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 March 31, 2025

OR
☐  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 2,168,902,635 common units of Enterprise Products Partners L.P. outstanding at the close of business on April 30, 2025. 

Table of Contents

ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS

 
 
Page No.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  

1

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PART I.  FINANCIAL INFORMATION.

ITEM 1.  FINANCIAL STATEMENTS.

ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

   
March 31,
2025
    
December 31,
2024
  
ASSETS
            
Current assets:
            
Cash and cash equivalents
  
$
220
    
$
583
  
Restricted cash
    
234
      
255
  
Accounts receivable – trade, net of allowance for credit losses
of $38 at March 31, 2025 and $38 at December 31, 2024
    
7,853
      
9,236
  
Accounts receivable – related parties
    
2
      
4
  
Inventories (see Note 3)
    
3,233
      
3,955
  
Derivative assets (see Note 14)
    
615
      
534
  
Prepaid and other current assets
    
606
      
566
  
Total current assets
    
12,763
      
15,133
  
Property, plant and equipment, net (see Note 4)
    
49,715
      
49,062
  
Investments in unconsolidated affiliates (see Note 5)
    
2,251
      
2,259
  
Intangible assets, net (see Note 6)
    
3,953
      
4,005
  
Goodwill (see Note 6)
    
5,712
      
5,712
  
Other assets
    
1,012
      
997
  
Total assets
  
$
75,406
    
$
77,168
  
 
                
LIABILITIES AND EQUITY
                
Current liabilities:
                
Current maturities of debt (see Note 7)
  
$
2,453
    
$
1,150
  
Accounts payable – trade
    
1,334
      
1,227
  
Accounts payable – related parties
    
91
      
198
  
Accrued product payables
    
9,421
      
10,777
  
Accrued interest
    
261
      
536
  
Derivative liabilities (see Note 14)
    
538
      
471
  
Other current liabilities
    
774
      
818
  
Total current liabilities
    
14,872
      
15,177
  
Long-term debt (see Note 7)
    
29,127
      
30,746
  
Deferred tax liabilities (see Note 16)
    
667
      
656
  
Other long-term liabilities
    
915
      
950
  
Commitments and contingent liabilities (see Note 17)
    
     
 
Redeemable preferred limited partner interests: (see Note 8)
                
    Series A cumulative convertible preferred units (“preferred units”)
        (50,782 units outstanding at March 31, 2025 and 50,687 units outstanding at
        December 31, 2024)
    
50
      
50
  
Equity: (see Note 8)
                
Partners’ equity:
                
Common limited partner interests (2,168,902,635 units issued and outstanding at
     March 31, 2025, 2,165,699,962 units issued and outstanding at December 31, 2024)
    
29,927
      
29,793
  
Treasury units, at cost
    
(1,297
)
    
(1,297
)
Accumulated other comprehensive income
    
285
      
236
  
Total partners’ equity
    
28,915
      
28,732
  
Noncontrolling interests in consolidated subsidiaries
    
860
      
857
  
Total equity
    
29,775
      
29,589
  
Total liabilities, preferred units, and equity
  
$
75,406
    
$
77,168
  

See Notes to Unaudited Condensed Consolidated Financial Statements.

2

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ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
 (Dollars in millions, except per unit amounts)

 
  
For the Three Months
Ended March 31,
  
 
  
2025
    
2024
  
Revenues:
            
Third parties
  
$
15,404
    
$
14,745
  
Related parties
    
13
      
15
  
Total revenues (see Note 9)
    
15,417
      
14,760
  
Costs and expenses:
                
Operating costs and expenses:
                
Third party and other costs
    
13,298
      
12,591
  
Related parties
    
392
      
383
  
Total operating costs and expenses
    
13,690
      
12,974
  
General and administrative costs:
                
Third party and other costs
    
27
      
22
  
Related parties
    
33
      
44
  
Total general and administrative costs
    
60
      
66
  
Total costs and expenses (see Note 10)
    
13,750
      
13,040
  
Equity in income of unconsolidated affiliates
    
94
      
102
  
Operating income
    
1,761
      
1,822
  
Other income (expense):
                
Interest expense
    
(340
)
    
(331
)
Interest income
    
8
      
13
  
Other, net
    
1
      
–
  
Total other expense, net
    
(331
)
    
(318
)
Income before income taxes
    
1,430
      
1,504
  
Provision for income taxes (see Note 16)
    
(24
)
    
(21
)
Net income
    
1,406
      
1,483
  
Net income attributable to noncontrolling interests
    
(12
)
    
(26
)
Net income attributable to preferred units
    
(1
)
    
(1
)
Net income attributable to common unitholders
  
$
1,393
    
$
1,456
  
 
                
Earnings per unit: (see Note 11)
                
Basic and diluted earnings per common unit
  
$
0.64
    
$
0.66
  

















See Notes to Unaudited Condensed Consolidated Financial Statements.
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ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED
COMPREHENSIVE INCOME
(Dollars in millions)

 
  
For the Three Months
Ended March 31,
  
 
  
2025
    
2024
  
 
            
Net income
  
$
1,406
    
$
1,483
  
Other comprehensive income (loss):
                
Cash flow hedges: (see Note 14)
                
Commodity hedging derivative instruments:
                
Changes in fair value of cash flow hedges
    
22
      
(162
)
Reclassification of losses (gains) to net income
    
26
      
(2
)
Interest rate hedging derivative instruments:
                
Changes in fair value of cash flow hedges
    
2
      
2
  
Reclassification of gains to net income
    
(1
)
    
(2
)
Total cash flow hedges
    
49
      
(164
)
Total other comprehensive income (loss)
    
49
      
(164
)
Comprehensive income
    
1,455
      
1,319
  
Comprehensive income attributable to noncontrolling interests
    
(12
)
    
(26
)
Comprehensive income attributable to preferred units
    
(1
)
    
(1
)
Comprehensive income attributable to common unitholders
  
$
1,442
    
$
1,292
  





























See Notes to Unaudited Condensed Consolidated Financial Statements.

4

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ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)

 
  
For the Three Months
Ended March 31,
  
 
  
2025
    
2024
  
Operating activities:
            
Net income
  
$
1,406
    
$
1,483
  
Reconciliation of net income to net cash flow provided by operating activities:
                
Depreciation and accretion
    
511
      
488
  
Amortization of intangible assets
    
52
      
50
  
Amortization of major maintenance costs for reaction-based plants
    
16
      
13
  
Other amortization expense
    
57
      
65
  
Impairment of assets other than goodwill
    
10
      
20
  
Equity in income of unconsolidated affiliates
    
(94
)
    
(102
)
Distributions received from unconsolidated affiliates attributable to earnings
    
88
      
97
  
Net gains attributable to asset sales and related matters
    
(2
)
    
–
  
Deferred income tax expense
    
11
      
9
  
Change in fair market value of derivative instruments
    
42
      
4
  
Non-cash expense related to long-term operating leases (see Note 17)
    
28
      
20
  
Net effect of changes in operating accounts (see Note 18)
    
203
      
(36
)
Other operating activities
    
(14
)
    
–
  
Net cash flow provided by operating activities
    
2,314
      
2,111
  
Investing activities:
                
Capital expenditures
    
(1,062
)
    
(1,047
)
Distributions received from unconsolidated affiliates attributable to the return of capital
    
15
      
15
  
Proceeds from asset sales and other matters
    
4
      
2
  
Other investing activities
    
(4
)
    
(8
)
Net cash flow used in investing activities
    
(1,047
)
    
(1,038
)
Financing activities:
                
Borrowings under debt agreements
    
19,103
      
14,328
  
Repayments of debt
    
(19,423
)
    
(13,632
)
Debt issuance costs
    
(12
)
    
(18
)
Monetization of interest rate derivative instruments
    
–
      
(29
)
Cash distributions paid to common unitholders (see Note 8)
    
(1,159
)
    
(1,117
)
Cash payments made in connection with distribution equivalent rights
    
(11
)
    
(10
)
Cash distributions paid to noncontrolling interests
    
(13
)
    
(38
)
Cash contributions from noncontrolling interests
    
4
      
8
  
Repurchase of common units under 2019 Buyback Program
    
(60
)
    
(40
)
Acquisition of noncontrolling interests
    
–
      
(400
)
Other financing activities
    
(80
)
    
(61
)
Net cash flow used in financing activities
    
(1,651
)
    
(1,009
)
Net change in cash and cash equivalents, including restricted cash
    
(384
)
    
64
  
Cash and cash equivalents, including restricted cash, at beginning of period
    
838
      
320
  
Cash and cash equivalents, including restricted cash, at end of period
  
$
454
    
$
384
  









See Notes to Unaudited Condensed Consolidated Financial Statements.

5

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ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY
(Dollars in millions)

 
  
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
    
1,393
      
–
      
–
      
12
      
1,405
  
   Cash distributions paid to common unitholders
    
(1,159
)
    
–
      
–
      
–
      
(1,159
)
   Cash payments made in connection with distribution equivalent rights
    
(11
)
    
–
      
–
      
–
      
(11
)
   Cash distributions paid to noncontrolling interests
    
–
      
–
      
–
      
(13
)
    
(13
)
   Cash contributions from noncontrolling interests
    
–
      
–
      
–
      
4
      
4
  
   Repurchase and cancellation of common units under 2019 Buyback Program
    
(60
)
    
–
      
–
      
–
      
(60
)
   Amortization of fair value of equity-based awards
    
49
      
–
      
–
      
–
      
49
  
   Cash flow hedges
    
–
      
–
      
49
      
–
      
49
  
   Other, net
    
(78
)
    
–
      
–
      
–
      
(78
)
Balance, March 31, 2025
  
$
29,927
    
$
(1,297
)
  
$
285
    
$
860
    
$
29,775
  



 
  
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
    
1,456
      
–
      
–
      
26
      
1,482
  
   Cash distributions paid to common unitholders
    
(1,117
)
    
–
      
–
      
–
      
(1,117
)
   Cash payments made in connection with distribution equivalent rights
    
(10
)
    
–
      
–
      
–
      
(10
)
   Cash distributions paid to noncontrolling interests
    
–
      
–
      
–
      
(38
)
    
(38
)
   Cash contributions from noncontrolling interests
    
–
      
–
      
–
      
8
      
8
  
   Repurchase and cancellation of common units under 2019 Buyback Program
    
(40
)
    
–
      
–
      
–
      
(40
)
   Amortization of fair value of equity-based awards
    
56
      
–
      
–
      
–
      
56
  
   Acquisition of noncontrolling interests
    
(118
)
    
–
      
–
      
(282
)
    
(400
)
   Cash flow hedges
    
–
      
–
      
(164
)
    
–
      
(164
)
   Other, net
    
(59
)
    
–
      
–
      
–
      
(59
)
Balance, March 31, 2024
  
$
28,831
    
$
(1,297
)
  
$
143
    
$
800
    
$
28,477
  


















See Notes to Unaudited Condensed Consolidated Financial Statements.  For information regarding Unit History,
Accumulated Other Comprehensive Income (Loss), see Note 8.

