nd Quarter	$3.44	$0.24	$0.78	$0.88	$0.93	$1.32	$0.38	$0.30	$0.30
3rd Quarter	$3.07	$0.23	$0.69	$0.86	$0.92	$1.30	$0.36	$0.28	$0.30
2025 Averages	$3.39	$0.25	$0.79	$0.93	$0.97	$1.38	$0.40	$0.30	$0.32

(1) Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts, which is a division of S&P Global, Inc.

(2) NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu, Texas Non-TET commercial index prices as reported by Oil Price Information Service, which is a division of Dow Jones.

(3) Polymer grade propylene prices represent average contract pricing for such product as reported by IHS Markit (“IHS”), which is a division of S&P Global, Inc. Refinery grade propylene (“RGP”) prices represent weighted-average spot prices for such product as reported by IHS.

(4) The “Indicative Gas Processing Gross Spread” represents our generic estimate of the gross economic benefit from extracting NGLs from natural gas production based on certain pricing assumptions. Specifically, it is the amount by which the assumed economic value of a composite gallon of NGLs in Chambers County, Texas exceeds the value of the equivalent amount of energy in natural gas at Henry Hub, Louisiana. Our estimate of the indicative spread does not consider the operating costs incurred by a natural gas processing facility to extract the NGLs nor the transportation and fractionation costs to deliver the NGLs to market. In addition, the actual gas processing spread earned at each plant is further influenced by regional pricing and extraction dynamics.

The weighted-average indicative market price for NGLs was $0.56 per gallon in the third quarter of 2025 versus $0.57 per gallon in the third quarter of 2024 . Likewise, the weighted-average indicative market price for NGLs was $0.60 per gallon during the nine months ended September 30, 2025 compared to $0.59 per gallon during the nine months ended September 30, 2024 .

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The following table presents selected average index prices for crude oil for the periods indicated:


	WTI Crude Oil, $/barrel	Midland Crude Oil, $/barrel	Houston Crude Oil, $/barrel
	(1)	(2)	(2)
2024 by quarter:
1st Quarter	$76.96	$78.55	$78.85
2nd Quarter	$80.57	$81.73	$82.33
3rd Quarter	$75.10	$75.96	$76.51
4th Quarter	$70.27	$71.19	$71.72
2024 Averages	$75.73	$76.86	$77.35

2025 by quarter:
1st Quarter	$71.42	$72.52	$72.81
2nd Quarter	$63.87	$64.42	$64.65
3rd Quarter	$64.93	$65.76	$66.09
2025 Averages	$66.74	$67.57	$67.85

(1) WTI prices are based on commercial index prices at Cushing, Oklahoma as measured by the NYMEX.

(2) Midland and Houston crude oil prices are based on commercial index prices as reported by Argus.

Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. An increase in our consolidated marketing revenues due to higher energy commodity sales prices may not result in an increase in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also be expected to increase due to comparable increases in the purchase prices of the underlying energy commodities. The same type of relationship would be true in the case of lower energy commodity sales prices and purchase costs.

We attempt to mitigate commodity price exposure through our hedging activities and the use of fee-based arrangements. See Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report and “ Quantitative and Qualitative Disclosures About Market Risk ” under Part I, Item 3 of this quarterly report for information regarding our commodity hedging activities.

Impact of Inflation

Inflation rates in the U.S. increased significantly in 2022 and have remained elevated compared to recent historical levels. While pandemic-era supply chain disruptions have largely dissipated and measures taken by the U.S. Federal Reserve Bank helped slow the growth of inflation, the high-cost environment that began in 2022 has generally remained intact in 2025. In addition, there is uncertainty of what effect, if any, trade tariffs will have on inflation in future periods. However, to the extent that a rising cost environment impacts our results, there are typically offsetting benefits either inherent in our business or that result from other steps we take proactively to reduce the impact of inflation on our net operating results. These benefits include: (1) provisions included in our long-term fee-based revenue contracts that offset cost increases in the form of rate escalations based on positive changes in the U.S. Consumer Price Index, Producer Price Index for Finished Goods or other factors; (2) provisions in other revenue contracts that enable us to pass through higher energy costs to customers in the form of gas, electricity and fuel rebills or surcharges; and (3) higher commodity prices, which generally enhance our results in the form of increased volumetric throughput and demand for our services. Additionally, we take measures to mitigate the impact of cost increases in certain commodities, including a portion of our electricity needs, using fixed-price, term purchase agreements, or financial derivatives. For these reasons, the increased cost environment, caused in part by inflation, has not had a material impact on our historical results of operations for the periods presented in this report. However, a significant or prolonged period of high inflation could adversely impact our results if costs were to increase at a rate greater than the increase in the revenues we receive.

See “ Capital Investments ” within this Part I, Item 2 for a discussion of the impact of inflation on our capital investment decisions.

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Income Statement Highlights

The following table summarizes the key components of our consolidated results of operations for the periods indicated (dollars in millions):


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Revenues	$	12,023	$	13,775	$	38,803	$	42,018
Costs and expenses:
Operating costs and expenses:
Cost of sales	8,590		10,387		28,494		31,976
Other operating costs and expenses	1,120		1,018		3,243		2,946
Depreciation, amortization and accretion expenses	643		601		1,886		1,791
Asset impairment charges	17		27		38		51
Net losses (gains) attributable to asset sales and related matters	(4)		–		(13)		5
Total operating costs and expenses	10,366		12,033		33,648		36,769
General and administrative costs	61		61		189		184
Total costs and expenses	10,427		12,094		33,837		36,953
Equity in income of unconsolidated affiliates	90		99		276		302
Operating income	1,686		1,780		5,242		5,367
Other income (expense):
Interest expense	(354)		(343)		(1,026)		(1,006)
Other, net	11		14		27		31
Total other expense, net	(343)		(329)		(999)		(975)
Income before income taxes	1,343		1,451		4,243		4,392
Benefit from (provision for) income taxes	13		(19)		(27)		(55)
Net income	1,356		1,432		4,216		4,337
Net income attributable to noncontrolling interests	(17)		(14)		(47)		(56)
Net income attributable to preferred units	(1)		(1)		(3)		(3)
Net income attributable to common unitholders	$	1,338	$	1,417	$	4,166	$	4,278

Revenues

The following table presents each business segment’s contribution to consolidated revenues for the periods indicated (dollars in millions):


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
NGL Pipelines & Services:
Sales of NGLs and related products	$	2,736	$	4,134	$	10,110	$	12,115
Midstream services	729		697		2,161		2,121
Total	3,465		4,831		12,271		14,236
Crude Oil Pipelines & Services:
Sales of crude oil	5,087		4,952		14,391		15,672
Midstream services	309		299		909		882
Total	5,396		5,251		15,300		16,554
Natural Gas Pipelines & Services:
Sales of natural gas	476		243		1,893		987
Midstream services	456		406		1,331		1,128
Total	932		649		3,224		2,115
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products	1,919		2,751		7,020		8,105
Midstream services	311		293		988		1,008
Total	2,230		3,044		8,008		9,113
Total consolidated revenues	$	12,023	$	13,775	$	38,803	$	42,018

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Third Quarter of 2025 Compared to Third Quarter of 2024 . Total revenues for the third quarter of 2025 decreased $1.8 billion when compared to the third quarter of 2024 primarily due to lower marketing revenues.

Revenues from the marketing of NGLs and petrochemicals and refined products decreased a combined $ 2.2 billion quarter-to-quarter primarily due to lower average sales prices, which accounted for a $1.6 billion decrease, and lower sales volumes, which accounted for an additional $583 million decrease. Revenues from the marketing of natural gas increased $233 million quarter-to-quarter primarily due to higher average sales prices. Revenues from the marketing of crude oil increased a net $134 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $738 million increase, partially offset by lower average sales prices, which accounted for a $604 million decrease.

Revenues from midstream services for the third quarter of 2025 increased $110 million when compared to the third quarter of 2024 . Revenues from our NGL and natural gas transportation assets increased a combined $69 million quarter-to-quarter primarily due to higher demand for transportation services. Revenues from our natural gas processing facilities increased $20 million quarter-to-quarter primarily due to an increase in total fee-based natural gas processing volumes as a result of the contributions from our Orion and Mentone West 1 natural gas processing trains, which were placed into service in the third quarter of 2025. Lastly, revenues from our Midland-to-ECHO System increased $22 million quarter-to-quarter primarily due to higher demand for transportation services.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024 . Total revenues for the nine months ended September 30, 2025 decreased $3.2 billion when compared to the nine months ended September 30, 2024 primarily due to lower marketing revenues.

Revenues from the marketing of NGLs and crude oil decreased a combined net $3.3 billion period-to-period primarily due to lower average sales prices, which accounted for a $4.9 billion decrease, partially offset by higher sales volumes, which accounted for a $1.6 billion increase. Revenues from the marketing of petrochemicals and refined products decreased $1.1 billion period-to-period primarily due to lower average sales prices. Revenues from the marketing of natural gas increased $906 million period-to-period primarily due to higher average sales prices.

Revenues from midstream services for the nine months ended September 30, 2025 increased a net $250 million when compared to the nine months ended September 30, 2024 . Revenues from our NGL and natural gas transportation assets increased a combined $298 million period-to-period primarily due to higher demand for transportation services. Revenues from our octane enhancement and related plant operations decreased $34 million period-to-period primarily due to lower deficiency fee revenues. Lastly, r evenues from our natural gas processing facilities decreased $29 million period-to-period primarily due to lower market values for the equity NGL-equivalent production volumes we receive as non-cash consideration for processing services.

Operating costs and expenses

Total operating costs and expenses for the three and nine months ended September 30, 2025 decreased $1.7 billion and $3.1 billion , respectively when compared to the same periods in 2024 .

Cost of sales

Third Quarter of 2025 Compared to Third Quarter of 2024 . Cost of sales for the third quarter of 2025 decreased a net $1.8 billion when compared to the third quarter of 2024 . The cost of sales associated with the marketing of NGLs decreased $1.3 billion quarter-to-quarter primarily due to lower average purchase prices. The cost of sales associated with the marketing of petrochemicals and refined products decreased $798 million quarter-to-quarter primarily due to lower volumes. The cost of sales associated with the marketing of crude oil increased a net $246 million quarter-to-quarter primarily due to higher volumes which accounted for a $677 million increase, partially offset by lower average purchase prices, which accounted for a $431 million decrease.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024 . Cost of sales for the nine months ended September 30, 2025 decreased a net $3.5 billion when compared to the nine months ended September 30, 2024 . The cost of sales associated with the marketing of NGLs and crude oil decreased a combined net $2.7 billion period-to-period primarily due to lower average purchase prices, which accounted for a $4.2 billion decrease, partially offset by higher volumes, which accounted for a $1.5 billion increase. The cost of sales associated with the marketing of petrochemicals and refined products decreased $1.1 billion period-to-period primarily due to lower volumes. The cost of sales associated with the marketing of natural gas increased $308 million period-to-period primarily due to higher average purchase prices.

