Enterprise Products Partners LP

08/11/2024 | Press release | Distributed by Public on 08/11/2024 15:09

Quarterly Report for Quarter Ending September 30, 2024 (Form 10-Q)


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2024

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 2,167,574,966 common units of Enterprise Products Partners L.P. outstanding at the close of business on October 31, 2024.

Table of Contents

ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS

Page No.
PART I. FINANCIAL INFORMATION.
Item 1.
Financial Statements.
Unaudited Condensed Consolidated Balance Sheets
2
Unaudited Condensed Statements of Consolidated Operations
3
Unaudited Condensed Statements of Consolidated Comprehensive Income
4
Unaudited Condensed Statements of Consolidated Cash Flows
5
Unaudited Condensed Statements of Consolidated Equity
6
Notes to Unaudited Condensed Consolidated Financial Statements:
1. Partnership Organization and Operations
9
2. Summary of Significant Accounting Policies
10
3. Inventories
10
4. Property, Plant and Equipment
11
5. Investments in Unconsolidated Affiliates
12
6. Intangible Assets and Goodwill
13
7. Debt Obligations
14
8. Capital Accounts
17
9. Revenues
20
10. Business Segments and Related Information
22
11. Earnings Per Unit
26
12. Equity-Based Awards
26
13. Hedging Activities and Fair Value Measurements
27
14. Related Party Transactions
34
15. Income Taxes
35
16. Commitments and Contingent Liabilities
37
17. Supplemental Cash Flow Information
38
18. Subsequent Event
38
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations.
39
Item 3.
Quantitative and Qualitative Disclosures About Market Risk.
66
Item 4.
Controls and Procedures.
68
PART II. OTHER INFORMATION.
Item 1.
Legal Proceedings.
69
Item 1A.
Risk Factors.
69
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds.
70
Item 3.
Defaults Upon Senior Securities.
71
Item 4.
Mine Safety Disclosures.
71
Item 5.
Other Information.
71
Item 6.
Exhibits.
71
Signatures
80

1

Table of Contents


PART I. FINANCIAL INFORMATION.

ITEM 1. FINANCIAL STATEMENTS.

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

September 30,
2024
December 31,
2023
ASSETS
Current assets:
Cash and cash equivalents
$
1,434
$
180
Restricted cash
239
140
Accounts receivable - trade, net of allowance for credit losses
of $38 at September 30, 2024 and $35 at December 31, 2023
8,197
7,765
Accounts receivable - related parties
5
7
Inventories (see Note 3)
3,319
3,352
Derivative assets (see Note 13)
626
347
Prepaid and other current assets
565
457
Total current assets
14,385
12,248
Property, plant and equipment, net (see Note 4)
48,099
45,804
Investments in unconsolidated affiliates (see Note 5)
2,268
2,330
Intangible assets, net (see Note 6)
3,619
3,770
Goodwill (see Note 6)
5,608
5,608
Other assets
1,083
1,222
Total assets
$
75,062
$
70,982
LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt (see Note 7)
$
1,149
$
1,300
Accounts payable - trade
1,203
1,195
Accounts payable - related parties
137
199
Accrued product payables
9,219
8,911
Accrued interest
270
455
Derivative liabilities (see Note 13)
616
396
Other current liabilities
810
675
Total current liabilities
13,404
13,131
Long-term debt (see Note 7)
30,756
27,448
Deferred tax liabilities (see Note 15)
634
611
Other long-term liabilities
1,060
984
Commitments and contingent liabilities (see Note 16)
Redeemable preferred limited partner interests: (see Note 8)
Series A cumulative convertible preferred units ("preferred units")
(50,594units outstanding at September 30, 2024and 50,412units outstanding at
December 31, 2023)
50
49
Equity:(see Note 8)
Partners' equity:
Common limited partner interests (2,167,752,040units issued and outstanding at
September 30, 2024, 2,168,245,238units issued and outstanding at December 31, 2023)
29,343
28,663
Treasury units, at cost
(1,297
)
(1,297
)
Accumulated other comprehensive income
303
307
Total partners' equity
28,349
27,673
Noncontrolling interests in consolidated subsidiaries
809
1,086
Total equity
29,158
28,759
Total liabilities, preferred units, and equity
$
75,062
$
70,982

See Notes to Unaudited Condensed Consolidated Financial Statements.

2

Table of Contents


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

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Revenues:
Third parties
$
13,759
$
11,980
$
41,976
$
35,049
Related parties
16
18
42
44
Total revenues (see Note 9)
13,775
11,998
42,018
35,093
Costs and expenses:
Operating costs and expenses:
Third party and other costs
11,661
10,009
35,672
29,246
Related parties
372
357
1,097
1,014
Total operating costs and expenses
12,033
10,366
36,769
30,260
General and administrative costs:
Third party and other costs
19
18
63
59
Related parties
42
41
121
113
Total general and administrative costs
61
59
184
172
Total costs and expenses (see Note 10)
12,094
10,425
36,953
30,432
Equity in income of unconsolidated affiliates
99
122
302
347
Operating income
1,780
1,695
5,367
5,008
Other income (expense):
Interest expense
(343
)
(328
)
(1,006
)
(944
)
Interest income
14
5
31
22
Other, net
-
-
-
14
Total other expense, net
(329
)
(323
)
(975
)
(908
)
Income before income taxes
1,451
1,372
4,392
4,100
Provision for income taxes (see Note 15)
(19
)
(22
)
(55
)
(45
)
Net income
1,432
1,350
4,337
4,055
Net income attributable to noncontrolling interests
(14
)
(31
)
(56
)
(91
)
Net income attributable to preferred units
(1
)
(1
)
(3
)
(3
)
Net income attributable to common unitholders
$
1,417
$
1,318
$
4,278
$
3,961
Earnings per unit:(see Note 11)
Basic earnings per common unit
$
0.65
$
0.60
$
1.95
$
1.81
Diluted earnings per common unit
$
0.65
$
0.60
$
1.95
$
1.81
















See Notes to Unaudited Condensed Consolidated Financial Statements.
3

Table of Contents


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

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Net income
$
1,432
$
1,350
$
4,337
$
4,055
Other comprehensive income (loss):
Cash flow hedges: (see Note 13)
Commodity hedging derivative instruments:
Changes in fair value of cash flow hedges
210
(96
)
127
(139
)
Reclassification of losses (gains)to net income
(77
)
33
(124
)
(15
)
Interest rate hedging derivative instruments:
Changes in fair value of cash flow hedges
(4
)
-
(2
)
(5
)
Reclassification of gainsto net income
(2
)
(2
)
(5
)
(3
)
Total cash flow hedges
127
(65
)
(4
)
(162
)
Total other comprehensive income (loss)
127
(65
)
(4
)
(162
)
Comprehensive income
1,559
1,285
4,333
3,893
Comprehensive income attributable to noncontrolling interests
(14
)
(31
)
(56
)
(91
)
Comprehensive income attributable to preferred units
(1
)
(1
)
(3
)
(3
)
Comprehensive income attributable to common unitholders
$
1,544
$
1,253
$
4,274
$
3,799




























See Notes to Unaudited Condensed Consolidated Financial Statements.

4

Table of Contents


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

For the Nine Months
Ended September 30,
2024
2023
Operating activities:
Net income
$
4,337
$
4,055
Reconciliation of net income to net cash flow provided by operating activities:
Depreciation and accretion
1,479
1,388
Amortization of intangible assets
155
148
Amortization of major maintenance costs for reaction-based plants
42
48
Other amortization expense
169
158
Impairment of assets other than goodwill
51
28
Equity in income of unconsolidated affiliates
(302
)
(347
)
Distributions received from unconsolidated affiliates attributable to earnings
303
330
Net losses (gains) attributable to asset sales and related matters
5
(4
)
Deferred income tax expense
23
5
Change in fair market value of derivative instruments
(11
)
48
Non-cash expense related to long-term operating leases (see Note 16)
68
51
Net effect of changes in operating accounts (see Note 17)
(563
)
(706
)
Other operating activities
1
1
Net cash flow provided by operating activities
5,757
5,203
Investing activities:
Capital expenditures
(3,485
)
(2,254
)
Investments in unconsolidated affiliates
-
(2
)
Distributions received from unconsolidated affiliates attributable to the return of capital
64
37
Proceeds from asset sales and other matters
11
7
Other investing activities
(23
)
(8
)
Net cash flow used in investing activities
(3,433
)
(2,220
)
Financing activities:
Borrowings under debt agreements
52,456
57,685
Repayments of debt
(49,271
)
(57,062
)
Debt issuance costs
(44
)
(17
)
Monetization of interest rate derivative instruments
(33
)
21
Cash distributions paid to common unitholders (see Note 8)
(3,374
)
(3,215
)
Cash payments made in connection with distribution equivalent rights
(32
)
(29
)
Cash distributions paid to noncontrolling interests
(84
)
(121
)
Cash contributions from noncontrolling interests
33
25
Repurchase of common units under 2019 Buyback Program
(156
)
(92
)
Acquisition of noncontrolling interests
(400
)
(10
)
Other financing activities
(66
)
(60
)
Net cash flow used in financing activities
(971
)
(2,875
)
Net change in cash and cash equivalents, including restricted cash
1,353
108
Cash and cash equivalents, including restricted cash, at beginning of period
320
206
Cash and cash equivalents, including restricted cash, at end of period
$
1,673
$
314









See Notes to Unaudited Condensed Consolidated Financial Statements.

5

Table of Contents


ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2024
(Dollars in millions)

Partners' Equity
Common
Limited
Partner
Interests
Treasury
Units
Accumulated
Other
Comprehensive
Income (Loss)
Noncontrolling
Interests in
Consolidated
Subsidiaries
Total
For the Three MonthsEnded September 30, 2024:
Balance June 30, 2024
$
29,110
$
(1,297
)
$
176
$
808
$
28,797
Net income
1,417
-
-
14
1,431
Cash distributions paid to common unitholders
(1,139
)
-
-
-
(1,139
)
Cash payments made in connection with
distribution equivalent rights
(11
)
-
-
-
(11
)
Cash distributions paid to noncontrolling interests
-
-
-
(21
)
(21
)
Cash contributions from noncontrolling interests
-
-
-
8
8
Repurchase and cancellation of common units under
2019 Buyback Program
(76
)
-
-
-
(76
)
Amortization of fair value of equity-based awards
44
-
-
-
44
Cash flow hedges
-
-
127
-
127
Other, net
(2
)
-
-
-
(2
)
Balance, September 30, 2024
$
29,343
$
(1,297
)
$
303
$
809
$
29,158



Partners' Equity
Common
Limited
Partner
Interests
Treasury
Units
Accumulated
Other
Comprehensive
Income (Loss)
Noncontrolling
Interests in
Consolidated
Subsidiaries
Total
For the Nine MonthsEnded September 30, 2024:
Balance, December 31, 2023
$
28,663
$
(1,297
)
$
307
$
1,086
$
28,759
Net income
4,278
-
-
56
4,334
Cash distributions paid to common unitholders
(3,374
)
-
-
-
(3,374
)
Cash payments made in connection with
distribution equivalent rights
(32
)
-
-
-
(32
)
Cash distributions paid to noncontrolling interests
-
-
-
(84
)
(84
)
Cash contributions from noncontrolling interests
-
-
-
33
33
Repurchase and cancellation of common units under
2019 Buyback Program
(156
)
-
-
-
(156
)
Amortization of fair value of equity-based awards
144
-
-
-
144
Acquisition of noncontrolling interests
(118
)
-
-
(282
)
(400
)
Cash flow hedges
-
-
(4
)
-
(4
)
Other, net
(62
)
-
-
-
(62
)
Balance, September 30, 2024
$
29,343
$
(1,297
)
$
303
$
809
$
29,158













See Notes to Unaudited Condensed Consolidated Financial Statements. For information regarding Unit History and
Accumulated Other Comprehensive Income (Loss), see Note 8.
6

Table of Contents


ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2023
(Dollars in millions)

Partners' Equity
Common
Limited
Partner
Interests
Treasury
Units
Accumulated
Other
Comprehensive
Income (Loss)
Noncontrolling
Interests in
Consolidated
Subsidiaries
Total
For the Three Months Ended September 30, 2023:
Balance, June 30, 2023
$
27,980
$
(1,297
)
$
268
$
1,071
$
28,022
Net income
1,318
-
-
31
1,349
Cash distributions paid to common unitholders
(1,086
)
-
-
-
(1,086
)
Cash payments made in connection with
distribution equivalent rights
(10
)
-
-
-
(10
)
Cash distributions paid to noncontrolling interests
-
-
-
(40
)
(40
)
Cash contributions from noncontrolling interests
-
-
-
10
10
Amortization of fair value of equity-based awards
43
-
-
-
43
Cash flow hedges
-
-
(65
)
-
(65
)
Other, net
(1
)
-
-
-
(1
)
Balance, September 30, 2023
$
28,244
$
(1,297
)
$
203
$
1,072
$
28,222



Partners' Equity
Common
Limited
Partner
Interests
Treasury
Units
Accumulated
Other
Comprehensive
Income (Loss)
Noncontrolling
Interests in
Consolidated
Subsidiaries
Total
For the Nine Months Ended September 30, 2023:
Balance, December 31, 2022
$
27,555
$
(1,297
)
$
365
$
1,079
$
27,702
Net income
3,961
-
-
91
4,052
Cash distributions paid to common unitholders
(3,215
)
-
-
-
(3,215
)
Cash payments made in connection with
distribution equivalent rights
(29
)
-
-
-
(29
)
Cash distributions paid to noncontrolling interests
-
-
-
(121
)
(121
)
Cash contributions from noncontrolling interests
-
-
-
25
25
Repurchase and cancellation of common units under
2019 Buyback Program
(92
)
-
-
-
(92
)
Amortization of fair value of equity-based awards
128
-
-
-
128
Acquisition of noncontrolling interests
(8
)
-
-
(2
)
(10
)
Cash flow hedges
-
-
(162
)
-
(162
)
Other, net
(56
)
-
-
-
(56
)
Balance, September 30, 2023
$
28,244
$
(1,297
)
$
203
$
1,072
$
28,222












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

7

Table of Contents
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 September 30, 2024.

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.

8

Table of Contents
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 14 for information regarding related party matters.

Our results of operations for the nine months ended September 30, 2024 are not necessarily indicative of results expected for the full year of 2024. 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, 2023 (the "2023 Form 10-K") filed with the SEC on February 28, 2024.




9

Table of Contents
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 2023 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.

September 30,
2024
December 31,
2023
Cash and cash equivalents
$
1,434
$
180
Restricted cash
239
140
Total cash, cash equivalents and restricted cash shown in the
Unaudited Condensed Statements of Consolidated Cash Flows
$
1,673
$
320

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 13 for information regarding our derivative instruments and hedging activities.


Note 3. Inventories

Our inventory amounts by product type were as follows at the dates indicated:

September 30,
2024
December 31,
2023
NGLs
$
2,298
$
2,392
Petrochemicals and refined products
447
536
Crude oil
570
419
Natural gas
4
5
Total
$
3,319
$
3,352

Due to fluctuating commodity prices, we recognize lower of cost or net realizable value adjustments when the carrying value of our available-for-sale inventories exceeds their net realizable value. The following table presents our total cost of sales amounts and lower of cost or net realizable value adjustments for the periods indicated:

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Cost of sales (1)
$
10,387
$
8,786
$
31,976
$
25,796
Lower of cost or net realizable value adjustments
recognized in cost of sales
3
8
5
17

(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
September 30,
2024
December 31,
2023
Plants, pipelines and facilities (1)(5)
3-45
$
60,008
$
57,983
Underground and other storage facilities (2)(6)
5-40
4,607
4,401
Transportation equipment (3)
3-10
265
242
Marine vessels (4)
15-30
939
935
Land
414
411
Construction in progress
3,539
2,245
Subtotal
69,772
66,217
Less accumulated depreciation
21,877
20,462
Subtotal property, plant and equipment, net
47,895
45,755
Capitalized major maintenance costs for reaction-based
plants, net of accumulated amortization (7)
204
49
Property, plant and equipment, net
$
48,099
$
45,804

(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 3.6years.