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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

KEY REFERENCES USED IN THESE
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unless the context requires otherwise, references to “we,” “us” or “our” within these Notes to Unaudited Condensed Consolidated Financial Statements are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.  

References to the “Partnership” or “Enterprise” mean Enterprise Products Partners L.P. on a standalone basis.

References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of the Partnership, and its consolidated subsidiaries, through which the Partnership conducts its business.  We are managed by our general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company.

The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors of Enterprise GP (the “Board”);  (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board; and (iii) W. Randall Fowler, who is also a director and a Co-Chief Executive Officer of Enterprise GP.  Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC.

References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates.  The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO; and (iii) Mr. Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO.  Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO.

We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees.  EPCO, together with its privately held affiliates, owned approximately 32.4% of the Partnership’s common units outstanding at March 31, 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 three months ended March 31, 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.




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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

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.

   
March 31,
2025
    
December 31,
2024
  
Cash and cash equivalents
  
$
220
    
$
583
  
Restricted cash
    
234
      
255
  
Total cash, cash equivalents and restricted cash shown in the
  Unaudited Condensed Statements of Consolidated Cash Flows
  
$
454
    
$
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, 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:

   
March 31,
2025
    
December 31,
2024
  
NGLs
  
$
2,405
    
$
2,768
  
Petrochemicals and refined products
    
578
      
652
  
Crude oil
    
240
      
523
  
Natural gas
    
10
      
12
  
Total
  
$
3,233
    
$
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 March 31,
  
 
2025
  
2024
  
Cost of sales (1)
  
$
12,005
    
$
11,405
  
Lower of cost or net realizable value adjustments recognized in cost of sales
    
2
      
1
  

(1)
Cost of sales is a component of “Operating costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations.  Fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.


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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 4.  Property, Plant and Equipment

The historical costs of our property, plant and equipment and related balances were as follows at the dates indicated:

 
Estimated
Useful Life
in Years
 
March 31,
2025
 
December 31,
2024
Plants, pipelines and facilities (1)(5)
3-45
  
$
61,011
  
$
60,716
Underground and other storage facilities (2)(6)
5-40
    
4,712
    
4,704
Transportation equipment (3)
3-10
    
273
    
272
Marine vessels (4)
15-30
    
954
    
949
Land
      
424
    
424
Construction in progress
      
4,981
    
4,138
   Subtotal
      
72,355
    
71,203
Less accumulated depreciation
      
22,814
    
22,330
   Subtotal property, plant and equipment, net
      
49,541
    
48,873
Capitalized major maintenance costs for reaction-based
   plants, net of accumulated amortization (7)
      
174
    
189
   Property, plant and equipment, net
    
$
49,715
  
$
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 3.2 years.

Property, plant and equipment at March 31, 2025 and December 31, 2024 includes $133 million and $134 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.

The following table presents information regarding our asset retirement obligations, or AROs, since December 31, 2024:

ARO liability balance, December 31, 2024
  
$
265
  
Liabilities incurred (1)
    
–
  
Revisions in estimated cash flows (2)
    
–
  
Liabilities settled (3)
    
(1
)
Accretion expense (4)
    
5
  
ARO liability balance, March 31, 2025
  
$
269
  

(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 $269 million total ARO liability recorded at March 31, 2025, $6 million was reflected as a current liability and $263 million as a long-term liability.

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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes our depreciation expense and capitalized interest amounts for the periods indicated:

 
For the Three Months
Ended March 31,
  
 
2025
  
2024
  
Depreciation expense (1)
  
$
506
    
$
485
  
Capitalized interest (2)
    
45
      
25
  

(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.

   
March 31,
2025
    
December 31,
2024
  
NGL Pipelines & Services
  
$
586
    
$
598
  
Crude Oil Pipelines & Services
    
1,630
      
1,628
  
Natural Gas Pipelines & Services
    
32
      
30
  
Petrochemical & Refined Products Services
    
3
      
3
  
Total
  
$
2,251
    
$
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 March 31,
  
 
  
2025
    
2024
  
NGL Pipelines & Services
  
$
20
    
$
31
  
Crude Oil Pipelines & Services
    
72
      
69
  
Natural Gas Pipelines & Services
    
2
      
2
  
Petrochemical & Refined Products Services
    
–
      
–
  
Total
  
$
94
    
$
102
  


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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 6.  Intangible Assets and Goodwill

Identifiable Intangible Assets

The following table summarizes our intangible assets by business segment at the dates indicated:

   
March 31, 2025
    
December 31, 2024
  
 
  
Gross
Value
    
Accumulated
Amortization
    
Carrying
Value
    
Gross
Value
    
Accumulated
Amortization
    
Carrying
Value
  
NGL Pipelines & Services:
                                    
Customer relationship intangibles
  
$
449
    
$
(279
)
  
$
170
    
$
449
    
$
(276
)
  
$
173
  
Contract-based intangibles
    
754
      
(149
)
    
605
      
754
      
(141
)
    
613
  
Segment total
    
1,203
      
(428
)
    
775
      
1,203
      
(417
)
    
786
  
Crude Oil Pipelines & Services:
                                                
Customer relationship intangibles
    
2,195
      
(648
)
    
1,547
      
2,195
      
(627
)
    
1,568
  
Contract-based intangibles
    
283
      
(278
)
    
5
      
283
      
(278
)
    
5
  
Segment total
    
2,478
      
(926
)
    
1,552
      
2,478
      
(905
)
    
1,573
  
Natural Gas Pipelines & Services:
                                                
Customer relationship intangibles
    
1,351
      
(673
)
    
678
      
1,351
      
(663
)
    
688
  
Contract-based intangibles
    
1,081
      
(235
)
    
846
      
1,081
      
(227
)
    
854
  
Segment total
    
2,432
      
(908
)
    
1,524
      
2,432
      
(890
)
    
1,542
  
Petrochemical & Refined Products Services:
                                                
Customer relationship intangibles
    
181
      
(94
)
    
87
      
181
      
(92
)
    
89
  
Contract-based intangibles
    
45
      
(30
)
    
15
      
45
      
(30
)
    
15
  
Segment total
    
226
      
(124
)
    
102
      
226
      
(122
)
    
104
  
Total intangible assets
  
$
6,339
    
$
(2,386
)
  
$
3,953
    
$
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 March 31,
  
 
  
2025
    
2024
  
NGL Pipelines & Services
  
$
11
    
$
10
  
Crude Oil Pipelines & Services
    
21
      
25
  
Natural Gas Pipelines & Services
    
18
      
13
  
Petrochemical & Refined Products Services
    
2
      
2
  
Total
  
$
52
    
$
50
  

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
  
$
165
    
$
215
    
$
209
    
$
198
    
$
199
  

Goodwill

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction.  There has been no change in our goodwill amounts since those reported in our 2024 Form 10-K.


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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 7.  Debt Obligations

The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated:

   
March 31,
2025
    
December 31,
2024
  
EPO senior debt obligations:
            
Commercial Paper Notes, variable-rates
  
$
830
    
$
–
  
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 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 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 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
    
29,605
      
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
    
31,887
      
32,207
  
Other, non-principal amounts
    
(307
)
    
(311
)
Less current maturities of debt
    
(2,453
)
    
(1,150
)
Total long-term debt
  
$
29,127
    
$
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 three months ended March 31, 2025:

Range of Interest
Rates Paid
Weighted-Average
Interest Rate Paid
Commercial Paper Notes
4.50% to 4.65%
4.54%
EPO Junior Subordinated Notes C
7.36% to 7.51%
7.45%
EPO Junior Subordinated Notes D
7.57% to 7.73%
7.65%

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 March 31, 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
  
$
830
    
$
830
    
$
–
    
$
–
    
$
–
    
$
–
    
$
–
  
Senior Notes
    
28,775
      
–
      
1,625
      
1,575
      
1,000
      
1,250
      
23,325
  
Junior Subordinated Notes
    
2,282
      
–
      
–
      
–
      
–
      
–
      
2,282
  
Total
  
$
31,887
    
$
830
    
$
1,625
    
$
1,575
    
$
1,000
    
$
1,250
    
$
25,607
  

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 March 31, 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.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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.

Letters of Credit

At March 31, 2025, EPO had $28 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 March 31, 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
  

Registration Statements
We have a universal shelf registration statement on file with the SEC which allows the Partnership and EPO (each on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively.

In addition, the Partnership has a registration statement on file with the SEC covering the issuance of up to $2.5 billion of its common units in amounts, at prices and on terms based on market conditions and other factors at the time of such offerings (referred to as the Partnership’s at-the-market (“ATM”) program).  The Partnership did not issue any common units under its ATM program during the three months ended March 31, 2025.  The Partnership’s capacity to issue additional common units under the ATM program remains at $2.5 billion as of March 31, 2025.

We may issue additional equity and debt securities to assist us in meeting our future liquidity requirements, including those related to capital investments.

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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 months ended March 31, 2025 and 2024, the Partnership repurchased 1,803,215 and 1,386,835 common units, respectively, under the 2019 Buyback Program through open market purchases.  The total cost of these repurchases, including commissions and fees, was $60 million and $40 million, respectively.  Common units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition.  At March 31, 2025, the remaining available capacity under the 2019 Buyback Program was $803 million.

Common Units Issued in Connection With the Vesting of Phantom Unit Awards
After taking into account tax withholding requirements, the Partnership issued 4,989,490 new common units to employees in connection with the vesting of phantom unit awards during the three months ended March 31, 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 three months ended March 31, 2025, agents of the Partnership purchased 1,063,842 common units on the open market and delivered them to participants in the DRIP and EUPP.  Apart from $1 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 May 14, 2025.

Preferred Units

The following table summarizes changes in the number of our Series A Cumulative Convertible Preferred Units (“preferred units”) outstanding since December 31, 2024.

Preferred units outstanding at December 31, 2024
    
50,687
  
Paid in-kind distribution to third party
    
95
  
Preferred units outstanding at March 31, 2025
    
50,782
  

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 three months ended March 31, 2025, the Partnership made quarterly cash distributions to its preferred unitholders of $1 million and paid-in-kind distributions of 95 new preferred units valued at less than $1 million.