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Other operating costs and expenses

Other operating costs and expenses for the three and nine months ended September 30, 2025 increased $102 million and $297 million , respectively, when compared to the same periods in 2024 primarily due to higher employee compensation, maintenance and utility costs.

Depreciation, amortization and accretion expenses

Depreciation, amortization and accretion expense for the three and nine months ended September 30, 2025 increased $42 million and $95 million , respectively, when compared to the same periods in 2024 primarily due to higher depreciation expense on assets placed into full or limited service since the end of the respective periods in 2024 .

General and administrative costs

General and administrative costs for the three months ended September 30, 2025 was flat when compared to the same period in 2024. General and administrative costs for the nine months ended September 30, 2025 increased $5 million when compared to the same period in 2024 primarily due to higher employee compensation costs.

Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for the three and nine months ended September 30, 2025 decreased $9 million and $26 million , respectively, when compared to the same periods in 2024 primarily due to lower earnings from investments in NGL pipelines and services.

Operating income

Operating income for the three and nine months ended September 30, 2025 decreased $94 million and $125 million , respectively, when compared to the same periods in 2024 due to the previously described quarter-to-quarter and period-to-period changes.

Interest expense

The following table presents the components of our consolidated interest expense for the periods indicated (dollars in millions):


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Interest charged on debt principal outstanding (1)	$	396	$	369	$	1,154	$	1,073
Impact of interest rate hedging program, including related amortization	(2)		(2)		(5)		(5)
Interest costs capitalized in connection with construction projects (2)	(49)		(31)		(147)		(82)
Other	9		7		24		20
Total	$	354	$	343	$	1,026	$	1,006

(1) The weighted-average interest rates on debt principal outstanding during the three and nine months ended September 30, 2025 were 4.62% and 4.66%, respectively. The weighted-average interest rates on debt principal outstanding during the three and nine months ended September 30, 2024 were 4.59% and 4.60%, respectively.

(2) We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. Capitalized interest amounts become part of the historical cost of an asset and are charged to earnings (as a component of depreciation expense) on a straight-line basis over the estimated useful life of the asset once the asset enters its intended service. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise. Capitalized interest amounts fluctuate based on the timing of when projects are placed into service, our capital investment levels and the interest rates charged on borrowings.

Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net $27 million quarter-to-quarter and a net $81 million period-to-period. These increases were primarily due to the issuance of $2.5 billion and $2.0 billion of fixed-rate senior notes in August 2024 and June 2025, respectively, which accounted for a combined increase of $37 million quarter-to-quarter and $106 million period-to-period. These increases were partially offset by the retirement of $1.15 billion of fixed-rate senior notes in February 2025, which accounted for a decrease of $11 million quarter-to-quarter and $27 million period-to-period.

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For additional information regarding our debt obligations, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. For a discussion of our capital projects, see “ Capital Investments ” within this Part I, Item 2.

Business Segment Highlights

We 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 and forms the basis of our internal financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.

The following table presents gross operating margin by segment and total gross operating margin, a non-generally accepted accounting principle (“non-GAAP”) financial measure, for the periods indicated (dollars in millions):


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Gross operating margin by segment:
NGL Pipelines & Services	$	1,303	$	1,335	$	4,018	$	4,000
Crude Oil Pipelines & Services	371		401		1,148		1,229
Natural Gas Pipelines & Services	339		349		1,113		954
Petrochemical & Refined Products Services	370		363		1,039		1,199
Total segment gross operating margin (1)	2,383		2,448		7,318		7,382
Net adjustment for shipper make-up rights	2		6		(25)		(26)
Total gross operating margin (non-GAAP)	$	2,385	$	2,454	$	7,293	$	7,356

(1) Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled within our business segment disclosures found under Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Gross operating margin includes equity in the earnings of unconsolidated affiliates, but 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. Segment gross operating margin for NGL Pipelines & Services and Crude Oil Pipelines & Services reflect adjustments for shipper make-up rights that are included in management’s evaluation of segment results. However, these adjustments are excluded from non-GAAP total gross operating margin.

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The GAAP financial measure most directly comparable to total gross operating margin is operating income. For a discussion of operating income and its components, see the previous section titled “ Income Statement Highlights ” within this Part I, Item 2. The following table presents a reconciliation of operating income to total gross operating margin for the periods indicated (dollars in millions):


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Operating income	$	1,686	$	1,780	$	5,242	$	5,367
Adjustments to reconcile operating income to total gross operating margin (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expense in operating costs and expenses (1)	625		586		1,837		1,749
Asset impairment charges in operating costs and expenses	17		27		38		51
Net losses (gains) attributable to asset sales and related matters in operating costs and expenses	(4)		–		(13)		5
General and administrative costs	61		61		189		184
Total gross operating margin (non-GAAP)	$	2,385	$	2,454	$	7,293	$	7,356

(1) Excludes amortization of major maintenance costs for reaction-based plants and amortization of finance lease right-of-use assets, which are components of gross operating margin.

Each of our business segments benefits from the supporting role of our marketing activities. The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment. In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin for us. The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.

NGL Pipelines & Services

The following table presents segment gross operating margin and selected volumetric data for the NGL Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Segment gross operating margin:
Natural gas processing and related NGL marketing activities	$	354	$	371	$	1,068	$	1,115
NGL pipelines, storage and terminals	746		716		2,309		2,166
NGL fractionation	203		248		641		719
Total	$	1,303	$	1,335	$	4,018	$	4,000

Selected volumetric data:
NGL pipeline transportation volumes (MBPD)	4,694		4,303		4,570		4,296
NGL marine terminal volumes (MBPD)	908		887		947		886
NGL fractionation volumes (MBPD)	1,636		1,662		1,650		1,661
Equity NGL-equivalent production volumes (MBPD) (1)	225		204		221		203
Fee-based natural gas processing volumes (MMcf/d) (2,3)	7,454		6,850		7,303		6,617

(1) Primarily represents the NGL and condensate volumes we earn and take title to in connection with our processing activities. The total equity NGL-equivalent production volumes also include residue natural gas volumes from our natural gas processing business.

(2) Volumes reported correspond to the revenue streams earned by our natural gas processing plants.

(3) Fee-based natural gas processing volumes are measured at either the wellhead or plant inlet in MMcf/d.

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Natural gas processing and related NGL marketing activities

Third Quarter of 2025 Compared to Third Quarter of 2024 . Gross operating margin from natural gas processing and related NGL marketing activities for the third quarter of 2025 decreased $17 million when compared to the third quarter of 2024 .

Gross operating margin from our NGL marketing activities decreased a net $21 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $49 million decrease, partially offset by higher mark-to-market earnings, which accounted for a $16 million increase, and higher sales volumes, which accounted for an additional $12 million increase.

Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $11 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities). On a combined basis, fee-based natural gas processing volumes and equity NGL-equivalent production volumes decreased 69 MMcf/d and increased 3 MBPD, respectively, quarter-to-quarter.

Gross operating margin from our Midland Basin natural gas processing facilities decreased a net $11 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $12 million decrease, and higher operating costs, which accounted for an additional $9 million decrease, partially offset by higher fee-based natural gas processing volumes, which accounted for an $8 million increase. Fee-based natural gas processing volumes at our Midland Basin natural gas processing facilities increased 211 MMcf/d quarter-to-quarter primarily due to contributions from our Orion natural gas processing train, which was placed into service in the third quarter of 2025.

Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $13 million quarter-to-quarter primarily due to higher fee-based natural gas processing volumes, which accounted for a $10 million increase, and higher average processing margins (including the impact of hedging activities), which accounted for an additional $9 million increase, partially offset by higher operating costs, which accounted for a $6 million decrease. Fee-based natural gas processing volumes at our Delaware Basin natural gas processing facilities increased 240 MMcf/d quarter-to-quarter primarily due to contributions from our Mentone West 1 natural gas processing train, which was placed into service in the third quarter of 2025.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities increased $8 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $4 million increase, a 12 MBPD increase in equity NGL-equivalent production volumes, which accounted for a $3 million increase, and a 318 MMcf/d increase in fee-based natural gas processing volumes, which accounted for an additional $2 million increase.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024 . Gross operating margin from natural gas processing and related NGL marketing activities for the nine months ended September 30, 2025 decreased $47 million when compared to the nine months ended September 30, 2024 .

Gross operating margin from our NGL marketing activities decreased a net $58 million period-to-period primarily due to lower average sales margins, which accounted for a $97 million decrease, partially offset by higher sales volumes, which accounted for a $36 million increase, and higher mark-to-market earnings, which accounted for an additional $4 million increase.

Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $28 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities). On a combined basis, fee-based natural gas processing volumes decreased 56 MMcf/d and equity NGL-equivalent production were flat period-to-period.

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Gross operating margin from our Midland Basin natural gas processing facilities increased a net $20 million period-to-period primarily due to higher fee-based natural gas processing volumes, which accounted for a $29 million increase, and a 6 MBPD increase in equity NGL-equivalent production volumes, which accounted for an additional $14 million increase, partially offset by higher operating costs, which accounted for a $23 million decrease. Fee-based natural gas processing volumes at our Midland Basin natural gas processing facilities increased 329 MMcf/d period-to-period primarily due to contributions from our Leonidas and Orion natural gas processing trains, which were placed into service in late first quarter of 2024 and the third quarter of 2025, respectively.

Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $14 million period-to-period primarily due to higher fee-based natural gas processing volumes, which accounted for a $32 million increase, and a 5 MBPD increase in equity NGL-equivalent production volumes, which accounted for an additional $21 million increase, partially offset by lower average processing margins (including the impact of hedging activities), which accounted for a $30 million decrease, and higher operating costs, which accounted for an additional $9 million decrease. Fee-based natural gas processing volumes at our Delaware Basin natural gas processing facilities increased 296 MMcf/d period-to-period primarily due to contributions from our Mentone 3 and Mentone West 1 natural gas processing trains, which were placed into service in late first quarter of 2024 and the third quarter of 2025, respectively.

NGL pipelines, storage and terminals

Third Quarter of 2025 Compared to Third Quarter of 2024 . Gross operating margin from our NGL pipelines, storage and terminal assets during the third quarter of 2025 increased $30 million when compared to the third quarter of 2024 .

Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $19 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for an $11 million increase, and a 109 MBPD increase in transportation volumes, which accounted for an additional $6 million increase.

Gross operating margin from our Tri-States NGL Pipeline increased $5 million quarter-to-quarter primarily due to an 11 MBPD increase in transportation volumes.