Property, plant and equipment at September 30, 2024 and December 31, 2023 includes $135 million and $109 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, 2023:

ARO liability balance, December 31, 2023
$
225
Liabilities incurred (1)
-
Revisions in estimated cash flows (2)
30
Liabilities settled (3)
(2
)
Accretion expense (4)
8
ARO liability balance, September 30, 2024
$
261

(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 $261million total ARO liability recorded at September 30, 2024, $6million was reflected as a current liability and $255million 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 September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Depreciation expense (1)
$
495
$
476
$
1,471
$
1,379
Capitalized interest (2)
31
17
82
86

(1)
Depreciation expense is a component of "Costs and expenses" as presented on our Unaudited Condensed Statements of Consolidated Operations.
(2)
We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset's estimated useful life as a component of depreciation expense. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise.


Note 5. Investments in Unconsolidated Affiliates

The following table presents our investments in unconsolidated affiliates by business segment at the dates indicated. We account for these investments using the equity method.

September 30,
2024
December 31,
2023
NGL Pipelines & Services
$
597
$
612
Crude Oil Pipelines & Services
1,634
1,681
Natural Gas Pipelines & Services
34
33
Petrochemical & Refined Products Services
3
4
Total
$
2,268
$
2,330

The following table presents our equity in income of unconsolidated affiliates by business segment for the periods indicated:

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
NGL Pipelines & Services
$
27
$
32
$
84
$
101
Crude Oil Pipelines & Services
70
89
212
241
Natural Gas Pipelines & Services
2
1
5
4
Petrochemical & Refined Products Services
-
-
1
1
Total
$
99
$
122
$
302
$
347


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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:

September 30, 2024
December 31, 2023
Gross
Value
Accumulated
Amortization
Carrying
Value
Gross
Value
Accumulated
Amortization
Carrying
Value
NGL Pipelines & Services:
Customer relationship intangibles
$
449
$
(273
)
$
176
$
449
$
(263
)
$
186
Contract-based intangibles
754
(133
)
621
752
(110
)
642
Segment total
1,203
(406
)
797
1,201
(373
)
828
Crude Oil Pipelines & Services:
Customer relationship intangibles
2,195
(606
)
1,589
2,195
(530
)
1,665
Contract-based intangibles
283
(277
)
6
283
(275
)
8
Segment total
2,478
(883
)
1,595
2,478
(805
)
1,673
Natural Gas Pipelines & Services:
Customer relationship intangibles
1,351
(653
)
698
1,351
(625
)
726
Contract-based intangibles
643
(220
)
423
641
(209
)
432
Segment total
1,994
(873
)
1,121
1,992
(834
)
1,158
Petrochemical & Refined Products Services:
Customer relationship intangibles
181
(90
)
91
181
(86
)
95
Contract-based intangibles
45
(30
)
15
45
(29
)
16
Segment total
226
(120
)
106
226
(115
)
111
Total intangible assets
$
5,901
$
(2,282
)
$
3,619
$
5,897
$
(2,127
)
$
3,770

The following table presents the amortization expense of our intangible assets by business segment for the periods indicated:

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
NGL Pipelines & Services
$
12
$
10
$
33
$
29
Crude Oil Pipelines & Services
27
28
78
76
Natural Gas Pipelines & Services
13
12
39
37
Petrochemical & Refined Products Services
2
2
5
6
Total
$
54
$
52
$
155
$
148

The following table presents our forecast of amortization expense associated with existing intangible assets for the periods indicated:

Remainder
of 2024
2025
2026
2027
2028
$
53
$
209
$
203
$
185
$
181

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 2023 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:

September 30,
2024
December 31,
2023
EPO senior debt obligations:
Commercial Paper Notes, variable-rates
$
-
$
450
Senior Notes JJ, 3.90% fixed-rate, due February 2024
-
850
Senior Notes MM, 3.75% fixed-rate, due February 2025
1,150
1,150
March 2024 $1.5 Billion 364-Day Revolving Credit Agreement, variable-rate, due March 2025 (1)
-
-
Senior Notes FFF, 5.05% fixed-rate, due January 2026
750
750
Senior Notes PP, 3.70% fixed-rate, due February 2026
875
875
Senior Notes HHH, 4.60% fixed-rate, due January 2027
1,000
-
Senior Notes SS, 3.95% fixed-rate, due February 2027
575
575
March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement, variable-rate, due March 2028 (2)
-
-
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
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
-
Senior Notes H, 6.65% fixed-rate, due October 2034
350
350
Senior Notes JJJ 4.95% fixed-rate, due February 2035
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
-
Senior Notes CCC, 3.95% fixed-rate, due January 2060
1,000
1,000
Total principal amount of senior debt obligations
29,925
26,725
EPO Junior Subordinated Notes C, variable-rate, due June 2067(3)(7)
232
232
EPO Junior Subordinated Notes D, variable-rate, due August 2077(4)(7)
350
350
EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077(5)(7)
1,000
1,000
EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078(6)(7)
700
700
TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 (3)(7)
14
14
Total principal amount of senior and junior debt obligations
32,221
29,021
Other, non-principal amounts
(316
)
(273
)
Less current maturities of debt
(1,149
)
(1,300
)
Total long-term debt
$
30,756
$
27,448

(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%.
(7)
Effective July 1, 2023 and in accordance with the Adjustable Interest Rate (LIBOR) Act, all series of our junior subordinated notes subject to a variable interest rate replaced the 3-month London Interbank Offered Rate ("LIBOR") with 3-month CME Term SOFR plus a 0.26161% tenor spread adjustment.
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

References to "TEPPCO" mean TEPPCO Partners, L.P. prior to its merger with one of our wholly owned subsidiaries in October 2009.

Variable Interest Rates

The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the nine months ended September 30, 2024:

Range of Interest
Rates Paid
Weighted-Average
Interest Rate Paid
Commercial Paper Notes
5.45% to 5.50%
5.46%
EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes
8.06% to 8.42%
8.35%
EPO Junior Subordinated Notes D
8.34% to 8.64%
8.55%

Amounts borrowed under EPO's March 2024 $1.5 Billion 364-Day Revolving Credit Agreement and March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement bear interest, at EPO's election, equal to: (i) SOFR, plus an additional variable spread; or (ii) an alternate base rate, which is the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 0.5%, or (c) Adjusted Term SOFR, for an interest period of one month in effect on such day plus 1%, and a variable spread. The applicable spreads are determined based on EPO's debt ratings.

Scheduled Maturities of Debt

The following table presents the scheduled maturities of principal amounts of EPO's consolidated debt obligations at September 30, 2024 for the next five years, and in total thereafter:

Scheduled Maturities of Debt
Total
Remainder
of 2024
2025
2026
2027
2028
Thereafter
Senior Notes
$
29,925
$
-
$
1,150
$
1,625
$
1,575
$
1,000
$
24,575
Junior Subordinated Notes
2,296
-
-
-
-
-
2,296
Total
$
32,221
$
-
$
1,150
$
1,625
$
1,575
$
1,000
$
26,871

March 2024 $1.5 Billion 364-Day Revolving Credit Agreement

In March 2024, EPO entered into a new 364-Day Revolving Credit Agreement (the "March 2024 $1.5 Billion 364-Day Revolving Credit Agreement") that replaced its prior 364-day revolving credit agreement. There were no principal amounts outstanding under the prior 364-day revolving credit agreement when it was replaced by the March 2024 $1.5 Billion 364-Day Revolving Credit Agreement. As of September 30, 2024, there were no principal amounts outstanding under the March 2024 $1.5 Billion 364-Day Revolving Credit Agreement.

Under the terms of the March 2024 $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 2024 $1.5 Billion 364-Day Revolving Credit Agreement matures in March 2025. 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 2026. Borrowings under the March 2024 $1.5 Billion 364-Day Revolving Credit Agreement may be used for working capital, capital expenditures, acquisitions and general company purposes.

The March 2024 $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 2024 $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 2024 $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

Issuance of $2.0 Billion of Senior Notes in January 2024

In January 2024, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of senior notes due January 2027 ("Senior Notes HHH") and (ii) $1.0 billion principal amount of senior notes due January 2034 ("Senior Notes III"). Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all of our $850million principal amount of 3.90%Senior Notes JJ at their maturity in February 2024 and amounts outstanding under our commercial paper program).

Senior Notes HHH were issued at 99.897% of their principal amount and have a fixed interest rate of 4.60% per year. Senior Notes III were issued at 99.705% of their principal amount and have a fixed interest rate of 4.85% per year. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

Issuance of $2.5 Billion of Senior Notes in August 2024

In August 2024, EPO issued $2.5 billion aggregate principal amount of senior notes comprised of (i) $1.1 billion principal amount of senior notes due February 2035 ("Senior Notes JJJ") and (ii) $1.4 billion principal amount of senior notes due February 2055 ("Senior Notes KKK"). Net proceeds from this offering will be used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all or a portion of our $1.15billion principal amount of 3.75%Senior Notes MM at their maturity in February 2025).

Senior Notes JJJ were issued at 99.400% of their principal amount and have a fixed interest rate of 4.95% per year. Senior Notes KKK were issued at 99.663% of their principal amount and have a fixed interest rate of 5.55% per year. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

Letters of Credit

At September 30, 2024, 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 September 30, 2024.

Parent-Subsidiary Guarantor Relationships

The Partnership acts as guarantor of the consolidated debt obligations of EPO, with the exception of the remaining debt obligations of TEPPCO. If EPO were to default on any of its guaranteed debt, the Partnership would be responsible for full and unconditional repayment of such obligations.


16

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

Note 8. Capital Accounts

Common Limited Partner Interests

The following table summarizes changes in the number of our common units outstanding since December 31, 2023:

Common units outstanding at December 31, 2023
2,168,245,238
Common unit repurchases under 2019 Buyback Program
(1,386,835
)
Common units issued in connection with the vesting of phantom unit awards, net
4,679,377
Other
20,574
Common units outstanding at March 31, 2024
2,171,558,354
Common unit repurchases under 2019 Buyback Program
(1,419,581
)
Common units issued in connection with the vesting of phantom unit awards, net
162,867
Common units outstanding at June 30, 2024
2,170,301,640
Common unit repurchases under 2019 Buyback Program
(2,646,351
)
Common units issued in connection with the vesting of phantom unit awards, net
96,751
Common units outstanding at September 30, 2024
2,167,752,040

Registration Statements
We have a universal shelf registration statement (the "2021 Shelf") 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. The 2021 Shelf will expire in November 2024, at which time we expect to file a replacement universal shelf registration statement.

In addition, the Partnership has a registration statement on file with the SEC covering the issuance of up to $2.5billion of its common units in amounts, at prices and on terms based on market conditions and other factors at the time of such offerings (referred to as the Partnership's at-the-market ("ATM") program). The Partnership did not issue any common units under its ATM program during the nine months ended September 30, 2024. The Partnership's capacity to issue additional common units under the ATM program remains at $2.5 billion as of September 30, 2024.

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

Common Unit Repurchases Under 2019 Buyback Program
In January 2019, we announced that the Board had approved a $2.0 billion multi-year unit buyback program (the "2019 Buyback Program"), which provides the Partnership with an additional method to return capital to investors. The 2019 Buyback Program authorizes the Partnership to repurchase its common units from time to time, including through open market purchases and negotiated transactions. No time limit has been set for completion of the program, and it may be suspended or discontinued at any time.

During the three and nine months ended September 30, 2024, the Partnership repurchased 2,646,351and 5,452,767common units, respectively, under the 2019 Buyback Program through open market purchases. The total cost of these repurchases, including commissions and fees, was $76million and $156million, respectively. The Partnership elected not to repurchase common units during the three months ended September 30, 2023. During the nine months ended September 30, 2023, the Partnership repurchased 3,592,710common units under the 2019 Buyback Program through open market purchases. The total cost of these repurchases, including commissions and fees, was $92million. Common units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition. At September 30, 2024, the remaining available capacity under the 2019 Buyback Program was $926 million.

Common Units Issued in Connection With the Vesting of Phantom Unit Awards
After taking into account tax withholding requirements, the Partnership issued 4,938,995new common units to employees in connection with the vesting of phantom unit awardsduring the nine months ended September 30, 2024. See Note 12 for information regarding our phantom unit awards.
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Common Units Delivered Under DRIP and EUPP
The Partnership has registration statements on file with the SEC in connection with its distribution reinvestment plan ("DRIP") and employee unit purchase plan ("EUPP"). In July 2019, the Partnership announced that, beginning with the quarterly distribution payment paid in August 2019, it would use common units purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP. This election is subject to change in future quarters depending on the Partnership's need for equity capital.

During the nine months ended September 30, 2024, agents of the Partnership purchased 4,971,186 common units on the open market and delivered them to participants in the DRIP and EUPP. Apart from $3 million attributable to the plan discount available to all participants in the EUPP, the funds used to effect these purchases were sourced from the DRIP and EUPP participants. No other Partnership funds were used to satisfy these obligations. We plan to use open market purchases to satisfy DRIP and EUPP reinvestments in connection with the distribution expected to be paid on November 14, 2024.

Preferred Units

The following table summarizes changes in the number of our Series A Cumulative Convertible Preferred Units ("preferred units") outstanding since December 31, 2023.

Preferred units outstanding at December 31, 2023and March 31, 2024
50,412
Paid in-kind distribution to third party
90
Preferred units outstanding at June 30, 2024
50,502
Paid in-kind distribution to third party
92
Preferred units outstanding at September 30, 2024
50,594

We present the capital accounts attributable to our preferred unitholders as mezzanine equity on our consolidated balance sheets since the terms of the preferred units allow for cash redemption by such unitholders in the event of a Change of Control (as defined in our partnership agreement), without regard to the likelihood of such an event.

During the nine months ended September 30, 2024, the Partnership made quarterly cash distributions to its preferred unitholders of $3 million and paid-in-kind distributions of 182 new preferred units valued at less than $1 million.

Accumulated Other Comprehensive Income (Loss)

The following tables present the components of accumulated other comprehensive income (loss) as reported on our Unaudited Condensed Consolidated Balance Sheets at the dates indicated:

Cash Flow Hedges
Commodity
Derivative
Instruments
Interest Rate
Derivative
Instruments
Other
Total
Accumulated Other Comprehensive Income (Loss), December 31, 2023
$
154
$
151
$
2
$
307
Other comprehensive income (loss) for period, before reclassifications
127
(2
)
-
125
Reclassification of losses (gains) to net income during period
(124
)
(5
)
-
(129
)
Total other comprehensive income (loss) for period
3
(7
)
-
(4
)
Accumulated Other Comprehensive Income (Loss), September 30, 2024
$
157
$
144
$
2
$
303

Cash Flow Hedges
Commodity
Derivative
Instruments
Interest Rate
Derivative
Instruments
Other
Total
Accumulated Other Comprehensive Income (Loss), December 31, 2022
$
171
$
192
$
2
$
365
Other comprehensive income (loss) for period, before reclassifications
(139
)
(5
)
-
(144
)
Reclassification of losses (gains) to net income during period
(15
)
(3
)
-
(18
)
Total other comprehensive income (loss) for period
(154
)
(8
)
-
(162
)
Accumulated Other Comprehensive Income (Loss), September 30, 2023
$
17
$
184
$
2
$
203
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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents reclassifications of losses (gains) out of accumulated other comprehensive income into net income during the periods indicated:

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
Losses (gains) on cash flow hedges:
Location
2024
2023
2024
2023
Interest rate derivatives
Interest expense
$
(2
)
$
(2
)
$
(5
)
$
(3
)
Commodity derivatives
Revenue
(96
)
58
(176
)
7
Commodity derivatives
Operating costs and expenses
19
(25
)
52
(22
)
Total
$
(79
)
$
31
$
(129
)
$
(18
)

For information regarding our interest rate and commodity derivative instruments, see Note 13.