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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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
              
 
  
Commodity
Derivative
Instruments
    
Interest Rate
Derivative
Instruments
    
Other
    
Total
  
Accumulated Other Comprehensive Income (Loss), December 31, 2024
  
$
91
    
$
143
    
$
2
    
$
236
  
Other comprehensive income (loss) for period, before reclassifications
    
22
      
2
      
–
      
24
  
Reclassification of losses (gains) to net income during period
    
26
      
(1
)
    
–
      
25
  
Total other comprehensive income (loss) for period
    
48
      
1
      
–
      
49
  
Accumulated Other Comprehensive Income (Loss), March 31, 2025
  
$
139
    
$
144
    
$
2
    
$
285
  

   
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
    
(162
)
    
2
      
–
      
(160
)
Reclassification of losses (gains) to net income during period
    
(2
)
    
(2
)
    
–
      
(4
)
Total other comprehensive income (loss) for period
    
(164
)
    
–
      
–
      
(164
)
Accumulated Other Comprehensive Income (Loss), March 31, 2024
  
$
(10
)
  
$
151
    
$
2
    
$
143
  

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 March 31,
  
Losses (gains) on cash flow hedges:
Location
  
2025
    
2024
  
Interest rate derivatives
Interest expense
  
$
(1
)
  
$
(2
)
Commodity derivatives
Revenue
    
14
      
(19
)
Commodity derivatives
Operating costs and expenses
    
12
      
17
  
Total
 
  
$
25
    
$
(4
)

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

Cash Distributions

On April 7, 2025, we announced that the Board declared a quarterly cash distribution of $0.535 per common unit, or $2.14 per common unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the first quarter of 2025.  The quarterly distribution is payable on May 14, 2025 to unitholders of record as of the close of business on April 30, 2025.  The total amount to be paid is $1.17 billion, which includes $11 million for distribution equivalent rights (“DERs”) on phantom unit awards.

The payment of quarterly cash distributions is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and Board approval.  Management will evaluate any future increases in cash distributions on a quarterly basis. 


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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 March 31,
  
 
  
2025
    
2024
  
NGL Pipelines & Services:
            
Sales of NGLs and related products
  
$
4,651
    
$
4,400
  
Segment midstream services:
                
Natural gas processing and fractionation
    
352
      
358
  
Transportation
    
312
      
279
  
Storage and terminals
    
85
      
103
  
Total segment midstream services
    
749
      
740
  
Total NGL Pipelines & Services
    
5,400
      
5,140
  
Crude Oil Pipelines & Services:
                
Sales of crude oil
    
4,825
      
5,122
  
Segment midstream services:
                
Transportation
    
189
      
193
  
Storage and terminals
    
107
      
100
  
Total segment midstream services
    
296
      
293
  
Total Crude Oil Pipelines & Services
    
5,121
      
5,415
  
Natural Gas Pipelines & Services:
                
Sales of natural gas
    
785
      
503
  
Segment midstream services:
                
Transportation
    
436
      
351
  
Total segment midstream services
    
436
      
351
  
Total Natural Gas Pipelines & Services
    
1,221
      
854
  
Petrochemical & Refined Products Services:
                
Sales of petrochemicals and refined products
    
3,326
      
2,965
  
Segment midstream services:
                
Fractionation and isomerization
    
103
      
126
  
Transportation, including marine logistics
    
175
      
178
  
Storage and terminals
    
71
      
82
  
Total segment midstream services
    
349
      
386
  
Total Petrochemical & Refined Products Services
    
3,675
      
3,351
  
Total consolidated revenues
  
$
15,417
    
$
14,760
  

Substantially all of our revenues are derived from contracts with customers as defined within Accounting Standards Codification (“ASC”) 606, Revenue from Contracts with Customers.
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unbilled Revenue and Deferred Revenue

The following table provides information regarding our contract assets and contract liabilities at March 31, 2025:

Contract Asset
Location
  
Balance
  
Unbilled revenue (current amount)
Prepaid and other current assets
  
$
9
  
Total
    
$
9
  

Contract Liability
Location
  
Balance
  
Deferred revenue (current amount)
Other current liabilities
  
$
198
  
Deferred revenue (noncurrent)
Other long-term liabilities
    
267
  
Total
    
$
465
  

The following table presents significant changes in our unbilled revenue and deferred revenue balances for the three months ended March 31, 2025:

   
Unbilled
Revenue
    
Deferred
Revenue
  
Balance at December 31, 2024
  
$
9
    
$
452
  
Amount included in opening balance transferred to other accounts during period (1)
    
(8
)
    
(111
)
Amount recorded during period (2)
    
22
      
243
  
Amounts recorded during period transferred to other accounts (1)
    
(14
)
    
(118
)
Other changes
    
–
      
(1
)
Balance at March 31, 2025
  
$
9
    
$
465
  

(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 March 31, 2025.

Period
  
Fixed
Consideration
  
Nine Months Ended December 31, 2025
  
$
3,083
  
One Year Ended December 31, 2026
    
3,950
  
One Year Ended December 31, 2027
    
3,613
  
One Year Ended December 31, 2028
    
3,155
  
One Year Ended December 31, 2029
    
2,328
  
Thereafter –
    
9,603
  
Total
  
$
25,732
  


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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 March 31,
  
 
  
2025
    
2024
  
Total segment gross operating margin
  
$
2,464
    
$
2,507
  
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)
    
(602
)
    
(582
)
Asset impairment charges in operating costs and expenses
    
(10
)
    
(20
)
Net gains attributable to asset sales and related matters in operating costs
   and expenses
    
2
      
–
  
General and administrative costs
    
(60
)
    
(66
)
     Non-refundable payments received from shippers attributable to make-up rights (2)
    
(37
)
    
(25
)
     Subsequent recognition of revenues attributable to make-up rights (3)
    
4
      
8
  
     Total other expense, net (4)
    
(331
)
    
(318
)
Income before income taxes
  
$
1,430
    
$
1,504
  

(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 nonrefundable 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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ENTERPRISE PRODUCTS PARTNERS L.P.
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 March 31, 2025
  
 
  
NGL
Pipelines
& Services
    
Crude Oil
Pipelines
& Services
    
Natural Gas
Pipelines
& Services
    
Petrochemical
& Refined
Products
Services
    
Segment
Total
  
Segment revenues:
                              
Revenues from third parties
  
$
5,398
    
$
5,115
    
$
1,216
    
$
3,675
    
$
15,404
  
Revenues from related parties
    
2
      
6
      
5
      
–
      
13
  
Intersegment and intrasegment revenues
    
17,017
      
10,622
      
232
      
7,195
      
35,066
  
Total segment revenues
    
22,417
      
15,743
      
1,453
      
10,870
      
50,483
  
Significant segment expenses:
                                        
Cost of sales
    
20,433
      
15,307
      
899
      
10,156
      
46,795
  
Variable operating costs and expenses (1)
    
199
      
35
      
22
      
106
      
362
  
Fixed operating costs and expenses (2)
    
423
      
101
      
177
      
294
      
995
  
Total significant segment expenses
    
21,055
      
15,443
      
1,098
      
10,556
      
48,152
  
Other segment income:
                                        
Equity in income of unconsolidated affiliates
    
20
      
72
      
2
      
–
      
94
  
Other segment items (3)
    
36
      
2
      
–
      
1
      
39
  
Total other segment income
    
56
      
74
      
2
      
1
      
133
  
Total segment gross operating margin
  
$
1,418
    
$
374
    
$
357
    
$
315
    
$
2,464
  
                                         
Other financial information:
                                        
Capital expenditures
  
$
635
    
$
23
    
$
303
    
$
101
    
$
1,062
  

(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 and subsequent recognition of revenues attributable to make-up rights.
• Crude Oil Pipelines & Services – Other segment expenses.
• Petrochemical & Refined Products Services – Other segment expenses.


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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
  
For the Three Months Ended March 31, 2024
  
 
  
NGL
Pipelines
& Services
    
Crude Oil
Pipelines
& Services
    
Natural Gas
Pipelines
& Services
    
Petrochemical
& Refined
Products
Services
    
Segment
Total
  
Segment revenues:
                              
Revenues from third parties
  
$
5,137
    
$
5,406
    
$
851
    
$
3,351
    
$
14,745
  
Revenues from related parties
    
3
      
9
      
3
      
–
      
15
  
Intersegment and intrasegment revenues
    
11,555
      
13,827
      
177
      
6,324
      
31,883
  
Total segment revenues
    
16,695
      
19,242
      
1,031
      
9,675
      
46,643
  
Significant segment expenses:
                                        
Cost of sales
    
14,810
      
18,749
      
558
      
8,875
      
42,992
  
Variable operating costs and expenses (1)
    
174
      
46
      
15
      
94
      
329
  
Fixed operating costs and expenses (2)
    
425
      
104
      
150
      
249
      
928
  
Total significant segment expenses
    
15,409
      
18,899
      
723
      
9,218
      
44,249
  
Other segment income (expense):
                                        
Equity in income of unconsolidated affiliates
    
31
      
69
      
2
      
–
      
102
  
Other segment items (3)
    
23
      
(1
)
    
2
      
(13
)
    
11
  
Total other segment income (expense), net
    
54
      
68
      
4
      
(13
)
    
113
  
Total segment gross operating margin
  
$
1,340
    
$
411
    
$
312
    
$
444
    
$
2,507
  
                                         
Other financial information:
                                        
Capital expenditures
  
$
577
    
$
37
    
$
204
    
$
229
    
$
1,047
  

(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 and subsequent recognition of revenues attributable to make-up rights.
• Crude Oil Pipelines & Services – Other segment expenses.
• Natural Gas Pipelines & Services – Other segment expenses.
• Petrochemical & Refined Products Services – Other segment expenses.

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 March 31,
  
 
  
2025
    
2024
  
Segment revenues:
            
NGL Pipelines & Services
  
$
22,417
    
$
16,695
  
Crude Oil Pipelines & Services
    
15,743
      
19,242
  
Natural Gas Pipelines & Services
    
1,453
      
1,031
  
Petrochemical & Refined Products Services
    
10,870
      
9,675
  
Total segment revenues
    
50,483
      
46,643
  
Elimination of intersegment and intrasegment revenues
    
(35,066
)
    
(31,883
)
Total consolidated revenues
  
$
15,417
    
$
14,760
  

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:

   
March 31,
2025
    
December 31,
2024
  
NGL Pipelines & Services
  
$
21,735
    
$
21,900
  
Crude Oil Pipelines & Services
    
11,327
      
11,390
  
Natural Gas Pipelines & Services
    
12,312
      
12,260
  
Petrochemical & Refined Products Services
    
11,276
      
11,350
  
Total segment assets
    
56,650
      
56,900
  
Construction in progress
    
4,981
      
4,138
  
Current assets
    
12,763
      
15,133
  
Other assets
    
1,012
      
997
  
Consolidated total assets
  
$
75,406
    
$
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 March 31,
  
 
  
2025
    
2024
  
Consolidated revenues:
            
NGL Pipelines & Services
  
$
5,400
    
$
5,140
  
Crude Oil Pipelines & Services
    
5,121
      
5,415
  
Natural Gas Pipelines & Services
    
1,221
      
854
  
Petrochemical & Refined Products Services
    
3,675
      
3,351
  
Total consolidated revenues
  
$
15,417
    
$
14,760
  
 
                
Consolidated costs and expenses
                
Operating costs and expenses:
                
Cost of sales
  
$
12,005
    
$
11,405
  
Other operating costs and expenses (1)
    
1,059
      
954
  
Depreciation, amortization and accretion
    
618
      
595
  
Asset impairment charges
    
10
      
20
  
Net gains attributable to asset sales and related matters
    
(2
)
    
–
  
General and administrative costs
    
60
      
66
  
Total consolidated costs and expenses
  
$
13,750
    
$
13,040
  

(1)
Represents the cost of operating our plants, pipelines and other fixed assets excluding depreciation, amortization and accretion charges; asset impairment charges; and net gains attributable to asset sales and related matters.

