ENTERPRISE PRODUCTS PARTNERS L.P. - Quarter Report: 2023 June (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 June 30, 2023

☐ 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 2,171,752,332 common units of Enterprise Products Partners L.P. outstanding at the close of business on July 31, 2023.

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
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

Table of Contents

PART I. FINANCIAL INFORMATION.

ITEM 1. FINANCIAL STATEMENTS.

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	June 30, 2023			December 31, 2022
ASSETS
Current assets:
Cash and cash equivalents	$	183		$	76
Restricted cash		94			130
Accounts receivable – trade, net of allowance for credit losses of $50 at June 30, 2023 and $54 at December 31, 2022		6,127			6,964
Accounts receivable – related parties		7			11
Inventories (see Note 3)		2,497			2,554
Derivative assets (see Note 13)		333			469
Prepaid and other current assets		463			394
Total current assets		9,704			10,598
Property, plant and equipment, net (see Note 4)		45,054			44,401
Investments in unconsolidated affiliates (see Note 5)		2,332			2,352
Intangible assets, net (see Note 6)		3,871			3,965
Goodwill (see Note 6)		5,608			5,608
Other assets		1,160			1,184
Total assets	$	67,729		$	68,108

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt (see Note 7)	$	1,204		$	1,744
Accounts payable – trade		999			743
Accounts payable – related parties		90			232
Accrued product payables		6,996			7,988
Accrued interest		458			426
Derivative liabilities (see Note 13)		330			354
Other current liabilities		632			778
Total current liabilities		10,709			12,265
Long-term debt (see Note 7)		27,443			26,551
Deferred tax liabilities (see Note 15)		591			600
Other long-term liabilities		915			941
Commitments and contingent liabilities (see Note 16)
Redeemable preferred limited partner interests: (see Note 8)
Series A cumulative convertible preferred units (“preferred units”) (50,412 units outstanding at June 30, 2023 and December 31, 2022)		49			49
Equity: (see Note 8)
Partners’ equity:
Common limited partner interests (2,171,752,332 units issued and outstanding at June 30, 2023, 2,170,806,347 units issued and outstanding at December 31, 2022)		27,980			27,555
Treasury units, at cost		(1,297	)		(1,297	)
Accumulated other comprehensive income		268			365
Total partners’ equity		26,951			26,623
Noncontrolling interests in consolidated subsidiaries		1,071			1,079
Total equity		28,022			27,702
Total liabilities, preferred units, and equity	$	67,729		$	68,108

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(Dollars in millions, except per unit amounts)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2023			2022			2023			2022
Revenues:
Third parties	$	10,638		$	16,041		$	23,069		$	29,033
Related parties		13			19			26			35
Total revenues (see Note 9)		10,651			16,060			23,095			29,068
Costs and expenses:
Operating costs and expenses:
Third party and other costs		8,805			14,004			19,237			25,086
Related parties		332			337			657			652
Total operating costs and expenses		9,137			14,341			19,894			25,738
General and administrative costs:
Third party and other costs		18			24			41			49
Related parties		38			38			72			75
Total general and administrative costs		56			62			113			124
Total costs and expenses (see Note 10)		9,193			14,403			20,007			25,862
Equity in income of unconsolidated affiliates		121			107			225			224
Operating income		1,579			1,764			3,313			3,430
Other income (expense):
Interest expense		(302	)		(309	)		(616	)		(628	)
Interest income		5			2			17			3
Other, net		14			–			14			2
Total other expense, net		(283	)		(307	)		(585	)		(623	)
Income before income taxes		1,296			1,457			2,728			2,807
Provision for income taxes (see Note 15)		(13	)		(17	)		(23	)		(36	)
Net income		1,283			1,440			2,705			2,771
Net income attributable to noncontrolling interests		(29	)		(28	)		(60	)		(62	)
Net income attributable to preferred units		(1	)		(1	)		(2	)		(2	)
Net income attributable to common unitholders	$	1,253		$	1,411		$	2,643		$	2,707

Earnings per unit: (see Note 11)
Basic earnings per common unit	$	0.57		$	0.64		$	1.21		$	1.23
Diluted earnings per common unit	$	0.57		$	0.64		$	1.20		$	1.23

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED

COMPREHENSIVE INCOME

(Dollars in millions)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2023			2022			2023			2022

Net income	$	1,283		$	1,440		$	2,705		$	2,771
Other comprehensive income (loss):
Cash flow hedges: (see Note 13)
Commodity hedging derivative instruments:
Changes in fair value of cash flow hedges		46			39			(43	)		(60	)
Reclassification of gains to net income		(16	)		(108	)		(48	)		(63	)
Interest rate hedging derivative instruments:
Changes in fair value of cash flow hedges		–			–			(5	)		–
Reclassification of losses (gains) to net income		(3	)		6			(1	)		14
Total cash flow hedges		27			(63	)		(97	)		(109	)
Total other comprehensive income (loss)		27			(63	)		(97	)		(109	)
Comprehensive income		1,310			1,377			2,608			2,662
Comprehensive income attributable to noncontrolling interests		(29	)		(28	)		(60	)		(62	)
Comprehensive income attributable to preferred units		(1	)		(1	)		(2	)		(2	)
Comprehensive income attributable to common unitholders	$	1,280		$	1,348		$	2,546		$	2,598

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in millions)

	For the Six Months Ended June 30,
	2023			2022
Operating activities:
Net income	$	2,705		$	2,771
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation and accretion		910			891
Amortization of intangible assets		96			86
Amortization of major maintenance costs for reaction-based plants		31			25
Other amortization expense		106			115
Impairment of assets other than goodwill		16			19
Equity in income of unconsolidated affiliates		(225	)		(224	)
Distributions received from unconsolidated affiliates attributable to earnings		217			224
Net losses (gains) attributable to asset sales and related matters		(4	)		2
Deferred income tax expense (benefit)		(8	)		16
Change in fair market value of derivative instruments		10			94
Non-cash expense related to long-term operating leases (see Note 16)		33			27
Net effect of changes in operating accounts (see Note 17)		(403	)		218
Other operating activities		1			–
Net cash flows provided by operating activities		3,485			4,264
Investing activities:
Capital expenditures		(1,433	)		(731	)
Cash used for business combinations, net of cash received (See Note 17)		–			(3,204	)
Distributions received from unconsolidated affiliates attributable to the return of capital		30			55
Proceeds from asset sales and other matters		6			14
Other investing activities		(5	)		(2	)
Cash used in investing activities		(1,402	)		(3,868	)
Financing activities:
Borrowings under debt agreements		28,595			42,112
Repayments of debt		(28,238	)		(42,872	)
Debt issuance costs		(17	)		–
Monetization of interest rate derivative instruments		21			–
Cash distributions paid to common unitholders (see Note 8)		(2,129	)		(2,026	)
Cash payments made in connection with distribution equivalent rights		(19	)		(17	)
Cash distributions paid to noncontrolling interests		(81	)		(82	)
Cash contributions from noncontrolling interests		15			4
Repurchase of common units under 2019 Buyback Program		(92	)		(35	)
Other financing activities		(67	)		(48	)
Cash used in financing activities		(2,012	)		(2,964	)
Net change in cash and cash equivalents, including restricted cash		71			(2,568	)
Cash and cash equivalents, including restricted cash, at beginning of period		206			2,965
Cash and cash equivalents, including restricted cash, at end of period	$	277		$	397

See Notes to Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 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 June 30, 2023:
Balance March 31, 2023	$	27,843		$	(1,297	)	$	241	$	1,072		$	27,859
Net income		1,253			–			–		29			1,282
Cash distributions paid to common unitholders		(1,065	)		–			–		–			(1,065	)
Cash payments made in connection with distribution equivalent rights		(10	)		–			–		–			(10	)
Cash distributions paid to noncontrolling interests		–			–			–		(39	)		(39	)
Cash contributions from noncontrolling interests		–			–			–		11			11
Repurchase and cancellation of common units under 2019 Buyback Program		(75	)		–			–		–			(75	)
Amortization of fair value of equity-based awards		44			–			–		–			44
Cash flow hedges		–			–			27		–			27
Other, net		(10	)		–			–		(2	)		(12	)
Balance, June 30, 2023	$	27,980		$	(1,297	)	$	268	$	1,071		$	28,022

	Partners’ Equity
	Common Limited Partner Interests			Treasury Units			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests in Consolidated Subsidiaries			Total
For the Six Months Ended June 30, 2023:
Balance, December 31, 2022	$	27,555		$	(1,297	)	$	365		$	1,079		$	27,702
Net income		2,643			–			–			60			2,703
Cash distributions paid to common unitholders		(2,129	)		–			–			–			(2,129	)
Cash payments made in connection with distribution equivalent rights		(19	)		–			–			–			(19	)
Cash distributions paid to noncontrolling interests		–			–			–			(81	)		(81	)
Cash contributions from noncontrolling interests		–			–			–			15			15
Repurchase and cancellation of common units under 2019 Buyback Program		(92	)		–			–			–			(92	)
Amortization of fair value of equity-based awards		85			–			–			–			85
Cash flow hedges		–			–			(97	)		–			(97	)
Other, net		(63	)		–			–			(2	)		(65	)
Balance, June 30, 2023	$	27,980		$	(1,297	)	$	268		$	1,071		$	28,022

See Notes to Unaudited Condensed Consolidated Financial Statements. For information regarding Unit History and

Accumulated Other Comprehensive Income (Loss), see Note 8.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2022

(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 June 30, 2022:
Balance, March 31, 2022	$	26,610		$	(1,297	)	$	240		$	1,104		$	26,657
Net income		1,411			–			–			28			1,439
Cash distributions paid to common unitholders		(1,014	)		–			–			–			(1,014	)
Cash payments made in connection with distribution equivalent rights		(9	)		–			–			–			(9	)
Cash distributions paid to noncontrolling interests		–			–			–			(40	)		(40	)
Cash contributions from noncontrolling interests		–			–			–			2			2
Repurchase and cancellation of common units under 2019 Buyback Program		(35	)		–			–			–			(35	)
Amortization of fair value of equity-based awards		41			–			–			–			41
Cash flow hedges		–			–			(63	)		–			(63	)
Other, net		(1	)		–			–			–			(1	)
Balance, June 30, 2022	$	27,003		$	(1,297	)	$	177		$	1,094		$	26,977

	Partners’ Equity
	Common Limited Partner Interests			Treasury Units			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests in Consolidated Subsidiaries			Total
For the Six Months Ended June 30, 2022:
Balance, December 31, 2021	$	26,340		$	(1,297	)	$	286		$	1,110		$	26,439
Net income		2,707			–			–			62			2,769
Cash distributions paid to common unitholders		(2,026	)		–			–			–			(2,026	)
Cash payments made in connection with distribution equivalent rights		(17	)		–			–			–			(17	)
Cash distributions paid to noncontrolling interests		–			–			–			(82	)		(82	)
Cash contributions from noncontrolling interests		–			–			–			4			4
Repurchase and cancellation of common units under 2019 Buyback Program		(35	)		–			–			–			(35	)
Amortization of fair value of equity-based awards		79			–			–			–			79
Cash flow hedges		–			–			(109	)		–			(109	)
Other, net		(45	)		–			–			–			(45	)
Balance, June 30, 2022	$	27,003		$	(1,297	)	$	177		$	1,094		$	26,977

See Notes to Unaudited Condensed Consolidated Financial Statements. For information regarding Unit History and

Accumulated Other Comprehensive Income (Loss), see Note 8.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

KEY REFERENCES USED IN THESE

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors of Enterprise GP (the “Board”); (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board; and (iii) W. Randall Fowler, who is also a director and the Co-Chief Executive Officer and Chief Financial 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 32.3% of the Partnership’s common units outstanding at June 30, 2023.

With the exception of per unit amounts, or as noted within the context of each disclosure,

the dollar amounts presented in the tabular data within these disclosures are

stated in millions of dollars.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Partnership Organization and Operations

We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Our preferred units are not publicly traded. We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership. We conduct substantially all of our business operations through EPO and its consolidated subsidiaries.

Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations include:

•

natural gas gathering, treating, processing, transportation and storage;

•

NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases (“LPG”) and ethane);

•

crude oil gathering, transportation, storage, and marine terminals;

•

propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities;

•

petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”)); and

•

a marine transportation business that operates on key U.S. inland and intracoastal waterway systems.

Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers. See Note 14 for information regarding related party matters.

Our results of operations for the six months ended June 30, 2023 are not necessarily indicative of results expected for the full year of 2023. 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, 2022 (the “2022 Form 10-K”) filed with the SEC on February 28, 2023.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 2. Summary of Significant Accounting Policies

Apart from those matters described in this footnote, there have been no updates to our significant accounting policies since those reported under Note 2 of the 2022 Form 10-K.

Allowance for Credit Losses

We estimate our allowance for credit losses at each reporting date using a current expected credit loss model, which requires the measurement of expected credit losses for financial assets (e.g., accounts receivable) based on historical experience with customers, current economic conditions, and reasonable and supportable forecasts. We may also increase the allowance for credit losses in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties.

The following table presents our allowance for credit losses activity since December 31, 2022:

Allowance for credit losses, December 31, 2022	$	54
Charged to costs and expenses		–
Charged to other accounts		–
Deductions		(4	)
Allowance for credit losses, June 30, 2023	$	50

Cash, Cash Equivalents and Restricted Cash

The following table provides a reconciliation of cash and cash equivalents, and restricted cash reported within the Unaudited Condensed Consolidated Balance Sheets that sum to the total of the amounts shown in the Unaudited Condensed Statements of Consolidated Cash Flows.

	June 30, 2023		December 31, 2022
Cash and cash equivalents	$	183	$	76
Restricted cash		94		130
Total cash, cash equivalents and restricted cash shown in the Unaudited Condensed Statements of Consolidated Cash Flows	$	277	$	206

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:

	June 30, 2023		December 31, 2022
NGLs	$	1,678	$	1,689
Petrochemicals and refined products		273		430
Crude oil		530		411
Natural gas		16		24
Total	$	2,497	$	2,554

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2023			2022			2023			2022
Cost of sales (1)		$	7,679		$	12,908		$	17,010		$	23,006
Lower of cost or net realizable value adjustments recognized in cost of sales			2			3			9			7

(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.