Gross operating margin from our Mont Belvieu area storage complex increased a net $5 million quarter-to-quarter primarily due to higher storage revenues, which accounted for a $9 million increase, partially offset by higher operating costs, which accounted for a $4 million decrease.

Gross operating margin from our Dixie Pipeline and related terminals increased $4 million quarter-to-quarter primarily due to higher average transportation and related fees. Transportation volumes on our Dixie Pipeline increased 6 MBPD quarter-to-quarter.

Gross operating margin from LPG-related activities at our Enterprise Hydrocarbons Terminal (“EHT”) decreased $44 million quarter-to-quarter primarily due to lower average loading fees. LPG export volumes at EHT decreased 42 MBPD quarter-to-quarter. Gross operating margin at our Morgan’s Point and Neches River Export Terminals increased a combined $22 million quarter-to-quarter primarily due to higher ethane export volumes, which accounted for a $16 million increase, and higher other fee revenues, which accounted for an additional $4 million increase. Ethane export volumes at these terminals increased a combined 63 MBPD quarter-to-quarter primarily due to contributions from the first phase of our Neches River export facility, which was placed into service in July 2025. Gross operating margin from our related Houston Ship Channel Pipeline System increased a net $1 million quarter-to-quarter primarily due to a 70 MBPD increase in transportation volumes, which accounted for a $5 million increase, partially offset by higher operating costs, which accounted for a $4 million decrease.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024 . Gross operating margin from our NGL pipelines, storage and terminal assets during the nine months ended September 30, 2025 increased $143 million when compared to the nine months ended September 30, 2024 .

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A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral Pipeline, and Shin Oak NGL Pipeline, serve Permian Basin and/or Rocky Mountain producers. On a combined basis, gross operating margin from these pipelines increased a net $63 million period-to-period primarily due to an 84 MBPD increase in transportation volumes, which accounted for a $49 million increase, higher other revenues, which accounted for a $19 million increase, and higher average transportation fees, which accounted for an additional $10 million increase, partially offset by higher operating costs, which accounted for a $15 million decrease.

Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $47 million period-to-period primarily due to higher average transportation fees, which accounted for a $29 million increase, and a 61 MBPD increase in transportation volumes, which accounted for an additional $15 million increase.

Gross operating margin from our Dixie Pipeline and related terminals increased $22 million period-to-period primarily due to higher average transportation fees, which accounted for an $11 million increase, and higher loading and other fee revenues, which accounted for an additional $10 million increase. Transportation volumes on our Dixie Pipeline increased 6 MBPD period-to-period.

Gross operating margin from our Tri-States NGL Pipeline increased $18 million period-to-period primarily due to a 9 MBPD increase in transportation volumes, which accounted for a $9 million increase, and higher average transportation fees, which accounted for an additional $5 million increase.

Gross operating margin from our South Texas NGL Pipeline System increased $15 million period-to-period primarily due to higher capacity reservation revenues, which accounted for an $8 million increase, and lower operating costs, which accounted for an additional $4 million increase. Transportation volumes on this system increased 15 MBPD period-to-period.

Gross operating margin from our Mont Belvieu area storage complex increased a net $12 million period-to-period primarily due to higher storage revenues, which accounted for a $22 million increase, partially offset by higher operating costs, which accounted for a $10 million decrease.

Gross operating margin from LPG-related activities at EHT decreased $84 million period-to-period primarily due to lower average loading fees, which accounted for a $76 million decrease, and higher operating costs, which accounted for an additional $11 million decrease. LPG export volumes at EHT increased 14 MBPD period-to-period . Gross operating margin at our Morgan’s Point and Neches River Export Terminals increased a combined $42 million period-to-period primarily due to higher ethane export volumes, which accounted for a $36 million increase, and higher other fee revenues, which accounted for an additional $6 million increase. The combined 47 MBPD period-to-period increase in e thane export volumes at these terminals included contributions from the first phase of our Neches River export facility, which was placed into service in July 2025. Gross operating margin from our related Houston Ship Channel Pipeline System increased $11 million period-to-period primarily due to an 84 MBPD increase in transportation volumes.

NGL fractionation

Third Quarter of 2025 Compared to Third Quarter of 2024 . Gross operating margin from NGL fractionation during the third quarter of 2025 decreased $45 million when compared to the third quarter of 2024 .

Gross operating margin from our Mont Belvieu area NGL fractionation complex decreased $33 million quarter-to-quarter primarily due to higher operating costs, which accounted for a $20 million decrease, and lower ancillary service revenues, which accounted for an additional $13 million decrease. NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex decreased 21 MBPD quarter-to-quarter.

On a combined basis, gross operating margin from NGL fractionators other than our Mont Belvieu area complex decreased $9 million quarter-to-quarter primarily due to lower ancillary service revenues. NGL fractionation volumes from these NGL fractionators decreased a combined 5 MBPD (net to our interest) quarter-to-quarter.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024 . Gross operating margin from NGL fractionation during the nine months ended September 30, 2025 decreased $78 million when compared to the nine months ended September 30, 2024 .

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Gross operating margin from our Mont Belvieu area NGL fractionation complex decreased $51 million period-to-period primarily due to higher operating costs, which accounted for a $28 million decrease, and lower ancillary service revenues, which accounted for an additional $23 million decrease. NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex decreased 2 MBPD period-to-period.

On a combined basis, gross operating margin from NGL fractionators other than our Mont Belvieu area complex decreased $23 million period-to-period primarily due to lower ancillary service revenues. NGL fractionation volumes from these NGL fractionators decreased a combined 9 MBPD (net to our interest) period-to-period.

Crude Oil Pipelines & Services

The following table presents segment gross operating margin and selected volumetric data for the Crude Oil Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Segment gross operating margin	$	371	$	401	$	1,148	$	1,229

Selected volumetric data:
Crude oil pipeline transportation volumes (MBPD)	2,631		2,537		2,581		2,507
Crude oil marine terminal volumes (MBPD)	720		910		757		992

Third Quarter of 2025 Compared to Third Quarter of 2024 . Gross operating margin from our Crude Oil Pipelines & Services segment for the third quarter of 2025 decreased $30 million when compared to the third quarter of 2024 .

Gross operating margin from our Texas crude oil pipelines, related terminals and marketing activities (excluding the Seaway Pipeline) decreased a combined net $26 million quarter-to-quarter primarily due to lower average sales margins from marketing activities, which accounted for a $30 million decrease, lower mark-to-market earnings, which accounted for an $11 million decrease, and higher operating expenses, which accounted for an additional $8 million decrease, partially offset by a combined 99 MBPD (net to our interest) increase in crude oil transportation volumes, which accounted for a $12 million increase, and higher other revenues, which accounted for an additional $10 million increase.

Gross operating margin from crude oil activities at EHT decreased a net $1 million quarter-to-quarter primarily due to lower storage and other revenues, which accounted for a $6 million decrease, partially offset by higher loading revenues, which accounted for a $5 million increase. Crude oil marine terminal volumes at EHT decreased 179 MBPD quarter-to-quarter.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024 . Gross operating margin from our Crude Oil Pipelines & Services segment for the nine months ended September 30, 2025 decreased $81 million when compared to the nine months ended September 30, 2024 .

Gross operating margin from our Texas crude oil pipelines, related terminals and marketing activities (excluding the Seaway Pipeline) decreased a combined net $100 million period-to-period primarily due to lower sales volumes from marketing activities, which accounted for a $43 million decrease, lower average sales margins from marketing activities, which accounted for a $41 million decrease, lower mark-to-market earnings, which accounted for a $20 million decrease, and higher operating costs, which accounted for an additional $19 million decrease, partially offset by higher average crude oil transportation fees, which accounted for a $14 million increase, and a combined 74 MBPD (net to our interest) increase in crude oil transportation volumes, which accounted for an additional $10 million increase.

Gross operating margin from crude oil activities at EHT increased $26 million period-to-period primarily due to lower operating costs, which accounted for a $12 million increase, higher loading revenues, which accounted for a $9 million increase, and higher storage and other revenues, which accounted for an additional $5 million increase. Crude oil marine terminal volumes at EHT decreased 217 MBPD period-to-period.

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Natural Gas Pipelines & Services

The following table presents segment gross operating margin and selected volumetric data for the Natural Gas Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Segment gross operating margin	$	339	$	349	$	1,113	$	954

Selected volumetric data:
Natural gas pipeline transportation volumes (BBtus/d)	21,027		19,517		20,583		19,057

Third Quarter of 2025 Compared to Third Quarter of 2024 . Gross operating margin from our Natural Gas Pipelines & Services segment for the third quarter of 2025 decreased $10 million when compared to the third quarter of 2024 .

Gross operating margin from our natural gas marketing activities decreased $47 million quarter-to-quarter primarily due to lower mark-to-market earnings, which accounted for a $41 million decrease, and lower average sales margins, which accounted for an additional $6 million decrease.

Gross operating margin from our Delaware Basin Gathering System, which includes the natural gas gathering system acquired in October 2024 through our acquisition of Pinon Midstream, increased a net $24 million quarter-to-quarter primarily due to higher treating and other revenues, which accounted for a $22 million increase, a 660 BBtus/d increase in natural gas gathering volumes, which accounted for an additional $13 million increase, partially offset by higher operating costs, which accounted for an $14 million decrease.

Gross operating margin from our Midland Basin Gathering System increased a net $7 million quarter-to-quarter primarily due to a 277 BBtus/d increase in natural gas gathering volumes, which accounted for a $12 million increase, partially offset by higher operating costs, which accounted for a $5 million decrease.

Gross operating margin from our Texas Intrastate System increased a net $5 million quarter-to-quarter primarily due to higher capacity reservation fees and other revenues, which accounted for a $23 million increase, and a 374 BBtus/d increase in transportation volumes, which accounted for an additional $4 million increase, partially offset by lower average transportation fees, which accounted for a $21 million decrease.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024 . Gross operating margin from our Natural Gas Pipelines & Services segment for the nine months ended September 30, 2025 increased $159 million when compared to the nine months ended September 30, 2024 .

Gross operating margin from our Delaware Basin Gathering System, increased a net $69 million period-to-period primarily due to higher treating and other revenues, which accounted for a $59 million increase, a 649 BBtus/d increase in natural gas gathering volumes, which accounted for a $39 million increase, and higher average gathering fees, which accounted for an additional $12 million increase, partially offset by higher operating costs, which accounted for a $41 million decrease.

Gross operating margin from our Texas Intrastate System increased a net $53 million period-to-period primarily due to higher capacity reservation fees and other revenues, which accounted for a $58 million increase, and a 311 BBtus/d increase in transportation volumes, which accounted for an additional $11 million increase, partially offset by lower average transportation fees, which accounted for a $15 million decrease.