Fluctuations in our product sales revenues and cost of sales amounts are explained in large part by changes in energy commodity prices.  In general, higher energy commodity prices result in an increase in our revenues attributable to product sales; however, these higher commodity prices would also be expected to increase the associated cost of sales as purchase costs are higher.  The same type of relationship would be true in the case of lower energy commodity sales prices and purchase costs.

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ENTERPRISE PRODUCTS PARTNERS L.P.
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 March 31,
  
 
  
2025
    
2024
  
BASIC EARNINGS PER COMMON UNIT
            
Net income attributable to common unitholders
  
$
1,393
    
$
1,456
  
Earnings allocated to phantom unit awards (1)
    
(13
)
    
(14
)
Net income allocated to common unitholders
  
$
1,380
    
$
1,442
  
 
                
Basic weighted-average number of common units outstanding
    
2,168
      
2,170
  
 
                
Basic earnings per common unit
  
$
0.64
    
$
0.66
  
 
                
DILUTED EARNINGS PER COMMON UNIT
                
Net income attributable to common unitholders
  
$
1,393
    
$
1,456
  
Net income attributable to preferred units
    
1
      
1
  
Net income attributable to limited partners
  
$
1,394
    
$
1,457
  
 
                
Diluted weighted-average number of units outstanding:
                
Distribution-bearing common units
    
2,168
      
2,170
  
Phantom units (2)
    
21
      
21
  
Preferred units (2)
    
2
      
2
  
Total
    
2,191
      
2,193
  
 
                
Diluted earnings per common unit
  
$
0.64
    
$
0.66
  

(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.

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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 12. Business Combination

Acquisition of Pinon Midstream

On October 28, 2024, we acquired Pinon Midstream for $953 million in cash consideration.  We funded this transaction using cash on hand.

Pinon Midstream’s assets include 43 miles of natural gas gathering and redelivery pipelines, five 3-stage compressor stations, 270 million cubic feet per day (“MMcf/d”) of hydrogen sulfide and carbon dioxide treating facilities and two high capacity acid gas injection wells.

The following table presents the preliminary fair value allocation of assets acquired and liabilities assumed in the acquisition at October 28, 2024 (the effective date of the acquisition).  The allocation is provisional and subject to ongoing efforts to clarify the values assigned to tangible and identifiable intangible assets.

Purchase price for 100% interest in Pinon Midstream
  
$
953
  
Recognized amounts of identifiable assets acquired and liabilities assumed (1):
        
  Cash and cash equivalents
  
$
4
  
  Property, plant and equipment
    
410
  
  Contract-based intangible asset
    
435
  
Total identifiable net assets
  
$
849
  
Goodwill
  
$
104
  

(1)
As part of this transaction, we acquired other assets and assumed liabilities that net to a negligible amount.  Acquired other assets primarily included accounts receivable and ROU assets.  Assumed liabilities primarily included accounts payable and operating lease liabilities.  None of these amounts were considered individually significant.

On a historical pro forma basis, our revenues, costs and expenses, operating income, net income attributable to common unitholders and earnings per unit for the three months ended March 31, 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.



26

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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 March 31,
  
 
  
2025
    
2024
  
Equity-classified awards:
            
Phantom unit awards
  
$
49
    
$
46
  
Profits interest awards
    
–
      
10
  
Total
  
$
49
    
$
56
  

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
    
(7,328,067
)
  
$
24.21
  
Forfeited
    
(59,680
)
  
$
27.59
  
Phantom unit awards at March 31, 2025
    
20,996,594
    
$
28.48
  

(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 March 31,
  
 
  
2025
    
2024
  
Cash payments made in connection with DERs
  
$
11
    
$
10
  
Total intrinsic value of phantom unit awards that vested during period
    
247
      
187
  

For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $385 million at March 31, 2025, of which our share of such cost is currently estimated to be $317 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 2.4 years.


27

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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 the first quarter of 2025, we entered into two treasury lock transactions to fix the seven-year treasury rate at a weighted-average rate of approximately 4.04% on an aggregate notional amount of $500 million.  As cash flow hedges, changes in the fair value of these derivative instruments are reflected as a component of accumulated other comprehensive income.  As of March 31, 2025, the fair value of these treasury locks was $2 million.  In April 2025, we entered into two additional treasury lock transactions to fix the seven-year treasury rate at a weighted-average rate of approximately 3.87% on an aggregate notional amount of $250 million.  Each of our outstanding treasury locks is expected to settle in May 2025.  Upon settlement, the gains or losses in accumulated other comprehensive income (loss) will be amortized to interest expense over the life of the future underlying debt issuance.

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.

At March 31, 2025, our predominant commodity hedging strategies consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities, (ii) hedging natural gas processing margins, (iii) hedging the fair value of commodity products held in inventory and (iv) hedging anticipated future purchases of power for certain operations in Southeast Texas.  

•
The objective of our anticipated future commodity purchases and sales hedging program is to hedge the margins of certain transportation, storage, blending and operational activities by locking in purchase and sale prices through the use of derivative instruments and related contracts.

•
The objective of our natural gas processing hedging program is to hedge an amount of earnings associated with these activities. We achieve this objective by executing fixed-price sales for a portion of our expected equity production using derivative instruments and related contracts. For certain natural gas processing contracts, the hedging of expected equity NGL production also involves the purchase of natural gas for plant thermal reduction, which is hedged using derivative instruments and related contracts.

•
The objective of our inventory hedging program is to hedge the fair value of commodity products currently held in inventory by locking in the sales price of the inventory through the use of derivative instruments and related contracts.

•
The objective of our commercial energy hedging program is to hedge anticipated future purchases of power for certain operations in Southeast Texas by locking in purchase prices through the use of derivative instruments and related contracts.
28

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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 March 31, 2025 (volume measures as noted):

 
Volume (1)
Accounting
Derivative Purpose
Current (2)
Long-Term (2)
Treatment
Derivatives designated as hedging instruments:
      
Natural gas processing:
      
Forecasted sales of natural gas (Bcf)
38.8
27.5
Cash flow hedge
Forecasted sales of NGLs (MMBbls)
4.3
n/a
Cash flow hedge
Octane enhancement:
      
Forecasted sales of octane enhancement products (MMBbls)
2.9
n/a
Cash flow hedge
Natural gas marketing:
      
Natural gas storage inventory management activities (Bcf)
2.2
n/a
Fair value hedge
NGL marketing:
      
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)
192.8
13.8
Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)
183.9
14.2
Cash flow hedge
Refined products marketing:
      
Forecasted purchases of refined products (MMBbls)
3.2
n/a
Cash flow hedge
Forecasted sales of refined products (MMBbls)
3.9
n/a
Cash flow hedge
Crude oil marketing:
    
 
Forecasted purchases of crude oil (MMBbls)
12.3
6.5
Cash flow hedge
Forecasted sales of crude oil (MMBbls)
22.2
13.1
Cash flow hedge
Petrochemical marketing:
      
Forecasted sales of petrochemical products (MMBbls)
0.2
n/a
Cash flow hedge
   Commercial energy:
      
Forecasted purchases of power related to asset operations (terawatt hours (“TWh”))
1.2
0.1
Cash flow hedge
Derivatives not designated as hedging instruments:
      
Natural gas risk management activities (Bcf) (3)
71.0
3.1
Mark-to-market
NGL risk management activities (MMBbls) (3)
21.6
16.8
Mark-to-market
Refined products risk management activities (MMBbls) (3)
7.1
n/a
Mark-to-market
Crude oil risk management activities (MMBbls) (3)
142.2
n/a
Mark-to-market
Commercial energy risk management activities (TWh) (3)
3.9
11.8
Mark-to-market

(1)
Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2)
The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2027, December 2025 and 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 $8 million and $11 million at March 31, 2025 and December 31, 2024, respectively.
29

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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
 
March 31, 2025
 
December 31, 2024
 
March 31, 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
                              
Interest rate derivatives
Current
 assets
$
2
  
Current
assets
$
–
  
Current
liabilities
$
–
  
Current
liabilities
$
–
Commodity derivatives
Current
assets
  
345
 
Current
assets
  
210
 
Current
liabilities
  
280
 
Current
liabilities
  
178
Commodity derivatives
Other assets
 
46
 
Other assets
 
22
 
Other liabilities
 
2
 
Other liabilities
 
4
Total commodity derivatives
    
391
      
232
      
282
      
182
Total derivatives designated as hedging instruments
  
$
393
    
$
232
    
$
282
    
$
182
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments
                              
Commodity derivatives
Current
assets
$
268
 
Current
assets
$
324
 
Current
liabilities
$
258
 
Current
liabilities
$
293
Commodity derivatives
Other assets
 
18
 
Other assets
  
19
 
Other liabilities
  
11
 
Other liabilities
  
20
Total commodity derivatives
 
 
286
 
 
  
343
 
 
  
269
 
 
  
313
Total derivatives not designated as hedging instruments
  
$
286
    
$
343
    
$
269
    
$
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 March 31, 2025:
                                          
Interest rate derivatives
  
$
2
    
$
–
    
$
2
    
$
–
    
$
–
    
$
–
    
$
2
  
Commodity derivatives
    
677
      
–
      
677
      
(550
)
    
(127
)
    
–
      
–
  
As of December 31, 2024:
                                                        
Commodity derivatives
  
$
575
    
$
–
    
$
575
    
$
(495
)
  
$
(79
)
  
$
–
    
$
1
  


 
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 March 31, 2025:
                                          
Commodity derivatives
  
$
551
    
$
–
    
$
551
    
$
(550
)
  
$
–
    
$
–
    
$
1
  
As of December 31, 2024:
                                                        
Commodity derivatives
  
$
495
    
$
–
    
$
495
    
$
(495
)
  
$
–
    
$
–
    
$
–
  
30

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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 March 31,
  
 
 
  
2025
    
2024
  
Commodity derivatives
Revenue
  
$
1
    
$
1
  
Total
 
  
$
1
    
$
1
  

Derivatives in Fair Value
Hedging Relationships
Location
  
Gain (Loss) Recognized in
Income on Hedged Item
  
 
  
  
For the Three Months
Ended March 31,
  
 
 
  
2025
    
2024
  
Commodity derivatives
Revenue
  
$
–
    
$
4
  
Total
 
  
$
–
    
$
4
  

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.