Note 4. Property, Plant and Equipment

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

	Estimated Useful Life in Years			June 30, 2023		December 31, 2022
Plants, pipelines and facilities (1)		3-45	(5)	$	54,879	$	54,396
Underground and other storage facilities (2)		5-40	(6)		4,363		4,329
Transportation equipment (3)		3-10			231		222
Marine vessels (4)		15-30			932		921
Land					397		387
Construction in progress					3,858		2,867
Subtotal					64,660		63,122
Less accumulated depreciation					19,667		18,800
Subtotal property, plant and equipment, net					44,993		44,322
Capitalized major maintenance costs for reaction-based plants, net of accumulated amortization (7)					61		79
Property, plant and equipment, net				$	45,054	$	44,401

(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 1.1 years.

Property, plant and equipment at June 30, 2023 and December 31, 2022 includes $108 million and $117 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents information regarding our asset retirement obligations, or AROs, since December 31, 2022:

ARO liability balance, December 31, 2022	$	234
Liabilities incurred (1)		3
Revisions in estimated cash flows (2)		(9	)
Liabilities settled (3)		(5	)
Accretion expense (4)		7
ARO liability balance, June 30, 2023	$	230

(1)	Represents the initial recognition of estimated ARO liabilities during period.
(2)	Represents subsequent adjustments to estimated ARO liabilities during period.
(3)	Represents cash payments to settle ARO liabilities during period.
(4)	Represents 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 $230 million total ARO liability recorded at June 30, 2023, $16 million was reflected as a current liability and $214 million as a long-term liability.

The following table summarizes our depreciation expense and capitalized interest amounts for the periods indicated:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022
Depreciation expense (1)	$	453	$	445	$	903	$	883
Capitalized interest (2)		37		21		69		38

(1)

Depreciation expense is a component of “Costs and expenses” as presented on our Unaudited Condensed Statements of Consolidated Operations.

(2)

We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life as a component of depreciation expense. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise.

Note 5. Investments in Unconsolidated Affiliates

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

	June 30, 2023		December 31, 2022
NGL Pipelines & Services	$	622	$	640
Crude Oil Pipelines & Services		1,675		1,677
Natural Gas Pipelines & Services		32		32
Petrochemical & Refined Products Services		3		3
Total	$	2,332	$	2,352

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022
NGL Pipelines & Services	$	30	$	36	$	69	$	70
Crude Oil Pipelines & Services		88		70		152		151
Natural Gas Pipelines & Services		2		–		3		2
Petrochemical & Refined Products Services		1		1		1		1
Total	$	121	$	107	$	225	$	224

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 6. Intangible Assets and Goodwill

Identifiable Intangible Assets

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

	June 30, 2023							December 31, 2022
	Gross Value		Accumulated Amortization			Carrying Value		Gross Value		Accumulated Amortization			Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	449	$	(257	)	$	192	$	449	$	(249	)	$	200
Contract-based intangibles		751		(95	)		656		749		(84	)		665
Segment total		1,200		(352	)		848		1,198		(333	)		865
Crude Oil Pipelines & Services:
Customer relationship intangibles		2,195		(477	)		1,718		2,195		(431	)		1,764
Contract-based intangibles		283		(273	)		10		283		(271	)		12
Segment total		2,478		(750	)		1,728		2,478		(702	)		1,776
Natural Gas Pipelines & Services:
Customer relationship intangibles		1,350		(607	)		743		1,350		(588	)		762
Contract-based intangibles		639		(201	)		438		639		(195	)		444
Segment total		1,989		(808	)		1,181		1,989		(783	)		1,206
Petrochemical & Refined Products Services:
Customer relationship intangibles		181		(83	)		98		181		(80	)		101
Contract-based intangibles		45		(29	)		16		45		(28	)		17
Segment total		226		(112	)		114		226		(108	)		118
Total intangible assets	$	5,893	$	(2,022	)	$	3,871	$	5,891	$	(1,926	)	$	3,965

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022
NGL Pipelines & Services	$	10	$	9	$	19	$	17
Crude Oil Pipelines & Services		25		21		48		41
Natural Gas Pipelines & Services		13		14		25		25
Petrochemical & Refined Products Services		2		1		4		3
Total	$	50	$	45	$	96	$	86

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

Remainder of 2023				2024				2025				2026				2027
$	107			$	222			$	230			$	237			$	235

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 2022 Form 10-K.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 7. Debt Obligations

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

	June 30, 2023			December 31, 2022
EPO senior debt obligations:
Commercial Paper Notes, variable-rates	$	355		$	495
Senior Notes HH, 3.35% fixed-rate, due March 2023		–			1,250
Senior Notes JJ, 3.90% fixed-rate, due February 2024		850			850
March 2023 $1.5 Billion 364-Day Revolving Credit Agreement, variable-rate, due March 2024 (1)		–			–
Senior Notes MM, 3.75% fixed-rate, due February 2025		1,150			1,150
Senior Notes FFF, 5.05% fixed-rate, due January 2026		750			–
Senior Notes PP, 3.70% fixed-rate, due February 2026		875			875
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			–
Senior Notes D, 6.875% fixed-rate, due March 2033		500			500
Senior Notes H, 6.65% fixed-rate, due October 2034		350			350
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 CCC, 3.95% fixed-rate, due January 2060		1,000			1,000
Total principal amount of senior debt obligations		26,630			26,270
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		28,926			28,566
Other, non-principal amounts		(279	)		(271	)
Less current maturities of debt		(1,204	)		(1,744	)
Total long-term debt	$	27,443		$	26,551

(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 London Interbank Offered Rate (“LIBOR”) plus 2.778%.
(4)	Variable rate is reset quarterly and based on 3-month LIBOR plus 2.986%.
(5)	Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 3.033%.
(6)	Fixed rate of 5.375% through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.57%.
(7)	See discussion below in “Variable Interest Rates” regarding the LIBOR replacement and LIBOR replacement rate.

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Variable Interest Rates

The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the six months ended June 30, 2023:

	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
Commercial Paper Notes	4.59% to 5.43%	5.17%
EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes	7.54% to 8.27%	7.76%
EPO Junior Subordinated Notes D	7.63% to 8.30%	7.91%

Amounts borrowed under EPO’s March 2023 $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) the Secured Overnight Financing Rate (“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.

In July 2017, the Financial Conduct Authority in the U.K. announced a desire to phase out LIBOR as a benchmark by the end of June 2023. In December 2022, the Board of Governors of the Federal Reserve System approved a final rule to implement the Adjustable Interest Rate (LIBOR) Act, which established benchmark replacements for certain contracts that reference various tenors of LIBOR and do not provide an alternative rate or would result in a rate that is expressed in terms of the last known value of LIBOR (typically referred to as a “frozen LIBOR” provision). The final rule became effective during the first quarter of 2023. As a result of the LIBOR Act, our Junior Subordinated Notes C and D and the TEPPCO Junior Subordinated Notes, which were subject to a variable rate (as defined by the applicable agreement) based on three-month LIBOR (in each case, a “LIBOR Rate”) through June 30, 2023, replaced the applicable LIBOR Rate with a variable rate based on the three-month CME Term SOFR (“SOFR Rate”) as administered by the CME Group Benchmark Administration, Ltd. plus a 0.26161% tenor spread adjustment beginning on July 1, 2023. Additionally, our Junior Subordinated Notes E and F, which would have been subject to a variable rate (as defined by the applicable agreement) based on three-month LIBOR beginning in August 2027 and February 2028, respectively, will replace the applicable LIBOR Rate with the three-month SOFR Rate plus a 0.26161% tenor spread adjustment. The foregoing tenor spread adjustment will be in addition to the applicable spread under the terms of each series of Junior Subordinated Notes. We do not expect the transition from LIBOR to have a material financial impact on us.

Scheduled Maturities of Debt

The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at June 30, 2023 for the next five years, and in total thereafter:

			Scheduled Maturities of Debt
	Total		Remainder of 2023		2024		2025		2026		2027		Thereafter
Commercial Paper Notes	$	355	$	355	$	–	$	–	$	–	$	–	$	–
Senior Notes		26,275		–		850		1,150		1,625		575		22,075
Junior Subordinated Notes		2,296		–		–		–		–		–		2,296
Total	$	28,926	$	355	$	850	$	1,150	$	1,625	$	575	$	24,371

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 2023 $1.5 Billion 364-Day Revolving Credit Agreement

In March 2023, EPO entered into a new 364-Day Revolving Credit Agreement (the “March 2023 $1.5 Billion 364-Day Revolving Credit Agreement”) that replaced its September 2022 364-Day Revolving Credit Agreement. There were no principal amounts outstanding under the September 2022 364-Day Revolving Credit Agreement when it was replaced by the March 2023 $1.5 Billion 364-Day Revolving Credit Agreement. As of June 30, 2023, there were no principal amounts outstanding under the March 2023 $1.5 Billion 364-Day Revolving Credit Agreement.

Under the terms of the March 2023 $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 2023 $1.5 Billion 364-Day Revolving Credit Agreement matures in March 2024. 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 2025. Borrowings under the March 2023 $1.5 Billion 364-Day Revolving Credit Agreement may be used for working capital, capital expenditures, acquisitions and general company purposes.

The March 2023 $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 2023 $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 2023 $1.5 Billion 364-Day Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by the Partnership.

March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement

In March 2023, EPO entered into a new revolving credit agreement that matures in March 2028 (the “March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement”). The March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement replaced EPO’s prior multi-year revolving credit agreement that was scheduled to mature in September 2026. There were no principal amounts outstanding under the prior multi-year revolving credit agreement when it was replaced by the March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement. As of June 30, 2023, there were no principal amounts outstanding under the March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement.

Under the terms of the March 2023 $2.7 Billion Multi-Year Revolving Credit 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) at a variable interest rate for a term of five years, subject to the terms and conditions set forth therein. The March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement matures in March 2028, although the maturity date may be extended at EPO’s request (up to two requests) for a one-year extension of the maturity date by delivering a request prior to the maturity date and with the consent of required lenders as set forth under the March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement. Borrowings under the March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement may be used for working capital, capital expenditures, acquisitions and general company purposes.

The March 2023 $2.7 Billion Multi-Year 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 2023 $2.7 Billion Multi-Year 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 2023 $2.7 Billion Multi-Year 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 $1.75 Billion of Senior Notes in January 2023

In January 2023, EPO issued $1.75 billion aggregate principal amount of senior notes comprised of (i) $750 million principal amount of senior notes due January 2026 (“Senior Notes FFF”) and (ii) $1.0 billion principal amount of senior notes due January 2033 (“Senior Notes GGG”). 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 $1.25 billion principal amount of 3.35% Senior Notes HH at their maturity in March 2023 and amounts outstanding under our commercial paper program).

Senior Notes FFF were issued at 99.893% of their principal amount and have a fixed-rate interest rate of 5.05% per year. Senior Notes GGG were issued at 99.803% of their principal amount and have a fixed-rate interest rate of 5.35% per year. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

Letters of Credit

At June 30, 2023, EPO had $110 million of letters of credit outstanding primarily related to our commodity hedging activities.

Lender Financial Covenants

We were in compliance with the financial covenants of our consolidated debt agreements at June 30, 2023.

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.

Note 8. Capital Accounts

Common Limited Partner Interests

The following table summarizes changes in the number of our common units outstanding since December 31, 2022:

Common units outstanding at December 31, 2022	2,170,806,347
Common unit repurchases under 2019 Buyback Program	(682,589	)
Common units issued in connection with the vesting of phantom unit awards, net	4,364,301
Other	20,892
Common units outstanding at March 31, 2023	2,174,508,951
Common unit repurchases under 2019 Buyback Program	(2,910,121	)
Common units issued in connection with the vesting of phantom unit awards, net	153,502
Common units outstanding at June 30, 2023	2,171,752,332

Registration Statements

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

In addition, the Partnership has a registration statement on file with the SEC covering the issuance of up to $2.5 billion of its common units in amounts, at prices and on terms based on market conditions and other factors at the time of such offerings (referred to as the Partnership’s at-the-market (“ATM”) program). The Partnership did not issue any common units under its ATM program during the six months ended June 30, 2023. The Partnership’s capacity to issue additional common units under the ATM program remains at $2.5 billion as of June 30, 2023.

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

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Common Unit Repurchases Under 2019 Buyback Program

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

During the three and six months ended June 30, 2023, the Partnership repurchased 2,910,121 and 3,592,710 common units, respectively, under the 2019 Buyback Program through open market purchases. The total cost of these repurchases, including commissions and fees, was $75 million and $92 million, respectively. During the three and six months ended June 30, 2022, the Partnership repurchased 1,408,121 common units under the 2019 Buyback Program through open market purchases. The total cost of these repurchases, including commissions and fees, was $35 million. Common units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition. At June 30, 2023, the remaining available capacity under the 2019 Buyback Program was $1.2 billion.

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

After taking into account tax withholding requirements, the Partnership issued 4,517,803 new common units to employees in connection with the vesting of phantom unit awards during the six months ended June 30, 2023. See Note 12 for information regarding our phantom unit awards.

Common Units Delivered Under DRIP and EUPP

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

During the six months ended June 30, 2023, agents of the Partnership purchased 3,607,985 common units on the open market and delivered them to participants in the DRIP and EUPP. Apart from $2 million attributable to the plan discount available to all participants in the EUPP, the funds used to effect these purchases were sourced from the DRIP and EUPP participants. No other Partnership funds were used to satisfy these obligations. We plan to use open market purchases to satisfy DRIP and EUPP reinvestments in connection with the distribution expected to be paid on August 14, 2023.

Preferred Units

There were 50,412 of our Series A Cumulative Convertible Preferred Units (“preferred units”) outstanding at June 30, 2023.