Noncontrolling Interests

On February 16, 2024, we acquired the remaining 20% equity interest in Whitethorn Pipeline Company LLC ("Whitethorn") and remaining 25% equity interest in Enterprise EF78 LLC ("EF78") from affiliates of Western Midstream Partners, LP ("Western Midstream") for total cash consideration of $375 million. We funded the cash consideration using cash on hand and proceeds from the issuance of short-term notes under our commercial paper program. As a result of these transactions, Whitethorn and EF78 are now our wholly owned subsidiaries.

Additionally, on March 27, 2024, we acquired an additional 15% equity interest in Panola Pipeline Company, LLC ("Panola") from an affiliate of Western Midstream for $25 million in cash consideration. We funded the cash consideration using cash on hand. As a result of this transaction, our equity interest in Panola increased to 70%.

Since we had a controlling interest in each of these entities before and after the acquisitions, the increase in our ownership interest in each entity was accounted for as an equity transaction with no gain or loss recognized.

Cash Distributions

On October 2, 2024, we announced that the Board declared a quarterly cash distribution of $0.525per common unit, or $2.10per common unit on an annualized basis, to be paid to the Partnership's common unitholders with respect to the third quarter of 2024. The quarterly distribution is payable on November 14, 2024 to unitholders of record as of the close of business on October 31, 2024. The total amount to be paid is $1.15billion, which includes $11million 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 September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
NGL Pipelines & Services:
Sales of NGLs and related products
$
4,134
$
3,021
$
12,115
$
10,325
Segment midstream services:
Natural gas processing and fractionation
315
344
1,009
944
Transportation
293
286
835
798
Storage and terminals
89
106
277
308
Total segment midstream services
697
736
2,121
2,050
Total NGL Pipelines & Services
4,831
3,757
14,236
12,375
Crude Oil Pipelines & Services:
Sales of crude oil
4,952
5,068
15,672
12,999
Segment midstream services:
Transportation
194
194
577
549
Storage and terminals
105
103
305
302
Total segment midstream services
299
297
882
851
Total Crude Oil Pipelines & Services
5,251
5,365
16,554
13,850
Natural Gas Pipelines & Services:
Sales of natural gas
243
537
987
1,828
Segment midstream services:
Transportation
406
347
1,128
1,046
Total segment midstream services
406
347
1,128
1,046
Total Natural Gas Pipelines & Services
649
884
2,115
2,874
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products
2,751
1,647
8,105
5,052
Segment midstream services:
Fractionation and isomerization
65
94
276
208
Transportation, including marine logistics
157
171
498
486
Storage and terminals
71
80
234
248
Total segment midstream services
293
345
1,008
942
Total Petrochemical & Refined Products Services
3,044
1,992
9,113
5,994
Total consolidated revenues
$
13,775
$
11,998
$
42,018
$
35,093

Substantially all of our revenues are derived from contracts with customers as defined within Accounting Standards Codification ("ASC") 606, Revenue from Contracts with Customers.
20

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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 September 30, 2024:

Contract Asset
Location
Balance
Unbilled revenue (current amount)
Prepaid and other current assets
$
8
Total
$
8

Contract Liability
Location
Balance
Deferred revenue (current amount)
Other current liabilities
$
203
Deferred revenue (noncurrent)
Other long-term liabilities
286
Total
$
489

The following table presents significant changes in our unbilled revenue and deferred revenue balances for the nine months ended September 30, 2024:

Unbilled
Revenue
Deferred
Revenue
Balance at December 31, 2023
$
11
$
519
Amount included in opening balance transferred to other accounts during period (1)
(11
)
(212
)
Amount recorded during period (2)
62
710
Amounts recorded during period transferred to other accounts (1)
(54
)
(522
)
Other changes
-
(6
)
Balance at September 30, 2024
$
8
$
489

(1)
Unbilled revenues are transferred to accounts receivable once we have an unconditional right to consideration from the customer. Deferred revenues are recognized as revenue upon satisfaction of our performance obligation to the customer.
(2)
Unbilled revenue represents revenue that has been recognized upon satisfaction of a performance obligation, but cannot be contractually invoiced (or billed) to the customer at the balance sheet date until a future period. Deferred revenue is recorded when payment is received from a customer prior to our satisfaction of the associated performance obligation.

Remaining Performance Obligations

The following table presents estimated fixed future consideration from revenue contracts that contain minimum volume commitments, deficiency and similar fees and the term of the contracts exceeds one year. These amounts represent the revenues we expect to recognize in future periods from these contracts as of September 30, 2024.

Period
Fixed
Consideration
Three Months Ended December 31, 2024
$
1,030
One Year Ended December 31, 2025
3,822
One Year Ended December 31, 2026
3,513
One Year Ended December 31, 2027
3,241
One Year Ended December 31, 2028
2,820
Thereafter -
10,997
Total
$
25,423


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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 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 co-chief operating decision makers. While these two officers evaluate results in a number of different ways, the business segment structure is the primary basis for which the allocation of resources and financial results are assessed.

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

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. 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.

22

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

The following table presents our measurement of total segment gross operating margin for the periods presented. The GAAP financial measure most directly comparable to total segment gross operating margin is operating income.

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Operating income
$
1,780
$
1,695
$
5,367
$
5,008
Adjustments to reconcile operating income to total segment gross operating margin
(addition or subtraction indicated by sign):
Depreciation, amortization and accretion expense in operating costs and expenses (1)
586
566
1,749
1,644
Asset impairment charges in operating costs and expenses
27
11
51
27
Net losses (gains) attributable to asset sales and related matters in operating costs
and expenses
-
-
5
(4
)
General and administrative costs
61
59
184
172
Non-refundable payments received from shippers attributable to make-up rights (2)
13
12
56
36
Subsequent recognition of revenues attributable to make-up rights (3)
(19
)
(23
)
(30
)
(68
)
Total segment gross operating margin
$
2,448
$
2,320
$
7,382
$
6,815

(1)
Excludes amortization of major maintenance costs for reaction-based plants, which are a component 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.

Gross operating margin by segment is calculated by subtracting segment operating costs and expenses from segment revenues, with both segment totals reflecting the adjustments noted in the preceding table, as applicable, and before the elimination of intercompany transactions. The following table presents gross operating margin by segment for the periods indicated:

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Gross operating margin by segment:
NGL Pipelines & Services
$
1,335
$
1,196
$
4,000
$
3,518
Crude Oil Pipelines & Services
401
432
1,229
1,251
Natural Gas Pipelines & Services
349
239
954
791
Petrochemical & Refined Products Services
363
453
1,199
1,255
Total segment gross operating margin
$
2,448
$
2,320
$
7,382
$
6,815

23

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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Summarized Segment Financial Information

Information by business segment, together with reconciliations to amounts presented on, or included in, our Unaudited Condensed Statements of Consolidated Operations, is presented in the following table:

Reportable Business Segments
NGL
Pipelines
& Services
Crude Oil
Pipelines
& Services
Natural Gas
Pipelines
& Services
Petrochemical
& Refined
Products
Services
Adjustments
and
Eliminations
Consolidated
Total
Revenues from third parties:
Three months ended September 30, 2024
$
4,828
$
5,241
$
646
$
3,044
$
-
$
13,759
Three months ended September 30, 2023
3,754
5,354
880
1,992
-
11,980
Nine months ended September 30, 2024
14,227
16,530
2,106
9,113
-
41,976
Nine months ended September 30, 2023
12,367
13,825
2,863
5,994
-
35,049
Revenues from related parties:
Three months ended September 30, 2024
3
10
3
-
-
16
Three months ended September 30, 2023
3
11
4
-
-
18
Nine months ended September 30, 2024
9
24
9
-
-
42
Nine months ended September 30, 2023
8
25
11
-
-
44
Intersegment and intrasegment revenues:
Three months ended September 30, 2024
11,044
13,678
166
6,944
(31,832
)
-
Three months ended September 30, 2023
12,367
16,343
133
4,307
(33,150
)
-
Nine months ended September 30, 2024
34,157
42,547
481
18,982
(96,167
)
-
Nine months ended September 30, 2023
34,347
41,139
386
13,108
(88,980
)
-
Total revenues:
Three months ended September 30, 2024
15,875
18,929
815
9,988
(31,832
)
13,775
Three months ended September 30, 2023
16,124
21,708
1,017
6,299
(33,150
)
11,998
Nine months ended September 30, 2024
48,393
59,101
2,596
28,095
(96,167
)
42,018
Nine months ended September 30, 2023
46,722
54,989
3,260
19,102
(88,980
)
35,093
Equity in income of unconsolidated affiliates:
Three months ended September 30, 2024
27
70
2
-
-
99
Three months ended September 30, 2023
32
89
1
-
-
122
Nine months ended September 30, 2024
84
212
5
1
-
302
Nine months ended September 30, 2023
101
241
4
1
-
347

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. Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base.

Information by business segment, together with reconciliations to our Unaudited Condensed Consolidated Balance Sheet totals, is presented in the following table:

Reportable Business Segments
NGL
Pipelines
& Services
Crude Oil
Pipelines
& Services
Natural Gas
Pipelines
& Services
Petrochemical
& Refined
Products
Services
Adjustments
and
Eliminations
Consolidated
Total
Property, plant and equipment, net:
(see Note 4)
At September 30, 2024
$
17,784
$
6,374
$
10,256
$
10,146
$
3,539
$
48,099
At December 31, 2023
17,541
6,627
10,019
9,372
2,245
45,804
Investments in unconsolidated affiliates:
(see Note 5)
At September 30, 2024
597
1,634
34
3
-
2,268
At December 31, 2023
612
1,681
33
4
-
2,330
Intangible assets, net:(see Note 6)
At September 30, 2024
797
1,595
1,121
106
-
3,619
At December 31, 2023
828
1,673
1,158
111
-
3,770
Goodwill:(see Note 6)
At September 30, 2024
2,811
1,841
-
956
-
5,608
At December 31, 2023
2,811
1,841
-
956
-
5,608
Segment assets:
At September 30, 2024
21,989
11,444
11,411
11,211
3,539
59,594
At December 31, 2023
21,792
11,822
11,210
10,443
2,245
57,512

24

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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Supplemental Revenue and Expense Information

The following table presents additional information regarding our consolidated revenues and costs and expenses for the periods indicated:

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Consolidated revenues:
NGL Pipelines & Services
$
4,831
$
3,757
$
14,236
$
12,375
Crude Oil Pipelines & Services
5,251
5,365
16,554
13,850
Natural Gas Pipelines & Services
649
884
2,115
2,874
Petrochemical & Refined Products Services
3,044
1,992
9,113
5,994
Total consolidated revenues
$
13,775
$
11,998
$
42,018
$
35,093
Consolidated costs and expenses
Operating costs and expenses:
Cost of sales
$
10,387
$
8,786
$
31,976
$
25,796
Other operating costs and expenses (1)
1,018
986
2,946
2,749
Depreciation, amortization and accretion
601
583
1,791
1,692
Asset impairment charges
27
11
51
27
Net losses (gains) attributable to asset sales and related matters
-
-
5
(4
)
General and administrative costs
61
59
184
172
Total consolidated costs and expenses
$
12,094
$
10,425
$
36,953
$
30,432

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

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

25

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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 September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
BASIC EARNINGS PER COMMON UNIT
Net income attributable to common unitholders
$
1,417
$
1,318
$
4,278
$
3,961
Earnings allocated to phantom unit awards (1)
(14
)
(12
)
(41
)
(36
)
Net income allocated to common unitholders
$
1,403
$
1,306
$
4,237
$
3,925
Basic weighted-average number of common units outstanding
2,169
2,172
2,170
2,173
Basic earnings per common unit
$
0.65
$
0.60
$
1.95
$
1.81
DILUTED EARNINGS PER COMMON UNIT
Net income attributable to common unitholders
$
1,417
$
1,318
$
4,278
$
3,961
Net income attributable to preferred units
1
1
3
3
Net income attributable to limited partners
$
1,418
$
1,319
$
4,281
$
3,964
Diluted weighted-average number of units outstanding:
Distribution-bearing common units
2,169
2,172
2,170
2,173
Phantom units (2)
21
20
21
20
Preferred units (2)
2
2
2
2
Total
2,192
2,194
2,193
2,195
Diluted earnings per common unit
$
0.65
$
0.60
$
1.95
$
1.81

(1)
Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 12 for information regarding 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 12 for information regarding phantom unit awards. See Note 8 for information regarding preferred units.


Note 12. Equity-Based Awards

An allocated portion of the fair value of EPCO's equity-based awards is charged to us under the ASA. The following table summarizes compensation expense we recognized in connection with equity-based awards for the periods indicated:

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Equity-classified awards:
Phantom unit awards
$
44
$
42
$
135
$
126
Profits interest awards
-
1
10
3
Total
$
44
$
43
$
145
$
129

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.
26

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

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, 2023
19,557,251
$
24.47
Granted (2)
8,871,820
$
26.25
Vested
(7,234,929
)
$
24.50
Forfeited
(458,867
)
$
25.38
Phantom unit awards at September 30, 2024
20,735,275
$
25.20

(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 2024 was $233 million based on a grant date market price of the Partnership's common units ranging from $26.25 to $28.05 per unit. An estimated annual forfeiture rate of 2.0% was applied to these awards.

Each phantom unit award includes a DER, which entitles the participant to nonforfeitable cash payments equal to the product of the number of phantom unit awards outstanding for the participant and the cash distribution per common unit paid by the Partnership to its common unitholders. Cash payments made in connection with DERs are charged to partners' equity when the phantom unit award is expected to result in the issuance of common units; otherwise, such amounts are expensed.

The following table presents supplemental information regarding phantom unit awards for the periods indicated:

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Cash payments made in connection with DERs
$
11
$
10
$
32
$
29
Total intrinsic value of phantom unit awards that vested during period
3
5
197
181

For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $244 million at September 30, 2024, of which our share of such cost is currently estimated to be $196 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 2.1 years.

Profits Interest Awards

As of January 1, 2024, EPCO had two limited partnerships (referred to as "Employee Partnerships") that served as long-term incentive arrangements for key employees of EPCO by providing them profits interest awards (or Class B limited partner interests) in one or more of the Employee Partnerships.

The Class B limited partner interests of these two Employee Partnerships vested on March 26, 2024 when the closing market price of the Partnership's common units exceeded $29.02per unit. As a result of these vesting events, we recognized an incremental $7 million of non-cash compensation expense in the three months ended March 31, 2024.


Note 13. 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.
27

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

Interest Rate Hedging Activities

We may utilize interest rate swaps, forward-starting swaps, options to enter into forward-starting swaps ("swaptions"), 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.

During the fourth quarter of 2023, we entered into three treasury lock transactions to fix the ten-year treasury rate at a weighted-average rate of approximately 4.48% on an aggregate notional amount of $600 million. In January 2024, we entered into two additional treasury lock transactions to fix the ten-year treasury rate at 3.97% on a notional amount of $400 million and to fix the three-year treasury rate at 4.11% on a notional amount of $750 million. The purpose of these transactions was to hedge the underlying interest rate risk associated with debt issuances that occurred in January 2024 (see Note 7). In January 2024, we terminated these treasury lock transactions simultaneously with our issuance of the three-year and ten-year notes and made total cash payments of $29 million.

In August 2024, we entered into two treasury lock transactions to fix the ten-year treasury rate at 3.98% on a notional amount of $1.0 billion and to fix the thirty-year treasury rate at 4.29% on a notional amount of $1.0 billion. The purpose of these transactions was to hedge the underlying interest rate risk associated with debt issuances that occurred in August 2024 (see Note 7). In August 2024, we terminated these treasury lock transactions simultaneously with our issuance of the ten-year and thirty-year notes and made total cash payments of $4 million.