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 March 31,
  
 
  
2025
    
2024
  
Interest rate derivatives
  
$
2
    
$
2
  
Commodity derivatives – Revenue (1)
    
18
      
(149
)
Commodity derivatives – Operating costs and expenses (1)
    
4
      
(13
)
Total
  
$
24
    
$
(160
)

(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.

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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Derivatives in Cash Flow
Hedging Relationships
Location
  
Gain (Loss) Reclassified from
Accumulated Other
Comprehensive Income (Loss)
to Income
  
 
  
  
For the Three Months
Ended March 31,
  
 
 
  
2025
    
2024
  
Interest rate derivatives
Interest expense
  
$
1
    
$
2
  
Commodity derivatives
Revenue
    
(14
)
    
19
  
Commodity derivatives
Operating costs and expenses
    
(12
)
    
(17
)
Total
 
  
$
(25
)
  
$
4
  

Over the next twelve months, we expect to reclassify $6 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 $107 million of net gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, with $94 million as an increase in revenue and $13 million as a decrease in operating costs and expenses.

The following table presents the effect of our derivative instruments not designated as hedging instruments on our Unaudited Condensed Statements of Consolidated Operations for the periods indicated:

Derivatives Not Designated
as Hedging Instruments
Location
  
Gain (Loss) Recognized in
Income on Derivative
  
 
  
  
For the Three Months
Ended March 31,
  
 
 
  
2025
    
2024
  
Commodity derivatives
Revenue
  
$
(21
)
  
$
13
  
Commodity derivatives
Operating costs and expenses
    
(2
)
    
(1
)
Total
    
$
(23
)
  
$
12
  

The $23 million net loss recognized for the three months ended March 31, 2025 (as noted in the preceding table) from derivatives not designated as hedging instruments consists of $15 million of net realized gains and $38 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.

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.
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
  
At March 31, 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:
                        
Interest rate derivatives
  
$
–
    
$
2
    
$
–
    
$
2
  
Commodity derivatives:
                                
Value before application of CME Rule 814
    
292
      
740
      
–
      
1,032
  
Impact of CME Rule 814
    
(57
)
    
(298
)
    
–
      
(355
)
Total commodity derivatives
    
235
      
442
      
–
      
677
  
Total
  
$
235
    
$
444
    
$
–
    
$
679
  
 
                                
Financial liabilities:
                                
Commodity derivatives:
                                
Value before application of CME Rule 814
  
$
330
    
$
637
    
$
–
    
$
967
  
Impact of CME Rule 814
    
(125
)
    
(291
)
    
–
      
(416
)
Total commodity derivatives
    
205
      
346
      
–
      
551
  
Total
  
$
205
    
$
346
    
$
–
    
$
551
  

 
  
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 March 31, 2025 was a net derivative asset of $65 million prior to the impact of CME Rule 814.

Financial assets and liabilities recorded on the balance sheet at March 31, 2025 using significant unobservable inputs (Level 3) are not material to the Unaudited Condensed Consolidated Financial Statements.

33

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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 $28.1 billion and $28.9 billion at March 31, 2025 and December 31, 2024, respectively.  The aggregate carrying value of these debt obligations was $30.5 billion and $31.6 billion at March 31, 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 March 31,
  
 
  
2025
    
2024
  
Revenues – related parties:
            
Unconsolidated affiliates
  
$
13
    
$
15
  
Costs and expenses – related parties:
                
EPCO and its privately held affiliates
  
$
387
    
$
381
  
Unconsolidated affiliates
    
38
      
46
  
Total
  
$
425
    
$
427
  

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

 
  
March 31,
2025
    
December 31,
2024
  
Accounts receivable - related parties:
            
Unconsolidated affiliates
  
$
2
    
$
4
  
 
                
Accounts payable - related parties:
                
EPCO and its privately held affiliates
  
$
77
    
$
180
  
Unconsolidated affiliates
    
14
      
18
  
Total
  
$
91
    
$
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 March 31, 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
702,222,874 common units
32.4%
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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 March 31, 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 three months ended March 31, 2025 and 2024, we paid EPCO and its privately held affiliates cash distributions totaling $363 million and $350 million, respectively.

We have no employees.  All of our administrative and operating functions are provided either by employees of EPCO (pursuant to the ASA) or by other service providers.  We and our general partner are parties to the ASA.  The following table presents our related party costs and expenses attributable to the ASA with EPCO for the periods indicated:

 
  
For the Three Months
Ended March 31,
  
 
  
2025
    
2024
  
Operating costs and expenses
  
$
351
    
$
334
  
General and administrative expenses
    
29
      
41
  
Total costs and expenses
  
$
380
    
$
375
  

We lease office space from privately held affiliates of EPCO.  For the three months ended March 31, 2025 and 2024, we recognized $6 million and $3 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 first quarters of 2025 and 2024.

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

 
  
For the Three Months
Ended March 31,
  
 
  
2025
    
2024
  
Current portion of income tax provision:
            
Federal
  
$
(1
)
  
$
–
  
State
    
(12
)
    
(12
)
Total current portion
    
(13
)
    
(12
)
Deferred portion of income tax provision:
                
    Federal
    
(4
)
    
(4
)
    State
    
(7
)
    
(5
)
Total deferred portion
    
(11
)
    
(9
)
Total provision for income taxes
  
$
(24
)
  
$
(21
)
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows:

 
  
For the Three Months
Ended March 31,
  
 
  
2025
    
2024
  
Pre-Tax Net Book Income (“NBI”)
  
$
1,430
    
$
1,504
  
 
                
Texas Margin Tax (1)
    
(19
)
    
(17
)
State income tax provision, net of federal benefit
    
(1
)
    
–
  
Federal income tax provision computed by applying the federal 
statutory rate to NBI of corporate entities
    
(4
)
    
(3
)
Other
    
–
      
(1
)
Provision for income taxes
  
$
(24
)
  
$
(21
)
 
                
Effective income tax rate
    
(1.7
)%
    
(1.4
)%

(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:

   
March 31,
    
December 31,
  
 
  
2025
    
2024
  
Deferred tax liabilities:
            
Attributable to investment in OTA (1)
  
$
470
    
$
462
  
Attributable to property, plant and equipment
    
157
      
151
  
Attributable to investments in other entities
    
4
      
5
  
Other
    
98
      
98
  
     Total deferred tax liabilities
    
729
      
716
  
Deferred tax assets:
                
Net operating loss carryovers (2)
    
59
      
56
  
Temporary differences related to Texas Margin Tax
    
3
      
4
  
Total deferred tax assets
    
62
      
60
  
Total net deferred tax liabilities
  
$
667
    
$
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 March 31, 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 March 31, 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 $31.9 billion and $32.2 billion at March 31, 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 March 31, 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
$
209
  
$
208
  
8 years
  
4.5%
Transportation equipment
  
            40
    
            41
  
4 years
  
4.8%
Office and warehouse space
  
            168
    
            203
  
12 years
  
3.4%
Total operating leases
  
 417
    
452
        
Finance leases
                  
Transportation equipment
  
12
    
13
  
4 years
  
4.8%
Total finance leases
  
12
    
13
        
Total leases
$
429
  
$
465
        

(1)
ROU asset amounts are a component of “Other assets” on our Unaudited Condensed Consolidated Balance Sheet.
(2)
At March 31, 2025, operating lease liabilities of $104 million and $348 million were included within “Other current liabilities” and “Other long-term liabilities,” respectively.  Additionally at March 31, 2025, finance lease liabilities of $2 million and $11 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 March 31,
  
 
  
2025
    
2024
  
Long-term leases:
            
   Fixed operating lease expense:
            
      Non-cash lease expense (amortization of ROU assets)
  
$
28
    
$
20
  
      Related accretion expense on lease liability balances
    
4
      
4
  
         Total fixed operating lease expense
    
32
      
24
  
   Fixed finance lease expense:
                
      Amortization of ROU assets (1)
    
–
*
    
–
  
      Interest on finance lease liabilities (1)
    
–
*
    
–
  
         Total fixed finance lease expense (1)
    
–
*
    
–
  
   Variable lease expense
    
5
      
4
  
   Total long-term lease expense
    
37
      
28
  
Short-term leases
    
35
      
29
  
Total lease expense
  
$
72
    
$
57
  

(1)
For the three months ended March 31, 2025, total fixed finance lease expense, which include amortization of finance lease ROU assets and interest on finance lease liabilities, was less than $1 million. 
*
Amount is negligible.

Cash paid for operating lease liabilities was $34 million and $23 million for the three months ended March 31, 2025 and 2024, respectively.

Operating lease income for each of the three months ended March 31, 2025 and 2024 was $4 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 March 31, 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 Three Months
Ended March 31,
  
 
  
2025
    
2024
  
Decrease (increase) in:
            
Accounts receivable – trade
  
$
1,384
    
$
274
  
Accounts receivable – related parties
    
2
      
–
  
Inventories
    
736
      
1
  
Prepaid and other current assets
    
111
      
(76
)
Other assets
    
13
      
(12
)
Increase (decrease) in:
                
Accounts payable – trade
    
(35
)
    
52
  
Accounts payable – related parties
    
(107
)
    
(117
)
Accrued product payables
    
(1,374
)
    
379
  
Accrued interest
    
(275
)
    
(201
)
Other current liabilities
    
(178
)
    
(288
)
Other long-term liabilities
    
(74
)
    
(48
)
Net effect of changes in operating accounts
  
$
203
    
$
(36
)
                 
Cash payments for interest, net of $45 and $25 capitalized during the
   three months ended March 31, 2025 and 2024, respectively
  
$
611
    
$
529
  
                 
Cash refunds for federal and state income taxes
  
$
(3
)
  
$
(1
)

We incurred liabilities for construction in progress that had not been paid at March 31, 2025 and December 31, 2024 of $586 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 Months Ended March 31, 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 months ended March 31, 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.

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.
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We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees.  EPCO, together with its privately held affiliates, owned approximately 32.4% of the Partnership’s common units outstanding at March 31, 2025.

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

/d
=
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 first quarter of 2025 compared to the first quarter of 2024.

Overview of Business

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 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. 