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

During the six months ended June 30, 2023, the Partnership made quarterly cash distributions to its preferred unitholders of $2 million.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Accumulated Other Comprehensive Income (Loss)

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

	Cash Flow Hedges
	Commodity Derivative Instruments			Interest Rate Derivative Instruments			Other		Total
Accumulated Other Comprehensive Income (Loss), December 31, 2022	$	171		$	192		$	2	$	365
Other comprehensive income (loss) for period, before reclassifications		(43	)		(5	)		–		(48	)
Reclassification of losses (gains) to net income during period		(48	)		(1	)		–		(49	)
Total other comprehensive income (loss) for period		(91	)		(6	)		–		(97	)
Accumulated Other Comprehensive Income (Loss), June 30, 2023	$	80		$	186		$	2	$	268

	Cash Flow Hedges
	Commodity Derivative Instruments			Interest Rate Derivative Instruments		Other		Total
Accumulated Other Comprehensive Income (Loss), December 31, 2021	$	137		$	147	$	2	$	286
Other comprehensive income (loss) for period, before reclassifications		(60	)		–		–		(60	)
Reclassification of losses (gains) to net income during period		(63	)		14		–		(49	)
Total other comprehensive income (loss) for period		(123	)		14		–		(109	)
Accumulated Other Comprehensive Income (Loss), June 30, 2022	$	14		$	161	$	2	$	177

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

		For the Three Months Ended June 30,						For the Six Months Ended June 30,
Losses (gains) on cash flow hedges:	Location	2023			2022			2023			2022
Interest rate derivatives	Interest expense	$	(3	)	$	6		$	(1	)	$	14
Commodity derivatives	Revenue		(27	)		(86	)		(51	)		(47	)
Commodity derivatives	Operating costs and expenses		11			(22	)		3			(16	)
Total		$	(19	)	$	(102	)	$	(49	)	$	(49	)

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

Cash Distributions

On July 10, 2023, we announced that the Board declared a quarterly cash distribution of $0.50 per common unit, or $2.00 per common unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the second quarter of 2023. The quarterly distribution is payable on August 14, 2023 to unitholders of record as of the close of business on July 31, 2023. The total amount to be paid is $1.1 billion, which includes $10 million for distribution equivalent rights (“DERs”) on phantom unit awards.

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

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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 June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022
NGL Pipelines & Services:
Sales of NGLs and related products	$	3,040	$	5,580	$	7,304	$	10,620
Segment midstream services:
Natural gas processing and fractionation		300		463		600		803
Transportation		246		229		512		458
Storage and terminals		103		108		202		253
Total segment midstream services		649		800		1,314		1,514
Total NGL Pipelines & Services		3,689		6,380		8,618		12,134
Crude Oil Pipelines & Services:
Sales of crude oil		4,005		5,031		7,931		8,747
Segment midstream services:
Transportation		200		249		355		488
Storage and terminals		99		105		199		222
Total segment midstream services		299		354		554		710
Total Crude Oil Pipelines & Services		4,304		5,385		8,485		9,457
Natural Gas Pipelines & Services:
Sales of natural gas		445		1,359		1,291		2,239
Segment midstream services:
Transportation		330		302		699		571
Total segment midstream services		330		302		699		571
Total Natural Gas Pipelines & Services		775		1,661		1,990		2,810
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		1,591		2,370		3,405		4,124
Segment midstream services:
Fractionation and isomerization		51		47		114		116
Transportation, including marine logistics		155		139		315		277
Storage and terminals		86		78		168		150
Total segment midstream services		292		264		597		543
Total Petrochemical & Refined Products Services		1,883		2,634		4,002		4,667
Total consolidated revenues	$	10,651	$	16,060	$	23,095	$	29,068

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

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unbilled Revenue and Deferred Revenue

The following table provides information regarding our contract assets and contract liabilities at June 30, 2023:

Contract Asset	Location	Balance
Unbilled revenue (current amount)	Prepaid and other current assets	$	4
Total		$	4

Contract Liability	Location	Balance
Deferred revenue (current amount)	Other current liabilities	$	154
Deferred revenue (noncurrent)	Other long-term liabilities		307
Total		$	461

The following table presents significant changes in our unbilled revenue and deferred revenue balances for the six months ended June 30, 2023:

	Unbilled Revenue			Deferred Revenue
Balance at December 31, 2022	$	6		$	501
Amount included in opening balance transferred to other accounts during period (1)		(6	)		(195	)
Amount recorded during period (2)		36			472
Amounts recorded during period transferred to other accounts (1)		(32	)		(305	)
Other changes		–			(12	)
Balance at June 30, 2023	$	4		$	461

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

Remaining Performance Obligations

The following table presents estimated fixed future consideration from revenue contracts that contain minimum volume commitments, deficiency and similar fees and the term of the contracts exceeds one year. These amounts represent the revenues we expect to recognize in future periods from these contracts as of June 30, 2023.

Period	Fixed Consideration
Six Months Ended December 31, 2023	$	1,998
One Year Ended December 31, 2024		3,607
One Year Ended December 31, 2025		3,158
One Year Ended December 31, 2026		2,928
One Year Ended December 31, 2027		2,716
Thereafter –		10,632
Total	$	25,039

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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.

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.

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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 June 30,						For the Six Months Ended June 30,
	2023			2022			2023			2022
Operating income	$	1,579		$	1,764		$	3,313		$	3,430
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)		545			531			1,078			1,045
Asset impairment charges in operating costs and expenses		3			5			16			19
Net losses (gains) attributable to asset sales and related matters in operating costs and expenses		(2	)		–			(4	)		2
General and administrative costs		56			62			113			124
Non-refundable payments received from shippers attributable to make-up rights (2)		(3	)		39			24			73
Subsequent recognition of revenues attributable to make-up rights (3)		(25	)		(17	)		(45	)		(45	)
Total segment gross operating margin	$	2,153		$	2,384		$	4,495		$	4,648

(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 June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022
Gross operating margin by segment:
NGL Pipelines & Services	$	1,110	$	1,327	$	2,322	$	2,552
Crude Oil Pipelines & Services		422		407		819		822
Natural Gas Pipelines & Services		238		229		552		449
Petrochemical & Refined Products Services		383		421		802		825
Total segment gross operating margin	$	2,153	$	2,384	$	4,495	$	4,648

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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 June 30, 2023	$	3,687	$	4,296	$	772	$	1,883	$	–		$	10,638
Three months ended June 30, 2022		6,374		5,380		1,653		2,634		–			16,041
Six months ended June 30, 2023		8,613		8,471		1,983		4,002		–			23,069
Six months ended June 30, 2022		12,126		9,443		2,797		4,667		–			29,033
Revenues from related parties:
Three months ended June 30, 2023		2		8		3		–		–			13
Three months ended June 30, 2022		6		5		8		–		–			19
Six months ended June 30, 2023		5		14		7		–		–			26
Six months ended June 30, 2022		8		14		13		–		–			35
Intersegment and intrasegment revenues:
Three months ended June 30, 2023		9,284		12,212		117		4,095		(25,708	)		–
Three months ended June 30, 2022		19,098		11,957		218		5,290		(36,563	)		–
Six months ended June 30, 2023		21,980		24,796		253		8,801		(55,830	)		–
Six months ended June 30, 2022		37,413		21,871		421		8,512		(68,217	)		–
Total revenues:
Three months ended June 30, 2023		12,973		16,516		892		5,978		(25,708	)		10,651
Three months ended June 30, 2022		25,478		17,342		1,879		7,924		(36,563	)		16,060
Six months ended June 30, 2023		30,598		33,281		2,243		12,803		(55,830	)		23,095
Six months ended June 30, 2022		49,547		31,328		3,231		13,179		(68,217	)		29,068
Equity in income of unconsolidated affiliates:
Three months ended June 30, 2023		30		88		2		1		–			121
Three months ended June 30, 2022		36		70		–		1		–			107
Six months ended June 30, 2023		69		152		3		1		–			225
Six months ended June 30, 2022		70		151		2		1		–			224

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 June 30, 2023	$	17,042	$	6,710	$	9,723	$	7,721	$	3,858	$	45,054
At December 31, 2022		17,283		6,760		9,721		7,770		2,867		44,401
Investments in unconsolidated affiliates: (see Note 5)
At June 30, 2023		622		1,675		32		3		–		2,332
At December 31, 2022		640		1,677		32		3		–		2,352
Intangible assets, net: (see Note 6)
At June 30, 2023		848		1,728		1,181		114		–		3,871
At December 31, 2022		865		1,776		1,206		118		–		3,965
Goodwill: (see Note 6)
At June 30, 2023		2,811		1,841		–		956		–		5,608
At December 31, 2022		2,811		1,841		–		956		–		5,608
Segment assets:
At June 30, 2023		21,323		11,954		10,936		8,794		3,858		56,865
At December 31, 2022		21,599		12,054		10,959		8,847		2,867		56,326

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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 June 30,					For the Six Months Ended June 30,
	2023			2022		2023			2022
Consolidated revenues:
NGL Pipelines & Services	$	3,689		$	6,380	$	8,618		$	12,134
Crude Oil Pipelines & Services		4,304			5,385		8,485			9,457
Natural Gas Pipelines & Services		775			1,661		1,990			2,810
Petrochemical & Refined Products Services		1,883			2,634		4,002			4,667
Total consolidated revenues	$	10,651		$	16,060	$	23,095		$	29,068

Consolidated costs and expenses
Operating costs and expenses:
Cost of sales	$	7,679		$	12,908	$	17,010		$	23,006
Other operating costs and expenses (1)		895			884		1,763			1,641
Depreciation, amortization and accretion		562			544		1,109			1,070
Asset impairment charges		3			5		16			19
Net losses (gains) attributable to asset sales and related matters		(2	)		–		(4	)		2
General and administrative costs		56			62		113			124
Total consolidated costs and expenses	$	9,193		$	14,403	$	20,007		$	25,862

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

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 11. Earnings Per Unit

The following table presents our calculation of basic and diluted earnings per common unit for the periods indicated:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2023			2022			2023			2022
BASIC EARNINGS PER COMMON UNIT
Net income attributable to common unitholders	$	1,253		$	1,411		$	2,643		$	2,707
Earnings allocated to phantom unit awards (1)		(11	)		(12	)		(24	)		(23	)
Net income allocated to common unitholders	$	1,242		$	1,399		$	2,619		$	2,684

Basic weighted-average number of common units outstanding		2,174			2,180			2,173			2,179

Basic earnings per common unit	$	0.57		$	0.64		$	1.21		$	1.23

DILUTED EARNINGS PER COMMON UNIT
Net income attributable to common unitholders	$	1,253		$	1,411		$	2,643		$	2,707
Net income attributable to preferred units		1			1			2			2
Net income attributable to limited partners	$	1,254		$	1,412		$	2,645		$	2,709

Diluted weighted-average number of units outstanding:
Distribution-bearing common units		2,174			2,180			2,173			2,179
Phantom units (2)		20			19			20			19
Preferred units (2)		2			2			2			2
Total		2,196			2,201			2,195			2,200

Diluted earnings per common unit	$	0.57		$	0.64		$	1.20		$	1.23

(1)	Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 12 for information regarding the 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 June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022
Equity-classified awards:
Phantom unit awards	$	44	$	40	$	84	$	78
Profits interest awards		1		1		2		2
Total	$	45	$	41	$	86	$	80

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.

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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, 2022		17,982,945		$	23.94
Granted (2)		8,888,370		$	25.80
Vested		(6,583,267	)	$	24.82
Forfeited		(367,253	)	$	24.46
Phantom unit awards at June 30, 2023		19,920,795		$	24.47

(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 2023 was $229 million based on a grant date market price of the Partnership’s common units ranging from $25.80 to $25.95 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 June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022
Cash payments made in connection with DERs	$	10	$	9	$	19	$	17
Total intrinsic value of phantom unit awards that vested during period		5		7		176		149

For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $272 million at June 30, 2023, of which our share of such cost is currently estimated to be $225 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 2.5 years.

Profits Interest Awards

EPCO has two limited partnerships (referred to as “Employee Partnerships”) that serve as long-term incentive arrangements for key employees of EPCO by providing them a profits interest in one or more of the Employee Partnerships. At June 30, 2023, our share of the total unrecognized compensation cost related to the Employee Partnerships was $2 million, which we expect to recognize over a weighted-average period of less than one year.

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.

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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 2022, we entered into a treasury lock transaction to fix the ten-year treasury rate at 3.45% on a notional amount of $750 million. In January 2023, we entered into an additional treasury lock transaction to fix the three-year treasury rate at 4.165% on a notional amount of $750 million. The purpose of these transactions was to hedge the underlying interest rate risk associated with debt issuances which occurred in January 2023 (see Note 7). Both of our treasury lock transactions were designated as cash flow hedges of the interest payments associated with these debt issuances. In January 2023, we terminated both treasury lock transactions simultaneously with our issuance of the three-year and ten-year notes and received total cash proceeds of $21 million. As cash flow hedges, gains on these derivative instruments are reflected as a component of accumulated other comprehensive income and will be amortized to earnings as a reduction to 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.

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

•

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

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

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

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes our portfolio of commodity derivative instruments outstanding at June 30, 2023 (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”))	0.2	n/a	Cash flow hedge
Forecasted sales of natural gas (Bcf)	9.2	n/a	Cash flow hedge
Forecasted sales of NGLs (MMBbls)	0.6	n/a	Cash flow hedge
Octane enhancement:
Forecasted sales of octane enhancement products (MMBbls)	3.2	0.9	Cash flow hedge
Natural gas marketing:
Forecasted purchases of natural gas (Bcf)	2.1	n/a	Cash flow hedge
Forecasted sales of natural gas (Bcf)	1.4	n/a	Cash flow hedge
Natural gas storage inventory management activities (Bcf)	2.9	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)	90.5	3.9	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)	108.0	2.8	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)	0.1	n/a	Cash flow hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)	11.4	n/a	Cash flow hedge
Forecasted sales of crude oil (MMBbls)	9.4	n/a	Cash flow hedge
Petrochemical marketing:
Forecasted sales of petrochemical products (MMBbls)	0.5	n/a	Cash flow hedge
Commercial energy:
Forecasted purchases of power related to asset operations (terawatt hours (“TWh”))	1.4	2.2	Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (3)	9.1	n/a	Mark-to-market
NGL risk management activities (MMBbls) (3)	23.5	2.6	Mark-to-market
Refined products risk management activities (MMBbls) (3)	2.6	n/a	Mark-to-market
Crude oil risk management activities (MMBbls) (3)	88.3	7.7	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 2025, January 2024 and January 2025, respectively.
(3)	Reflects the use of derivative instruments to manage risks associated with our transportation, processing and storage assets.