As cash flow hedges, losses on these derivative instruments are reflected as a component of accumulated other comprehensive income and will be amortized to earnings as a component of interest expense over the full term of each 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 September 30, 2024, 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 September 30, 2024 (volume measures as noted):

Volume (1)
Accounting
Derivative Purpose
Current(2)
Long-Term (2)
Treatment
Derivatives designated as hedging instruments:
Natural gas processing:
Forecasted natural gas purchases for plant thermal reduction (billion cubic feet ("Bcf"))
4.5
n/a
Cash flow hedge
Forecasted sales of natural gas (Bcf)
39.1
34.8
Cash flow hedge
Forecasted sales of NGLs (MMBbls)
2.8
n/a
Cash flow hedge
Octane enhancement:
Forecasted sales of octane enhancement products (MMBbls)
3.2
1.0
Cash flow hedge
Natural gas marketing:
Forecasted purchases of natural gas (Bcf)
0.4
n/a
Cash flow hedge
Natural gas storage inventory management activities (Bcf)
1.1
n/a
Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)
123.7
10.4
Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)
119.3
13.5
Cash flow hedge
Refined products marketing:
Forecasted purchases of refined products (MMBbls)
0.1
n/a
Cash flow hedge
Forecasted sales of refined products (MMBbls)
0.5
n/a
Cash flow hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)
17.1
3.3
Cash flow hedge
Forecasted sales of crude oil (MMBbls)
30.1
8.8
Cash flow hedge
Petrochemical marketing:
Forecasted purchases of petrochemical products (MMBbls)
0.1
n/a
Cash flow hedge
Forecasted sales of petrochemical products (MMBbls)
0.1
n/a
Cash flow hedge
Commercial energy:
Forecasted purchases of power related to asset operations (terawatt hours ("TWh"))
1.5
0.4
Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (3)
27.1
1.8
Mark-to-market
NGL risk management activities (MMBbls) (3)
16.9
24.7
Mark-to-market
Refined products risk management activities (MMBbls) (3)
4.4
n/a
Mark-to-market
Crude oil risk management activities (MMBbls) (3)
136.6
33.3
Mark-to-market
Commercial energy risk management activities (TWh) (3)
n/a
0.1
Mark-to-market

(1)
Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2)
The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2027, January 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 $3 million and $2 million at September 30, 2024 and December 31, 2023, 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
September 30, 2024
December 31, 2023
September 30, 2024
December 31, 2023
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 derivatives
Current
assets
$
-
Current
assets
$
-
Current
liabilities
$
-
Current
liabilities
$
31
Commodity derivatives
Current
assets
$
153
Current
assets
$
118
Current
liabilities
$
152
Current
liabilities
$
136
Commodity derivatives
Other assets
22
Other assets
31
Other liabilities
19
Other liabilities
35
Total commodity derivatives
175
149
171
171
Total derivatives designated as hedging instruments
$
175
$
149
$
171
$
202
Derivatives not designated as hedging instruments
Commodity derivatives
Current
assets
$
473
Current
assets
$
229
Current
liabilities
$
464
Current
liabilities
$
229
Commodity derivatives
Other assets
140
Other assets
72
Other liabilities
141
Other liabilities
71
Total commodity derivatives
613
301
605
300
Total derivatives not designated as hedging instruments
$
613
$
301
$
605
$
300

Certain of our commodity derivative instruments are subject to master netting arrangements or similar agreements. The following tables present our derivative instruments subject to such arrangements at the dates indicated:

Offsetting of Financial Assets and Derivative Assets
Gross
Amounts of
Recognized
Assets
Gross
Amounts
Offset in the
Balance Sheet
Amounts
of Assets
Presented
in the
Balance Sheet
Gross Amounts Not Offset
in the Balance Sheet
Amounts That
Would Have
Been Presented
On Net Basis
Financial
Instruments
Cash
Collateral
Received
Cash
Collateral
Paid
(i)
(ii)
(iii) = (i) - (ii)
(iv)
(v) = (iii) + (iv)
As of September 30, 2024:
Commodity derivatives
$
788
$
-
$
788
$
(775
)
$
(13
)
$
-
$
-
As of December 31, 2023:
Commodity derivatives
$
450
$
-
$
450
$
(450
)
$
-
$
-
$
-


Offsetting of Financial Liabilities and Derivative Liabilities
Gross
Amounts of
Recognized
Liabilities
Gross
Amounts
Offset in the
Balance Sheet
Amounts
of Liabilities
Presented
in the
Balance Sheet
Gross Amounts Not Offset
in the Balance Sheet
Amounts That
Would Have
Been Presented
On Net Basis
Financial
Instruments
Cash
Collateral
Received
Cash
Collateral
Paid
(i)
(ii)
(iii) = (i) - (ii)
(iv)
(v) = (iii) + (iv)
As of September 30, 2024:
Commodity derivatives
$
776
$
-
$
776
$
(775
)
$
-
$
-
$
1
As of December 31, 2023:
Interest rate derivatives
$
31
$
-
$
31
$
-
$
-
$
-
$
31
Commodity derivatives
471
-
471
(450
)
1
(21
)
1
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 September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Commodity derivatives
Revenue
$
1
$
1
$
2
$
5
Total
$
1
$
1
$
2
$
5

Derivatives in Fair Value
Hedging Relationships
Location
Gain (Loss) Recognized in
Income on Hedged Item
For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Commodity derivatives
Revenue
$
-
$
(7
)
$
5
$
(5
)
Total
$
-
$
(7
)
$
5
$
(5
)

The gain (loss) corresponding to the hedge ineffectiveness on the fair value hedges was negligible for all periods presented. The remaining gain (loss) for each period presented is primarily attributable to prompt-to-forward month price differentials that were excluded from the assessment of hedge effectiveness.

The following tables present the effect of our derivative instruments designated as cash flow hedges on our Unaudited Condensed Statements of Consolidated Operations and Unaudited Condensed Statements of Consolidated Comprehensive Income for the periods indicated:

Derivatives in Cash Flow
Hedging Relationships
Change in Value Recognized in
Other Comprehensive Income (Loss) on Derivative
For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Interest rate derivatives
$
(4
)
$
-
$
(2
)
$
(5
)
Commodity derivatives - Revenue (1)
261
(129
)
186
(160
)
Commodity derivatives - Operating costs and expenses (1)
(51
)
33
(59
)
21
Total
$
206
$
(96
)
$
125
$
(144
)

(1)
The fair value of these derivative instruments will be reclassified to their respective locations on the Unaudited Condensed Statement of Consolidated Operations when the forecasted transactions affect earnings.

Derivatives in Cash Flow
Hedging Relationships
Location
Gain (Loss) Reclassified from
Accumulated Other Comprehensive Income (Loss) to Income
For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Interest rate derivatives
Interest expense
$
2
$
2
$
5
$
3
Commodity derivatives
Revenue
96
(58
)
176
(7
)
Commodity derivatives
Operating costs and expenses
(19
)
25
(52
)
22
Total
$
79
$
(31
)
$
129
$
18
31

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

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 $125 million of net gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, with $139 million as an increase in revenue and $14 million as an increase in operating costs and expenses.

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

Derivatives Not Designated
as Hedging Instruments
Location
Gain (Loss) Recognized in
Income on Derivative
For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Commodity derivatives
Revenue
$
(13
)
$
(27
)
$
(5
)
$
190
Commodity derivatives
Operating costs and expenses
(4
)
-
(5
)
-
Total
$
(17
)
$
(27
)
$
(10
)
$
190

The $10 million net loss recognized for the nine months ended September 30, 2024 (as noted in the preceding table) from derivatives not designated as hedging instruments consists of $16 million of net realized losses and $6 million of net unrealized mark-to-market gains attributable to commodity derivatives.

Fair Value Measurements

The following tables set forth, by level within the Level 1, 2 and 3 fair value hierarchy, the carrying values of our financial assets and liabilities at the dates indicated. These assets and liabilities are measured on a recurring basis and are classified based on the lowest level of input used to estimate their fair value. Our assessment of the relative significance of such inputs requires judgment.

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.
32

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

At September 30, 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
$
761
$
344
$
1
$
1,106
Impact of CME Rule 814
(151
)
(166
)
(1
)
(318
)
Total commodity derivatives
610
178
-
788
Total
$
610
$
178
$
-
$
788
Financial liabilities:
Commodity derivatives:
Value before application of CME Rule 814
$
603
$
351
$
14
$
968
Impact of CME Rule 814
(29
)
(149
)
(14
)
(192
)
Total commodity derivatives
574
202
-
776
Total
$
574
$
202
$
-
$
776

At December 31, 2023
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
$
431
$
297
$
-
$
728
Impact of CME Rule 814
(147
)
(131
)
-
(278
)
Total commodity derivatives
284
166
-
450
Total
$
284
$
166
$
-
$
450
Financial liabilities:
Interest rate derivatives:
$
-
$
31
$
-
$
31
Commodity derivatives:
Value before application of CME Rule 814
317
308
-
625
Impact of CME Rule 814
(22
)
(132
)
-
(154
)
Total commodity derivatives
295
176
-
471
Total
$
295
$
207
$
-
$
502

In the aggregate, the fair value of our commodity hedging portfolios at September 30, 2024was a net derivative asset of $138 million prior to the impact of CME Rule 814.

Financial assets and liabilities recorded on the balance sheet at September 30, 2024 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 $30.4 billion and $26.7 billion at September 30, 2024 and December 31, 2023, respectively. The aggregate carrying value of these debt obligations was $31.6 billion and $28.0 billion at September 30, 2024 and December 31, 2023, 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 14. Related Party Transactions

The following table summarizes our related party transactions for the periods indicated:

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Revenues - related parties:
Unconsolidated affiliates
$
16
$
18
$
42
$
44
Costs and expenses - related parties:
EPCO and its privately held affiliates
$
367
$
347
$
1,085
$
992
Unconsolidated affiliates
47
51
133
135
Total
$
414
$
398
$
1,218
$
1,127

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

September 30,
2024
December 31,
2023
Accounts receivable - related parties:
Unconsolidated affiliates
$
5
$
7
Accounts payable - related parties:
EPCO and its privately held affiliates
$
123
$
183
Unconsolidated affiliates
14
16
Total
$
137
$
199

We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties.

Relationship with EPCO and Affiliates

We have an extensive and ongoing relationship with EPCO and its privately held affiliates (including Enterprise GP, our general partner), which are not a part of our consolidated group of companies.

At September 30, 2024, 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
701,927,123 common units
32.4%
34

Table of Contents
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, 62,976,464 have been pledged as security under the separate credit facilities of EPCO and its privately held affiliates at September 30, 2024. These credit facilities contain customary and other events of default, including defaults by us and other affiliates of EPCO. An event of default, followed by a foreclosure on the pledged collateral, could ultimately result in a change in ownership of these units and affect the market price of the Partnership's common units.

The Partnership and Enterprise GP are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are also separate from those of EPCO and its other affiliates. EPCO and its privately held affiliates use cash on hand and cash distributions they receive from us and other investments to fund their other activities and to meet their respective debt obligations, if any. During the nine months ended September 30, 2024 and 2023, we paid EPCO and its privately held affiliates cash distributions totaling $1.1 billion and $1.0 billion, respectively.

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

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Operating costs and expenses
$
323
$
305
$
956
$
873
General and administrative expenses
37
36
111
102
Total costs and expenses
$
360
$
341
$
1,067
$
975

We lease office space from privately held affiliates of EPCO at rental rates that approximate market rates. For the three months ended September 30, 2024and 2023, we recognized $7 million and $3 million, respectively, of related party operating lease expense in connection with these office space leases. For the nine months ended September 30, 2024 and 2023, we recognized $17 million and $10 million, respectively, of related party operating lease expense in connection with these office space leases.


Note 15. Income Taxes

Income taxes are accounted for under the asset-and-liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. We recognize the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs. We did not rely on any uncertain tax positions in recording our income tax-related amounts during the three and nine months ended September 30, 2024and 2023.

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

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Current portion of income tax provision:
Federal
$
(1
)
$
(1
)
$
(1
)
$
(11
)
State
(9
)
(8
)
(31
)
(29
)
Total current portion
(10
)
(9
)
(32
)
(40
)
Deferred portion of income tax provision:
Federal
(4
)
(4
)
(12
)
-
State
(4
)
(9
)
(10
)
(5
)
Foreign
(1
)
-
(1
)
-
Total deferred portion
(9
)
(13
)
(23
)
(5
)
Total provision for income taxes
$
(19
)
$
(22
)
$
(55
)
$
(45
)

35

Table of Contents
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 September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Pre-Tax Net Book Income ("NBI")
$
1,451
$
1,372
$
4,392
$
4,100
Texas Margin Tax (1)
(13
)
(17
)
(40
)
(33
)
State income tax provision, net of federal benefit
(1
)
-
(1
)
(1
)
Federal income tax provision computed by applying
the federal statutory rate to NBI of corporate entities
(4
)
(5
)
(12
)
(11
)
Other
(1
)
-
(2
)
-
Provision for income taxes
$
(19
)
$
(22
)
$
(55
)
$
(45
)
Effective income tax rate
(1.3
)%
(1.6
)%
(1.3
)%
(1.1
)%

(1)
Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.

The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated:

September 30,
December 31,
2024
2023
Deferred tax liabilities:
Attributable to investment in OTA (1)
$
456
$
436
Attributable to property, plant and equipment
148
138
Attributable to investments in other entities
5
4
Other
83
83
Total deferred tax liabilities
692
661
Deferred tax assets:
Net operating loss carryovers (2)
55
46
Temporary differences related to Texas Margin Tax
3
4
Total deferred tax assets
58
50
Total net deferred tax liabilities
$
634
$
611

(1)
Represents the deferred tax liability balance held by our wholly owned subsidiary, OTA Holdings, Inc. ("OTA"), which we acquired in March 2020.
(2)
The loss amount presented as of September 30, 2024 has an indefinite carryover period. All losses are subject to limitations on their utilization.


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

Note 16. Commitments and Contingent Liabilities

Litigation

As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from future legal proceedings. We will vigorously defend the Partnership in litigation matters.

There were no accruals for litigation contingencies at September 30, 2024 and December 31, 2023, 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 $32.2 billion and $29.0 billion at September 30, 2024 and December 31, 2023, 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 lease obligations since those disclosed in the 2023 Form 10-K.

The following table presents information regarding operating leases where we are the lessee at September 30, 2024:

Asset Category
ROU
Asset
Carrying
Value (1)
Lease
Liability
Carrying
Value (2)
Weighted-
Average
Remaining
Term
Weighted-
Average
Discount
Rate (3)
Storage and pipeline facilities
$
191
$
191
8 years
4.5%
Transportation equipment
46
47
4 years
4.8%
Office and warehouse space
172
207
12 years
3.4%
Total
$
409
$
445

(1)
Right of use ("ROU") asset amounts are a component of "Other assets" on our Unaudited Condensed Consolidated Balance Sheet.
(2)
At September 30, 2024, lease liabilities of $95 million and $350 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.

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

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Long-term operating leases:
Fixed lease expense:
Non-cash lease expense (amortization of ROU assets)
$
25
$
18
$
68
$
51
Related accretion expense on lease liability balances
4
4
12
11
Total fixed lease expense
29
22
80
62
Variable lease expense
4
3
12
9
Total long-term operating lease expense
33
25
92
71
Short-term operating leases
32
30
91
82
Total operating lease expense
$
65
$
55
$
183
$
153

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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Cash paid for operating lease liabilities was $28 million and $21 million for the three months ended September 30, 2024 and 2023, respectively. For the nine months ended September 30, 2024 and 2023, cash paid for operating lease liabilities was $78 million and $62 million, respectively.