Gross operating margin from our Midland Basin Gathering System increased a net $23 million period-to-period primarily due to a 428 BBtus/d increase in natural gas gathering volumes, which accounted for a $45 million increase, partially offset by higher operating costs, which accounted for a $22 million decrease.

Gross operating margin from our natural gas marketing activities increased a net $13 million period-to-period primarily due to higher average sales margins, which accounted for a $21 million increase, and higher sales volumes, which accounted for an additional $9 million increase, partially offset by lower mark-to-market earnings, which accounted for a $17 million decrease.

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Petrochemical & Refined Products Services

The following table presents segment gross operating margin and selected volumetric data for the Petrochemical & Refined Products Services segment for the periods indicated (dollars in millions, volumes as noted):


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Segment gross operating margin:
Propylene production and related activities	$	112	$	128	$	332	$	396
Butane isomerization and related operations	30		28		88		90
Octane enhancement and related plant operations	81		96		197		344
Refined products pipelines and related activities	93		67		274		212
Ethylene exports and related activities	36		25		90		106
Marine transportation and other services	18		19		58		51
Total	$	370	$	363	$	1,039	$	1,199

Selected volumetric data:
Propylene production volumes (MBPD)	119		124		117		112
Butane isomerization volumes (MBPD)	123		116		120		117
Standalone deisobutanizer (“DIB”) processing volumes (MBPD)	196		191		190		199
Octane enhancement and related plant sales volumes (MBPD) (1)	41		37		42		37
Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD)	1,056		995		1,003		942
Marine terminal volumes, primarily refined products and petrochemicals (MBPD)	347		286		329		333

(1) Reflects aggregate sales volumes for our octane enhancement and iBDH facilities located at our Mont Belvieu area complex and our HPIB facility located adjacent to the Houston Ship Channel.

Propylene production and related activities

Third Quarter of 2025 Compared to Third Quarter of 2024 . Gross operating margin from propylene production and related activities for the third quarter of 2025 decreased $16 million when compared to the third quarter of 2024 .

On a combined basis, gross operating margin from our Mont Belvieu area propylene production facilities decreased a net $8 million quarter-to-quarter primarily due to higher operating costs, which accounted for a $16 million decrease, partially offset by higher propylene sales volumes, which accounted for a $5 million increase, and higher propylene processing and other revenues, which accounted for an additional $4 million increase. Propylene and associated by-product production volumes at these facilities decreased a combined 7 MBPD quarter-to-quarter .

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024 . Gross operating margin from propylene production and related activities for the nine months ended September 30, 2025 decreased $64 million when compared to the nine months ended September 30, 2024 .

On a combined basis, gross operating margin from our Mont Belvieu area propylene production facilities decreased a net $48 million period-to-period primarily due to higher operating costs, which accounted for an $82 million decrease, and lower average propylene sales margins, which accounted for an additional $42 million decrease, partially offset by higher propylene sales volumes, which accounted for a $52 million increase, and higher propylene processing and other revenues, which accounted for an additional $25 million increase . Propylene and associated by-product production volumes at these facilities increased a combined 4 MBPD .

Butane isomerization and related operations

Third Quarter of 2025 Compared to Third Quarter of 2024 . Gross operating margin from butane isomerization and related operations for the third quarter of 2025 increased $2 million when compared to the third quarter of 2024 primarily due to higher average sales margins and a 7 MBPD increase in isomerization volumes.

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Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024 . Gross operating margin from butane isomerization and related operations for the nine months ended September 30, 2025 decreased a net $2 million when compared to the nine months ended September 30, 2024 primarily due to higher operating costs, which accounted for a $9 million decrease, partially offset by higher ancillary service revenues, which accounted for a $7 million increase.

Octane enhancement and related plant operations

Third Quarter of 2025 Compared to Third Quarter of 2024 . Gross operating margin from our octane enhancement and related plant operations for the third quarter of 2025 decreased a net $15 million when compared to the third quarter of 2024 primarily due to lower average sales margins, which accounted for a $27 million decrease, and higher operating costs, which accounted for an additional $5 million decrease, partially offset by higher sales volumes, which accounted for a $17 million increase.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024 . Gross operating margin from our octane enhancement and related plant operations for the nine months ended September 30, 2025 decreased a net $147 million when compared to the nine months ended September 30, 2024 primarily due to lower average sales margins, which accounted for a $125 million decrease, lower deficiency revenues, which accounted for a $32 million decrease, and higher operating costs, which accounted for an additional $8 million decrease, partially offset by higher sales volumes, which accounted for a $19 million increase.

Refined products pipelines and related activities

Third Quarter of 2025 Compared to Third Quarter of 2024 . Gross operating margin from refined products pipelines and related activities for the third quarter of 2025 increased $26 million when compared to the third quarter of 2024 .

Gross operating margin from our TW Products System increased $10 million quarter-to-quarter primarily due to the full start-up of the system, which was placed into service in stages during 2024 and was fully operational in October 2024.

Gross operating margin from our TE Products Pipeline System increased a net $9 million quarter-to-quarter primarily due to a 61 MBPD increase in transportation volumes, which accounted for a $16 million increase, partially offset by higher operating costs, which accounted for a $10 million decrease.

Gross operating margin from our refined products marketing activities increased a net $5 million quarter-to-quarter primarily due to higher average sales margins, which accounted for a $13 million increase, partially offset by lower sales volumes, which accounted for a $6 million decrease.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024 . Gross operating margin from refined products pipelines and related activities for the nine months ended September 30, 2025 increased $62 million when compared to the nine months ended September 30, 2024 .

Gross operating margin from our TE Products Pipeline System increased a net $38 million period-to-period primarily due to a 33 MBPD increase in transportation volumes, which accounted for a $39 million increase, higher average transportation fees, which accounted for a $12 million increase, and higher other revenues, which accounted for an additional $10 million increase, partially offset by higher operating costs, which accounted for a $23 million decrease.

Gross operating margin from our TW Products System increased $36 million period-to-period primarily due to the full start-up of the system, which was placed into service in stages during 2024 and was fully operational in October 2024.

Gross operating margin from our refined products marketing activities decreased $14 million period-to-period primarily due to lower average sales margins.

Ethylene exports and related activities

Third Quarter of 2025 Compared to Third Quarter of 2024 . Gross operating margin from ethylene exports and related activities for the third quarter of 2025 increased a net $11 million when compared to the third quarter of 2024 primarily due to a 28 MBPD increase in ethylene export volumes, which accounted for a $14 million increase, and higher storage and other revenues, which accounted for a $3 million increase, partially offset by higher operating costs, which accounted for a $7 million decrease. Ethylene transportation volumes increased 22 MBPD quarter-to-quarter.

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Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024 . Gross operating margin from ethylene exports and related activities for the nine months ended September 30, 2025 decreased a net $16 million when compared to the nine months ended September 30, 2024 primarily due to lower deficiency fee revenues from our ethylene pipelines, which accounted for a $16 million decrease, and higher operating costs, which accounted for an additional $10 million decrease, partially offset by a 3 MBPD increase in ethylene export volumes, which accounted for a $5 million increase, and higher storage and other revenues, which accounted for an additional $5 million increase. Ethylene transportation volumes increased 3 MBPD period-to-period.

Marine transportation and other services

Third Quarter of 2025 Compared to Third Quarter of 2024 . Gross operating margin from marine transportation and other services for the third quarter of 2025 decreased $1 million when compared to the third quarter of 2024 primarily due to higher operating costs.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024 . Gross operating margin from marine transportation and other services for the nine months ended September 30, 2025 increased a net $7 million when compared to the nine months ended September 30, 2024 primarily due to higher average fees, which accounted for a $10 million increase, partially offset by higher operating costs, which accounted for a $3 million decrease.

Liquidity and Capital Resources

Based on current market conditions (as of the filing date of this quarterly report), we believe that the Partnership and its consolidated businesses will have sufficient liquidity, cash flow from operations and access to capital markets to fund their capital investments and working capital needs for the reasonably foreseeable future. At September 30, 2025 , we had $3.6 billion of consolidated liquidity. This amount was comprised of $3.4 billion of available borrowing capacity under EPO’s revolving credit facilities, which is the net of $4.2 billion of total borrowing capacity under EPO’s revolving credit facilities and $840 million outstanding under EPO’s commercial paper program, and $206 million of unrestricted cash on hand.

We may issue debt and equity securities to assist us in meeting our future funding and liquidity requirements, including those related to capital investments. We have a universal shelf registration statement on file with the SEC that allows the Partnership and EPO to issue an unlimited amount of equity and debt securities, respectively. In addition, we have a registration statement on file with the SEC covering the issuance of up to $2.5 billion of the Partnership’s 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).

Enterprise Declares Cash Distribution for Third Quarter of 2025

On October 7, 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 third quarter of 2025. The quarterly distribution is payable on November 14, 2025 to unitholders of record as of the close of business on October 31, 2025. The total amount to be paid is $1.19 billion , which includes $11 million for distribution equivalent rights on phantom unit awards.

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Consolidated Debt

At September 30, 2025 , the average maturity of EPO’s consolidated debt obligations was approximately 17.2 years. The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at September 30, 2025 for the years indicated (dollars in millions):


			Scheduled Maturities of Debt
	Total		Remainder of 2025		2026		2027		2028		2029		Thereafter
Commercial Paper Notes	$	840	$	840	$	–	$	–	$	–	$	–	$	–
Senior Notes	30,775		–		1,625		1,575		1,500		1,250		24,825
Junior Subordinated Notes	2,282		–		–		–		–		–		2,282
Total	$	33,897	$	840	$	1,625	$	1,575	$	1,500	$	1,250	$	27,107

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. The March 2025 $1.5 Billion 364-Day Revolving Credit Agreement matures in March 2026. EPO’s borrowing capacity was unchanged from the prior 364-day revolving credit agreement. As of September 30, 2025 , there are no principal amounts outstanding under this new revolving credit agreement.

Also in March 2025, EPO amended its Multi-Year Revolving Credit Agreement (the “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. As of September 30, 2025 , there are no principal amounts outstanding under this revolving credit agreement.

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”). 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. 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).

For additional information regarding our consolidated debt obligations, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Credit Ratings

As of November 6, 2025 , the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were A- from Standard and Poor’s, A3 from Moody’s and A- from Fitch Ratings. In addition, the credit ratings of EPO’s short-term senior unsecured debt securities were A-2 from Standard and Poor’s, P-2 from Moody’s and F-2 from Fitch Ratings. EPO’s credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities. A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change. A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies.

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 Partnership repurchased 2,543,004 and 7,913,198 common units during the three and nine months ended September 30, 2025, respectively . The total cost of these repurchases, including commissions and fees was $80 million and $250 million, respectively . As of September 30, 2025 , the remaining available capacity under the 2019 Buyback Program was $613 million.