The carrying amount of our inventories subject to fair value hedges was $8 million and $12 million at June 30, 2023 and December 31, 2022, respectively.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Tabular Presentation of Fair Value Amounts, and Gains and Losses on

Derivative Instruments and Related Hedged Items

The following table provides a balance sheet overview of our derivative assets and liabilities at the dates indicated:

	Asset Derivatives						Liability Derivatives
	June 30, 2023			December 31, 2022			June 30, 2023			December 31, 2022
	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	$	26	Current liabilities	$	–	Current liabilities	$	–
Commodity derivatives	Current assets	$	278	Current assets	$	422	Current liabilities	$	266	Current liabilities	$	316
Commodity derivatives	Other assets		39	Other assets		43	Other liabilities		51	Other liabilities		58
Total commodity derivatives			317			465			317			374
Total derivatives designated as hedging instruments		$	317		$	491		$	317		$	374

Derivatives not designated as hedging instruments
Commodity derivatives	Current assets	$	55	Current assets	$	21	Current liabilities	$	64	Current liabilities	$	38
Commodity derivatives	Other assets		2	Other assets		–	Other liabilities		1	Other liabilities		–
Total commodity derivatives			57			21			65			38
Total derivatives not designated as hedging instruments		$	57		$	21		$	65		$	38

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
	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet			Amounts of Assets Presented in the Balance Sheet			Financial Instruments				Cash Collateral Received		Cash Collateral Paid			Amounts That Would Have Been Presented On Net Basis
	(i)			(ii)			(iii) = (i) – (ii)			(iv)									(v) = (iii) + (iv)
As of June 30, 2023:
Commodity derivatives		$	374		$	–		$	374		$	(373	)	$	–	$	–			$	1
As of December 31, 2022:
Interest rate derivatives		$	26		$	–		$	26		$	–		$	–	$	–			$	26
Commodity derivatives			486			–			486			(411	)		–		(74	)			1

	Offsetting of Financial Liabilities and Derivative Liabilities
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet			Amounts of Liabilities Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet											Amounts That Would Have Been Presented On Net Basis
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet			Amounts of Liabilities Presented in the Balance Sheet			Financial Instruments				Cash Collateral Received			Cash Collateral Paid				Amounts That Would Have Been Presented On Net Basis
	(i)			(ii)			(iii) = (i) – (ii)			(iv)											(v) = (iii) + (iv)
As of June 30, 2023:
Commodity derivatives		$	382		$	–		$	382		$	(373	)		$	–		$	(9	)		$	–
As of December 31, 2022:
Commodity derivatives		$	412		$	–		$	412		$	(411	)		$	–		$	–			$	1

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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 June 30,					For the Six Months Ended June 30,
		2023		2022			2023		2022
Commodity derivatives	Revenue	$	–	$	(59	)	$	4	$	(124	)
Total		$	–	$	(59	)	$	4	$	(124	)

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Hedged Item
		For the Three Months Ended June 30,				For the Six Months Ended June 30,
		2023		2022		2023		2022
Commodity derivatives	Revenue	$	3	$	4	$	2	$	25
Total		$	3	$	4	$	2	$	25

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 June 30,				For the Six Months Ended June 30,
	2023		2022		2023			2022
Interest rate derivatives	$	–	$	–	$	(5	)	$	–
Commodity derivatives – Revenue (1)		34		23		(31	)		(98	)
Commodity derivatives – Operating costs and expenses (1)		12		16		(12	)		38
Total	$	46	$	39	$	(48	)	$	(60	)

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

Derivatives in Cash Flow Hedging Relationships	Location	Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income
		For the Three Months Ended June 30,						For the Six Months Ended June 30,
		2023			2022			2023			2022
Interest rate derivatives	Interest expense	$	3		$	(6	)	$	1		$	(14	)
Commodity derivatives	Revenue		27			86			51			47
Commodity derivatives	Operating costs and expenses		(11	)		22			(3	)		16
Total		$	19		$	102		$	49		$	49

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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 $9 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 $93 million of net gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, with $120 million as an increase in revenue and $27 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 June 30,				For the Six Months Ended June 30,
		2023		2022		2023		2022
Commodity derivatives	Revenue	$	17	$	2	$	217	$	45
Commodity derivatives	Operating costs and expenses		–		3		–		7
Total		$	17	$	5	$	217	$	52

The $217 million net gain recognized for the six months ended June 30, 2023 (as noted in the preceding table) from derivatives not designated as hedging instruments consists of $226 million of net realized gains and $9 million of net unrealized mark-to-market losses attributable to commodity derivatives.

Fair Value Measurements

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

The values for commodity derivatives are presented before and after the application of Chicago Mercantile Exchange (“CME”) Rule 814, which deems that financial instruments cleared by the CME are settled daily in connection with variation margin payments. As a result of this exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. Derivative transactions cleared on exchanges other than the CME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	At June 30, 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	$	147		$	984		$	–	$	1,131
Impact of CME Rule 814		(109	)		(648	)		–		(757	)
Total commodity derivatives		38			336			–		374
Total	$	38		$	336		$	–	$	374

Financial liabilities:
Commodity derivatives:
Value before application of CME Rule 814	$	80		$	961		$	–	$	1,041
Impact of CME Rule 814		(42	)		(617	)		–		(659	)
Total commodity derivatives		38			344			–		382
Total	$	38		$	344		$	–	$	382

	At December 31, 2022 Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
Financial assets:
Interest rate derivatives:	$	–		$	26		$	–	$	26
Commodity derivatives:
Value before application of CME Rule 814		166			1,170			–		1,336
Impact of CME Rule 814		(161	)		(689	)		–		(850	)
Total commodity derivatives		5			481			–		486
Total	$	5		$	507		$	–	$	512

Financial liabilities:
Commodity derivatives:
Value before application of CME Rule 814	$	95		$	1,118		$	–	$	1,213
Impact of CME Rule 814		(90	)		(711	)		–		(801	)
Total commodity derivatives		5			407			–		412
Total	$	5		$	407		$	–	$	412

In the aggregate, the fair value of our commodity hedging portfolios at June 30, 2023 was a net derivative asset of $90 million prior to the impact of CME Rule 814.

Financial assets and liabilities recorded on the balance sheet at June 30, 2023 using significant unobservable inputs (Level 3) are not material to the Unaudited Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Other Fair Value Information

The carrying amounts of cash and cash equivalents (including restricted cash balances), accounts receivable, commercial paper notes and accounts payable approximate their fair values based on their short-term nature. The estimated total fair value of our fixed-rate debt obligations was $25.6 billion and $24.2 billion at June 30, 2023 and December 31, 2022, respectively. The aggregate carrying value of these debt obligations was $28.0 billion and $27.5 billion at June 30, 2023 and December 31, 2022, 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 June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022
Revenues – related parties:
Unconsolidated affiliates	$	13	$	19	$	26	$	35
Costs and expenses – related parties:
EPCO and its privately held affiliates	$	335	$	315	$	645	$	606
Unconsolidated affiliates		35		60		84		121
Total	$	370	$	375	$	729	$	727

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

	June 30, 2023		December 31, 2022
Accounts receivable - related parties:
EPCO and its privately held affiliates	$	–	$	1
Unconsolidated affiliates		7		10
Total	$	7	$	11

Accounts payable - related parties:
EPCO and its privately held affiliates	$	83	$	221
Unconsolidated affiliates		7		11
Total	$	90	$	232

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

Relationship with EPCO and Affiliates

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

At June 30, 2023, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us:

Total Number of Limited Partner Interests Held	Percentage of Common Units Outstanding
702,185,916 common units	32.3%

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Of the total number of Partnership common units held by EPCO and its privately held affiliates, 62,976,464 have been pledged as security under the separate credit facilities of EPCO and its privately held affiliates at June 30, 2023. These credit facilities contain customary and other events of default, including defaults by us and other affiliates of EPCO. An event of default, followed by a foreclosure on the pledged collateral, could ultimately result in a change in ownership of these units and affect the market price of the Partnership’s common units.

The Partnership and Enterprise GP are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are also separate from those of EPCO and its other affiliates. EPCO and its privately held affiliates use cash on hand and cash distributions they receive from us and other investments to fund their other activities and to meet their respective debt obligations, if any. During the six months ended June 30, 2023 and 2022, we paid EPCO and its privately held affiliates cash distributions totaling $666 million and $632 million, respectively.

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022
Operating costs and expenses	$	295	$	275	$	568	$	526
General and administrative expenses		35		36		66		72
Total costs and expenses	$	330	$	311	$	634	$	598

We lease office space from privately held affiliates of EPCO at rental rates that approximate market rates. For each of the three months ended June 30, 2023 and 2022, we recognized $4 million of related party operating lease expense in connection with these office space leases. For each of the six months ended June 30, 2023 and 2022, we recognized $7 million 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 six months ended June 30, 2023 and 2022.

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2023			2022			2023			2022
Current portion of income tax benefit (provision):
Federal	$	(14	)	$	–		$	(10	)	$	–
State		(10	)		(7	)		(21	)		(17	)
Foreign		–			(3	)		–			(3	)
Total current portion		(24	)		(10	)		(31	)		(20	)
Deferred portion of income tax benefit (provision):
Federal		11			(6	)		4			(13	)
State		–			(1	)		4			(3	)
Total deferred portion		11			(7	)		8			(16	)
Total provision for income taxes	$	(13	)	$	(17	)	$	(23	)	$	(36	)

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2023			2022			2023			2022
Pre-Tax Net Book Income (“NBI”)	$	1,296		$	1,457		$	2,728		$	2,807

Texas Margin Tax (1)		(10	)		(7	)		(16	)		(19	)
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		(3	)		(4	)		(6	)		(7	)
Other		–			(5	)		–			(9	)
Provision for income taxes	$	(13	)	$	(17	)	$	(23	)	$	(36	)

Effective income tax rate		(1.0	)%		(1.2	)%		(0.8	)%		(1.3	)%

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

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

	June 30,		December 31,
	2023		2022
Deferred tax liabilities:
Attributable to investment in OTA	$	423	$	406
Attributable to property, plant and equipment		127		133
Attributable to investments in other entities		5		5
Other		60		60
Total deferred tax liabilities		615		604
Deferred tax assets:
Net operating loss carryovers (1)		42		22
Temporary differences related to Texas Margin Tax		4		4
Total deferred tax assets		46		26
Valuation allowance		22		22
Total deferred tax assets, net of valuation allowance		24		4
Total net deferred tax liabilities	$	591	$	600

(1)	The loss amount presented as of June 30, 2023 has an indefinite carryover period. All losses are subject to limitations on their utilization.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 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 June 30, 2023 and December 31, 2022, 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 $28.9 billion and $28.6 billion at June 30, 2023 and December 31, 2022, 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 2022 Form 10-K.

The following table presents information regarding operating leases where we are the lessee at June 30, 2023:

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	$	194	$	194	9 years	3.9%
Transportation equipment		17		18	4 years	4.1%
Office and warehouse space		154		188	14 years	3.0%
Total	$	365	$	400

(1)	Right of use (“ROU”) asset amounts are a component of “Other assets” on our Unaudited Condensed Consolidated Balance Sheet.
(2)	At June 30, 2023, lease liabilities of $65 million and $335 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 June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022
Long-term operating leases:
Fixed lease expense:
Non-cash lease expense (amortization of ROU assets)	$	17	$	14	$	33	$	27
Related accretion expense on lease liability balances		3		3		7		6
Total fixed lease expense		20		17		40		33
Variable lease expense		3		1		6		1
Subtotal operating lease expense		23		18		46		34
Short-term operating leases		27		23		52		40
Total operating lease expense	$	50	$	41	$	98	$	74

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Cash payments attributable to operating lease liabilities were $21 million and $16 million for the three months ended June 30, 2023 and 2022, respectively. For the six months ended June 30, 2023 and 2022, cash paid for operating lease liabilities was $41 million and $28 million, respectively.

Operating lease income for the three months ended June 30, 2023 and 2022 was $4 million and $3 million, respectively. For the six months ended June 30, 2023 and 2022, operating lease income was $8 million and $6 million, 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 $17.6 billion at December 31, 2022 to $13.8 billion at June 30, 2023 primarily due to a decrease in crude oil and NGL prices between the two reporting dates.

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 Six Months Ended June 30,
	2023			2022
Decrease (increase) in:
Accounts receivable – trade	$	835		$	(1,355	)
Accounts receivable – related parties		2			(8	)
Inventories		62			(467	)
Prepaid and other current assets		(167	)		70
Other assets		10			25
Increase (decrease) in:
Accounts payable – trade		86			(38	)
Accounts payable – related parties		(141	)		(35	)
Accrued product payables		(989	)		2,542
Accrued interest		31			(18	)
Other current liabilities		(86	)		(457	)
Other long-term liabilities		(46	)		(41	)
Net effect of changes in operating accounts	$	(403	)	$	218

Cash payments for interest, net of $69 and $38 capitalized during the six months ended June 30, 2023 and 2022, respectively	$	576		$	624

Cash payments (refunds) for federal and state income taxes	$	12		$	(3	)

We incurred liabilities for construction in progress that had not been paid at June 30, 2023 and December 31, 2022 of $425 million and $238 million, respectively. Such amounts are not included under the caption “Capital expenditures” on the Unaudited Condensed Statements of Consolidated Cash Flows.