Operating lease income for each of the three months ended September 30, 2024 and 2023 was $4million. For the nine months ended September 30, 2024and 2023, operating lease income was $11million and $12million, respectively.

Purchase Obligations
We have contractual future product purchase commitments for natural gas, NGLs, crude oil, petrochemicals and refined products representing enforceable and legally binding agreements as of the reporting date. Our product purchase commitments decreased from $11.9 billion at December 31, 2023 to $9.0 billion at September 30, 2024 primarily due to commitments that expired during the year.


Note 17. Supplemental Cash Flow Information

The following table provides information regarding the net effect of changes in our operating accounts and cash payments for interest and income taxes for the periods indicated:

For the Nine Months
Ended September 30,
2024
2023
Decrease (increase) in:
Accounts receivable - trade
$
(426
)
$
36
Accounts receivable - related parties
2
4
Inventories
32
(766
)
Prepaid and other current assets
(96
)
(665
)
Other assets
62
31
Increase (decrease) in:
Accounts payable - trade
(147
)
67
Accounts payable - related parties
(62
)
(84
)
Accrued product payables
305
457
Accrued interest
(185
)
(189
)
Other current liabilities
52
467
Other long-term liabilities
(100
)
(64
)
Net effect of changes in operating accounts
$
(563
)
$
(706
)
Cash payments for interest, net of $82and $86capitalized during the
nine months ended September 30, 2024and 2023, respectively
$
1,180
$
1,123
Cash payments for federal and state income taxes
$
19
$
22

We incurred liabilities for construction in progress that had not been paid at September 30, 2024 and December 31, 2023 of $491 million and $400 million, respectively. Such amounts are not included under the caption "Capital expenditures" on the Unaudited Condensed Statements of Consolidated Cash Flows.


Note 18. Subsequent Event

Acquisition ofPiñon Midstream

In August 2024, we announced that an affiliate of Enterprise entered into a definitive agreement to acquire Piñon Midstream, LLC ("Piñon Midstream") for $950 million in cash consideration. This transaction, which closed October 28, 2024, was funded using cash on hand.

Piñon Midstream's assets include approximately 50 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. Due to the recent nature of this transaction, we have not completed the preliminary allocation of the purchase price.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.

For the Three and Nine Months Ended September 30, 2024 and 2023

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, 2023 (the "2023 Form 10-K"), as filed on February 28, 2024 with the U.S. Securities and Exchange Commission ("SEC"). Our financial statements have been prepared in accordance with generally accepted accounting principles ("GAAP") in the United States ("U.S.").

Cautionary Statement Regarding Forward-Looking Information

This quarterly report on Form 10-Q for the three and nine months ended September 30, 2024 (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 2023 Form 10-K. 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 September 30, 2024.

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 third quarter of 2024 compared to the third quarter of 2023. Likewise, the phrase "period-to-period" means the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023.

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 2023 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 2023 Form 10-K.
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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.

Recent Developments

Enterprise and 1PointFive Sign Agreement to Support Development of Carbon Dioxide Transportation Network for Southeast Texas Sequestration Hub

In October 2024, Enterprise and 1PointFive, a subsidiary of Occidental Petroleum Corporation, announced an agreement to develop a carbon dioxide ("CO2") transportation network to support the Bluebonnet Sequestration Hub that 1PointFive is developing in southeast Texas. Under the transportation services agreement, once 1PointFive provides notice, Enterprise will develop the new pipeline network and provide fee-based transportation service to 1PointFive to transport CO2 emissions captured by third parties at facilities in the vicinity of the Houston Ship Channel to 1PointFive's Bluebonnet Sequestration Hub.

Enterprise Announces Acquisition of Piñon Midstream

In August 2024, we announced that an affiliate of Enterprise entered into a definitive agreement to acquire Piñon Midstream, LLC ("Piñon Midstream") in a debt-free transaction for $950 million in cash consideration (subject to adjustment in accordance with the agreement). Piñon Midstream's assets include approximately 50 miles of natural gas gathering and redelivery pipelines, five 3-stage compressor stations, 270 MMcf/d of hydrogen sulfide and carbon dioxide treating facilities and two high capacity acid gas injection wells. This transaction, which closed October 28, 2024, was funded using cash on hand.

Issuance of $2.5 Billion of Senior Notes in August 2024

In August 2024, EPO issued $2.5 billion aggregate principal amount of senior notes comprised of (i) $1.1 billion principal amount of senior notes due February 2035 ("Senior Notes JJJ") and (ii) $1.4 billion principal amount of senior notes due February 2055 ("Senior Notes KKK"). Net proceeds from this offering will be used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all or a portion of our $1.15 billion principal amount of 3.75% Senior Notes MM at their maturity in February 2025).

Senior Notes JJJ were issued at 99.400% of their principal amount and have a fixed interest rate of 4.95% per year. Senior Notes KKK were issued at 99.663% of their principal amount and have a fixed interest rate of 5.55% per year. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

Enterprise to Expand LPG Export Capacity at EHT

In July 2024, we announced plans to move forward with the construction of a fourth refrigeration train at our Enterprise Hydrocarbon Terminal ("EHT"). The addition of a fourth refrigeration train ("Ref 4"), which is expected to be placed into service by the end of 2026, will increase our propane and butane export capabilities by approximately 300 MBPD. In addition to providing incremental LPG export capacity, Ref 4 will increase the instantaneous loading rates for propane and butane at EHT, while also making additional capacity available for propylene exports.

Enterprise Receives Deepwater Port License for SPOT Project

In April 2024, we received the deepwater port license for the Sea Port Oil Terminal ("SPOT") from the U.S. Department of Transportation's Maritime Administration. The receipt of the deepwater port license is a significant milestone in the development and commercialization of SPOT.

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As planned, SPOT would consist of proposed onshore and offshore facilities, including a fixed platform located approximately 30 nautical miles off the Texas coast in approximately 115 feet of water. SPOT is designed to load Very Large Crude Carriers ("VLCCs") and other crude oil tankers at rates of approximately 85,000 barrels per hour. The platform would be connected to an onshore storage facility with approximately 4.8 MMBbls of capacity in Brazoria County, Texas, by two 36-inch, bi-directional pipelines. The SPOT project includes state-of-the-art pipeline control, vapor recovery and leak detection systems that are designed to minimize emissions. SPOT would provide customers with an efficient export solution that leverages our extensive integrated supply, storage and distribution network.

We continue our efforts to commercialize this project in order to support a final investment decision.

Enterprise to Build Mentone West 2; Mentone 3 and Leonidas Begin Service

In April 2024, we announced plans to further expand our natural gas processing capabilities in the Delaware Basin with construction of a second natural gas processing train at our Mentone West location ("Mentone West 2") in Loving County, Texas. This natural gas processing train, which will have the capacity to process more than 300 MMcf/d of natural gas and extract in excess of 40 MBPD of NGLs, is expected to begin service during the first half of 2026.

Additionally, we placed into service our third natural gas processing train at Mentone in the Delaware Basin ("Mentone 3") and our seventh Midland Basin natural gas processing train ("Leonidas"). Both Mentone 3 and Leonidas are capable of processing over 300 MMcf/d of natural gas and extracting more than 40 MBPD of NGLs. Supported by a combination of long-term producer dedications and minimum volume commitments, Mentone 3 and Leonidas will support Permian Basin producers as they meet growing demand in the U.S. and internationally.

Enterprise Begins Service on TW Products System

In March 2024, we placed into service the first phase of our Texas Western Products System ("TW Products System") and began truck loading operations at our new Permian terminal in Gaines County, Texas. Additionally, we placed into service and began truck loading operations at our Jal and Moriarty Terminals located in New Mexico during the second quarter of 2024 and our Grand Junction Terminal located in Utah in October 2024. On a combined basis, the four terminals offer 1.5 MMBbls of refined products storage capacity and can load up to 63 MBPD.

Enterprise Acquires Equity Interests from Western Midstream

In February 2024, we announced that we had acquired the remaining equity interests in Whitethorn Pipeline Company LLC ("Whitethorn") and Enterprise EF78 LLC ("EF78") from affiliates of Western Midstream Partners, LP ("Western Midstream") for $375 million in total cash consideration. This transaction, which closed on February 16, 2024, was funded using cash on hand and proceeds from the issuance of short-term notes under our commercial paper program.

Additionally, on March 27, 2024, we acquired an additional 15% equity interest in Panola Pipeline Company, LLC ("Panola") from an affiliate of Western Midstream for $25 million in cash consideration. We funded the cash consideration using cash on hand.

Issuance of $2.0 Billion of Senior Notes in January 2024

In January 2024, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of senior notes due January 2027 ("Senior Notes HHH") and (ii) $1.0 billion principal amount of senior notes due January 2034 ("Senior Notes III"). Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all of our $850 million principal amount of 3.90% Senior Notes JJ at their maturity in February 2024 and amounts outstanding under our commercial paper program).

Senior Notes HHH were issued at 99.897% of their principal amount and have a fixed interest rate of 4.60% per year. Senior Notes III were issued at 99.705% of their principal amount and have a fixed interest rate of 4.85% per year. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

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Selected Energy Commodity Price Data

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

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)
2023 by quarter:
1st Quarter
$3.44
$0.25
$0.82
$1.11
$1.16
$1.62
$0.50
$0.22
$0.37
2nd Quarter
$2.09
$0.21
$0.67
$0.78
$0.84
$1.44
$0.40
$0.21
$0.37
3rd Quarter
$2.54
$0.30
$0.68
$0.83
$0.94
$1.55
$0.36
$0.15
$0.40
4th Quarter
$2.88
$0.23
$0.67
$0.91
$1.07
$1.48
$0.46
$0.17
$0.33
2023 Averages
$2.74
$0.25
$0.71
$0.91
$1.00
$1.52
$0.43
$0.19
$0.37
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
2024 Averages
$2.10
$0.18
$0.77
$0.97
$1.16
$1.52
$0.52
$0.22
$0.42

(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 $0.57 per gallon in the third quarter of 2024 versus $0.61 per gallon in the third quarter of 2023. Likewise, the weighted-average indicative market price for NGLs was $0.59 per gallon during the nine months ended September 30, 2024 compared to $0.61 per gallon during the same period in 2023.

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

WTI
Midland
Houston
LLS
Crude Oil,
Crude Oil,
Crude Oil,
Crude Oil,
$/barrel
$/barrel
$/barrel
$/barrel
(1)
(2)
(2)
(3)
2023 by quarter:
1st Quarter
$76.13
$77.50
$77.74
$79.00
2nd Quarter
$73.78
$74.48
$74.68
$75.87
3rd Quarter
$82.26
$83.85
$84.02
$84.72
4th Quarter
$78.32
$79.62
$79.89
$80.93
2023 Averages
$77.62
$78.86
$79.08
$80.13
2024 by quarter:
1st Quarter
$76.96
$78.55
$78.85
$79.75
2nd Quarter
$80.57
$81.73
$82.33
$83.60
3rd Quarter
$75.10
$75.96
$76.51
$77.20
2024 Averages
$77.54
$78.75
$79.23
$80.18

(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.
(3)
Light Louisiana Sweet ("LLS") prices are based on commercial index prices as reported by Platts.
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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 13 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 remain elevated in 2024 compared to recent historical levels. While pandemic-era supply chain disruptions have largely dissipated and measures taken by the U.S. Federal Reserve Bank have helped slow the growth of inflation, the high cost environment that began in 2022 generally remains intact in 2024. However, to the extent that a rising cost environment impacts our results, there are typically offsetting benefits either inherent in our business or that result from other steps we take proactively to reduce the impact of inflation on our net operating results. These benefits include: (1) provisions included in our long-term fee-based revenue contracts that offset cost increases in the form of rate escalations based on positive changes in the U.S. Consumer Price Index, Producer Price Index for Finished Goods or other factors; (2) provisions in other revenue contracts that enable us to pass through higher energy costs to customers in the form of gas, electricity and fuel rebills or surcharges; and (3) higher commodity prices, which generally enhance our results in the form of increased volumetric throughput and demand for our services. Additionally, we take measures to mitigate the impact of cost increases in certain commodities, including a portion of our electricity needs, using fixed-price, term purchase agreements or financial derivatives. For these reasons, the increased cost environment, caused in part by inflation, has not had a material impact on our historical results of operations for the periods presented in this report. However, a significant or prolonged period of high inflation could adversely impact our results if costs were to increase at a rate greater than the increase in the revenues we receive.

See "Capital Investments" within this Part I, Item 2 for a discussion of the impact of inflation on our capital investment decisions.
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Income Statement Highlights

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

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Revenues
$
13,775
$
11,998
$
42,018
$
35,093
Costs and expenses:
Operating costs and expenses:
Cost of sales
10,387
8,786
31,976
25,796
Other operating costs and expenses
1,018
986
2,946
2,749
Depreciation, amortization and accretion expenses
601
583
1,791
1,692
Asset impairment charges
27
11
51
27
Net losses (gains) attributable to asset sales and related matters
−
−
5
(4
)
Total operating costs and expenses
12,033
10,366
36,769
30,260
General and administrative costs
61
59
184
172
Total costs and expenses
12,094
10,425
36,953
30,432
Equity in income of unconsolidated affiliates
99
122
302
347
Operating income
1,780
1,695
5,367
5,008
Other income (expense):
Interest expense
(343
)
(328
)
(1,006
)
(944
)
Other, net
14
5
31
36
Total other expense, net
(329
)
(323
)
(975
)
(908
)
Income before income taxes
1,451
1,372
4,392
4,100
Provision for income taxes
(19
)
(22
)
(55
)
(45
)
Net income
1,432
1,350
4,337
4,055
Net income attributable to noncontrolling interests
(14
)
(31
)
(56
)
(91
)
Net income attributable to preferred units
(1
)
(1
)
(3
)
(3
)
Net income attributable to common unitholders
$
1,417
$
1,318
$
4,278
$
3,961

Revenues

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

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
NGL Pipelines & Services:
Sales of NGLs and related products
$
4,134
$
3,021
$
12,115
$
10,325
Midstream services
697
736
2,121
2,050
Total
4,831
3,757
14,236
12,375
Crude Oil Pipelines & Services:
Sales of crude oil
4,952
5,068
15,672
12,999
Midstream services
299
297
882
851
Total
5,251
5,365
16,554
13,850
Natural Gas Pipelines & Services:
Sales of natural gas
243
537
987
1,828
Midstream services
406
347
1,128
1,046
Total
649
884
2,115
2,874
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products
2,751
1,647
8,105
5,052
Midstream services
293
345
1,008
942
Total
3,044
1,992
9,113
5,994
Total consolidated revenues
$
13,775
$
11,998
$
42,018
$
35,093


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Third Quarter of 2024 Compared to Third Quarter of 2023. Total revenues for the third quarter of 2024 increased $1.8 billion when compared to the third quarter of 2023 primarily due to higher marketing revenues.

Revenues from the marketing of NGLs and petrochemicals and refined products increased a combined $2.2 billion quarter-to-quarter primarily due to higher sales volumes, which accounted for a $1.9 billion increase, and higher average sales prices, which accounted for an additional $267 million increase. Revenues from the marketing of crude oil and natural gas decreased a combined net $408 million quarter-to-quarter primarily due to lower average sales prices, which accounted for a $563 million decrease, partially offset by higher sales volumes, which accounted for a $155 million increase.

Revenues from midstream services for the third quarter of 2024 decreased a net $30 million when compared to the third quarter of 2023. Revenues from our Mont Belvieu area propylene production facilities decreased $29 million quarter-to-quarter primarily due to lower propylene processing revenues as a result of downtime at our PDH 2 facility during the third quarter of 2024. Revenues from our refined products pipelines decreased $21 million quarter-to-quarter primarily due to lower transportation revenues. Revenues from our Morgan's Point export terminals decreased a combined $10 million quarter-to-quarter primarily due to lower loading fee revenues. Lastly, revenues from our natural gas transportation assets increased $36 million quarter-to-quarter primarily due to higher transportation revenues from our Texas Intrastate System.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Total revenues for the nine months ended September 30, 2024 increased $6.9 billion when compared to the nine months ended September 30, 2023 primarily due to higher marketing revenues.