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In October 2025, we announced that the Board approved an increase to the authorized maximum aggregate purchase price (excluding fees, commissions and other ancillary expenses) of the Partnership’s common units that may be repurchased under the 2019 Buyback Program from $2.0 billion to $5.0 billion. After giving effect to this increase, the remaining available capacity under the 2019 Buyback Program is $3.6 billion.

Cash Flow Statement Highlights

The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods indicated (dollars in millions).


	For the Nine Months Ended September 30,
	2025		2024
Net cash flow provided by operating activities	$	6,113	$	5,757
Net cash flow used in investing activities	4,256		3,433
Net cash flow used in financing activities	2,263		971

Net cash flow provided by operating activities are largely dependent on earnings from our consolidated business activities. Changes in energy commodity prices may impact the demand for natural gas, NGLs, crude oil, petrochemicals and refined products, which could impact sales of our products and the demand for our midstream services. Changes in demand for our products and services may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, public health emergencies, adverse weather conditions and government regulations affecting prices and production levels. We may also incur credit and price risk to the extent customers do not fulfill their contractual obligations to us in connection with our marketing activities and long-term take-or-pay and dedication agreements. For a more complete discussion of these and other risk factors pertinent to our business, see “ Risk Factors ” included under Part I, Item 1A of the 2024 Form 10-K and Part II, Item 1A of this quarterly report.

For additional information regarding our cash flow amounts, please refer to the Unaudited Condensed Statements of Consolidated Cash Flows included under Part I, Item 1 of this quarterly report.

The following information highlights significant quarter-to-quarter fluctuations in our consolidated cash flow amounts:

Operating activities

Net cash flow provided by operating activities for the nine months ended September 30, 2025 increased $356 million when compared to the nine months ended September 30, 2024 primarily due to changes in operating accounts primarily due to the use of working capital employed in our marketing activities, which includes the impact of (i) fluctuations in commodity prices, (ii) timing of our inventory purchase and sale strategies, and (iii) changes in margin deposit requirements associated with our commodity derivative instruments.

For information regarding significant period-to-period changes in our consolidated net income and underlying segment results, see “ Income Statement Highlights ” and “ Business Segment Highlights ” within this Part I, Item 2.

Investing activities

Net cash flow used in investing activities during the nine months ended September 30, 2025 increased $823 million when compared to the nine months ended September 30, 2024 primarily due to an increase in investments for property, plant and equipment (see “ Capital Investments ” within this Part I, Item 2 for additional information).

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Financing activities

Net cash flow used in financing activities during the nine months ended September 30, 2025 increased a net $1.3 billion when compared to the nine months ended September 30, 2024 primarily due to:

• a net cash inflow of $1.7 billion related to debt transactions that occurred during the nine months ended September 30, 2025 compared to a net cash inflow of $3.1 billion related to debt transactions that occurred during the nine months ended September 30, 2024 . During the nine months ended September 30, 2025 , we issued $2.0 billion aggregate principal amount of senior notes and issued a net $840 million under EPO’s commercial paper program, partially offset by the repayment of $1.15 billion principal amount of senior notes. During the nine months ended September 30, 2024 , we issued $4.5 billion aggregate principal amount of senior notes, partially offset by the repayment of $850 million principal amount of senior notes and net repayments of $450 million under EPO’s commercial paper program;

• a $125 million period-to-period increase in cash distributions paid to common unitholders primarily attributable to increases in the quarterly cash distribution rate per unit; and

• a $94 million period-to-period increase in the repurchase of common units under the 2019 Buyback Program; p artially offset by

• a $400 million cash outflow during the first quarter of 2024 in connection with the acquisition of noncontrolling interests from affiliates of Western Midstream Partners, LP.

Non-GAAP Cash Flow Measures

Distributable Cash Flow and Operational Distributable Cash Flow

Our partnership agreement requires us to make quarterly distributions to our common unitholders of all available cash, after any cash reserves established by Enterprise GP in its sole discretion. Cash reserves include those for the proper conduct of our business, including those for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash allows us to reinvest in our growth and reduce our future reliance on the equity and debt capital markets.

We measure available cash by reference to distributable cash flow (“DCF”), which is a non-GAAP cash flow measure. DCF is an important financial measure for our common unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain our declared quarterly cash distributions. DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships since the value of a partnership unit is, in part, measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. Our management compares the DCF we generate to the cash distributions we expect to pay our common unitholders. Using this metric, management computes our distribution coverage ratio. Our calculation of DCF may or may not be comparable to similarly titled measures used by other companies.

Based on the level of available cash each quarter, management proposes a quarterly cash distribution rate to the Board, which has sole authority in approving such matters. Enterprise GP has a non-economic ownership interest in the Partnership and is not entitled to receive any cash distributions from it based on incentive distribution rights or other equity interests.

Operational distributable cash flow (“Operational DCF”), which is defined as DCF excluding the impact of proceeds from asset sales and other matters and monetization of interest rate derivative instruments, is a supplemental non-GAAP liquidity measure that quantifies the portion of cash available for distribution to common unitholders that was generated from our normal operations. We believe that it is important to consider this non-GAAP measure as it provides an enhanced perspective of our assets’ ability to generate cash flows without regard for certain items that do not reflect our core operations.

Our use of DCF and Operational DCF for the limited purposes described above and in this quarterly report is not a substitute for net cash flow provided by operating activities, which is the most comparable GAAP measure to DCF and Operational DCF. For a discussion of net cash flow provided by operating activities, see “ Cash Flow Statement Highlights ” within this Part I, Item 2.

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The following table summarizes our calculation of DCF and Operational DCF for the periods indicated (dollars in millions):


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2025			2024			2025			2024
Net income attributable to common unitholders (GAAP) (1)	$	1,338		$	1,417		$	4,166		$	4,278
Adjustments to net income attributable to common unitholders to derive DCF and Operational DCF (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expenses	660			618			1,939			1,845
Cash distributions received from unconsolidated affiliates (2)	112			124			336			367
Equity in income of unconsolidated affiliates	(90)			(99)			(276)			(302)
Asset impairment charges	17			27			38			51
Change in fair market value of derivative instruments	34			(3)			24			(11)
Deferred income tax expense (benefit)	(17)			9			(1)			23
Sustaining capital expenditures (3)	(198)			(129)			(417)			(554)
Other, net	(37)			(8)			(67)			9
Operational DCF (non-GAAP)	$	1,819		$	1,956		$	5,742		$	5,706
Proceeds from asset sales and other matters	6			5			21			11
Monetization of interest rate derivative instruments accounted for as cash flow hedges	–			(4)			14			(33)
DCF (non-GAAP)	$	1,825		$	1,957		$	5,777		$	5,684

Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards	$	1,190		$	1,149		$	3,552		$	3,428

Cash distribution per common unit declared by Enterprise GP with respect to period (4)	$	0.5450		$	0.5250		$	1.6250		$	1.5650

Total DCF retained by the Partnership with respect to period (5)	$	635		$	808		$	2,225		$	2,256

Distribution coverage ratio (6)	1.5		x	1.7		x	1.6		x	1.7		x

(1) For a discussion of the primary drivers of changes in our comparative income statement amounts, see “ Income Statement Highlights ” within this Part I, Item 2.

(2) Reflects aggregate distributions received from unconsolidated affiliates attributable to both earnings and the return of capital.

(3) Sustaining capital expenditures include cash payments and accruals applicable to the period.

(4) See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for information regarding our quarterly cash distributions declared with respect to the periods indicated.

(5) Cash retained by the Partnership may be used for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash reduces our reliance on the capital markets.

(6) Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to common unitholders and in connection with distribution equivalent rights with respect to the period.

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The following table presents a reconciliation of net cash flow provided by operating activities to DCF and Operational DCF for the periods indicated (dollars in millions):


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Net cash flow provided by operating activities (GAAP)	$	1,738	$	2,072	$	6,113	$	5,757
Adjustments to reconcile net cash flow provided by operating activities to DCF and Operational DCF (addition or subtraction indicated by sign):
Net effect of changes in operating accounts	322		36		169		563
Sustaining capital expenditures	(198)		(129)		(417)		(554)
Distributions received from unconsolidated affiliates attributable to the return of capital	21		25		56		64
Net income attributable to noncontrolling interests	(17)		(14)		(47)		(56)
Other, net	(47)		(34)		(132)		(68)
Operational DCF (non-GAAP)	$	1,819	$	1,956	$	5,742	$	5,706
Proceeds from asset sales and other matters	6		5		21		11
Monetization of interest rate derivative instruments accounted for as cash flow hedges	–		(4)		14		(33)
DCF (non-GAAP)	$	1,825	$	1,957	$	5,777	$	5,684

Capital Investments

Since the beginning of 2025, we have placed into service two natural gas processing trains in the Permian Basin, the first phase of our Neches River Ethane / Propane Export Facility and an NGL fractionator (“Frac 14”) and associated DIB unit at our Mont Belvieu area NGL fractionation complex. We have approximately $5.1 billion of growth capital projects scheduled to be completed by the end of 2026, including the following projects (including their respective scheduled completion dates):

• natural gas gathering, compression and treating expansion projects in the Delaware and Midland Basins (2025 and 2026);

• the Bahia NGL Pipeline (fourth quarter of 2025);

• the second phase of enhancements at our Morgan’s Point terminal (fourth quarter of 2025);

• the second phase of our Neches River Ethane / Propane Export Facility located in Orange County, Texas (first half of 2026);

• our second natural gas processing train at our Mentone West location in the Delaware Basin (first half of 2026);

• the expansion of our LPG and PGP export capacity at EHT, including Ref 4 (fourth quarter of 2026); and

• a ninth natural gas processing train (“Athena”) in the Midland Basin (fourth quarter of 2026).

Based on information currently available, we expect our total organic capital investments for 2025 , net of contributions from noncontrolling interests, to approximate $5.0 billion, which reflects organic growth capital investments of $4.5 billion and sustaining capital expenditures of $525 million.

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Our forecast of capital investments is dependent upon our ability to generate the required funds from either operating cash flows or other means, including borrowings under debt agreements, the issuance of additional equity and debt securities, and potential divestitures. We may revise our forecast of capital investments due to factors beyond our control, such as adverse economic conditions, weather-related issues and changes in supplier prices resulting from raw material or labor shortages, supply chain disruptions or inflation. Furthermore, our forecast of capital investments may change over time based on future decisions by management, which may include changing the scope or timing of projects or cancelling projects altogether. Our success in raising capital, having the ability to increase revenues commensurate with cost increases and our ability to partner with other companies to share project costs and risks continue to be significant factors in determining how much capital we can invest. We believe our access to capital resources is sufficient to meet the demands of our current and future growth needs, and although we currently expect to make the forecast capital investments noted above, we may revise our plans in response to changes in economic and capital market conditions.