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.

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.

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.
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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.

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:


            
Polymer
Refinery
Indicative Gas
 
Natural
    
Normal
  
Natural
Grade
Grade
Processing
 
Gas,
Ethane,
Propane,
Butane,
Isobutane,
Gasoline,
Propylene,
Propylene,
Gross Spread
 
$/MMBtu
$/gallon
$/gallon
$/gallon
$/gallon
$/gallon
$/pound
$/pound
$/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

(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 $0.67 per gallon in the first quarter of 2025 versus $0.62 per gallon in the first quarter of 2024.

The following table presents selected average index prices for crude oil for the periods indicated:
WTI
Midland
Houston
 
Crude Oil,
Crude Oil,
Crude Oil,
 
$/barrel
$/barrel
$/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

(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.
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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.  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 March 31,
  
 
  
2025
    
2024
  
Revenues
  
$
15,417
    
$
14,760
  
Costs and expenses:
                
   Operating costs and expenses:
                
      Cost of sales
    
12,005
      
11,405
  
      Other operating costs and expenses
    
1,059
      
954
  
      Depreciation, amortization and accretion expenses
    
618
      
595
  
      Asset impairment charges
    
10
      
20
  
      Net gains attributable to asset sales and related matters
    
(2
)
    
−
  
      Total operating costs and expenses
    
13,690
      
12,974
  
   General and administrative costs
    
60
      
66
  
      Total costs and expenses
    
13,750
      
13,040
  
Equity in income of unconsolidated affiliates
    
94
      
102
  
Operating income
    
1,761
      
1,822
  
Other income (expense):
                
   Interest expense
    
(340
)
    
(331
)
   Other, net
    
9
      
13
  
      Total other expense, net
    
(331
)
    
(318
)
Income before income taxes
    
1,430
      
1,504
  
Provision for income taxes
    
(24
)
    
(21
)
Net income
    
1,406
      
1,483
  
Net income attributable to noncontrolling interests
    
(12
)
    
(26
)
Net income attributable to preferred units
    
(1
)
    
(1
)
Net income attributable to common unitholders
  
$
1,393
    
$
1,456
  

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 March 31,
  
 
  
2025
    
2024
  
NGL Pipelines & Services:
            
Sales of NGLs and related products
  
$
4,651
    
$
4,400
  
Midstream services
    
749
      
740
  
Total
    
5,400
      
5,140
  
Crude Oil Pipelines & Services:
                
    Sales of crude oil
    
4,825
      
5,122
  
    Midstream services
    
296
      
293
  
        Total
    
5,121
      
5,415
  
Natural Gas Pipelines & Services:
                
    Sales of natural gas
    
785
      
503
  
    Midstream services
    
436
      
351
  
       Total
    
1,221
      
854
  
Petrochemical & Refined Products Services:
                
    Sales of petrochemicals and refined products
    
3,326
      
2,965
  
    Midstream services
    
349
      
386
  
       Total
    
3,675
      
3,351
  
Total consolidated revenues
  
$
15,417
    
$
14,760
  


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Total revenues for the first quarter of 2025 increased $657 million when compared to the first quarter of 2024 primarily due to higher marketing revenues.

Revenues from the marketing of NGLs and petrochemicals and refined products increased a combined net $613 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $1.3 billion increase, partially offset by lower average sales prices, which accounted for a $711 million decrease.  Revenues from the marketing of natural gas increased $281 million quarter-to-quarter primarily due to higher average sales prices.  Revenues from the marketing of crude oil decreased $297 million quarter-to-quarter primarily due to lower average sales prices.

Revenues from midstream services for the first quarter of 2025 increased a net $60 million when compared to the first quarter of 2024.  Revenues from our NGL and natural gas transportation assets increased a combined $118 million quarter-to-quarter primarily due to higher demand for transportation services.  Revenues from our octane enhancement and related plant operations decreased $34 million quarter-to-quarter primarily due to lower deficiency fee revenues.  Lastly, revenues from our ethylene exports and related activities decreased $23 million quarter-to-quarter primarily due to lower deficiency fee revenues and lower ethylene loading fee revenues.

Operating costs and expenses

Total operating costs and expenses for the first quarter of 2025 increased $716 million when compared to the first quarter of 2024.

Cost of sales
Cost of sales for the first quarter of 2025 increased a net $600 million when compared to the first quarter of 2024.  The cost of sales associated with the marketing of NGLs and petrochemicals and refined products increased a combined net $640 million quarter-to-quarter primarily due to higher volumes, which accounted for a $1.1 billion increase, partially offset by lower average purchase prices, which accounted for a $424 million decrease.  The cost of sales associated with the marketing of natural gas increased $161 million quarter-to-quarter primarily due to higher average purchase prices.  The cost of sales associated with the marketing of crude oil decreased $201 million quarter-to-quarter primarily due to lower average purchase prices.

Other operating costs and expenses
Other operating costs and expenses for the first quarter of 2025 increased $105 million when compared to the first quarter in 2024 primarily due to higher maintenance, employee compensation and utility costs.

Depreciation, amortization and accretion expenses
Depreciation, amortization and accretion expense for the first quarter of 2025 increased $23 million when compared to the first quarter of 2024 primarily due to higher depreciation expense on assets placed into full or limited service since the end of the first quarter of 2024.

General and administrative costs

General and administrative costs for the first quarter of 2025 decreased $6 million when compared to the first quarter of 2024 primarily due to lower employee compensation costs.

Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for the first quarter of 2025 decreased $8 million when compared to the first quarter of 2024 primarily due to lower earnings from investments in NGL pipelines and services.

Operating income

Operating income for the first quarter of 2025 decreased $61 million when compared to the first quarter of 2024 due to the previously described quarter-to-quarter changes.

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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 March 31,
  
 
  
2025
    
2024
  
Interest charged on debt principal outstanding (1)
  
$
379
    
$
351
  
Impact of interest rate hedging program, including related amortization
    
(1
)
    
(2
)
Interest costs capitalized in connection with construction projects (2)
    
(45
)
    
(25
)
Other
    
7
      
7
  
Total
  
$
340
    
$
331
  

(1)
The weighted-average interest rates on debt principal outstanding during the first quarters of 2025 and 2024 were 4.70% 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 $28 million quarter-to-quarter.  This increase was primarily due to the issuance of $2.0 billion and $2.5 billion of fixed-rate senior notes in January 2024 and August 2024, respectively, which accounted for a combined $36 million increase, partially offset by the retirement of $850 million and $1.15 billion of fixed-rate senior notes in February 2024 and February 2025, respectively, which accounted for a combined $10 million decrease.

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.

Income taxes

Our income taxes are primarily comprised of our state tax obligations under the Revised Texas Franchise Tax (“Texas Margin Tax”).  Our provision for income taxes for the first quarter of 2025 increased $3 million when compared to the first quarter of 2024.

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Business Segment Highlights

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.

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 March 31,
  
 
  
2025
    
2024
  
Gross operating margin by segment:
            
NGL Pipelines & Services
  
$
1,418
    
$
1,340
  
Crude Oil Pipelines & Services
    
374
      
411
  
Natural Gas Pipelines & Services
    
357
      
312
  
Petrochemical & Refined Products Services
    
315
      
444
  
Total segment gross operating margin (1)
    
2,464
      
2,507
  
Net adjustment for shipper make-up rights
    
(33
)
    
(17
)
Total gross operating margin (non-GAAP)
  
$
2,431
    
$
2,490
  

(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.

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 March 31,
  
 
  
2025
    
2024
  
Operating income
  
$
1,761
    
$
1,822
  
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)
    
602
      
582
  
   Asset impairment charges in operating costs and expenses
    
10
      
20
  
   Net gains attributable to asset sales and related matters in operating
      costs and expenses
    
(2
)
    
–
  
   General and administrative costs
    
60
      
66
  
Total gross operating margin (non-GAAP)
  
$
2,431
    
$
2,490
  

(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.
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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 March 31,
  
 
  
2025
    
2024
  
Segment gross operating margin:
            
   Natural gas processing and related NGL marketing activities
  
$
373
    
$
358
  
   NGL pipelines, storage and terminals
    
831
      
749
  
   NGL fractionation
    
214
      
233
  
      Total
  
$
1,418
    
$
1,340
  
                 
Selected volumetric data:
                
   NGL pipeline transportation volumes (MBPD)
    
4,447
      
4,238
  
   NGL marine terminal volumes (MBPD)
    
994
      
895
  
   NGL fractionation volumes (MBPD)
    
1,652
      
1,642
  
   Equity NGL-equivalent production volumes (MBPD) (1)
    
225
      
185
  
   Fee-based natural gas processing volumes (MMcf/d) (2,3)
    
7,181
      
6,421
  

(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.

Natural gas processing and related NGL marketing activities
Gross operating margin from natural gas processing and related NGL marketing activities for the first quarter of 2025 increased $15 million when compared to the first quarter of 2024.

Gross operating margin from our Midland Basin natural gas processing facilities increased a net $42 million quarter-to-quarter primarily due to a 21 MBPD increase in equity NGL-equivalent production volumes, which accounted for an $18 million increase, higher fee-based natural gas processing volumes, which accounted for a $16 million increase, and higher average processing margins (including the impact of hedging activities), which accounted for an additional $16 million increase, partially offset by lower average processing fees, which accounted for a $4 million decrease, and higher operating expenses, which accounted for an additional $4 million decrease.  Fee-based natural gas processing volumes at our Midland Basin natural gas processing facilities increased 479 MMcf/d quarter-to-quarter primarily due to contributions from our Leonidas natural gas processing train, which was placed into service in late first quarter of 2024.

Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $4 million quarter-to-quarter primarily due to higher fee-based natural gas processing volumes, which accounted for a $14 million increase, a 15 MBPD increase in equity NGL-equivalent production volumes, which accounted for a $9 million increase, and lower operating costs, which accounted for an additional $3 million increase, partially offset by lower average processing margins (including the impact of hedging activities), which accounted for a $23 million decrease.  Fee-based natural gas processing volumes at our Delaware Basin natural gas processing facilities increased 388 MMcf/d quarter-to-quarter, primarily due to contributions from our Mentone 3 natural gas processing train, which was placed into service in late first quarter of 2024.

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Gross operating margin from our NGL marketing activities decreased a net $20 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $62 million decrease, partially offset by higher sales volumes, which accounted for a $38 million increase, and higher mark-to-market earnings, which accounted for an additional $5 million increase.

Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $7 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 61 MMcf/d and increased 2 MBPD, respectively, quarter-to-quarter.

NGL pipelines, storage and terminals
Gross operating margin from our NGL pipelines, storage and terminal assets during the first quarter of 2025 increased $82 million when compared to the first quarter of 2024.