Revenues from the marketing of NGLs, crude oil and petrochemicals and refined products increased a combined $7.5 billion period-to-period primarily due to higher sales volumes, which accounted for a $7.0 billion increase, and higher average sales prices, which accounted for an additional $508 million increase. Revenues from the marketing of natural gas decreased $841 million period-to-period primarily due to lower average sales prices.

Revenues from midstream services for the nine months ended September 30, 2024 increased $250 million when compared to the nine months ended September 30, 2023. Revenues from our natural gas transportation assets increased $77 million period-to-period primarily due to higher transportation revenues from our Texas Intrastate System. Revenues from our natural gas processing facilities increased $72 million period-to-period primarily due to an increase in equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Revenues from our Mont Belvieu area propylene production facilities increased $44 million period-to-period primarily due to higher propylene processing revenues as a result of contributions from our PDH 2 facility, which was placed into service in July 2023. Lastly, revenues from our Midland-to-ECHO System and related business activities increased $30 million period-to-period primarily due to higher demand for transportation services.

Operating costs and expenses

Total operating costs and expenses for the three and nine months ended September 30, 2024 increased $1.7 billion and $6.5 billion, respectively, when compared to the same periods in 2023.

Cost of sales
Third Quarter of 2024 Compared to Third Quarter of 2023. Cost of sales for the third quarter of 2024 increased $1.6 billion when compared to the third quarter of 2023. The cost of sales associated with the marketing of NGLs, crude oil and petrochemicals and refined products increased a combined net $1.7 billion quarter-to-quarter primarily due to higher volumes, which accounted for a $1.9 billion increase, partially offset by lower average purchase prices, which accounted for a $248 million decrease.

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Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Cost of sales for the nine months ended September 30, 2024 increased a net $6.2 billion when compared to the nine months ended September 30, 2023. The cost of sales associated with the marketing of NGLs, crude oil and petrochemicals and refined products increased a combined net $6.3 billion period-to-period primarily due to higher volumes, which accounted for a $6.5 billion increase, partially offset by lower average purchase prices, which accounted for a $168 million decrease. The cost of sales associated with the marketing of natural gas decreased $184 million period-to-period primarily due to lower average purchase prices.

Other operating costs and expenses
Other operating costs and expenses for the third quarter of 2024 increased $32 million when compared to the third quarter in 2023 primarily due to higher maintenance, employee compensation, rental, and other operating costs, which accounted for a $79 million increase, partially offset by lower utility costs, which accounted for a $47 million decrease.

Other operating costs and expenses for the nine months ended September 30, 2024 increased $197 million when compared to the same period in 2023 primarily due to higher maintenance, employee compensation, rental, chemical, and other operating costs, which accounted for a $224 million increase, partially offset by lower utility costs, which accounted for a $27 million decrease.

Depreciation, amortization and accretion expenses
Depreciation, amortization and accretion expense for the three and nine months ended September 30, 2024 increased a combined $18 million and $99 million, respectively, when compared to the same periods in 2023 primarily due to higher depreciation expense on assets placed into full or limited service since the end of the respective periods in 2023.

General and administrative costs

General and administrative costs for the three and nine months ended September 30, 2024 increased $2 million and $12 million, respectively, when compared to the same periods in 2023 primarily due to higher employee compensation costs.

Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for the three and nine months ended September 30, 2024 decreased $23 million and $45 million, respectively, when compared to the same periods in 2023 primarily due to lower earnings from investments in crude oil and NGL pipelines.

Operating income

Operating income for the three and nine months ended September 30, 2024 increased $85 million and $359 million, respectively, when compared to the same periods in 2023 due to the previously described quarter-to-quarter and period-to-period 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 September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Interest charged on debt principal outstanding (1)
$
369
$
341
$
1,073
$
1,014
Impact of interest rate hedging program, including related amortization
(2
)
(2
)
(5
)
(3
)
Interest costs capitalized in connection with construction projects (2)
(31
)
(17
)
(82
)
(86
)
Other
7
6
20
19
Total
$
343
$
328
$
1,006
$
944

(1)
The weighted-average interest rates on debt principal outstanding during the three and nine months ended September 30, 2024 were 4.59% and 4.60%, respectively. The weighted-average interest rate on debt principal outstanding during the three and nine months ended September 30, 2023 were 4.55% and 4.56%, 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 $43 million increase, partially offset by an $8 million decrease as a result of the retirement of $850 million of fixed-rate senior notes in February 2024 and an additional $7 million decrease from a reduction in outstanding commercial paper notes.

Interest charged on debt principal outstanding increased a net $59 million period-to-period. This increase was primarily due to the aforementioned issuance of senior notes, which accounted for an $88 million increase, partially offset by a $29 million decrease as a result of the retirement of $1.25 billion and $850 million of fixed-rate senior notes in March 2023 and February 2024, respectively.

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 three and nine months ended September 30, 2024 decreased $3 million and increased $10 million, respectively, when compared to the same periods in 2023.

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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 September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Gross operating margin by segment:
NGL Pipelines & Services
$
1,335
$
1,196
$
4,000
$
3,518
Crude Oil Pipelines & Services
401
432
1,229
1,251
Natural Gas Pipelines & Services
349
239
954
791
Petrochemical & Refined Products Services
363
453
1,199
1,255
Total segment gross operating margin (1)
2,448
2,320
7,382
6,815
Net adjustment for shipper make-up rights
6
11
(26
)
32
Total gross operating margin (non-GAAP)
$
2,454
$
2,331
$
7,356
$
6,847

(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 September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Operating income
$
1,780
$
1,695
$
5,367
$
5,008
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)
586
566
1,749
1,644
Asset impairment charges in operating costs and expenses
27
11
51
27
Net losses (gains) attributable to asset sales and related matters in operating
costs and expenses
−
−
5
(4
)
General and administrative costs
61
59
184
172
Total gross operating margin (non-GAAP)
$
2,454
$
2,331
$
7,356
$
6,847

(1)
Excludes amortization of major maintenance costs for reaction-based plants, which are a component 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 September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Segment gross operating margin:
Natural gas processing and related NGL marketing activities
$
371
$
293
$
1,115
$
929
NGL pipelines, storage and terminals
716
704
2,166
1,992
NGL fractionation
248
199
719
597
Total
$
1,335
$
1,196
$
4,000
$
3,518
Selected volumetric data:
NGL pipeline transportation volumes (MBPD)
4,223
3,974
4,216
3,965
NGL marine terminal volumes (MBPD)
887
771
886
787
NGL fractionation volumes (MBPD)
1,611
1,519
1,599
1,528
Equity NGL-equivalent production volumes (MBPD) (1)
204
184
202
173
Fee-based natural gas processing volumes (MMcf/d) (2,3)
6,804
5,928
6,561
5,717

(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
Third Quarter of 2024 Compared to Third Quarter of 2023. Gross operating margin from natural gas processing and related NGL marketing activities for the third quarter of 2024 increased $78 million when compared to the third quarter of 2023.

Gross operating margin from our Midland Basin natural gas processing facilities increased $60 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $36 million increase, a 19 MBPD increase in equity NGL-equivalent production volumes, which accounted for a $13 million increase, and higher fee-based natural gas processing volumes,which accounted for an additional $15 million increase. Fee-based natural gas processing volumes at our Midland Basin natural gas processing facilities increased 434 MMcf/d quarter-to-quarter primarily due to contributions from our Poseidon and Leonidas natural gas processing trains, which were placed into service in the third quarter of 2023 and late first quarter of 2024, respectively.

Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $19 million quarter-to-quarter primarily due to higher fee-based natural gas processing volumes, which accounted for a $21 million increase, and higher average processing margins (including the impact of hedging activities), which accounted for an additional $10 million increase, partially offset by lower average processing fees, which accounted for a $6 million decrease. Fee-based natural gas processing volumes at our Delaware Basin natural gas processing facilities increased 547 MMcf/d quarter-to-quarter, primarily due to processing volumes contributed by our Mentone 2 and Mentone 3 natural gas processing trains, which were placed into service in the fourth quarter of 2023 and late first quarter of 2024, respectively.

Gross operating margin from our NGL marketing activities increased $19 million quarter-to-quarter primarily due to higher sales volumes.

Gross operating margin from our South Texas natural gas processing facilities decreased $9 million quarter-to-quarter primarily due to higher operating costs, which accounted for a $5 million decrease, and lower average processing margins (including the impact of hedging), which accounted for an additional $4 million decrease.
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Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined net $7 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $13 million decrease, partially offset by a 219MMcf/d increase in fee-based natural gas processing volumes, which accounted for a $3 million increase.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Gross operating margin from natural gas processing and related NGL marketing activities for the nine months ended September 30, 2024 increased $186 million when compared to the nine months ended September 30, 2023.

Gross operating margin from our Midland Basin natural gas processing facilities increased a net $138 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $71 million increase, a 19 MBPD increase in equity NGL-equivalent production volumes,which accounted for a $36 million increase, and higher fee-based natural gas processing volumes, which accounted for an additional $39 million increase, partially offset by higher operating costs, which accounted for a $19 million decrease. Fee-based natural gas processing volumes at our Midland Basin natural gas processing facilities increased 348 MMcf/d period-to-period primarily due to contributions from the aforementioned Poseidon and Leonidas natural gas processing trains.

Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $57 million period-to-period primarily due to higher fee-based natural gas processing volumes, which accounted for a $42 million increase, and higher average processing margins (including the impact of hedging activities), which accounted for an additional $38 million increase, partially offset by lower average processing fees, which accounted for a $17 million decrease. Fee-based natural gas processing volumes at our Delaware Basin natural gas processing facilities increased 356 MMcf/d period-to-period, primarily due to processing volumes contributed by the aforementioned Mentone 2 and Mentone 3 natural gas processing trains.

Gross operating margin from our South Texas natural gas processing facilities increased $18 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $14 million increase, and lower operating costs, which accounted for an additional $4 million increase.

Gross operating margin from our NGL marketing activities increased a net $7 million period-to-period primarily due to higher sales volumes, which accounted for a $42 million increase, and higher non-cash, mark-to-market earnings, which accounted for an additional $13 million increase, partially offset by lower average sales margins, which accounted for a $48 million decrease.

Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $36 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities). On a combined basis, fee-based natural gas processing volumes and equity NGL-equivalent production volumes increased 272MMcf/d and 8 MBPD, respectively, period-to-period.

NGL pipelines, storage and terminals
Third Quarter of 2024 Compared to Third Quarter of 2023. Gross operating margin from our NGL pipelines, storage and terminal assets during the third quarter of 2024 increased $12 million when compared to the third quarter of 2023.

Gross operating margin from LPG-related activities at our EHT increased $15 million quarter-to-quarter primarily due to a 114 MBPD increase in LPG export volumes. Gross operating margin from our related Houston Ship Channel Pipeline System increased $5 million quarter-to-quarter primarily due to a 96 MBPD increase in transportation volumes.

A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral NGL 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 $14 million quarter-to-quarter primarily due to a $19 million increase in transportation revenues as a result of higher transportation volumes, partially offset by higher operating costs, which accounted for a $4 million decrease. On a combined basis, transportation volumes on these systems increased 186 MBPD (net to our interest) quarter-to-quarter.
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Gross operating margin at our Morgan's Point Ethane Export Terminal decreased $12 million quarter-to-quarter primarily due to lower average loading fees, which accounted for a $5 million decrease, and higher operating costs, which accounted for an additional $5 million decrease.

Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, decreased a combined $10 million quarter-to-quarter primarily due to an 11 MBPD decrease in transportation volumes.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Gross operating margin from our NGL pipelines, storage and terminal assets during the nine months ended September 30, 2024 increased $174 million when compared to the nine months ended September 30, 2023.

Gross operating margin from LPG-related activities at EHT increased $56 million period-to-period primarily due to an 89 MBPD increase in LPG export volumes, which accounted for a $39 million increase, and higher average loading fees, which accounted for an additional $19 million increase. Gross operating margin from our related Houston Ship Channel Pipeline System increased $24 million period-to-period primarily due to a 107 MBPD increase in transportation volumes, which accounted for a $15 million increase, and higher average transportation fees, which accounted for an additional $11 million increase.

A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral NGL 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 $50 million period-to-period primarily due to a 138 MBPD (net to our interest) increase in transportation volumes, which accounted for a $66 million increase, and higher average transportation fees, which accounted for an additional $19 million increase, partially offset by higher operating costs, which accounted for a $30 million decrease.

Gross operating margin from our Mont Belvieu area storage complex increased $42 million period-to-period primarily due to higher storage revenues.

Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $32 million period-to-period primarily due to higher average transportation fees. Transportation volumes on these pipelines decreased a combined 15 MBPD period-to-period.

Gross operating margin at our Morgan's Point Ethane Export Terminal decreased a net $16 million period-to-period primarily due to lower average loading fees, which accounted for a $15 million decrease, and a higher operating costs, which accounted for an additional $6 million decrease, partially offset by a 10 MBPD increase in export volumes, which accounted for a $7 million increase.

NGL fractionation
Third Quarter of 2024 Compared to Third Quarter of 2023. Gross operating margin from NGL fractionation during the third quarter of 2024 increased $49 million when compared to the third quarter of 2023. Gross operating margin from our Mont Belvieu area NGL fractionation complex increased $44 million quarter-to-quarter primarily due to lower operating costs, which accounted for a $20 million increase, higher ancillary service revenues, which accounted for a $15 million increase, and higher fractionation volumes, which accounted for an additional $10 million increase. NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex increased 97 MBPD (net to our interest) primarily due to contributions from Frac 12, which entered service during the third quarter of 2023, and the acquisition of the remaining equity interest in EF78 in February 2024.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Gross operating margin from NGL fractionation during the nine months ended September 30, 2024 increased $122 million when compared to the nine months ended September 30, 2023. Gross operating margin from our Mont Belvieu area NGL fractionation complex increased a net $108 million period-to-period primarily due to higher fractionation volumes, which accounted for an $84 million increase, and higher ancillary service revenues, which accounted for an additional $43 million increase, partially offset by higher operating costs, which accounted for a $17 million decrease. NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex increased 67 MBPD (net to our interest) primarily due to contributions from Frac 12 and the acquisition of the remaining equity interest in EF78.
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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 September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Segment gross operating margin:
$
401
$
432
$
1,229
$
1,251
Selected volumetric data:
Crude oil pipeline transportation volumes (MBPD)
2,537
2,560
2,482
2,409
Crude oil marine terminal volumes (MBPD)
910
988
992
881

Third Quarter of 2024 Compared to Third Quarter of 2023. Gross operating margin from our Crude Oil Pipelines & Services segment for the third quarter of 2024 decreased $31 million when compared to the third quarter of 2023.

Gross operating margin from our Texas in-basin crude oil pipelines, terminals and other marketing activities (excluding our Midland-to-ECHO System and Seaway Pipeline) decreased a combined net $35 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $23 million decrease, higher operating costs, which accounted for a $21 million decrease, lower other revenues, which accounted for an $18 million decrease, and lower sales volumes, which accounted for an additional $13 million decrease, partially offset by higher non-cash, mark-to-market earnings, which accounted for a $37 million increase. Crude oil transportation volumes on these pipelines increased a combined 2 MBPD (net to our interest) quarter-to-quarter.

Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $7 million quarter-to-quarter primarily due to higher deficiency and other fee revenues, which accounted for an $18 million increase, and lower operating costs, which accounted for an additional $21 million increase, partially offset by lower transportation revenues, which accounted for a $20 million decrease, and lower margins from marketing activities, which accounted for an additional $13 million decrease. Crude oil transportation volumes on these pipelines were flat (net to our interest) quarter-to-quarter.