The following table summarizes our capital investments for the periods indicated (dollars in millions):


	For the Nine Months Ended September 30,
	2025		2024
Capital investments: (1)
Growth capital projects (2)	$	3,368	$	2,950
Sustaining capital projects (3)	368		535
Asset acquisitions (4)	583		–
Total	$	4,319	$	3,485

(1) Growth capital, sustaining capital and asset acquisition amounts presented in the table above are presented on a cash basis. In total, these amounts represent “Capital expenditures” as presented on our Unaudited Condensed Statements of Consolidated Cash Flows.

(2) Growth capital projects either (a) result in new sources of cash flow due to enhancements of or additions to existing assets (e.g., additional revenue streams, cost savings resulting from debottlenecking of a facility, etc.) or (b) expand our asset base through construction of new facilities that will generate additional revenue streams and cash flows.

(3) Sustaining capital projects are capital expenditures (as defined by GAAP) resulting from improvements to existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues or result in significant cost savings. Sustaining capital expenditures include the costs of major maintenance activities at our reaction-based plants, which are accounted for using the deferral method.

(4) Amount for the nine months ended September 30, 2025 represents the total cost of the acquisition of the Oxy natural gas gathering affiliate, which closed in August 2025. The total acquisition cost presented is comprised of $581 million in cash consideration paid to Oxy and $2 million in transaction-related costs. For additional information, see Note 12 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Comparison of Nine Months Ended September 30, 2025 with Nine Months Ended September 30, 2024

In total, investments in growth capital projects increased a net $418 million period-to-period primarily due to the following:

• higher investments in the construction of natural gas processing trains and related gathering system expansions in the Delaware and Midland Basins, which accounted for a $291 million increase;

• higher investments in our Bahia NGL Pipeline, which accounted for an additional $254 million increase; partially offset by

• lower investments in our TW Products System (placed into service during 2024), which accounted for a $145 million decrease.

Investments attributable to sustaining capital projects decreased $167 million period-to-period primarily due to lower major maintenance activities performed at certain of our reaction-based plants (e.g., our PDH 1 and iBDH facilities) and fluctuations in timing and costs of pipeline integrity and similar projects.

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our 2024 Form 10-K. The following types of estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis:

• depreciation methods and estimated useful lives of property, plant and equipment;

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• measuring recoverability of long-lived assets and fair value of equity method investments;

• amortization methods of customer relationships and contract-based intangible assets;

• methods we employ to measure the fair value of goodwill and related assets; and

• the use of estimates for revenue and expenses.

When used to prepare our Unaudited Condensed Consolidated Financial Statements, the foregoing types of estimates are based on our current knowledge and understanding of the underlying facts and circumstances. Such estimates may be revised as a result of changes in the underlying facts and circumstances. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.

Other Matters

Parent-Subsidiary Guarantor Relationship

The Partnership (the “Parent Guarantor”) has guaranteed the payment of principal and interest on the consolidated debt obligations of EPO (the “Subsidiary Issuer”) (collectively, the “Guaranteed Debt”). If EPO were to default on any of its Guaranteed Debt, the Partnership would be responsible for full and unconditional repayment of such obligations. At September 30, 2025 , the total amount of Guaranteed Debt was $34.2 billion , which was comprised of $30.8 billion of EPO’s senior notes, $2.3 billion of EPO’s junior subordinated notes, $840 million of commercial paper and $288 million of related accrued interest.

The Partnership’s guarantees of EPO’s senior note obligations, commercial paper notes and borrowings under bank credit facilities represent unsecured and unsubordinated obligations of the Partnership that rank equal in right of payment to all other existing or future unsecured and unsubordinated indebtedness of the Partnership. In addition, these guarantees effectively rank junior in right of payment to any existing or future indebtedness of the Partnership that is secured and unsubordinated, to the extent of the assets securing such indebtedness.

The Partnership’s guarantees of EPO’s junior subordinated notes represent unsecured and subordinated obligations of the Partnership that rank equal in right of payment to all other existing or future subordinated indebtedness of the Partnership and senior in right of payment to all existing or future equity securities of the Partnership. The Partnership’s guarantees of EPO’s junior subordinated notes effectively rank junior in right of payment to (i) any existing or future indebtedness of the Partnership that is secured, to the extent of the assets securing such indebtedness and (ii) all other existing or future unsecured and unsubordinated indebtedness of the Partnership.

The Partnership may be released from its guarantee obligations only in connection with EPO’s exercise of its legal or covenant defeasance options as described in the underlying agreements.

Selected Financial Information of Obligor Group

The following tables present summarized financial information of the Partnership (as Parent Guarantor) and EPO (as Subsidiary Issuer) on a combined basis (collectively, the “Obligor Group”), after the elimination of intercompany balances and transactions among the Obligor Group.

In accordance with Rule 13.01 of Regulation S-X, the summarized financial information of the Obligor Group excludes the Obligor Group’s equity in income and investments in the consolidated subsidiaries of EPO that are not party to the guarantee obligations (the “Non-Obligor Subsidiaries”). The total carrying value of the Obligor Group’s investments in the Non-Obligor Subsidiaries was $54.5 billion at September 30, 2025 . The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the nine months ended September 30, 2025 was $5.0 billion . Although the net assets and earnings of the Non-Obligor Subsidiaries are not directly available to the holders of the Guaranteed Debt to satisfy the repayment of such obligations, there are no significant restrictions on the ability of the Non-Obligor Subsidiaries to pay distributions or make loans to EPO or the Partnership. EPO exercises control over the Non-Obligor Subsidiaries. We continue to believe that the unaudited condensed consolidated financial statements of the Partnership presented under Part I, Item 1 of this quarterly report provide a more appropriate view of our credit standing. Our investment grade credit ratings are based on the Partnership’s consolidated financial statements and not the Obligor Group’s financial information presented below.

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The following table presents summarized balance sheet information for the combined Obligor Group at the dates indicated (dollars in millions):


Selected asset information:	September 30, 2025		December 31, 2024
Current receivables from Non-Obligor Subsidiaries	$	520	$	1,569
Other current assets	6,044		6,487
Long-term receivables from Non-Obligor Subsidiaries	187		187
Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $54.5 billion at September 30, 2025 and $50.8 billion at December 31, 2024	9,293		9,350

Selected liability information:
Current portion of Guaranteed Debt, including interest of $288 million at September 30, 2025 and $536 million at December 31, 2024	$	2,752	$	1,686
Current payables to Non-Obligor Subsidiaries	1,551		1,438
Other current liabilities	4,219		4,074
Noncurrent portion of Guaranteed Debt, principal only	31,432		31,057
Noncurrent payables to Non-Obligor Subsidiaries	55		55
Other noncurrent liabilities	188		215

Mezzanine equity of Obligor Group:
Preferred units	$	50	$	50

The following table presents summarized income statement information for the combined Obligor Group for the periods indicated (dollars in millions):


	For the Nine Months Ended September 30, 2025		For the Twelve Months Ended December 31, 2024
Revenues from Non-Obligor Subsidiaries	$	14,187	$	22,286
Revenues from other sources	12,053		19,781
Operating income of Obligor Group	186		443
Net loss of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $5.0 billion for the nine months ended September 30, 2025 and $6.8 billion for the twelve months ended December 31, 2024	(882)		(933)

Related Party Transactions

For information regarding our related party transactions, see Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES

ABOUT MARKET RISK.

General

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 and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities.

We assess the risk associated with each of our derivative instrument portfolios using a sensitivity analysis model. This approach measures the change in fair value of the derivative instrument portfolio based on a hypothetical 10% change in the underlying interest rates or quoted market prices on a particular day. In addition to these variables, the fair value of each portfolio is influenced by changes in the notional amounts of the instruments outstanding. The sensitivity analysis approach does not reflect the impact that the same hypothetical price movement would have on the hedged exposures to which they relate. Therefore, the impact on the fair value of a derivative instrument resulting from a change in interest rates or quoted market prices (as applicable) would normally be offset by a corresponding gain or loss on the hedged debt instrument, inventory value or forecasted transaction assuming:

• the derivative instrument functions effectively as a hedge of the underlying risk;

• the derivative instrument is not closed out in advance of its expected term; and

• the hedged forecasted transaction occurs within the expected time period.

We routinely review the effectiveness of our derivative instrument portfolios in light of current market conditions. Accordingly, the nature and volume of our derivative instruments may change depending on the specific exposure being managed.

Commodity Hedging Activities

The price of energy commodities such as 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.

At September 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. For a summary of our portfolio of commodity derivative instruments outstanding, see Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Sensitivity Analysis

The following tables show the effect of hypothetical price movements on the estimated fair values of our principal commodity derivative instrument portfolios at the dates indicated (dollars in millions).

The fair value information presented in the sensitivity analysis tables excludes the impact of applying Chicago Mercantile Exchange (“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.

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Natural gas marketing portfolio


		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2024		September 30, 2025		October 15, 2025
Fair value assuming no change in underlying commodity prices	Asset (Liability)	$	5	$	(4)	$	20
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)	4		(15)		11
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)	6		7		29

NGL, petrochemical and refined products marketing, natural gas processing and octane enhancement portfolio


		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2024		September 30, 2025		October 15, 2025
Fair value assuming no change in underlying commodity prices	Asset (Liability)	$	61	$	44	$	50
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)	24		13		30
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)	98		75		70

Crude oil marketing portfolio


		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2024		September 30, 2025		October 15, 2025
Fair value assuming no change in underlying commodity prices	Asset (Liability)	$	19	$	58	$	112
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)	(79)		(52)		23
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)	117		168		201

Commercial energy derivative portfolio


		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2024		September 30, 2025		October 15, 2025
Fair value assuming no change in underlying commodity prices	Asset (Liability)	$	(3)	$	(2)	$	(7)
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)	7		6		–
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)	(13)		(10)		(14)

Interest Rate Hedging Activities

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ITEM 4. CONTROLS AND PROCEDURES.

Disclosure Controls and Procedures

As of the end of the period covered by this quarterly report, our management carried out an evaluation, with the participation of (i) A. James Teague, Co-Chief Executive Officer of Enterprise GP, (ii) W. Randall Fowler, Co-Chief Executive Officer of Enterprise GP and (iii) R. Daniel Boss, Executive Vice President and Chief Financial Officer of Enterprise GP, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Based on this evaluation, as of the end of the period covered by this quarterly report, Messrs. Teague, Fowler and Boss concluded:

(i) that our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive and financial officers, as appropriate to allow for timely decisions regarding required disclosures; and

(ii) that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) during the third quarter of 2025 , that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Section 302 and 906 Certifications

The required certifications of Messrs. Teague, Fowler and Boss under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 are included as exhibits to this quarterly report (see Exhibits 31 and 32 under Part II, Item 6 of this quarterly report).