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 $22 million quarter-to-quarter primarily due to a 74 MBPD increase in transportation volumes, which accounted for a $22 million increase, and higher average transportation fees, which accounted for an additional $5 million increase, partially offset by higher operating costs, which accounted for a $6 million decrease.

Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $19 million quarter-to-quarter primarily due to a 68 MBPD increase in export volumes.

Gross operating margin from our Dixie Pipeline and related terminals increased $16 million quarter-to-quarter primarily due to higher loading and other fee revenues, which accounted for a $7 million increase, higher average transportation fees, which accounted for a $6 million increase, and a 27 MBPD increase in transportation volumes, which accounted for an additional $5 million increase.

Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $12 million quarter-to-quarter primarily due to higher average transportation fees.  Transportation volumes on these pipelines decreased a combined 25 MBPD quarter-to-quarter.

Gross operating margin from our South Texas NGL Pipeline System increased $9 million quarter-to-quarter primarily due to higher capacity reservation revenues, which accounted for a $5 million increase, and lower operating costs, which accounted for an additional $2 million increase.  Transportation volumes on this system increased 12 MBPD quarter-to-quarter.

NGL fractionation
Gross operating margin from NGL fractionation during the first quarter of 2025 decreased $19 million when compared to the first quarter of 2024.  Gross operating margin from our Mont Belvieu area NGL fractionation complex decreased $15 million quarter-to-quarter primarily due to higher operating costs, which accounted for a $9 million decrease, and lower ancillary service revenues, which accounted for an additional $5 million decrease.  NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex increased 10 MBPD.
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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 March 31,
  
 
  
2025
    
2024
  
Segment gross operating margin
  
$
374
    
$
411
  
                 
Selected volumetric data:
                
    Crude oil pipeline transportation volumes (MBPD)
    
2,484
      
2,456
  
    Crude oil marine terminal volumes (MBPD)
    
736
      
1,094
  

Gross operating margin from our Crude Oil Pipelines & Services segment for the first quarter of 2025 decreased $37 million when compared to the first quarter of 2024.

Gross operating margin from our Texas crude oil pipelines, related terminals and marketing activities (excluding the Seaway Pipeline) decreased a combined $39 million quarter-to-quarter primarily due to lower sales volumes, which accounted for a $23 million decrease, and lower average sales margins, which accounted for an additional $14 million decrease.  Crude oil transportation volumes on these pipelines increased a combined 38 MBPD (net to our interest) quarter-to-quarter.

Gross operating margin from crude oil activities at EHT increased $9 million quarter-to-quarter primarily due to higher storage and other revenues, which accounted for a $6 million increase, and lower operating costs, which accounted for an additional $3 million increase.  Crude oil terminal volumes at EHT decreased 309 MBPD quarter-to-quarter.

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 March 31,
  
 
  
2025
    
2024
  
Segment gross operating margin
  
$
357
    
$
312
  
                 
Selected volumetric data:
                
   Natural gas pipeline transportation volumes (BBtus/d)
    
20,310
      
18,934
  

Gross operating margin from our Natural Gas Pipelines & Services segment for the first quarter of 2025 increased $45 million when compared to the first quarter of 2024.

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 $27 million quarter-to-quarter primarily due to higher treating and other revenues, which accounted for a $20 million increase, a 700 BBtus/d increase in natural gas gathering volumes, which accounted for a $14 million increase, and higher average gathering fees, which accounted for an additional $8 million increase, partially offset by higher operating costs, which accounted for a $15 million decrease.

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Gross operating margin from our Texas Intrastate System increased $27 million quarter-to-quarter primarily due to higher capacity reservation fees and other revenues, which accounted for a $14 million increase, and higher average transportation fees, which accounted for an additional $13 million increase. Transportation volumes increased 129 BBtus/d on this system quarter-to-quarter.

Gross operating margin from our Midland Basin Gathering System increased a net $10 million quarter-to-quarter primarily due to a 589 BBtus/d increase in natural gas gathering volumes, which accounted for a $19 million increase, partially offset by higher operating costs, which accounted for a $9 million decrease.

Gross operating margin from our natural gas marketing activities decreased a net $15 million quarter-to-quarter primarily due to lower mark-to-market earnings, which accounted for a $31 million decrease, partially offset by higher average sales margins, which accounted for a $16 million increase.

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 March 31,
  
 
  
2025
    
2024
  
Segment gross operating margin:
            
   Propylene production and related activities
  
$
85
    
$
137
  
   Butane isomerization and related operations
    
27
      
33
  
   Octane enhancement and related plant operations
    
59
      
142
  
   Refined products pipelines and related activities
    
105
      
72
  
   Ethylene exports and related activities
    
20
      
48
  
   Marine transportation and other services
    
19
      
12
  
      Total
  
$
315
    
$
444
  
 
                
Selected volumetric data:
                
   Propylene production volumes (MBPD)
    
113
      
106
  
   Butane isomerization volumes (MBPD)
    
114
      
117
  
   Standalone deisobutanizer (“DIB”) processing volumes (MBPD)
    
188
      
196
  
   Octane enhancement and related plant sales volumes (MBPD) (1)
    
46
      
35
  
   Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD)
    
949
      
870
  
   Marine terminal volumes, primarily refined products and petrochemicals (MBPD)
    
311
      
350
  

(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
Gross operating margin from propylene production and related activities for the first quarter of 2025 decreased $52 million when compared to the first quarter of 2024.

On a combined basis, gross operating margin from our Mont Belvieu area propylene production facilities decreased $47 million quarter-to-quarter primarily due to lower average propylene sales margins.  Propylene and associated by-product production volumes at these facilities increased a combined 8 MBPD quarter-to-quarter primarily due to higher production from one of our propylene splitters, which had experienced downtime during the first quarter of 2024.

Butane isomerization and related operations
Gross operating margin from butane isomerization and related operations for the first quarter of 2025 decreased $6 million when compared to the first quarter of 2024 primarily due to higher operating costs.

Octane enhancement and related plant operations
Gross operating margin from our octane enhancement and related plant operations for the first quarter of 2025 decreased $83 million when compared to the first quarter of 2024 primarily due to lower average sales margins, which accounted for a $51 million decrease, and lower deficiency revenues, which accounted for an additional $32 million decrease.
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Refined products pipelines and related activities
Gross operating margin from refined products pipelines and related activities for the first quarter of 2025 increased $33 million when compared to the first quarter of 2024.

Gross operating margin from our TE Products Pipeline System increased a net $27 million quarter-to-quarter primarily due to a 34 MBPD increase in transportation volumes, which accounted for a $22 million increase, and higher average transportation fees, which accounted for an additional $9 million increase, partially offset by higher operating costs, which accounted for a $7 million decrease.

Gross operating margin from our TW Products System increased $13 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 refined products marketing activities decreased $5 million quarter-to-quarter primarily due to lower average sales margins.

Ethylene exports and related activities
Gross operating margin from ethylene exports and related activities for the first quarter of 2025 decreased $28 million when compared to the first quarter of 2024 primarily due to lower deficiency fee revenues from our ethylene pipelines, which accounted for a $17 million decrease, and a 25 MBPD decrease in ethylene export volumes, which accounted for an additional $13 million decrease.  Ethylene transportation volumes decreased 13 MBPD quarter-to-quarter.

Marine transportation and other services
Gross operating margin from marine transportation and other services for the first quarter of 2025 increased $7 million when compared to the first quarter of 2024 primarily due to higher average fees.

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 March 31, 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 $830 million outstanding under EPO’s commercial paper program, and $220 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 First Quarter of 2025

On April 7, 2025, we announced that the Board declared a quarterly cash distribution of $0.535 per common unit, or $2.14 per unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the first quarter of 2025.  The quarterly distribution is payable on May 14, 2025 to unitholders of record as of the close of business on April 30, 2025.  The total amount to be paid is $1.17 billion, which includes $11 million for distribution equivalent rights on phantom unit awards.

The payment of quarterly cash distributions is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and Board approval.  Management will evaluate any future increases in cash distributions on a quarterly basis.

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Consolidated Debt

At March 31, 2025, the average maturity of EPO’s consolidated debt obligations was approximately 18.3 years.  The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at March 31, 2025 for the years indicated (dollars in millions):

 
        
Scheduled Maturities of Debt
  
 
  
Total
    
Remainder
of 2025
    
2026
    
2027
    
2028
    
2029
    
Thereafter
  
Commercial Paper
  
$
830
    
$
830
    
$
–
    
$
–
    
$
–
    
$
–
    
$
–
  
Senior Notes
    
28,775
      
–
      
1,625
      
1,575
      
1,000
      
1,250
      
23,325
  
Junior Subordinated Notes
    
2,282
      
–
      
–
      
–
      
–
      
–
      
2,282
  
Total
  
$
31,887
    
$
830
    
$
1,625
    
$
1,575
    
$
1,000
    
$
1,250
    
$
25,607
  

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 March 31, 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 March 31, 2025, there are no principal amounts outstanding under this revolving credit agreement.

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 May 7, 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 1,803,215 common units through open market purchases during the three months ended March 31, 2025.  The total cost of these repurchases, including commissions and fees was $60 million.  As of March 31, 2025, the remaining available capacity under the 2019 Buyback Program was $803 million.
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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 Three Months
Ended March 31,
  
 
2025
  
2024
  
Net cash flow provided by operating activities
  
$
2,314
    
$
2,111
  
Net cash flow used in investing activities
    
1,047
      
1,038
  
Net cash flow used in financing activities
    
1,651
      
1,009
  

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 first quarter of 2025 increased a net $203 million when compared to the first quarter of 2024 primarily due to:

•
a $239 million quarter-to-quarter increase from 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; partially offset by

•
a $27 million quarter-to-quarter decrease resulting from lower partnership earnings (determined by adjusting our $77 million quarter-to-quarter decrease in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows).