Acquisition of Navitas Midstream

In February 2022, we acquired all of the member interests in Navitas Midstream Partners, LLC (“Navitas Midstream”) for $3.2 billion in net cash consideration.

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

RESULTS OF OPERATIONS.

For the Three and Six Months Ended June 30, 2023 and 2022

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, 2022 (the “2022 Form 10-K”), as filed on February 28, 2023 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 six months ended June 30, 2023 (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 2022 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.

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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 second quarter of 2023 compared to the second quarter of 2022. Likewise, the phrase “period-to-period” means the six months ended June 30, 2023 compared to the six months ended June 30, 2022.

Overview of Business

Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the U.S., Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations include:

•

natural gas gathering, treating, processing, transportation and storage;

•

NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases (“LPG”) and ethane);

•

crude oil gathering, transportation, storage, and marine terminals;

•

petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”)); and

•

a marine transportation business that operates on key U.S. inland and intracoastal waterway systems.

The safe operation of our assets is a top priority. We are committed to protecting the environment and the health and safety of the public and those working on our behalf by conducting our business activities in a safe and environmentally responsible manner. For additional information, see “Environmental, Safety and Conservation” within the Regulatory Matters section of Part I, Items 1 and 2 of the 2022 Form 10-K.

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 2022 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 Begins Service At PDH 2 Plant

In July 2023 we placed into service our second propane dehydrogenation plant (“PDH 2”) in Chambers County, Texas. Supported by long-term, fee-based contracts, PDH 2 has the capacity to consume 35 MBPD of propane to produce 1.65 billion pounds of PGP per year, which will help us supply our petrochemical customers with the feedstock to produce products that meet the needs of a growing global population. With the completion and integration of our PDH 2 plant with our existing PDH 1 plant and other propylene production facilities, we now have the capacity to produce approximately 11 billion pounds of propylene per year.

Enterprise Begins Service At Its Twelfth NGL Fractionator in Chambers County, Texas

In July 2023, our twelfth NGL fractionator (“Frac XII”) located in Chambers County, Texas was placed into service. The incremental 150 MBPD of nameplate capacity at Frac XII will help accommodate growing NGL production from new natural gas processing plants in the Permian Basin and help satisfy the demand for feedstocks by the petrochemical and refining industries and LPG exports to developing nations. Supported by long-term customer agreements, the addition of Frac XII increases total NGL fractionation capacity to approximately 1.2 MMBPD at our Chambers County complex and approximately 1.7 MMBPD company-wide.

Enterprise Begins Service At Its Poseidon Natural Gas Processing Plant

In July 2023, we placed into service our Poseidon cryogenic natural gas processing plant (“Poseidon”), which is located in Glasscock County, Texas. The new plant, which is our sixth in the Midland Basin, has a nameplate capacity of 300 MMcf/d and can extract more than 40 MBPD of NGLs. Supported by long-term acreage dedication agreements, the new plant will support Permian Basin producers as they meet growing demand in the U.S. and internationally. With the addition of Poseidon, we now have the capability to process 1.3 Bcf/d of natural gas and extract more than 185 MBPD of NGLs in the Midland Basin.

Enterprise Completes Expansion of Acadian Haynesville Extension

In May 2023, we completed an expansion of our Acadian Haynesville Extension natural gas pipeline. This expansion adds approximately 400 MMcf/d of Haynesville natural gas takeaway capacity to meet growing industrial demand in the Mississippi River Corridor and supports the Louisiana liquefied natural gas export market.

The incremental compression added as part of the expansion project increased total natural gas transportation capacity on the Acadian Haynesville Extension from approximately 2.1 Bcf/d to 2.5 Bcf/d. This expansion is underwritten by long-term, take-or-pay contracts.

Issuance of $1.75 Billion of Senior Notes in January 2023

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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)
2022 by quarter:
1st Quarter	$4.96	$0.40	$1.30	$1.59	$1.60	$2.21	$0.63	$0.39	$0.55
2nd Quarter	$7.17	$0.59	$1.24	$1.50	$1.68	$2.17	$0.61	$0.40	$0.46
3rd Quarter	$8.20	$0.55	$1.08	$1.19	$1.44	$1.72	$0.47	$0.28	$0.26
4th Quarter	$6.26	$0.39	$0.79	$0.97	$1.03	$1.54	$0.32	$0.18	$0.17
2022 Averages	$6.65	$0.48	$1.10	$1.31	$1.44	$1.91	$0.51	$0.31	$0.36

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
2023 Averages	$2.77	$0.23	$0.75	$0.95	$1.00	$1.53	$0.45	$0.22	$0.37

(1)	Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts, which is a division of S&P Global, Inc.
(2)	NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu, Texas Non-TET commercial index prices as reported by Oil Price Information Service, which is a division of Dow Jones.
(3)	Polymer grade propylene prices represent average contract pricing for such product as reported by IHS Markit (“IHS”), which is a division of S&P Global, Inc. Refinery grade propylene (“RGP”) prices represent weighted-average spot prices for such product as reported by IHS.
(4)	The “Indicative Gas Processing Gross Spread” represents our generic estimate of the gross economic benefit from extracting NGLs from natural gas production based on certain pricing assumptions. Specifically, it is the amount by which the assumed economic value of a composite gallon of NGLs in Chambers County, Texas exceeds the value of the equivalent amount of energy in natural gas at Henry Hub, Louisiana. Our estimate of the indicative spread does not consider the operating costs incurred by a natural gas processing facility to extract the NGLs nor the transportation and fractionation costs to deliver the NGLs to market. In addition, the actual gas processing spread earned at each plant is further influenced by regional pricing and extraction dynamics.

The weighted-average indicative market price for NGLs was $0.55 per gallon in the second quarter of 2023 versus $1.06 per gallon in the second quarter of 2022. Likewise, the weighted-average indicative market price for NGLs was $0.61 per gallon during the six months ended June 30, 2023 compared to $1.01 per gallon during the same period in 2022.

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)
2022 by quarter:
1st Quarter	$94.29	$96.43	$96.77	$96.77
2nd Quarter	$108.41	$109.66	$109.96	$110.17
3rd Quarter	$91.56	$93.41	$93.77	$94.17
4th Quarter	$82.64	$83.97	$84.33	$85.50
2022 Averages	$94.23	$95.87	$96.21	$96.65

2023 by quarter:
1st Quarter	$76.13	$77.50	$77.74	$79.00
2nd Quarter	$73.78	$74.48	$74.68	$75.87
2023 Averages	$74.96	$75.99	$76.21	$77.44

(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 United States increased significantly in 2022 and have continued to remain elevated in 2023 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 in 2023, the high cost environment that began in 2022 has generally remained intact in 2023. 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 June 30,						For the Six Months Ended June 30,
	2023			2022			2023			2022
Revenues	$	10,651		$	16,060		$	23,095		$	29,068
Costs and expenses:
Operating costs and expenses:
Cost of sales		7,679			12,908			17,010			23,006
Other operating costs and expenses		895			884			1,763			1,641
Depreciation, amortization and accretion expenses		562			544			1,109			1,070
Asset impairment charges		3			5			16			19
Net losses (gains) attributable to asset sales and related matters		(2	)	‒				(4	)		2
Total operating costs and expenses		9,137			14,341			19,894			25,738
General and administrative costs		56			62			113			124
Total costs and expenses		9,193			14,403			20,007			25,862
Equity in income of unconsolidated affiliates		121			107			225			224
Operating income		1,579			1,764			3,313			3,430
Other income (expense):
Interest expense		(302	)		(309	)		(616	)		(628	)
Other, net		19			2			31			5
Total other expense, net		(283	)		(307	)		(585	)		(623	)
Income before income taxes		1,296			1,457			2,728			2,807
Provision for income taxes		(13	)		(17	)		(23	)		(36	)
Net income		1,283			1,440			2,705			2,771
Net income attributable to noncontrolling interests		(29	)		(28	)		(60	)		(62	)
Net income attributable to preferred units		(1	)		(1	)		(2	)		(2	)
Net income attributable to common unitholders	$	1,253		$	1,411		$	2,643		$	2,707

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 June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022
NGL Pipelines & Services:
Sales of NGLs and related products	$	3,040	$	5,580	$	7,304	$	10,620
Midstream services		649		800		1,314		1,514
Total		3,689		6,380		8,618		12,134
Crude Oil Pipelines & Services:
Sales of crude oil		4,005		5,031		7,931		8,747
Midstream services		299		354		554		710
Total		4,304		5,385		8,485		9,457
Natural Gas Pipelines & Services:
Sales of natural gas		445		1,359		1,291		2,239
Midstream services		330		302		699		571
Total		775		1,661		1,990		2,810
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		1,591		2,370		3,405		4,124
Midstream services		292		264		597		543
Total		1,883		2,634		4,002		4,667
Total consolidated revenues	$	10,651	$	16,060	$	23,095	$	29,068

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Second Quarter of 2023 Compared to Second Quarter of 2022.

Total revenues for the second quarter of 2023 decreased $5.4 billion when compared to the second quarter of 2022 primarily due to a $5.3 billion decrease in marketing revenues.

Revenues from the marketing of NGLs decreased $2.5 billion quarter-to-quarter primarily due to lower average sales prices, which accounted for a $2.3 billion decrease, and lower sales volumes, which accounted for an additional $229 million decrease. Revenues from the marketing of crude oil, natural gas and petrochemicals and refined products decreased a combined net $2.7 billion quarter-to-quarter primarily due to lower average sales prices, which accounted for a $3.5 billion decrease, partially offset by higher sales volumes, which accounted for a $760 million increase.

Revenues from midstream services for the second quarter of 2023 decreased a net $150 million when compared to the second quarter of 2022. Revenues from our natural gas processing facilities decreased $148 million quarter-to-quarter primarily due to lower market values for the equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Revenues from our crude oil pipeline assets decreased $49 million quarter-to-quarter primarily due to lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long-term gathering agreements on our EFS Midstream System. Lastly, revenues from our NGL, natural gas and petrochemicals and refined products pipeline assets increased a combined $57 million quarter-to-quarter primarily due to higher demand for transportation services.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Total revenues for the six months ended June 30, 2023 decreased $6.0 billion when compared to the six months ended June 30, 2022 primarily due to a $5.8 billion decrease in marketing revenues.

Revenues from the marketing of NGLs decreased $3.3 billion period-to-period primarily due to lower average sales prices. Revenues from the marketing of crude oil, natural gas and petrochemicals and refined products decreased a combined net $2.5 billion period-to-period primarily due to lower average sales prices, which accounted for a $4.4 billion decrease, partially offset by higher sales volumes, which accounted for a $1.9 billion increase.

Revenues from midstream services for the six months ended June 30, 2023 decreased a net $174 million when compared to the six months ended June 30, 2022. Revenues from our natural gas processing facilities decreased $181 million period-to-period primarily due to lower market values for the equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Revenues from our crude oil pipeline assets decreased $133 million period-to-period primarily due to lower deficiency revenues as a result of the aforementioned expiration of minimum volume commitments on our EFS Midstream System. Lastly, revenues from our natural gas pipeline assets increased $127 million period-to-period primarily due to higher demand for transportation services and the addition of the Midland Basin Gathering System, which was acquired in February 2022.

Operating costs and expenses

Total operating costs and expenses for the three and six months ended June 30, 2023 decreased $5.2 billion and $5.8 billion, respectively, when compared to the same periods in 2022.

Cost of sales

Second Quarter of 2023 Compared to Second Quarter of 2022. Cost of sales for the second quarter of 2023 decreased $5.2 billion when compared to the second quarter of 2022. The cost of sales associated with the marketing of NGLs decreased $2.9 billion quarter-to-quarter primarily due to lower average purchase prices, which accounted for a $2.7 billion decrease, and lower volumes, which accounted for an additional $235 million decrease. The cost of sales associated with the marketing of crude oil, natural gas and petrochemicals and refined products decreased a combined net $2.3 billion primarily due to lower average purchase prices, which accounted for a $3.0 billion decrease, partially offset by higher volumes, which accounted for a $676 million increase.

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Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Cost of sales for the six months ended June 30, 2023 decreased $6.0 billion when compared to the six months ended June 30, 2022. The cost of sales associated with our marketing of NGLs decreased $3.5 billion period-to-period primarily due to lower average purchase prices. The cost of sales associated with the marketing of crude oil, natural gas and petrochemicals and refined products decreased a combined net $2.5 billion primarily due to lower average purchase prices, which accounted for a $4.2 billion decrease, partially offset by higher volumes, which accounted for a $1.7 billion increase.

Other operating costs and expenses

Other operating costs and expenses for the second quarter of 2023 increased a net $11 million when compared to the second quarter of 2022 primarily due to higher maintenance, rental and other operating costs, which accounted for a $71 million increase, partially offset by lower utility costs, which accounted for a $60 million decrease.

Other operating costs and expenses for the six months ended June 30, 2023 increased $122 million when compared to the six months ended June 30, 2022 primarily due to higher maintenance, rental and other operating costs, which accounted for a $183 million increase, partially offset by lower utility costs, which accounted for a $61 million decrease.

Depreciation, amortization and accretion expenses

Depreciation, amortization and accretion expense for the three and six months ended June 30, 2023 increased a combined $18 million and $39 million, respectively, when compared to the same periods in 2022. Depreciation expense increased $8 million quarter-to-quarter and $21 million period-to-period primarily due to the addition of assets attributable to the acquisition of our Midland Basin System in February 2022 and other assets placed into full or limited service since the end of the respective periods in 2022. Additionally, amortization expense associated with our contract-based intangible assets accounted for an additional $5 million of the quarter-to-quarter increase and $10 million of the period-to-period increase.

General and administrative costs

General and administrative costs for the three and six months ended June 30, 2023 decreased $6 million and $11 million, respectively, when compared to the same periods in 2022 primarily due to lower employee compensation and professional services costs.

Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for the three and six months ended June 30, 2023 increased $14 million and $1 million, respectively, when compared to the same periods in 2022 primarily due to higher earnings from investments in crude oil pipelines.