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PART II. OTHER INFORMATION.

ITEM 1. LEGAL PROCEEDINGS.

As part of our normal business activities, we may be named as defendants in litigation and 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 indemnify us against liabilities arising from future legal proceedings. We will vigorously defend the Partnership in litigation matters.

For additional information regarding our litigation matters, see Note 17 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

On occasion, we are assessed monetary penalties by governmental authorities related to administrative or judicial proceedings involving environmental matters. The following information summarizes matters where the eventual resolution of each of these matters may result in monetary sanctions in excess of $0.3 million. We do not expect that any expenditures related to the following matters will be material to our consolidated financial statements.

• In June 2019, we received a Notice of Violation from the U.S. Environmental Protection Agency (“EPA”) in connection with regulatory requirements applicable to facilities that we operate near Baton Rouge, Louisiana.

• In August 2022, we received a Notice of Violation from the U.S. EPA alleging that gasoline at two of our refined products terminals in Texas had exceeded certain Clean Air Act-related standards during two past regulatory control periods.

• In November 2024 and January 2025, we received notices that the New Mexico Environment Department intended to pursue enforcement for alleged exceedances of emission limits, and alleged associated late emissions reports, at our recently acquired Pinon Midstream treating facility and compressor station on various occasions from 2021 through October 2024 (prior to our acquisition date).

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ITEM 1A. RISK FACTORS.

An investment in our securities involves certain risks. Security holders and potential investors in our securities should carefully consider the risks described under “ Risk Factors ” set forth in Part I, Item 1A of our 2024 Form 10-K, in addition to other information in such annual report and this quarterly report (including the risk factor set forth below). The risk factors set forth in our 2024 Form 10-K and as set forth below are important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

Changes in U.S. trade policy and the impact of tariffs may have a material adverse effect on our business and results of operations.

Our business and results of operations may be adversely affected by uncertainty and changes in U.S. trade policies, including tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments. These actions have caused uncertainty and volatility in financial markets, may result in retaliatory measures on U.S. goods and may adversely impact both the U.S. and global economies.

Our business requires access to steel and other materials to construct and maintain our pipelines. While our practice is to source steel through domestic producers in the U.S. in most instances, any imposition of or increase in tariffs on imports of steel or other materials, as well as corresponding price increases for such materials available domestically, could increase our construction costs and our costs to maintain our assets. To the extent that we are unable to pass all or any such cost increases on to our customers, such cost increases could adversely affect our returns on investment. Higher materials costs could also diminish our ability to develop new projects at acceptable returns, particularly during times of economic uncertainty, and limit our ability to pursue growth opportunities.

Tariffs or other trade restrictions may lead to continuing uncertainty and volatility in U.S. and global financial and economic conditions and commodity markets, inflation, and reduced demand for our and our customers’ products and services. Such conditions could have a material adverse impact on our business, results of operations and cash flows. Also, disruptions and volatility in the financial markets may lead to adverse changes in the availability, terms and cost of capital. Such adverse changes could increase our costs of capital and limit our access to external financing sources to fund acquisitions, capital projects, or refinancing of debt maturities on similar terms, which could in turn reduce our cash flows and limit our ability to pursue growth opportunities.

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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

Recent Issuances of Unregistered Securities

Holders of our Series A Cumulative Convertible Preferred Units (“preferred units”) are entitled to receive cumulative quarterly distributions at a rate of 7.25% per annum. We may satisfy our obligation to pay distributions to the preferred unitholders through the issuance, in whole or in part, of additional preferred units (referred to as paid-in-kind or “PIK” distributions), with the remainder in cash, subject to certain rights of a holder to elect all cash and other conditions as described in our partnership agreement.

The Partnership made quarterly PIK distributions to preferred unitholders in the first, second and third quarters of 2025 of 20,965, 21,345 and 21,732 preferred units, respectively. With the exception of 95, 97 and 99 preferred units distributed to an unaffiliated third party in the first, second and third quarters of 2025 , respectively, all of the PIK distributions made during the nine months ended September 30, 2025 were to OTA Holdings, Inc. (“OTA”), an indirect, wholly owned subsidiary of the Partnership. The preferred units held by OTA are accounted for as treasury units in consolidation. For additional information regarding the preferred units, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

The issuances of preferred units as PIK distributions during the three and nine months ended September 30, 2025 were undertaken in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof.

Other than as described above, there were no sales of unregistered equity securities during the third quarter of 2025 .

Issuer Purchases of Equity Securities

The following table summarizes our equity repurchase activity during the third quarter of 2025 :


Period	Total Number of Units Purchased	Average Price Paid per Unit		Total Number Of Units Purchased as Part of 2019 Buyback Program	Remaining Dollar Amount of Units That May Be Purchased Under the 2019 Buyback Program ($ thousands)
2019 Buyback Program: (1)
July 2025	318,079	$	31.44	318,079	$	682,293
August 2025	1,657,949	$	31.21	1,657,949	$	630,544
September 2025	566,976	$	31.75	566,976	$	612,544
Vesting of phantom unit awards:
July 2025 (2)	217	$	31.16	n/a	n/a
August 2025 (3)	41,736	$	30.84	n/a	n/a
September 2025 (4)	750	$	31.68	n/a	n/a

(1) In January 2019, we announced the 2019 Buyback Program, which authorized the repurchase of up to $2 billion of the Partnership’s common units. In October 2025, we announced that the 2019 Buyback Program was increased to authorize the repurchase of up to $5 billion of the Partnership’s common units. After giving effect to this increase, the remaining available capacity under the 2019 Buyback Program is $3.6 billion. Units repurchased under this program are cancelled immediately upon acquisition.

(2) Of the 9,250 phantom unit awards that vested in July 2025 and converted to common units, 217 units were sold back to us by employees to cover related withholding tax requirements. These repurchases are not part of any announced program. We cancelled these units immediately upon acquisition.

(3) Of the 144,020 phantom unit awards that vested in August 2025 and converted to common units, 41,736 units were sold back to us by employees to cover related withholding tax requirements. These repurchases are not part of any announced program. We cancelled these units immediately upon acquisition.

(4) Of the 2,530 phantom unit awards that vested in September 2025 and converted to common units, 750 units were sold back to us by employees to cover related withholding tax requirements. These repurchases are not part of any announced program. We cancelled these units immediately upon acquisition.

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ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5. OTHER INFORMATION.

During the three months ended September 30, 2025 , no director or officer (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) of Enterprise GP adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

ITEM 6. EXHIBITS.


Exhibit Number			Exhibit
2.1			Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2003).
2.2			Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2004).
2.3			Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed December 15, 2003).
2.4			Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 21, 2004).
2.5			Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Form 8-K filed December 15, 2003).
2.6			Agreement and Plan of Merger, dated as of June 28, 2009, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub B LLC, TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed June 29, 2009).
2.7			Agreement and Plan of Merger, dated as of June 28, 2009, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub A LLC, TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed June 29, 2009).
2.8			Agreement and Plan of Merger, dated as of September 3, 2010, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise ETE LLC, Enterprise GP Holdings L.P. and EPE Holdings, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2010).
2.9			Agreement and Plan of Merger, dated as of September 3, 2010, by and among Enterprise Products GP, LLC, Enterprise GP Holdings L.P. and EPE Holdings, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed September 7, 2010).
2.10			Contribution Agreement, dated as of September 30, 2010, by and between Enterprise Products Company and Enterprise Products Partners L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K filed October 1, 2010).

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2.11			Agreement and Plan of Merger, dated as of April 28, 2011, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPD MergerCo LLC, Duncan Energy Partners L.P. and DEP Holdings, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 29, 2011).
2.12			Contribution and Purchase Agreement, dated as of October 1, 2014, by and among Enterprise Products Partners L.P., Oiltanking Holding Americas, Inc. and OTB Holdco, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed October 1, 2014).
2.13			Agreement and Plan of Merger, dated as of November 11, 2014, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPOT MergerCo LLC, Oiltanking Partners, L.P. and OTLP GP, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed November 12, 2014).
2.14			Amendment No. 1 dated as of June 6, 2018 to Contribution and Purchase Agreement, by and among Enterprise Products Partners L.P., Oiltanking Holding Americas, Inc., Enterprise Products Holdings LLC and Marquard & Bahls, AG (incorporated by reference to Exhibit 2.2 to Form 8-K filed June 12, 2018).
3.1			Certificate of Limited Partnership of Enterprise Products Partners L.P. (incorporated by reference to Exhibit 3.6 to Form 10-Q filed November 9, 2007).
3.2			Certificate of Amendment to Certificate of Limited Partnership of Enterprise Products Partners L.P., filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.6 to Form 8-K filed November 23, 2010).
3.3			Seventh Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated as of September 30, 2020 (incorporated by reference to Exhibit 3.1 to Form 8-K filed October 1, 2020).
3.4			Certificate of Formation of Enterprise Products Holdings LLC (formerly named EPE Holdings, LLC) (incorporated by reference to Exhibit 3.3 to Form S-1/A Registration Statement, Reg. No. 333-124320, filed by Enterprise GP Holdings L.P. on July 22, 2005).
3.5			Certificate of Amendment to Certificate of Formation of Enterprise Products Holdings LLC (formerly named EPE Holdings, LLC), filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.5 to Form 8-K filed November 23, 2010).
3.6			Sixth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC dated effective as of August 9, 2022 (incorporated by reference to Exhibit 3.9 to Form 10-Q filed August 9, 2022).
3.7			Company Agreement of Enterprise Products Operating LLC dated June 30, 2007 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed August 8, 2007).
3.8			Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
3.9			Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
4.1			Form of Common Unit certificate (incorporated by reference to Exhibit A to Exhibit 3.1 to Form 8-K filed October 1, 2020).
4.2			Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated by reference to Exhibit 4.2 to Form 10-K filed February 28, 2020).
4.3			Indenture, dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 14, 2000).
4.4			Second Supplemental Indenture, dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.5			Third Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and U.S. Bank National Association, as successor Trustee (incorporated by reference to Exhibit 4.55 to Form 10-Q filed August 8, 2007).
4.6			Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 6, 2004).