Gross operating margin from crude oil activities at EHT increased a net $3 million quarter-to-quarter primarily due to lower operating costs, which accounted for a $3 million increase, and higher storage revenues, which accounted for an additional $2 million increase, partially offset by lower loading revenues, which accounted for a $3 million decrease. Crude oil terminal volumes at EHT decreased 92 MBPD quarter-to-quarter.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Gross operating margin from our Crude Oil Pipelines & Services segment for the nine months ended September 30, 2024 decreased $22 million when compared to the nine months ended September 30, 2023.

Gross operating margin from our Texas in-basin crude oil pipelines, terminals and other marketing activities (excluding our Midland-to-ECHO System and Seaway Pipeline) decreased a combined net $60 million period-to-period primarily due to lower average sales margins, which accounted for a $103 million decrease, and higher operating costs, which accounted for an additional $34 million decrease, partially offset by higher non-cash, mark-to-market earnings, which accounted for a $48 million increase, and higher sales volumes, which accounted for an additional $34 million increase. Crude oil transportation volumes on these pipelines increased a combined 4 MBPD (net to our interest) period-to-period.

Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $26 million period-to-period primarily due to higher deficiency and other fee revenues, which accounted for a $31 million increase, lower operating costs, which accounted for a $21 million increase, and higher transportation revenues, which accounted for an additional $10 million increase, partially offset by lower margins from marketing activities, which accounted for a $32 million decrease. Crude oil transportation volumes on these pipelines increased a combined 73 MBPD (net to our interest) period-to-period.

Gross operating margin from crude oil activities at EHT increased $11 million period-to-period primarily due to lower operating costs, which accounted for a $6 million increase, and higher storage revenues, which accounted for an additional $5 million increase. Crude oil terminal volumes at EHT increased 106 MBPD period-to-period.
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Natural Gas Pipelines & Services

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

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Segment gross operating margin
$
349
$
239
$
954
$
791
Selected volumetric data:
Natural gas pipeline transportation volumes (BBtus/d)
19,090
18,440
18,685
18,244

Third Quarter of 2024 Compared to Third Quarter of 2023. Gross operating margin from our Natural Gas Pipelines & Services segment for the third quarter of 2024 increased $110 million when compared to the third quarter of 2023.

Gross operating margin from our natural gas marketing activities increased $55 million quarter-to-quarter primarily due to higher average sales margins.

Gross operating margin from our Texas Intrastate System increased $39 million quarter-to-quarter primarily due to higher average transportation fees. Transportation volumes decreased 61BBtus/d on this system quarter-to-quarter.

Gross operating margin from our Delaware and Midland Basin Gathering Systems increased a combined net $13 million quarter-to-quarter primarily due to a 1,111BBtus/d increase in natural gas gathering volumes, which accounted for a $28 million increase, partially offset by higher operating costs, which accounted for a $15 million decrease.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Gross operating margin from our Natural Gas Pipelines & Services segment for the nine months ended September 30, 2024 increased $163 million when compared to the nine months ended September 30, 2023.

Gross operating margin from our natural gas marketing activities increased $97 million period-to-period primarily due to higher average sales margins.

Gross operating margin from our Texas Intrastate System increased a net $90 million period-to-period primarily due to higher average transportation fees, which accounted for a $71 million increase, higher capacity reservation fees and other revenues, which accounted for an additional $29 million increase, partially offset by higher operating costs, which accounted for a $7 million decrease. Transportation volumes decreased 103BBtus/d on this system period-to-period.

Gross operating margin from our Delaware and Midland Basin Gathering Systems increased a combined net $23 million period-to-period primarily due to an 816BBtus/d increase in natural gas gathering volumes, which accounted for a $64 million increase, partially offset by higher operating costs, which accounted for a $46 million decrease.

Gross operating margin from our Acadian Gas System increased a net $16 million period-to-period primarily due to higher average fees, which accounted for a $26 million increase, partially offset by higher operating costs, which accounted for a $10 million decrease. Transportation volumes on our Acadian Gas System increased 99 BBtus/d period-to-period.

On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering System in the Rocky Mountains decreased $40 million period-to-period primarily due to lower average gathering fees. The gathering fees on these systems are indexed to regional gas prices, which were lower during the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023. Gathering volumes on our Rocky Mountain gathering systems decreased a combined 111BBtus/d period-to-period.

Gross operating margin from our Haynesville Gathering System decreased $15 million period-to-period primarily due to lower deficiency fees, which accounted for a $7 million decrease, and a 122BBtus/d decrease in gathering volumes, which accounted for an additional $5 million decrease.
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Petrochemical & Refined Products Services

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

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Segment gross operating margin:
Propylene production and related activities
$
128
$
120
$
396
$
427
Butane isomerization and related operations
28
30
90
92
Octane enhancement and related plant operations
96
164
344
341
Refined products pipelines and related activities
67
93
212
261
Ethylene exports and related activities
25
28
106
89
Marine transportation and other services
19
18
51
45
Total
$
363
$
453
$
1,199
$
1,255
Selected volumetric data:
Propylene production volumes (MBPD)
113
103
102
104
Butane isomerization volumes (MBPD)
116
112
117
110
Standalone deisobutanizer ("DIB") processing volumes (MBPD)
191
185
199
170
Octane enhancement and related plant sales volumes (MBPD) (1)
37
41
37
34
Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD)
979
826
928
817
Marine terminal volumes, primarily refined products and petrochemicals (MBPD)
275
331
315
311

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

Propylene production and related activities
Third Quarter of 2024 Compared to Third Quarter of 2023. Gross operating margin from propylene production and related activities for the third quarter of 2024 increased $8 million when compared to the third quarter of 2023.

On a combined basis, gross operating margin from our Mont Belvieu area propylene production facilities increased a net $9 million quarter-to-quarter primarily due tohigher average propylene sales margins, which accounted for a $23 million increase, and lower operating costs, which accounted for an additional $8 million increase, partially offset by lower propylene processing revenues, which accounted for a $20 million decrease. Propylene and associated by-product production volumes at these facilities increased a combined 11MBPD (net to our interest) quarter-to-quarter primarily due to downtime at our PDH 1 facility for unplanned maintenance during the third quarter of 2023. Partially offsetting this increase was lower production from our PDH 2 facility due to scheduled maintenance that was completed during the third quarter of 2024.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Gross operating margin from propylene production and related activities for the nine months ended September 30, 2024 decreased $31 million when compared to the nine months ended September 30, 2023.

On a combined basis, gross operating margin from our Mont Belvieu area propylene production facilities decreased a net $19 million period-to-period primarily due tolower propylene sales volumes, which accounted for a $72 million decrease, and higher operating costs, which accounted for an additional $36 million decrease, partially offset by higher propylene processing revenues, which accounted for a $58 million increase, higher average propylene sales margins, which accounted for a $23 million increase, and higher storage and other revenues, which accounted for an additional $7 million increase. Propylene and associated by-product production volumes at these facilities decreased a combined 2 MBPD (net to our interest) period-to-period.

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Butane isomerization and related operations
Third Quarter of 2024 Compared to Third Quarter of 2023. Gross operating margin from butane isomerization and related operations for the third quarter of 2024 decreased a net $2 million when compared to the third quarter of 2023 primarily due to lower by-product sales, which accounted for a $4 million decrease, and lower isomerization and other fee revenues, which accounted for an additional $2 million decrease, partially offset by lower operating costs, which accounted for a $5 million increase.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Gross operating margin from butane isomerization and related operations for the nine months ended September 30, 2024 decreased a net $2 million when compared to the nine months ended September 30, 2023 primarily due to lower ancillary service revenues, which accounted for a $7 million decrease, and lower by-product sales, which accounted for an additional $3 million decrease, partially offset by lower operating costs, which accounted for a $6 million increase, and a 7 MBPD increase in isomerization volumes, which accounted for an additional $3 million increase.

Octane enhancement and related plant operations
Third Quarter of 2024 Compared to Third Quarter of 2023. Gross operating margin from our octane enhancement and related plant operations for the third quarter of 2024 decreased $68 million when compared to the third quarter of 2023 primarily due to lower average sales margins, which accounted for a $35 million decrease, and lower sales volumes, which accounted for an additional $34 million decrease.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Gross operating margin from our octane enhancement and related plant operations for the nine months ended September 30, 2024 increased a net $3 million when compared to the nine months ended September 30, 2023 primarily due to higher deficiency revenues, which accounted for an $18 million increase, and lower operating costs, which accounted for an additional $6 million increase, partially offset by lower average sales margins, which accounted for a $21 million decrease.

Refined products pipelines and related activities
Third Quarter of 2024 Compared to Third Quarter of 2023. Gross operating margin from refined products pipelines and related activities for the third quarter of 2024 decreased $26 million when compared to the third quarter of 2023.

Gross operating margin from our refined products marketing activities decreased $24 million quarter-to-quarter primarily due to lower average sales margins.

Gross operating margin from our refined products terminal in Beaumont, Texas decreased $7 million quarter-to-quarter primarily due to lower loading and other fee revenues. Refined product marine terminal volumes at Beaumont decreased 32 MBPD quarter-to-quarter.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Gross operating margin from refined products pipelines and related activities for the nine months ended September 30, 2024 decreased $49 million when compared to the nine months ended September 30, 2023.

Gross operating margin from our refined products marketing activities decreased a net $47 million period-to-period primarily due to lower average sales margins, which accounted for a $56 million decrease, partially offset by higher sales volumes, which accounted for an $12 million increase.

Gross operating margin from our refined products terminal in Beaumont, Texas decreased $14 million period-to-period primarily due to lower loading and other fee revenues. Refined product marine terminal volumes at Beaumont increased 18 MBPD period-to-period.

Ethylene exports and related activities
Third Quarter of 2024 Compared to Third Quarter of 2023. Gross operating margin from ethylene exports and related activities for the third quarter of 2024 decreased a net $3 million when compared to the third quarter of 2023 primarily due to a 12 MBPD (net to our interest) decrease in ethylene export volumes, which accounted for a $13 million decrease, partially offset by lower operating costs, which accounted for a $5 million increase, higher deficiency fee revenues from our ethylene export terminal, which accounted for a $3 million increase, and a combined 22 MBPD (net to our interest) increase in transportation volumes, which accounted for an additional $2 million increase.
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Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Gross operating margin from ethylene exports and related activities for the nine months ended September 30, 2024 increased a net $17 million when compared to the nine months ended September 30, 2023 primarily due to higher deficiency fee revenues from our ethylene pipelines and ethylene export terminal, which accounted for a $23 million increase, a combined 31 MBPD (net to our interest) increase in transportation volumes, which accounted for a $10 million increase, and lower operating costs, which accounted for an additional $4 million increase, partially offset by a 6 MBPD (net to our interest) decrease in ethylene export volumes, which accounted for a $20 million decrease.

Marine transportation and other services
Third Quarter of 2024 Compared to Third Quarter of 2023. Gross operating margin from marine transportation and other services for the third quarter of 2024 increased $1 million when compared to the third quarter of 2023 primarily due to higher average fees.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Gross operating margin from marine transportation and other services for the nine months ended September 30, 2024 increased a net $6 million when compared to the nine months ended September 30, 2023 primarily due to higher average fees, which accounted for a $13 million increase, partially offset by higher operating costs, which accounted for a $6 million decrease.

Liquidity and Capital Resources

Based on current market conditions (as of the filing date of this quarterly report), we believe that the Partnership and its consolidated businesses will have sufficient liquidity, cash flow from operations and access to capital markets to fund their capital investments and working capital needs for the reasonably foreseeable future. At September 30, 2024, we had $5.6 billion of consolidated liquidity. This amount was comprised of $4.2 billion of available borrowing capacity under EPO's revolving credit facilities and $1.4 billion 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 (the "2021 Shelf") on file with the SEC which allows the Partnership and EPO to issue an unlimited amount of equity and debt securities, respectively. The 2021 Shelf will expire in November 2024, at which time we expect to file a replacement universal shelf registration statement. In addition, we have a registration statement on file with the SEC covering the issuance of up to $2.5 billion of the Partnership's common units in amounts, at prices and on terms based on market conditions and other factors at the time of such offerings (referred to as the Partnership's at-the-market ("ATM") program).

Enterprise Declares Cash Distribution for Third Quarter of 2024

On October 2, 2024, we announced that the Board declared a quarterly cash distribution of $0.525 per common unit, or $2.10 per unit on an annualized basis, to be paid to the Partnership's common unitholders with respect to the third quarter of 2024. The quarterly distribution is payable on November 14, 2024 to unitholders of record as of the close of business on October 31, 2024. The total amount to be paid is $1.15 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 September 30, 2024, the average maturity of EPO's consolidated debt obligations was approximately 18.5years. The following table presents the scheduled maturities of principal amounts of EPO's consolidated debt obligations at September 30, 2024 for the years indicated (dollars in millions):

Scheduled Maturities of Debt
Total
Remainder
of 2024
2025
2026
2027
2028
Thereafter
Senior Notes
$
29,925
$
-
$
1,150
$
1,625
$
1,575
$
1,000
$
24,575
Junior Subordinated Notes
2,296
-
-
-
-
-
2,296
Total
$
32,221
$
-
$
1,150
$
1,625
$
1,575
$
1,000
$
26,871

In January 2024, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of senior notes due January 2027 ("Senior Notes HHH") and (ii) $1.0 billion principal amount of senior notes due January 2034 ("Senior Notes III"). Senior Notes HHH were issued at 99.897% of their principal amount and have a fixed interest rate of 4.60% per year. Senior Notes III were issued at 99.705% of their principal amount and have a fixed interest rate of 4.85% per year. Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all of our $850 million principal amount of 3.90% Senior Notes JJ at their maturity in February 2024 and amounts outstanding under our commercial paper program).

In March 2024, EPO entered into a new 364-Day Revolving Credit Agreement (the "March 2024 $1.5 Billion 364-Day Revolving Credit Agreement") that replaced its prior 364-day revolving credit agreement. The March 2024 $1.5 Billion 364-Day Revolving Credit Agreement matures in March 2025. EPO's borrowing capacity was unchanged from the prior 364-day revolving credit agreement. As of September 30, 2024, there are no principal amounts outstanding under this new revolving credit agreement.

In August 2024, EPO issued $2.5 billion aggregate principal amount of senior notes comprised of (i) $1.1 billion principal amount of senior notes due February 2035 ("Senior Notes JJJ") and (ii) $1.4 billion principal amount of senior notes due February 2055 ("Senior Notes KKK"). Senior Notes JJJ were issued at 99.400% of their principal amount and have a fixed interest rate of 4.95% per year. Senior Notes KKK were issued at 99.663% of their principal amount and have a fixed interest rate of 5.55% per year. Net proceeds from this offering will be used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all or a portion of our $1.15 billion principal amount of 3.75% Senior Notes MM at their maturity in February 2025).

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

Credit Ratings

As of November 8, 2024, the investment-grade credit ratings of EPO's long-term senior unsecured debt securities were A- from Standard and Poor's, A3 from Moody's and A- from Fitch Ratings. In addition, the credit ratings of EPO's short-term senior unsecured debt securities were A-2 from Standard and Poor's, P-2 from Moody's and F-2 from Fitch Ratings. EPO's credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities. A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change. A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies.

Common Unit Repurchases Under 2019 Buyback Program

In January 2019, we announced that the Board had approved a $2.0 billion multi-year unit buyback program (the "2019 Buyback Program"), which provides the Partnership with an additional method to return capital to investors. The Partnership repurchased 2,646,351and 5,452,767 common units through open market purchases during the three and nine months ended September 30, 2024, respectively. The total cost of these repurchases, including commissions and fees, was $76 million and $156 million, respectively. As of September 30, 2024, the remaining available capacity under the 2019 Buyback Program was $926 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 Nine Months
Ended September 30,
2024
2023
Net cash flow provided by operating activities
$
5,757
$
5,203
Net cash flow used in investing activities
3,433
2,220
Net cash flow used in financing activities
971
2,875

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 2023 Form 10-K.