Operating income

Operating income for the three and six months ended June 30, 2023 decreased $185 million and $117 million, respectively, when compared to the same periods in 2022 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 June 30,						For the Six Months Ended June 30,
	2023			2022			2023			2022
Interest charged on debt principal outstanding (1)	$	336		$	318		$	673		$	641
Impact of interest rate hedging program, including related amortization		(3	)		6			(1	)		14
Interest costs capitalized in connection with construction projects (2)		(37	)		(21	)		(69	)		(38	)
Other		6			6			13			11
Total	$	302		$	309		$	616		$	628

(1)

The weighted-average interest rates on debt principal outstanding during the three and six months ended June 30, 2023 were 4.58% and 4.57%, respectively. The weighted-average interest rate on debt principal outstanding during each of the three and six months ended June 30, 2022 was 4.31%.

(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 $18 million quarter-to-quarter. This increase was primarily due to the issuance of $1.75 billion fixed-rate senior notes in January 2023, which accounted for a $23 million increase, partially offset by a $15 million decrease as a result of the retirement of $1.25 billion of fixed-rate senior notes in March 2023 and the redemption of $350 million of junior subordinated notes in August 2022. In addition, interest expense on our outstanding variable-rate junior subordinated notes increased $6 million primarily due to a quarter-to-quarter increase in the 3-month LIBOR.

Interest charged on debt principal outstanding increased a net $32 million period-to-period. This increase was primarily due to the aforementioned issuance of senior notes, which accounted for a $43 million increase, partially offset by a $26 million decrease as a result of the retirement of $1.4 billion and $1.25 billion of fixed-rate senior notes in February 2022 and March 2023, respectively, and the aforementioned junior subordinated notes. In addition, interest expense on our outstanding variable-rate junior subordinated notes increased $11 million primarily due to a period-to-period increase in the 3-month LIBOR.

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 six months ended June 30, 2023 decreased $4 million and $13 million, respectively, when compared to the same periods in 2022.

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Business Segment Highlights

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 June 30,					For the Six Months Ended June 30,
	2023		2022			2023		2022
Gross operating margin by segment:
NGL Pipelines & Services	$	1,110	$	1,327		$	2,322	$	2,552
Crude Oil Pipelines & Services		422		407			819		822
Natural Gas Pipelines & Services		238		229			552		449
Petrochemical & Refined Products Services		383		421			802		825
Total segment gross operating margin (1)		2,153		2,384			4,495		4,648
Net adjustment for shipper make-up rights		28		(22	)		21		(28	)
Total gross operating margin (non-GAAP)	$	2,181	$	2,362		$	4,516	$	4,620

(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.

Total 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. Total 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 June 30,					For the Six Months Ended June 30,
	2023			2022		2023			2022
Operating income	$	1,579		$	1,764	$	3,313		$	3,430
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)		545			531		1,078			1,045
Asset impairment charges in operating costs and expenses		3			5		16			19
Net losses (gains) attributable to asset sales and related matters in operating costs and expenses		(2	)	‒			(4	)		2
General and administrative costs		56			62		113			124
Total gross operating margin (non-GAAP)	$	2,181		$	2,362	$	4,516		$	4,620

(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 June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022
Segment gross operating margin:
Natural gas processing and related NGL marketing activities	$	310	$	587	$	636	$	1,002
NGL pipelines, storage and terminals		598		539		1,288		1,105
NGL fractionation		202		201		398		445
Total	$	1,110	$	1,327	$	2,322	$	2,552

Selected volumetric data:
NGL pipeline transportation volumes (MBPD)		3,910		3,683		3,944		3,626
NGL marine terminal volumes (MBPD)		765		747		794		696
NGL fractionation volumes (MBPD)		1,376		1,336		1,373		1,327
Equity NGL-equivalent production volumes (MBPD) (1)		173		195		169		189
Fee-based natural gas processing volumes (MMcf/d) (2,3)		5,677		5,133		5,609		5,025

(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

Second Quarter of 2023 Compared to Second Quarter of 2022. Gross operating margin from natural gas processing and related NGL marketing activities for the second quarter of 2023 decreased $277 million when compared to the second quarter of 2022.

Gross operating margin from our NGL marketing activities decreased $102 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $76 million decrease, and lower sales volumes, which accounted for an additional $33 million decrease.

Gross operating margin from our Midland Basin natural gas processing facilities decreased a net $88 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $108 million decrease, partially offset by a 190 MMcf/d increase in fee-based natural gas processing volumes, which accounted for a $21 million increase. Equity NGL-equivalent production volumes at these facilities were flat quarter-to-quarter.

Gross operating margin from our Delaware Basin natural gas processing facilities decreased $29 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes at these facilities increased 64 MMcf/d and equity NGL-equivalent production volumes decreased 3 MBPD quarter-to-quarter.

Gross operating margin from our South Texas natural gas processing facilities decreased $29 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes increased 28 MMcf/d and equity NGL-equivalent production volumes decreased 2 MBPD quarter-to-quarter.

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Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $20 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities). On a combined basis, fee-based natural gas processing volumes and equity NGL-equivalent production volumes decreased 74 MMcf/d and 10 MBPD, respectively, quarter-to-quarter.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $7 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes increased 195 MMcf/d and equity NGL-equivalent production volumes decreased 7 MBPD quarter-to-quarter (net to our interest).

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Gross operating margin from natural gas processing and related NGL marketing activities for the six months ended June 30, 2023 decreased $366 million when compared to the six months ended June 30, 2022.

Gross operating margin from our NGL marketing activities decreased a net $179 million period-to-period primarily due to lower average sales margins, which accounted for a $152 million decrease, and lower sales volumes, which accounted for an additional $39 million decrease, partially offset by higher non-cash, mark-to-market earnings, which accounted for a $12 million increase.

Gross operating margin from our Midland Basin natural gas processing facilities decreased a net $80 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $129 million decrease, and higher operating costs, which accounted for an additional $11 million decrease, partially offset by an increase in total equity NGL-equivalent production volumes, which accounted for a $19 million increase, and an increase in total fee-based natural gas processing volumes, which accounted for an additional $43 million increase. Fee-based natural gas processing volumes at these facilities, which reflect the average daily operating rates from the time the asset was acquired, increased 162 MMcf/d and equity NGL-equivalent production volumes were flat period-to-period.

Gross operating margin from our Delaware Basin natural gas processing facilities decreased $51 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes at these facilities increased 130 MMcf/d and equity NGL-equivalent production volumes decreased 2 MBPD period-to-period.

Gross operating margin from our South Texas natural gas processing facilities decreased $36 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $24 million decrease, and higher maintenance and other operating costs, which accounted for an additional $11 million decrease. Fee-based natural gas processing volumes and equity NGL-equivalent production volumes increased 53 MMcf/d and 2 MBPD, respectively, period-to-period.

Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $14 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes increased 190 MMcf/d and equity NGL-equivalent production volumes decreased 5 MBPD period-to-period (net to our interest).

On a combined basis, gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a net $4 million period-to-period primarily due to a 16 MBPD decrease in equity NGL-equivalent production volumes, which accounted for a $13 million decrease, partially offset by higher average processing fees, which accounted for a $5 million increase. Fee-based natural gas processing volumes decreased a combined 71 MMcf/d period-to-period.

NGL pipelines, storage and terminals

Second Quarter of 2023 Compared to Second Quarter of 2022. Gross operating margin from our NGL pipelines, storage and terminal assets during the second quarter of 2023 increased $59 million when compared to the second quarter of 2022.

Gross operating margin from our Chambers County storage complex increased $13 million quarter-to-quarter primarily due to lower operating costs.

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Gross operating margin from LPG-related activities at our Enterprise Hydrocarbons Terminal (“EHT”) increased $12 million quarter-to-quarter primarily due to higher average loading fees. LPG export volumes at EHT decreased 4 MBPD quarter-to-quarter. Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $11 million quarter-to-quarter primarily due to a 22 MBPD increase in export volumes, which accounted for a $6 million increase, and higher average loading fees, which accounted for an additional $3 million increase. Gross operating margin from our related Houston Ship Channel Pipeline System increased $6 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for a $3 million increase, and a 59 MBPD increase in transportation volumes, which accounted for an additional $2 million increase.

Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $4 million quarter-to-quarter primarily due to higher average transportation fees. Transportation volumes on these pipelines increased a combined 95 MBPD quarter-to-quarter.

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 $2 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for a $6 million increase, and higher other revenues, which accounted for an additional $5 million increase, partially offset by higher operating costs, which accounted for a $9 million decrease. Transportation volumes on these pipelines increased a combined 72 MBPD (net to our interest) quarter-to-quarter.

Gross operating margin from our Dixie Pipeline and related terminals decreased $8 million quarter-to-quarter primarily due to higher maintenance and other operating costs.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Gross operating margin from our NGL pipelines, storage and terminal assets during the six months ended June 30, 2023 increased $183 million when compared to the six months ended June 30, 2022.

Gross operating margin from LPG-related activities at EHT increased $37 million period-to-period primarily due to a 68 MBPD increase in LPG export volumes, which accounted for a $17 million increase, and higher average loading fees, which accounted for an additional $15 million increase. Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $25 million period-to-period primarily due to a 30 MBPD increase in export volumes, which accounted for a $16 million increase, and higher average loading fees, which accounted for an additional $6 million increase. Gross operating margin from our related Houston Ship Channel Pipeline System increased $13 million period-to-period primarily due to a 124 MBPD increase in transportation volumes, which accounted for a $10 million increase, and higher average transportation fees, which accounted for an additional $5 million increase.

On a combined basis gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased $33 million period-to-period primarily due to a combined 61 MBPD increase in transportation volumes.

Gross operating margin from our South Texas NGL Pipeline System increased $17 million period-to-period primarily due to higher average transportation fees, which accounted for a $6 million increase, higher pipeline capacity fee revenues, which accounted for a $5 million increase, and higher storage and other revenues, which accounted for an additional $5 million increase.

Gross operating margin from our Chambers County storage complex increased $9 million period-to-period primarily due to lower operating costs.

On a combined basis, gross operating margin for our pipelines that serve Permian Basin and/or Rocky Mountain producers increased a net $5 million period-to-period primarily due to higher other revenues, which accounted for a $12 million increase, higher average transportation fees, which accounted for a $7 million increase, and a 78 MBPD (net to our interest) increase in transportation volumes, which accounted for an additional $5 million increase, partially offset by higher maintenance and other operating costs, which accounted for a $19 million decrease.

Gross operating margin from our Dixie Pipeline and related terminals decreased $10 million period-to-period primarily due to higher maintenance and other operating costs.

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NGL fractionation

Second Quarter of 2023 Compared to Second Quarter of 2022. Gross operating margin from NGL fractionation during the second quarter of 2023 increased $1 million when compared to the second quarter of 2022.

Gross operating margin from our Chambers County NGL fractionation complex increased a net $7 million quarter-to-quarter primarily due to lower utility and other operating costs, which accounted for a $35 million increase, and a 34 MBPD (net to our interest) increase in fractionation volumes, which accounted for an additional $6 million increase, partially offset by lower average fractionation fees, which accounted for an $18 million decrease, and lower ancillary service revenues, which accounted for an additional $16 million decrease.

On a combined basis, gross operating margin from our other NGL fractionators decreased $7 million quarter-to-quarter primarily due to lower average fractionation fees. NGL fractionation volumes from our other NGL fractionators increased a combined 6 MBPD (net to our interest) quarter-to-quarter.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Gross operating margin from NGL fractionation during the six months ended June 30, 2023 decreased $47 million when compared to the six months ended June 30, 2022.

Gross operating margin from our Chambers County NGL fractionation complex decreased a net $35 million period-to-period primarily due to lower ancillary services revenues, which accounted for a $41 million decrease, and lower average fractionation fees, which accounted for an additional $30 million decrease, partially offset by lower utility and other operating costs, which accounted for a $33 million increase. NGL fractionation volumes at our Chambers County NGL fractionation complex increased 15 MBPD (net to our interest) period-to-period.

On a combined basis, gross operating margin from our other NGL fractionators decreased a net $16 million period-to-period primarily due to lower average fractionation fees, which accounted for an $11 million decrease, and lower ancillary service revenues, which accounted for an additional $9 million decrease, partially offset by a combined 31 MBPD (net to our interest) increase in NGL fractionation volumes, which accounted for a $6 million increase.

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 June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022
Segment gross operating margin:
Midland-to-ECHO System and related business activities	$	155	$	96	$	270	$	197
Other crude oil pipelines, terminals and related marketing results		267		311		549		625
Total	$	422	$	407	$	819	$	822

Selected volumetric data:
Crude oil pipeline transportation volumes (MBPD)		2,366		2,197		2,332		2,197
Crude oil marine terminal volumes (MBPD)		814		777		829		786

Second Quarter of 2023 Compared to Second Quarter of 2022. Gross operating margin from our Crude Oil Pipelines & Services segment for the second quarter of 2023 increased $15 million when compared to the second quarter of 2022.

Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $59 million quarter-to-quarter primarily due to higher average transportation fees and related margins from marketing activities, which accounted for a $45 million increase, and a 124 MBPD (net to our interest) increase in transportation volumes, which accounted for an additional $23 million increase, partially offset by higher utility, chemical and other operating costs, which accounted for a $4 million decrease.

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Gross operating margin from our crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System) increased $51 million quarter-to-quarter primarily due to higher non-cash, mark-to-market earnings, which accounted for a $33 million increase, and higher average sales margins, which accounted for an additional $20 million increase.

Gross operating margin from our West Texas Pipeline System increased $42 million quarter-to-quarter primarily due to higher ancillary service and other revenues. Transportation volumes on our West Texas Pipeline System increased 17 MBPD quarter-to-quarter.

Gross operating margin from our EFS Midstream System decreased $82 million quarter-to-quarter primarily due to lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long-term gathering agreements at the end of June 2022, which accounted for a $54 million decrease, and lower average transportation fees, which accounted for an additional $20 million decrease. Our EFS Midstream System continues to transport volumes produced on dedicated acreage through the remaining term of these agreements, most of which have a life-of-lease duration.