For information regarding significant quarter-to-quarter 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 first quarter of 2025 increased $9 million when compared to the first quarter of 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 first quarter of 2025 increased a net $642 million when compared to the first quarter of 2024 primarily due to:

•
a net cash outflow of $332 million related to debt transactions that occurred during the first quarter of 2025 compared to a net cash inflow of $649 million related to debt transactions that occurred during the first quarter of 2024.  During the first quarter of 2025, we repaid $1.15 billion principal amount of senior notes, partially offset by net issuances of $830 million under EPO’s commercial paper program.  During the first quarter of 2024, we issued $2.0 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; and

•
a $42 million quarter-to-quarter increase in cash distributions paid to common unitholders primarily attributable to increases in the quarterly cash distribution rate per unit; partially 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 March 31,
  
 
  
2025
    
2024
  
Net income attributable to common unitholders (GAAP) (1)
  
$
1,393
    
$
1,456
  
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
    
636
      
616
  
   Cash distributions received from unconsolidated affiliates (2)
    
103
      
112
  
   Equity in income of unconsolidated affiliates
    
(94
)
    
(102
)
   Asset impairment charges
    
10
      
20
  
   Change in fair market value of derivative instruments
    
42
      
4
  
   Deferred income tax expense
    
11
      
9
  
   Sustaining capital expenditures (3)
    
(102
)
    
(180
)
   Other, net
    
10
      
7
  
Operational DCF (non-GAAP)
  
$
2,009
    
$
1,942
  
   Proceeds from asset sales and other matters
    
4
      
2
  
   Monetization of interest rate derivative instruments accounted for as cash flow hedges
    
–
      
(29
)
DCF (non-GAAP)
  
$
2,013
    
$
1,915
  
 
                
Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards
  
$
1,171
    
$
1,129
  
 
                
Cash distribution per common unit declared by Enterprise GP with respect to period (4)
  
$
0.535
    
$
0.5150
  
 
                
Total DCF retained by the Partnership with respect to period (5)
  
$
842
    
$
786
  
 
                
Distribution coverage ratio (6)
    
1.7
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 March 31,
  
 
  
2025
    
2024
  
Net cash flow provided by operating activities (GAAP)
  
$
2,314
    
$
2,111
  
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
    
(203
)
    
36
  
   Sustaining capital expenditures
    
(102
)
    
(180
)
   Distributions received from unconsolidated affiliates attributable to the return of capital
    
15
      
15
  
   Net income attributable to noncontrolling interests
    
(12
)
    
(26
)
   Other, net
    
(3
)
    
(14
)
Operational DCF (non-GAAP)
  
$
2,009
    
$
1,942
  
   Proceeds from asset sales and other matters
    
4
      
2
  
   Monetization of interest rate derivative instruments accounted for as cash flow hedges
    
–
      
(29
)
DCF (non-GAAP)
  
$
2,013
    
$
1,915
  

Capital Investments

We have approximately $7.6 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);

•
an NGL fractionator (“Frac 14”) and an associated DIB unit at our Mont Belvieu area NGL fractionation complex (third quarter of 2025);

•
our first natural gas processing train at our Mentone West location in the Delaware Basin (third quarter of 2025);

•
an eighth natural gas processing train (“Orion”) in the Midland Basin (third quarter of 2025);

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

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

•
our Neches River Ethane / Propane Export Facility located in Orange County, Texas (third quarter of 2025 and first half of 2026);

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

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

Based on information currently available, we expect our total capital investments for 2025, net of contributions from noncontrolling interests, to approximate $4.5 billion to $5.0 billion, which reflects growth capital investments of $4.0 billion to $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 Three Months
Ended March 31,
 
 
  
2025
    
2024
  
Capital investments for property, plant and equipment: (1)
            
   Growth capital projects (2)
  
$
959
    
$
909
  
   Sustaining capital projects (3)
    
103
      
138
  
      Total
  
$
1,062
    
$
1,047
  

(1)
Growth and sustaining capital 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.

Comparison of First Quarter of 2025 with the First Quarter of 2024

In total, investments in growth capital projects increased a net $50 million quarter-to-quarter 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 $92 million increase;

•
higher investments in ethane and LPG export expansion and enhancement projects at our Gulf Coast terminals, which accounted for an additional $33 million increase; partially offset by

•
lower investments in our TW Products System (placed into service during 2024), which accounted for a $74 million decrease.

Investments attributable to sustaining capital projects decreased $35 million quarter-to-quarter 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.

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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;

•
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 March 31, 2025, the total amount of Guaranteed Debt was $32.1 billion, which was comprised of $28.8 billion of EPO’s senior notes, $2.3 billion of EPO’s junior subordinated notes, $830 million of commercial paper, and $261 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.

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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 $51.9 billion at March 31, 2025.  The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the first quarter of 2025 was $1.6 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.

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

Selected asset information:
  
March 31,
2025
    
December 31,
2024
  
   Current receivables from Non-Obligor Subsidiaries
  
$
1,344
    
$
1,569
  
   Other current assets
    
5,484
      
6,487
  
   Long-term receivables from Non-Obligor Subsidiaries
    
187
      
187
  
   Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries
      of $51.9 billion at March 31, 2025 and $50.8 billion at December 31, 2024
    
9,312
      
9,350
  
                 
Selected liability information:
                
   Current portion of Guaranteed Debt, including interest of $261 million at March 31, 2025 and
      $536 million at December 31, 2024
  
$
2,714
    
$
1,686
  
   Current payables to Non-Obligor Subsidiaries
    
1,450
      
1,438
  
   Other current liabilities
    
4,264
      
4,074
  
   Noncurrent portion of Guaranteed Debt, principal only
    
29,432
      
31,057
  
   Noncurrent payables to Non-Obligor Subsidiaries
    
55
      
55
  
   Other noncurrent liabilities
    
217
      
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 Three
Months Ended
March 31,
2025
    
For the Twelve
Months Ended
December 31,
2024
  
Revenues from Non-Obligor Subsidiaries
  
$
6,547
    
$
22,286
  
Revenues from other sources
    
4,970
      
19,781
  
Operating income of Obligor Group
    
154
      
443
  
Net loss of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of
     $1.6 billion for the three months ended March 31, 2025 and
     $6.8 billion for the twelve months ended December 31, 2024
    
(200
)
    
(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.

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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 March 31, 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.

Natural gas marketing portfolio
 
  
Portfolio Fair Value at
  
Scenario
Resulting
Classification
December 31,
2024
  
March 31,
2025
  
April 15,
2025
  
Fair value assuming no change in underlying commodity prices
Asset (Liability)
  
$
5
    
$
(11
)
  
$
82
  
Fair value assuming 10% increase in underlying commodity prices
Asset (Liability)
    
4
      
(27
)
    
75
  
Fair value assuming 10% decrease in underlying commodity prices
Asset (Liability)
    
6
      
5
      
89
  

NGL, petrochemical and refined products marketing, natural gas processing and octane enhancement portfolio
 
  
Portfolio Fair Value at
  
Scenario
Resulting
Classification
December 31,
2024
  
March 31,
2025
  
April 15,
2025
  
Fair value assuming no change in underlying commodity prices
Asset (Liability)
  
$
61
    
$
55
    
$
(46
)
Fair value assuming 10% increase in underlying commodity prices
Asset (Liability)
    
24
      
82
      
(20
)
Fair value assuming 10% decrease in underlying commodity prices
Asset (Liability)
    
98
      
28
      
(72
)

Crude oil marketing portfolio
 
  
Portfolio Fair Value at
  
Scenario
Resulting
Classification
December 31,
2024
  
March 31,
2025
  
April 15,
2025
  
Fair value assuming no change in underlying commodity prices
Asset (Liability)
  
$
19
    
$
9
    
$
139
  
Fair value assuming 10% increase in underlying commodity prices
Asset (Liability)
    
(79
)
    
(103
)
    
45
  
Fair value assuming 10% decrease in underlying commodity prices
Asset (Liability)
    
117
      
121
      
233
  

Commercial energy derivative portfolio
 
  
Portfolio Fair Value at
  
Scenario
Resulting
Classification
December 31,
2024
  
March 31,
2025
  
April 15,
2025
  
Fair value assuming no change in underlying commodity prices
Asset (Liability)
  
$
(3
)
  
$
12
    
$
6
  
Fair value assuming 10% increase in underlying commodity prices
Asset (Liability)
    
7
      
22
      
15
  
Fair value assuming 10% decrease in underlying commodity prices
Asset (Liability)
    
(13
)
    
2
      
(3
)

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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.

At March 31, 2025, our interest rate hedging portfolio consisted of 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.  For a summary of our treasury lock portfolio, 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 table shows the effect of hypothetical price movements on the estimated fair value of our treasury lock portfolio at the dates indicated (dollars in millions).
 
  
Portfolio Fair Value at
  
Scenario
Resulting
Classification
December 31,
2024 (1)
  
March 31,
2025
  
April 15,
2025 (2)
  
Fair value assuming no change in underlying interest rates
Asset (Liability)
  
$
–
    
$
2
    
$
7
  
Fair value assuming 10% increase in underlying interest rates
Asset (Liability)
    
–
      
2
      
7
  
Fair value assuming 10% decrease in underlying interest rates
Asset (Liability)
    
–
      
2
      
7
  

(1)
We did not have any treasury locks outstanding as of December 31, 2024.
(2)
Includes treasury lock transactions entered into in April 2025.


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 first 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 August 2022, we received two Notices of Enforcement from the Texas Commission on Environmental Quality for alleged exceedances of air permit emission limits at our PDH 1 and iBDH facilities in Texas.

•
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 quarter of 2025 of 20,965 preferred units.  With the exception of 95 preferred units distributed to an unaffiliated third party in the first quarter of 2025, all of the PIK distributions made during 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 first quarter of 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 first quarter of 2025.

Issuer Purchases of Equity Securities

The following table summarizes our equity repurchase activity during the first 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)
                        
   January 2025
    
–
    
$
–
      
–
    
$
862,646
  
   February 2025
    
860,198
    
$
33.12
      
860,198
    
$
834,153
  
   March 2025
    
943,017
    
$
33.41
      
943,017
    
$
802,646
  
Vesting of phantom unit awards:
                                
   February 2025 (2)
    
2,335,787
    
$
33.72
      
n/a
      
n/a
  
   March 2025 (3)
    
2,790
    
$
33.42
      
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.  Units repurchased under this program are cancelled immediately upon acquisition.
(2)
Of the 7,318,493 phantom unit awards that vested in February 2025 and converted to common units, 2,335,787 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 9,574 phantom unit awards that vested in March 2025 and converted to common units, 2,790 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 March 31, 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
2.2
2.3
2.4
2.5
2.6
2.7
2.8
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2.9
2.10
2.11
2.12
2.13
2.14
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
4.1
4.2
4.3

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4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
 
4.13
4.14
4.15
4.16

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4.17
4.18
4.19
4.20
4.21
4.22
4.23
4.24
4.25
4.26
4.27
4.28
4.29

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4.30
4.31
4.32
4.33
4.34
4.35
4.36
4.37
4.38
4.39
4.40
4.41
4.42
4.43
4.44
4.45

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4.46
4.47
4.48
4.49
4.50
4.51
4.52
4.53
4.54
4.55
4.56
4.57
4.58
4.59
4.60
4.61
4.62
4.63

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4.64
4.65
4.66
4.67
4.68
4.69
4.70
4.71
4.72
4.73
4.74
4.75
4.76
4.77
10.1
10.2
10.3

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10.4
10.5
22.1#
31.1#
31.2#
31.3#
32.1#
32.2#
32.3#
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 May 7, 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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