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 period-to-period fluctuations in our consolidated cash flow amounts:

Operating activities
Net cash flow provided by operating activities for the nine months ended September 30, 2024increased $554 million when compared to thenine months ended September 30, 2023primarily due to:

•
a $438 million period-to-period increase resulting from higher partnership earnings (determined by adjusting our $282 million period-to-period increase in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows); and

•
a $143 million period-to-period 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.

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

Investing activities
Net cash flow used in investing activities during the nine months ended September 30, 2024increased $1.2 billion when compared to the nine months ended September 30,2023 primarily due to an increase in investments for property, plant and equipment (see "Capital Investments" within this Part I, Item 2 for additional information).
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Financing activities
Net cash flow used in financing activities during the nine months ended September 30, 2024decreased a net $1.9 billion when compared to the nine months ended September 30,2023 primarily due to:

•
a net cash inflow of $3.1 billion related to debt transactions that occurred during the nine months ended September 30,2024 compared to a net cash inflow of $627 million related to debt transactions that occurred during the nine months ended September 30, 2023. During the nine months ended September 30,2024, we issued $4.5 billion aggregate principal amount of senior notes, partially offset by the repayment of $850 million principal amount of senior notes and net repayments of $450 million under EPO's commercial paper program. During the nine months ended September 30,2023, we issued $1.75billion aggregate principal amount of senior notes and issued a net $126 million under EPO's commercial paper program, partially offset by the repayment of $1.25 billion principal amount of senior notes; partially offset by

•
a $400 million cash outflow during the nine months ended September 30,2024 in connection with the acquisition of noncontrolling interests. In February 2024, we acquired the remaining 20% equity interest in Whitethorn and remaining 25% equity interest in EF78 from affiliates of Western Midstream for total cash consideration of $375 million. In March 2024, we acquired an additional 15% equity interest in Panola from an affiliate of Western Midstream for $25 million in cash consideration; and

•
a $159 million period-to-period increase in cash distributions paid to common unitholders primarily attributable to increases in the quarterly cash distribution rate per unit.

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

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

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

Our use of DCF and Operational DCF for the limited purposes described above and in this quarterly report is not a substitute for net cash flow provided by operating activities, which is the most comparable GAAP measure to DCF and Operational DCF. For a discussion of net cash flow provided by operating activities, see "Cash Flow Statement Highlights" within this Part I, Item 2.
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The following table summarizes our calculation of DCF and Operational DCF for the periods indicated (dollars in millions):

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Net income attributable to common unitholders (GAAP) (1)
$
1,417
$
1,318
$
4,278
$
3,961
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
618
599
1,845
1,742
Cash distributions received from unconsolidated affiliates (2)
124
120
367
367
Equity in income of unconsolidated affiliates
(99
)
(122
)
(302
)
(347
)
Asset impairment charges
27
12
51
28
Change in fair market value of derivative instruments
(3
)
38
(11
)
48
Deferred income tax expense
9
13
23
5
Sustaining capital expenditures (3)
(129
)
(99
)
(554
)
(284
)
Other, net
(8
)
(11
)
9
(6
)
Operational DCF (non-GAAP)
$
1,956
$
1,868
$
5,706
$
5,514
Proceeds from asset sales and other matters
5
1
11
7
Monetization of interest rate derivative instruments accounted for as cash flow hedges
(4
)
‒
(33
)
21
DCF (non-GAAP)
$
1,957
$
1,869
$
5,684
$
5,542
Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards
$
1,149
$
1,095
$
3,428
$
3,266
Cash distribution per common unit declared by Enterprise GP with respect to period (4)
$
0.5250
$
0.5000
$
1.5650
$
1.4900
Total DCF retained by the Partnership with respect to period (5)
$
808
$
774
$
2,256
$
2,276
Distribution coverage ratio (6)
1.7
x
1.7
x
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 cash distributions declared with respect to the periods indicated.
(5)
Cash retained by the Partnership may be used for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash reduces our reliance on the capital markets.
(6)
Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to common unitholders and in connection with distribution equivalent rights with respect to the period.

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

For the Three Months
Ended September 30,
For the Nine Months
Ended September 30,
2024
2023
2024
2023
Net cash flow provided by operating activities (GAAP)
$
2,072
$
1,718
$
5,757
$
5,203
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
36
303
563
706
Sustaining capital expenditures
(129
)
(99
)
(554
)
(284
)
Distributions received from unconsolidated affiliates attributable to the return of capital
25
7
64
37
Net income attributable to noncontrolling interests
(14
)
(31
)
(56
)
(91
)
Other, net
(34
)
(30
)
(68
)
(57
)
Operational DCF (non-GAAP)
$
1,956
$
1,868
$
5,706
$
5,514
Proceeds from asset sales and other matters
5
1
11
7
Monetization of interest rate derivative instruments accounted for as cash flow hedges
(4
)
‒
(33
)
21
DCF (non-GAAP)
$
1,957
$
1,869
$
5,684
$
5,542

Capital Investments

Since the beginning of 2024, we placed into service two natural gas processing trains in the Permian Basin and our TW Products System. We have approximately $6.9 billion of growth capital projects scheduled to be completed by the end of 2026, including the following major projects (including their respective scheduled completion dates):

•
natural gas gathering expansion projects in the Delaware and Midland Basins (2024 and 2025);

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

•
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);

•
an expansion of our Morgan's Point terminal to increase ethylene export capacity and enhance our ethane loading capabilities (fourth quarter of 2024 and 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 2024, net of contributions from noncontrolling interests, to approximate $4.14 billion to $4.39 billion, which reflects growth capital investments of $3.5 billion to $3.75 billion and sustaining capital expenditures of $640 million. These amounts do not include capital investments associated with our proposed deep-water offshore crude oil terminal (SPOT), which remains subject to a final investment decision.

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In August 2024, we announced that an affiliate of Enterprise entered into a definitive agreement to acquire Piñon Midstream for $950 million. This transaction, which closed October 28, 2024, was funded using cash on hand.

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

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

For the Nine Months
Ended September 30,
2024
2023
Capital investments for property, plant and equipment: (1)
Growth capital projects (2)
$
2,950
$
1,945
Sustaining capital projects (3)
535
309
Total
$
3,485
$
2,254

(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 Nine Months Ended September 30, 2024 with Nine Months Ended September 30, 2023

In total, investments in growth capital projects increased $1.0 billion period-to-period primarily due to the following:

•
higher investments in ethane, ethylene, and LPG export expansion projects at our Gulf Coast terminals, which accounted for a $417 million increase;

•
higher investments in our Bahia NGL Pipeline, which accounted for a $349 million increase; and

•
higher investments in the construction of natural gas processing trains and related gathering system expansions in the Delaware and Midland Basins, which accounted for an additional $192 million increase.

Investments attributable to sustaining capital projects increased $226 million period-to-period primarily due to higher major maintenance activities performed at certain of our reaction-based plants (e.g., our PDH 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 2023 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"), with the exception of the remaining debt obligations of TEPPCO Partners, L.P. (collectively, the "Guaranteed Debt"). If EPO were to default on any of its Guaranteed Debt, the Partnership would be responsible for full and unconditional repayment of such obligations. At September 30, 2024, the total amount of Guaranteed Debt was $32.5 billion, which was comprised of $29.9 billion of EPO's senior notes, $2.3 billion of EPO's junior subordinated notes, and $270 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 $48.0 billion at September 30, 2024. The Obligor Group's equity in the earnings of the Non-Obligor Subsidiaries for the nine months ended September 30, 2024 was $5.0 billion. Although the net assets and earnings of the Non-Obligor Subsidiaries are not directly available to the holders of the Guaranteed Debt to satisfy the repayment of such obligations, there are no significant restrictions on the ability of the Non-Obligor Subsidiaries to pay distributions or make loans to EPO or the Partnership. EPO exercises control over the Non-Obligor Subsidiaries. We continue to believe that the unaudited condensed consolidated financial statements of the Partnership presented under Part I, Item 1 of this quarterly report provide a more appropriate view of our credit standing. Our investment grade credit ratings are based on the Partnership's consolidated financial statements and not the Obligor Group's financial information presented below.

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

Selected asset information:
September 30,
2024
December 31,
2023
Current receivables from Non-Obligor Subsidiaries
$
2,880
$
2,569
Other current assets
6,676
5,416
Long-term receivables from Non-Obligor Subsidiaries
187
187
Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries
of $48.0 billion at September 30, 2024 and $46.8 billion at December 31, 2023
9,423
9,185
Selected liability information:
Current portion of Guaranteed Debt, including interest of $270 million at September 30, 2024 and
$455 million at December 31, 2023
$
1,419
$
1,755
Current payables to Non-Obligor Subsidiaries
1,258
1,567
Other current liabilities
3,916
4,239
Noncurrent portion of Guaranteed Debt, principal only
31,057
27,707
Noncurrent payables to Non-Obligor Subsidiaries
55
57
Other noncurrent liabilities
111
122
Mezzanine equity of Obligor Group:
Preferred units
$
50
$
49

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

For the Nine
Months Ended
September 30,
2024
For the Twelve
Months Ended
December 31,
2023
Revenues from Non-Obligor Subsidiaries
$
16,583
$
17,344
Revenues from other sources
13,860
15,375
Operating income of Obligor Group
346
835
Net loss of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of
$5.0 billion for the nine months ended September 30, 2024 and
$6.0 billion for the twelve months ended December 31, 2023
(693
)
(483
)

Related Party Transactions

For information regarding our related party transactions, see Note 14 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 September 30, 2024, 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 13 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,
2023
September 30,
2024
October 15,
2024
Fair value assuming no change in underlying commodity prices
Asset (Liability)
$
7
$
2
$
3
Fair value assuming 10% increase in underlying commodity prices
Asset (Liability)
6
1
2
Fair value assuming 10% decrease in underlying commodity prices
Asset (Liability)
8
3
4

NGL and refined products marketing, natural gas processing and octane enhancement portfolio
Portfolio Fair Value at
Scenario
Resulting
Classification
December 31,
2023
September 30,
2024
October 15,
2024
Fair value assuming no change in underlying commodity prices
Asset (Liability)
$
39
$
61
$
104
Fair value assuming 10% increase in underlying commodity prices
Asset (Liability)
9
50
105
Fair value assuming 10% decrease in underlying commodity prices
Asset (Liability)
69
72
103

Crude oil marketing portfolio
Portfolio Fair Value at
Scenario
Resulting
Classification
December 31,
2023
September 30,
2024
October 15,
2024
Fair value assuming no change in underlying commodity prices
Asset (Liability)
$
66
$
88
$
44
Fair value assuming 10% increase in underlying commodity prices
Asset (Liability)
(61
)
(35
)
(65
)
Fair value assuming 10% decrease in underlying commodity prices
Asset (Liability)
193
211
153

Commercial energy derivative portfolio
Portfolio Fair Value at
Scenario
Resulting
Classification
December 31,
2023
September 30,
2024
October 15,
2024
Fair value assuming no change in underlying commodity prices
Asset (Liability)
$
(9
)
$
(13
)
$
(28
)
Fair value assuming 10% increase in underlying commodity prices
Asset (Liability)
9
(3
)
(18
)
Fair value assuming 10% decrease in underlying commodity prices
Asset (Liability)
(27
)
(23
)
(38
)

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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. As of the filing date of this quarterly report, we do not have any interest rate hedging instruments outstanding.


ITEM 4. CONTROLS AND PROCEDURES.

Disclosure Controls and Procedures

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

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

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

Changes in Internal Control over Financial Reporting

There were no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) during the third quarter of 2024, 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 16 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.


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 2023 Form 10-K, in addition to other information in such annual report and this quarterly report. The risk factors set forth in our 2023 Form 10-K 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.

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

Recent Issuances of Unregistered Securities

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

The Partnership made quarterly PIK distributions to preferred unitholders in the first, second and third quarters of 2024 of 19,423, 19,865 and 20,225 preferred units, respectively. With the exception of 90 and 92 preferred units distributed in the second and third quarters of 2024, respectively, to an unaffiliated third party, all of the PIK distributions made during the nine months ended September 30, 2024 were to OTA Holdings, Inc., an indirect, wholly owned subsidiary of the Partnership ("OTA"). 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 issuance of preferred units as PIK distributions during the three and nine months ended September 30, 2024 were undertaken in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof.

Other than as described above, there were no sales of unregistered equity securities during the third quarter of 2024.

Issuer Purchases of Equity Securities

The following table summarizes our equity repurchase activity during the third quarter of 2024:

Period
Total Number
of Units
Purchased
Average
Price Paid
per Unit
Total Number
Of Units
Purchased
as Part of
2019 Buyback
Program
Remaining
Dollar Amount
of Units That May
Be Purchased
Under the 2019 Buyback Program
($ thousands)
2019 Buyback Program: (1)
July 2024
-
$
-
-
$
1,001,709
August 2024
2,126,818
$
28.66
2,126,818
$
940,752
September 2024
519,533
$
28.95
519,533
$
925,709
Vesting of phantom unit awards:
August 2024 (2)
35,362
$
28.48
n/a
n/a
September 2024 (3)
1,284
$
29.29
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 129,147 phantom unit awards that vested in August 2024 and converted to common units, 35,362 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 4,250 phantom unit awards that vested in September 2024 and converted to common units, 1,284 units were sold back to us by employees to cover related withholding tax requirements. These repurchases are not part of any announced program. We cancelled these units immediately upon acquisition.


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ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.


ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.


ITEM 5. OTHER INFORMATION.

During the three months ended September 30, 2024, 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
4.46
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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
4.64
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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
4.78
4.79
4.80

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4.81
4.82
4.83
4.84
4.85
4.86
4.87
4.88
4.89
4.90
22.1#
List of Issuers of Debt Securities Guaranteed by Enterprise Products Partners L.P. and Associated Securities at September 30, 2024.
31.1#
Sarbanes-Oxley Section 302 certification of A. James Teague for Enterprise Products Partners L.P.'s quarterly report on Form 10-Q.
31.2#
Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P.'s quarterly report on Form 10-Q.

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31.3#
Sarbanes-Oxley Section 302 certification of R. Daniel Boss for Enterprise Products Partners L.P.'s quarterly report on Form 10-Q.
32.1#
Sarbanes-Oxley Section 906 certification of A. James Teague for Enterprise Products Partners L.P.'s quarterly report on Form 10-Q.
32.2#
Sarbanes-Oxley Section 906 certification of W. Randall Fowler for Enterprise Products Partners L.P.'s quarterly report on Form 10-Q.
32.3#
Sarbanes-Oxley Section 906 certification of R. Daniel Boss for Enterprise Products Partners L.P.'s quarterly report on Form 10-Q.
101#
Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) in this Form 10-Q include the: (i) Unaudited Condensed Consolidated Balance Sheets, (ii) Unaudited Condensed Statements of Consolidated Operations, (iii) Unaudited Condensed Statements of Consolidated Comprehensive Income, (iv) Unaudited Condensed Statements of Consolidated Cash Flows, (v) Unaudited Condensed Statements of Consolidated Equity and (vi) Notes to the Unaudited Condensed Consolidated Financial Statements.
104#
Cover Page Interactive Data File (embedded within the iXBRL document).


*
With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file numbers for Enterprise Products Partners L.P., Enterprise GP Holdings L.P, TEPPCO Partners, L.P. and TE Products Pipeline Company, LLC are 1-14323, 1-32610, 1-10403 and 1-13603, respectively.
***
Identifies management contract and compensatory plan arrangements.
#
Filed with this report.


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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on November 8, 2024.

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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