Gross operating margin from our South Texas Crude Oil Pipeline System decreased $30 million quarter-to-quarter primarily due to lower ancillary service and other revenues, which accounted for an $11 million decrease, lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long-term agreements at the end of July 2022, which accounted for an $8 million decrease, and lower average transportation fees, which accounted for an additional $7 million decrease. Transportation volumes on our South Texas Crude Oil Pipeline System decreased 50 MBPD quarter-to-quarter.

Gross operating margin from our equity investment in the Seaway Pipeline decreased $24 million quarter-to-quarter primarily due to lower ancillary service and other fee revenues. Transportation volumes on our Seaway Pipeline increased 52 MBPD (net to our interest) quarter-to-quarter.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Gross operating margin from our Crude Oil Pipelines & Services segment for the six months ended June 30, 2023 decreased $3 million when compared to the six months ended June 30, 2022.

Gross operating margin from our crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System) increased $95 million period-to-period primarily due to higher non-cash, mark-to-market earnings, which accounted for a $74 million increase, and higher average sales margins, which accounted for an additional $27 million increase.

Gross operating margin from our West Texas Pipeline System increased $87 million period-to-period primarily due to higher ancillary service and other revenues. Transportation volumes on our West Texas Pipeline System increased 14 MBPD period-to-period.

Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $73 million period-to-period primarily due to higher average transportation fees and related margins from marketing activities, which accounted for a $49 million increase, and a 93 MBPD (net to our interest) increase in transportation volumes, which accounted for an additional $36 million increase, partially offset by higher utility, chemical and other operating costs, which accounted for a $10 million decrease.

Gross operating margin from our EFS Midstream system decreased $157 million period-to-period primarily due to lower deficiency revenues as a result of the aforementioned expiration of minimum volume commitments, which accounted for a $108 million decrease, and lower average transportation fees, which accounted for an additional $41 million decrease.

Gross operating margin from our South Texas Crude Oil Pipeline System decreased $42 million period-to-period primarily due to lower deficiency revenues as a result of the aforementioned expiration of minimum volume commitments, which accounted for a $15 million decrease, lower average transportation fees, which accounted for a $13 million decrease, and lower ancillary service and other revenues, which accounted for an additional $9 million decrease. Transportation volumes on our South Texas Crude Oil Pipeline System decreased 41 MBPD period-to-period.

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Gross operating margin from our equity investment in the Seaway Pipeline decreased $42 million period-to-period primarily due to lower ancillary service and other fee revenues. Transportation volumes on our Seaway Pipeline increased 57 MBPD (net to our interest) period-to-period.

Gross operating margin from our Midland terminal decreased $15 million period-to-period primarily due to lower ancillary service and other revenues, which accounted for a $9 million decrease, and higher operating costs, which accounted for an additional $8 million decrease.

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 June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022
Segment gross operating margin	$	238	$	229	$	552	$	449

Selected volumetric data:
Natural gas pipeline transportation volumes (BBtus/d)		18,264		16,803		18,145		16,629

Second Quarter of 2023 Compared to Second Quarter of 2022. Gross operating margin from our Natural Gas Pipelines & Services segment for the second quarter of 2023 increased $9 million when compared to the second quarter of 2022.

Gross operating margin from our natural gas marketing activities increased $11 million quarter-to-quarter primarily due to higher average sales margins attributable to location price differentials.

Gross operating margin from our East Texas Gathering System increased $8 million quarter-to-quarter primarily due to a 459 BBtus/d increase in gathering volumes.

Gross operating margin from our Delaware Basin Gathering System increased $6 million quarter-to-quarter primarily due to higher average gathering fees. Natural gas gathering volumes on our Delaware Basin Gathering System increased 67 BBtus/d quarter-to-quarter.

Gross operating margin from our Acadian Gas System increased $4 million quarter-to-quarter primarily due to lower maintenance and other operating costs. Transportation volumes on our Acadian Gas System increased 91 BBtus/d quarter-to-quarter.

Gross operating margin from our Texas Intrastate System increased a net $2 million quarter-to-quarter primarily due a 793 BBtus/d increase in transportation volumes, which accounted for a $7 million increase, and higher average transportation fees, which accounted for an additional $5 million increase, partially offset by lower ancillary and other revenues, which accounted for a $10 million decrease.

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 $22 million quarter-to-quarter primarily due to lower average gathering fees on our San Juan Gathering System, which accounted for a $12 million decrease, a combined 126 BBtus/d decrease in gathering volumes, which accounted for a $3 million decrease, and higher maintenance and other operating costs, which accounted for an additional $3 million decrease.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Gross operating margin from our Natural Gas Pipelines & Services segment for the six months ended June 30, 2023 increased $103 million when compared to the six months ended June 30, 2022.

Gross operating margin from our natural gas marketing activities increased $35 million period-to-period primarily due to higher average sales margins attributable to location price differentials.

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Gross operating margin from our Texas Intrastate System increased a net $20 million period-to-period primarily due to higher average transportation fees, which accounted for a $19 million increase, and a 675 BBtus/d increase in transportation volumes, which accounted for an additional $14 million increase, partially offset by higher operating costs, which accounted for a $9 million decrease, and lower ancillary and other revenues, which accounted for an additional $4 million decrease.

Gross operating margin from our East Texas Gathering System increased $13 million period-to-period primarily due to a 406 BBtus/d increase in gathering volumes.

Gross operating margin from our Delaware Basin Gathering System increased $9 million period-to-period primarily due to a 165 BBtus/d increase in gathering volumes, which accounted for a $5 million increase, and higher average gathering fees, which accounted for an additional $3 million increase.

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 increased a net $6 million period-to-period primarily due to higher average gathering fees on our Jonah Gathering System and San Juan Gathering System, which accounted for a $19 million increase, partially offset by higher maintenance and other operating costs, which accounted for a $7 million decrease, and a decrease in condensate sales, which accounted for an additional $4 million decrease. Natural gas gathering volumes on our Rocky Mountain gathering systems decreased a combined 133 BBtus/d period-to-period.

Gross operating margin from our Acadian Gas System increased $4 million period-to-period primarily due to lower maintenance and other operating costs. Transportation volumes on our Acadian Gas System increased 154 BBtus/d period-to-period.

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 June 30,				For the Six Months Ended June 30,
	2023		2022		2023		2022
Segment gross operating margin:
Propylene production and related activities	$	125	$	154	$	307	$	364
Butane isomerization and related operations		36		28		62		54
Octane enhancement and related plant operations		92		144		177		204
Refined products pipelines and related activities		81		56		168		127
Ethylene exports and related activities		32		28		61		60
Marine transportation and other services		17		11		27		16
Total	$	383	$	421	$	802	$	825

Selected volumetric data:
Propylene production volumes (MBPD)		84		109		90		107
Butane isomerization volumes (MBPD)		120		115		109		103
Standalone deisobutanizer (“DIB”) processing volumes (MBPD)		174		162		163		156
Octane enhancement and related plant sales volumes (MBPD) (1)		37		42		31		38
Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD)		837		751		812		749
Marine terminal volumes, primarily refined products and petrochemicals (MBPD)		283		225		303		217

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

Propylene production and related activities

Second Quarter of 2023 Compared to Second Quarter of 2022. Gross operating margin from propylene production and related activities for the second quarter of 2023 decreased $29 million when compared to the second quarter of 2022.

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Gross operating margin from our Chambers County propylene production facilities decreased a combined $34 million quarter-to-quarter primarily due to lower average propylene sales margins, which accounted for a $23 million decrease, and lower propylene sales volumes, which accounted for an additional $13 million decrease. Propylene and associated by-product production volumes at these facilities decreased a combined 25 MBPD (net to our interest) quarter-to-quarter primarily due to planned major maintenance activities at three of our propylene splitters during the second quarter of 2023.

Gross operating margin from our propylene pipeline systems increased a combined $6 million quarter-to-quarter primarily due to higher average transportation fees. On a combined basis, transportation volumes were flat (net to our interest) quarter-to-quarter.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Gross operating margin from propylene production and related activities for the six months ended June 30, 2023 decreased $57 million when compared to the six months ended June 30, 2022.

Gross operating margin from our Chambers County propylene production facilities decreased a combined $71 million period-to-period primarily due to lower propylene sales volumes, which accounted for a $48 million decrease, and lower average propylene sales margins, which accounted for an additional $29 million decrease. Propylene and associated by-product production volumes at these facilities decreased a combined 17 MBPD (net to our interest) period-to-period primarily due to planned major maintenance activities at our PDH 1 facility during the first quarter of 2023 and planned major maintenance at three of our propylene splitters during the second quarter of 2023.

Gross operating margin from our propylene pipeline systems increased a combined $9 million period-to-period primarily due to higher average transportation fees. On a combined basis, transportation volumes decreased 5 MBPD (net to our interest) period-to-period.

Butane isomerization and related operations

Second Quarter of 2023 Compared to Second Quarter of 2022. Gross operating margin from butane isomerization and related operations increased $8 million quarter-to-quarter primarily due to lower utility and other operating costs.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Gross operating margin from butane isomerization and related operations increased $8 million period-to-period primarily due to lower utility and other operating costs.

Octane enhancement and related plant operations

Second Quarter of 2023 Compared to Second Quarter of 2022. Gross operating margin from our octane enhancement and related plant operations for the second quarter of 2023 decreased a net $52 million when compared to the second quarter of 2022 primarily due to lower average sales margins, which accounted for a $38 million decrease, and lower sales volumes, which accounted for an additional $20 million decrease, partially offset by lower utility and other operating costs, which accounted for a $6 million increase.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Gross operating margin from our octane enhancement and related plant operations during the six months ended June 30, 2023 decreased $27 million when compared to the six months ended June 30, 2022 primarily due to lower sales volumes, which accounted for a $15 million decrease, and lower average sales margins, which accounted for an additional $14 million decrease.

Refined products pipelines and related activities

Second Quarter of 2023 Compared to Second Quarter of 2022. Gross operating margin from refined products pipelines and related activities for the second quarter of 2023 increased $25 million when compared to the second quarter of 2022.

Gross operating margin from our refined products marketing activities increased $26 million quarter-to-quarter primarily due to higher average sales margins.

Gross operating margin from our refined products terminal in Beaumont, Texas increased $5 million quarter-to-quarter primarily due to higher storage and other fee revenues. Refined product marine terminal volumes at Beaumont increased 68 MBPD quarter-to-quarter.

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Gross operating margin from our TE Products Pipeline System decreased $8 million quarter-to-quarter primarily due to higher operating costs. Overall, transportation volumes on our TE Products Pipeline System increased a net 51 MBPD quarter-to-quarter.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Gross operating margin from refined products pipelines and related activities for the six months ended June 30, 2023 increased $41 million when compared to the six months ended June 30, 2022.

Gross operating margin from our refined products marketing activities increased $50 million period-to-period primarily due to higher average sales margins.

Gross operating margin from our refined products terminal in Beaumont, Texas increased $11 million period-to-period primarily due to higher storage and other fee revenues. Refined product marine terminal volumes at Beaumont increased 99 MBPD period-to-period.

Gross operating margin from our TE Products Pipeline System decreased $24 million period-to-period primarily due to higher operating costs. Overall, transportation volumes on our TE Products Pipeline System increased a net 38 MBPD period-to-period.

Ethylene exports and related activities

Second Quarter of 2023 Compared to Second Quarter of 2022. Gross operating margin from ethylene exports and related activities during the second quarter of 2023 increased a net $4 million when compared to the second quarter of 2022. Gross operating margin from our ethylene pipelines, storage and related marketing activities increased a combined $6 million quarter-to-quarter primarily due to higher transportation, storage and other fee revenues, which accounted for a $3 million increase, and higher average sales margins, which accounted for an additional $2 million increase. Gross operating margin from our ethylene export terminal decreased $2 million quarter-to-quarter primarily due to lower average loading fees. Ethylene transportation volumes and ethylene export volumes increased 17 MBPD and 1 MBPD, respectively, quarter-to-quarter (net to our interest).

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Gross operating margin from ethylene exports and related activities during the six months ended June 30, 2023 increased a net $1 million when compared to the six months ended June 30, 2022. Gross operating margin from our ethylene pipelines, storage and related marketing activities increased a combined $6 million period-to-period primarily due to higher transportation, storage and other fee revenues, which accounted for a $4 million increase, and higher sales volumes, which accounted for an additional $2 million increase. Gross operating margin from our ethylene export terminal decreased $5 million period-to-period primarily due to lower average loading fees. Ethylene transportation volumes increased 15 MBPD and ethylene export volumes were flat period-to-period (net to our interest).

Marine transportation and other services

Second Quarter of 2023 Compared to Second Quarter of 2022. Gross operating margin from marine transportation and other services increased $6 million quarter-to-quarter primarily due to higher average fees and fleet utilization rates.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Gross operating margin from marine transportation and other services increased a net $11 million period-to-period primarily due to higher average fees, which accounted for an $11 million increase, and higher fleet utilization rates, which accounted for an additional $6 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 June 30, 2023, we had $4.0 billion of consolidated liquidity. This amount was comprised of $3.8 billion of available borrowing capacity under EPO’s revolving credit facilities, which is the net of $4.2 billion of total borrowing capacity under EPO’s revolving credit facilities and $355 million outstanding under EPO’s commercial paper program, and $183 million of unrestricted cash on hand.

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We may issue debt and equity securities to assist us in meeting our future funding and liquidity requirements, including those related to capital investments. We have a universal shelf registration statement on file with the SEC which allows the Partnership and EPO to issue an unlimited amount of equity and debt securities, respectively.

Enterprise Declares Cash Distribution for Second Quarter of 2023

On July 10, 2023, we announced that the Board declared a quarterly cash distribution of $0.50 per common unit, or $2.00 per unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the second quarter of 2023. The quarterly distribution is payable on August 14, 2023 to unitholders of record as of the close of business on July 31, 2023. The total amount to be paid is $1.1 billion, which includes $10 million for distribution equivalent rights on phantom unit awards.