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4.7			Fourth Supplemental Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Form 8-K filed October 6, 2004).
4.8			Sixth Supplemental Indenture, dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed March 3, 2005).
4.9			Tenth Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8, 2007).
4.10			Sixteenth Supplemental Indenture, dated as of October 5, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.11			Seventeenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 28, 2009).
4.12			Eighteenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed October 28, 2009).
4.13			Nineteenth Supplemental Indenture, dated as of May 20, 2010, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed May 20, 2010).
4.14			Twentieth Supplemental Indenture, dated as of January 13, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed January 13, 2011).
4.15			Twenty-First Supplemental Indenture, dated as of August 24, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 24, 2011).
4.16			Twenty-Second Supplemental Indenture, dated as of February 15, 2012, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.25 to Form 10-Q filed May 10, 2012).
4.17			Twenty-Third Supplemental Indenture, dated as of August 13, 2012, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 13, 2012).
4.18			Twenty-Fourth Supplemental Indenture, dated as of March 18, 2013, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.19			Twenty-Fifth Supplemental Indenture, dated as of February 12, 2014, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed February 12, 2014).
4.20			Twenty-Sixth Supplemental Indenture, dated as of October 14, 2014, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.21			Twenty-Seventh Supplemental Indenture, dated as of May 7, 2015, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee(incorporated by reference to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.22			Twenty-Eighth Supplemental Indenture, dated as of April 13, 2016, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed April 13, 2016).
4.23			Twenty-Ninth Supplemental Indenture, dated as of August 16, 2017, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 16, 2017).

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4.24			Thirtieth Supplemental Indenture, dated as of February 15, 2018, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed February 15, 2018).
4.25			Thirty-First Supplemental Indenture, dated as of February 15, 2018, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed February 15, 2018).
4.26			Thirty-Second Supplemental Indenture, dated as of October 11, 2018, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 11, 2018).
4.27			Thirty-Third Supplemental Indenture, dated as of July 8, 2019, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed July 8, 2019).
4.28			Thirty-Fourth Supplemental Indenture, dated as of January 15, 2020, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.29			Thirty-Fifth Supplemental Indenture, dated as of August 7, 2020, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed August 7, 2020).
4.30			Thirty-Sixth Supplemental Indenture, dated as of September 15, 2021, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Wells Fargo Bank, National Association, as Original Trustee, and U.S. Bank National Association, as Series Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed September 15, 2021).
4.31			Thirty-Seventh Supplemental Indenture, dated as of January 10, 2023, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and U.S. Bank Trust Company, National Association, as Series Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed January 10, 2023).
4.32			Thirty-Eighth Supplemental Indenture, dated as of January 11, 2024, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and U.S. Bank Trust Company, National Association, as Series Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed January 11, 2024).
4.33			Thirty-Ninth Supplemental Indenture, dated as of August 8, 2024, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and U.S. Bank Trust Company, National Association, as Series Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed August 8, 2024).
4.34			Fortieth Supplemental Indenture, dated as of June 20, 2025, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and U.S. Bank Trust Company, National Association, as Series Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed June 20, 2025).
4.35			Form of Global Note representing $500 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.36			Form of Global Note representing $350 million principal amount of 6.65% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
4.37			Form of Global Note representing $250 million principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed November 4, 2005).
4.38			Form of Global Note representing $600 million principal amount of 6.125% Senior Notes due 2039 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.39			Form of Global Note representing $399.6 million principal amount of 7.55% Senior Notes due 2038 with attached Guarantee (incorporated by reference to Exhibit E to Exhibit 4.1 to Form 8-K filed October 28, 2009).
4.40			Form of Global Note representing $285.8 million principal amount of Junior Subordinated Notes due 2067 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.2 to Form 8-K filed October 28, 2009).

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4.41			Form of Global Note representing $600 million principal amount of 6.45% Senior Notes due 2040 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed May 20, 2010).
4.42			Form of Global Note representing $750 million principal amount of 5.95% Senior Notes due 2041 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed January 13, 2011).
4.43			Form of Global Note representing $600 million principal amount of 5.70% Senior Notes due 2042 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed August 24, 2011).
4.44			Form of Global Note representing $750 million principal amount of 4.85% Senior Notes due 2042 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.25 to Form 10-Q filed May 10, 2012).
4.45			Form of Global Note representing $1.1 billion principal amount of 4.45% Senior Notes due 2043 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed August 13, 2012).
4.46			Form of Global Note representing $1.0 billion principal amount of 4.85% Senior Notes due 2044 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.47			Form of Global Note representing $1.15 billion principal amount of 5.10% Senior Notes due 2045 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed February 12, 2014).
4.48			Form of Global Note representing $1.15 billion principal amount of 3.75% Senior Notes due 2025 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.49			Form of Global Note representing $400 million principal amount of 4.95% Senior Notes due 2054 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.50			Form of Global Note representing $400 million principal amount of 4.85% Senior Notes due 2044 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.51			Form of Global Note representing $875 million principal amount of 3.70% Senior Notes due 2026 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.52			Form of Global Note representing $875 million principal amount of 4.90% Senior Notes due 2046 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.53			Form of Global Note representing $575 million principal amount of 3.95% Senior Notes due 2027 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed April 13, 2016).
4.54			Form of Global Note representing $100 million principal amount of 4.90% Senior Notes due 2046 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.55			Form of Global Note representing $700 million principal amount of Junior Subordinated Notes D due 2077 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed August 16, 2017).
4.56			Form of Global Note representing $1.0 billion principal amount of Junior Subordinated Notes E due 2077 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed August 16, 2017).
4.57			Form of Global Note representing $1.25 billion principal amount of 4.25% Senior Notes due 2048 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed February 15, 2018).
4.58			Form of Global Note representing $700 million principal amount of Junior Subordinated Notes F due 2078 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed February 15, 2018).
4.59			Form of Global Note representing $1.0 billion principal amount of 4.15% Senior Notes due 2028 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed October 11, 2018).

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4.60			Form of Global Note representing $1.25 billion principal amount of 4.80% Senior Notes due 2049 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed October 11, 2018).
4.61			Form of Global Note representing $1.25 billion principal amount of 3.125% Senior Notes due 2029 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed July 8, 2019).
4.62			Form of Global Note representing $1.25 billion principal amount of 4.200% Senior Notes due 2050 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed July 8, 2019).
4.63			Form of Global Note representing $1.0 billion principal amount of 2.800% Senior Notes due 2030 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.64			Form of Global Note representing $1.0 billion principal amount of 3.700% Senior Notes due 2051 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.65			Form of Global Note representing $1.0 billion principal amount of 3.950% Senior Notes due 2060 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.66			Form of Global Note representing $250 million principal amount of 2.800% Senior Notes due 2030 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.67			Form of Global Note representing $1.0 billion principal amount of 3.200% Senior Notes due 2052 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed August 7, 2020).
4.68			Form of Global Note representing $1.0 billion principal amount of 3.300% Senior Notes due 2053 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed September 15, 2021).
4.69			Form of Global Note representing $750 million principal amount of 5.050% Senior Notes due 2026 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed January 10, 2023).
4.70			Form of Global Note representing $1.0 billion principal amount of 5.350% Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed January 10, 2023).
4.71			Form of Global Note representing $1.0 billion principal amount of 4.600% Senior Notes due 2027 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed January 11, 2024).
4.72			Form of Global Note representing $1.0 billion principal amount of 4.850% Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed January 11, 2024).
4.73			Form of Global Note representing $1.1 billion principal amount of 4.95% Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed August 8, 2024).
4.74			Form of Global Note representing $1.4 billion principal amount of 5.55% Senior Notes due 2055 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed August 8, 2024).
4.75			Form of Global Note representing $500 million principal amount of 4.30% Senior Notes due 2028 with attached Guarantee ( incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed June 20, 2025).
4.76			Form of Global Note representing $ 750 million principal amount of 4. 60 % Senior Notes due 2031 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed June 20, 2025).
4.77			Form of Global Note representing $ 750 million principal amount of 5.20 % Senior Notes due 2036 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.4 to Form 8-K filed June 20, 2025).
4.78			Replacement Capital Covenant, dated October 27, 2009, executed by Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 4.9 to Form 8-K filed October 28, 2009).

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4.79			Amendment to Replacement Capital Covenants, dated May 6, 2015, executed by Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 4.59 to Form 10-Q filed May 8, 2015).
4.80			Specimen Unit Certificate for the Series A Cumulative Convertible Preferred Units, (incorporated by reference to Exhibit B to Exhibit 3.1 to Form 8-K filed October 1, 2020).
4.81			Registration Rights Agreement, dated as of September 30, 2020, by and among Enterprise Products Partners L.P. and the Purchasers party thereto (incorporated by reference to Exhibit 4.2 to Form 8-K filed October 1, 2020).
22.1#			List of Issuers of Debt Securities Guaranteed by Enterprise Products Partners L.P. and Associated Securities at September 30, 2025.
31.1#			Sarbanes-Oxley Section 302 certification of A. James Teague for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q.
31.2#			Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q.
31.3#			Sarbanes-Oxley Section 302 certification of R. Daniel Boss for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q.
32.1#			Sarbanes-Oxley Section 906 certification of A. James Teague for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q.
32.2#			Sarbanes-Oxley Section 906 certification of W. Randall Fowler for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q.
32.3#			Sarbanes-Oxley Section 906 certification of R. Daniel Boss for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q.
101#			Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) in this Form 10-Q include the: (i) Unaudited Condensed Consolidated Balance Sheets, (ii) Unaudited Condensed Statements of Consolidated Operations, (iii) Unaudited Condensed Statements of Consolidated Comprehensive Income, (iv) Unaudited Condensed Statements of Consolidated Cash Flows, (v) Unaudited Condensed Statements of Consolidated Equity and (vi) Notes to the Unaudited Condensed Consolidated Financial Statements.
104#			Cover Page Interactive Data File (embedded within the iXBRL document).
#			Filed with this report.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on November 6, 2025 .


			ENTERPRISE PRODUCTS PARTNERS L.P. (A Delaware Limited Partnership)

			By:			Enterprise Products Holdings LLC, as General Partner

			By:			/s/ R. Daniel Boss
			Name:			R. Daniel Boss
			Title:			Executive Vice President and Chief Financial Officer of the General Partner

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Part I. Financial Information Item 1. Financial Statements Note 1. Partnership Organization and Operations Note 2. Summary Of Significant Accounting Policies Note 3. Inventories Note 4. Property, Plant and Equipment Note 5. Investments in Unconsolidated Affiliates Note 6. Intangible Assets and Goodwill Note 7. Debt Obligations Note 8. Capital Accounts Note 9. Revenues Note 10. Business Segments and Related Information Note 11. Earnings Per Unit Note 12. Acquisitions Note 13. Equity-based Awards Note 14. Hedging Activities and Fair Value Measurements Note 15. Related Party Transactions Note 16. Income Taxes Note 17. Commitments and Contingent Liabilities Note 18. Supplemental Cash Flow Information Item 2. Management S Discussion and Analysis Of Financial Condition and Item 3. Quantitative and Qualitative Disclosures Item 4. Controls and Procedures Part II. Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 3. Defaults Upon Senior Securities Item 4. Mine Safety Disclosures Item 5. Other Information Item 6. Exhibits

Exhibits

EPD 10-Q Quarter ended Sept. 30, 2025

Exhibits