Consolidated Debt

At June 30, 2023, the average maturity of EPO’s consolidated debt obligations was approximately 19.7 years. The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at June 30, 2023 for the years indicated (dollars in millions):

			Scheduled Maturities of Debt
	Total		Remainder of 2023		2024		2025		2026		2027		Thereafter
Commercial Paper Notes	$	355	$	355	$	–	$	–	$	–	$	–	$	–
Senior Notes		26,275		–		850		1,150		1,625		575		22,075
Junior Subordinated Notes		2,296		–		–		–		–		–		2,296
Total	$	28,926	$	355	$	850	$	1,150	$	1,625	$	575	$	24,371

In January 2023, EPO issued $1.75 billion aggregate principal amount of senior notes comprised of (i) $750 million principal amount of senior notes due January 2026 (“Senior Notes FFF”) and (ii) $1.0 billion principal amount of senior notes due January 2033 (“Senior Notes GGG”). Senior Notes FFF were issued at 99.893% of their principal amount and have a fixed-rate interest rate of 5.05% per year. Senior Notes GGG were issued at 99.803% of their principal amount and have a fixed-rate interest rate of 5.35% 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 $1.25 billion principal amount of 3.35% Senior Notes HH at their maturity in March 2023 and amounts outstanding under our commercial paper program).

In March 2023, EPO entered into a new 364-Day Revolving Credit Agreement (the “March 2023 $1.5 Billion 364-Day Revolving Credit Agreement”) that replaced its September 2022 364-Day Revolving Credit Agreement. The March 2023 $1.5 Billion 364-Day Revolving Credit Agreement matures in March 2024. EPO’s borrowing capacity was unchanged from the prior 364-day revolving credit agreement. As of June 30, 2023, there are no principal amounts outstanding under this new revolving credit agreement.

In March 2023, EPO entered into a new revolving credit agreement that matures in March 2028 (the “March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement”). The March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement replaced EPO’s prior multi-year revolving credit agreement that was scheduled to mature in September 2026. We proposed to reduce EPO’s borrowing capacity from $3.0 billion under the prior multi-year revolving credit agreement to $2.7 billion under the March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement. Under the new agreement, EPO retains the right to increase its borrowing capacity by up to $500 million to $3.2 billion, provided certain conditions for the election are met. As of June 30, 2023, there are no principal amounts outstanding under this new revolving credit agreement.

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

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Credit Ratings

As of August 9, 2023, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were A- from Standard and Poor’s, Baa1 from Moody’s and BBB+ 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 2,910,121 and 3,592,710 common units through open market purchases during the three and six months ended June 30, 2023, respectively. The total cost of these repurchases, including commissions and fees, was $75 million and $92 million, respectively. As of June 30, 2023, the remaining available capacity under the 2019 Buyback Program was $1.2 billion.

Cash Flow Statement Highlights

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

	For the Six Months Ended June 30,
	2023			2022
Net cash flows provided by operating activities		$	3,485		$	4,264
Cash used in investing activities			1,402			3,868
Cash used in financing activities			2,012			2,964

Net cash flows 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 2022 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 quarter-to-quarter fluctuations in our consolidated cash flow amounts:

Operating activities

Net cash flows provided by operating activities for the six months ended June 30, 2023 decreased $779 million when compared to the six months ended June 30, 2022 primarily due to:

•

a $621 million period-to-period decrease 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; and

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•

a $151 million period-to-period decrease resulting from lower partnership earnings (determined by adjusting our $66 million period-to-period decrease in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows).

For information regarding significant 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

Cash used in investing activities during the six months ended June 30, 2023 decreased a net $2.5 billion when compared to the six months ended June 30, 2022 primarily due to:

•

a net $3.2 billion cash outflow in February 2022 in connection with the acquisition of our Midland Basin System; partially offset by

•

a $702 million period-to-period increase in investments for property, plant and equipment (see “Capital Investments” within this Part I, Item 2 for additional information).

Financing activities

Cash used in financing activities during the six months ended June 30, 2023 decreased a net $952 million when compared to the six months ended June 30, 2022 primarily due to:

•

a net cash inflow of $361 million related to debt transactions that occurred during the six months ended June 30, 2023 compared to a net cash outflow of $760 million related to debt transactions that occurred during the six months ended June 30, 2022. During the six months ended June 30, 2023, we issued $1.75 billion aggregate principal amount of senior notes, partially offset by the repayment of $1.25 billion principal amount of senior notes and net repayments of $140 million under EPO’s commercial paper program. During the six months ended June 30, 2022, we repaid $1.4 billion aggregate principal amount of senior notes, partially offset by net issuances of $640 million under EPO’s commercial paper program; partially offset by

•

a $103 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

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

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

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

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

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2023			2022			2023			2022
Net income attributable to common unitholders (GAAP) (1)	$	1,253		$	1,411		$	2,643		$	2,707
Adjustments to net income attributable to common unitholders to derive DCF (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expenses		576			566			1,143			1,117
Cash distributions received from unconsolidated affiliates (2)		128			159			247			279
Equity in income of unconsolidated affiliates		(121	)		(107	)		(225	)		(224	)
Asset impairment charges		3			5			16			19
Change in fair market value of derivative instruments		7			52			10			94
Deferred income tax expense (benefit)		(11	)		7			(8	)		16
Sustaining capital expenditures (3)		(101	)		(82	)		(185	)		(157	)
Other, net		(3	)		4			5			(10	)
Operational DCF (4)	$	1,731		$	2,015		$	3,646		$	3,841
Proceeds from asset sales and other matters		4			3			6			14
Monetization of interest rate derivative instruments accounted for as cash flow hedges	‒			‒				21		‒
DCF (non-GAAP)	$	1,735		$	2,018		$	3,673		$	3,855

Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards	$	1,096		$	1,044		$	2,171		$	2,067

Cash distribution per common unit declared by Enterprise GP with respect to period (5)	$	0.5000		$	0.4750		$	0.9900		$	0.9400

Total DCF retained by the Partnership with respect to period (6)	$	639		$	974		$	1,502		$	1,788

Distribution coverage ratio (7)		1.6	x		1.9	x		1.7	x		1.9	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)	Represents DCF before proceeds from asset sales and the monetization of interest rate derivative instruments accounted for as cash flow hedges.
(5)	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.
(6)	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.
(7)	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 flows provided by operating activities to DCF for the periods indicated (dollars in millions):

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2023			2022			2023			2022
Net cash flows provided by operating activities (GAAP)	$	1,902		$	2,119		$	3,485		$	4,264
Adjustments to reconcile net cash flows provided by operating activities to DCF (addition or subtraction indicated by sign):
Net effect of changes in operating accounts		(36	)		(27	)		403			(218	)
Sustaining capital expenditures		(101	)		(82	)		(185	)		(157	)
Distributions received from unconsolidated affiliates attributable to the return of capital		15			44			30			55
Proceeds from asset sales and other matters		4			3			6			14
Net income attributable to noncontrolling interests		(29	)		(28	)		(60	)		(62	)
Monetization of interest rate derivative instruments accounted for as cash flow hedges	‒			‒				21		‒
Other, net		(20	)		(11	)		(27	)		(41	)
DCF (non-GAAP)	$	1,735		$	2,018		$	3,673		$	3,855

Capital Investments

During the second quarter of 2023, we completed the 400 MMcf/d expansion of our Acadian Gas System. In addition, PDH 2, Frac XII and our Poseidon natural gas processing plant were placed into service in July 2023. We have approximately $4.1 billion of growth capital projects scheduled to be completed by the first half of 2026, including the following major projects (including their respective scheduled completion dates):

•

natural gas gathering expansion projects in the Delaware and Midland Basins (2023 and 2024);

•

our Mentone II natural gas processing plant in the Delaware Basin (fourth quarter of 2023);

•

our Texas Western Products System, created by repurposing a portion of our Mid-America Pipeline System’s Rocky Mountain segment and adding westbound service to our Chaparral Pipeline business to transport refined products from the U.S. Gulf Coast to markets in West Texas, New Mexico, Colorado and Utah (fourth quarter of 2023 through second quarter of 2024);

•

our Mentone III natural gas processing plant in the Delaware Basin (first quarter of 2024);

•

our Leonidas natural gas processing plant in the Midland Basin (first quarter of 2024);

•

the expansion of our LPG and PGP export capacity at EHT (first half of 2025);

•

the expansion of our Shin Oak NGL Pipeline (first half of 2025);

•

an Ethane and Propane Export Terminal located in Orange County, Texas (second half of 2025 and first half of 2026); and

•

an expansion of our Morgan’s Point terminal to increase ethylene export capacity (second half of 2024 and second half of 2025).

Based on information currently available, we expect our total capital investments for 2023, net of contributions from noncontrolling interests, to approximate $2.8 billion to $3.2 billion, which reflects growth capital investments of $2.4 billion to $2.8 billion and sustaining capital expenditures of $400 million. These amounts do not include capital investments associated with our proposed deep-water offshore crude oil terminal (the Sea Port Oil Terminal, or “SPOT”), which remains subject to state and federal permitting, mitigation and related requirements. We received a favorable Record of Decision from the Department of Transportation’s Maritime Administration for SPOT during the fourth quarter of 2022; however, we can give no assurance as to when or whether the project will ultimately be authorized to begin construction or operation.

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

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

	For the Six Months Ended June 30,
	2023		2022
Capital investments for property, plant and equipment: (1)
Growth capital projects (2)	$	1,227	$	564
Sustaining capital projects (3)		206		167
Total	$	1,433	$	731

Cash used for business combinations, net (4)	$	–	$	3,204

(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.
(4)	Amount for the six months ended June 30, 2022 represents net cash used for the acquisition of our Midland Basin System, which closed on February 17, 2022.

Comparison of Six Months Ended June 30, 2023 with Six Months Ended June 30, 2022

In total, investments in growth capital projects increased $663 million period-to-period primarily due to the following:

•	higher investments in natural gas processing and related pipeline projects in the Permian Basin (e.g., construction of four natural gas processing plants and related gathering systems), which accounted for a $425 million increase;

•	higher investments in our Texas Western Products System, which accounted for an $88 million increase;

•	higher investments in ethane, LPG and ethylene export expansion projects at our Gulf Coast terminals, which accounted for an $83 million increase; and

•	higher investments in Frac XII at our Chambers County complex, which accounted for an additional $68 million increase.

Investments attributable to sustaining capital projects increased $39 million period-to-period primarily due to 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 2022 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:

•

valuation of assets and liabilities acquired in a business combination

•

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 June 30, 2023, the total amount of Guaranteed Debt was $29.4 billion, which was comprised of $26.3 billion of EPO’s senior notes, $2.3 billion of EPO’s junior subordinated notes, $355 million of short-term commercial paper notes and $458 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 $47.3 billion at June 30, 2023. The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the six months ended June 30, 2023 was $2.7 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:	June 30, 2023		December 31, 2022
Current receivables from Non-Obligor Subsidiaries	$	1,177	$	1,012
Other current assets		3,854		4,949
Long-term receivables from Non-Obligor Subsidiaries		187		187
Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $47.3 billion at June 30, 2023 and $47.5 billion at December 31, 2022		9,190		9,130

Selected liability information:
Current portion of Guaranteed Debt, including interest of $458 million at June 30, 2023 and $426 million at December 31, 2022	$	1,662	$	2,171
Current payables to Non-Obligor Subsidiaries		1,206		1,899
Other current liabilities		2,999		4,121
Noncurrent portion of Guaranteed Debt, principal only		27,707		26,807
Noncurrent payables to Non-Obligor Subsidiaries		39		38
Other noncurrent liabilities		87		98

Mezzanine equity of Obligor Group:
Preferred units	$	49	$	49

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

	For the Six Months Ended June 30, 2023			For the Twelve Months Ended December 31, 2022
Revenues from Non-Obligor Subsidiaries	$	7,845		$	14,145
Revenues from other sources		7,335			27,312
Operating income of Obligor Group		536			836
Net income (loss) of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $2.7 billion for the six months ended June 30, 2023 and $5.9 billion for the twelve months ended December 31, 2022		(97	)		(450	)

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 and the discount rates used to determine the present values. 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 June 30, 2023, 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, 2022			June 30, 2023			July 14, 2023
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	90		$	2		$	4
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			97			1			3
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			83			3			4

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

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2022				June 30, 2023			July 14, 2023
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	18			$	78		$	28
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			(29	)			20			(27	)
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			64				136			83

Crude oil marketing portfolio

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2022			June 30, 2023				July 14, 2023
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	53		$	36			$	13
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			24			(2	)		‒
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			81			75				26

Commercial energy derivative portfolio

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2022				June 30, 2023				July 14, 2023
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	(38	)		$	(26	)		$	(16	)
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			(10	)			(5	)			7
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			(63	)			(48	)			(39	)

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Interest Rate Hedging Activities

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 and (ii) W. Randall Fowler, Co-Chief Executive Officer 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 and Fowler 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 second quarter of 2023, 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 and Fowler 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 July 2021, we received a civil penalty demand from the U.S. Department of Justice and the State of Colorado regarding alleged violations of hydrocarbon leak detection and repair regulations applicable to our Meeker gas processing plant in Colorado.

•	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 2022 Form 10-K, in addition to other information in such annual report and this quarterly report. The risk factors set forth in our 2022 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 of 18,076 and 18,404 preferred units to OTA Holdings, Inc., an indirect, wholly owned subsidiary of the Partnership (“OTA”) in the first and second quarters of 2023, respectively. The preferred units held by OTA are accounted for as treasury units in consolidation. For additional information regarding the preferred units, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

The issuances of preferred units as PIK distributions during the three and six months ended June 30, 2023 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 second quarter of 2023.

Issuer Purchases of Equity Securities

The following table summarizes our equity repurchase activity during the second quarter of 2023:

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)
April 2023		–	$	–		–	$	1,252,162
May 2023		1,262,808	$	25.64		1,262,808	$	1,219,781
June 2023		1,647,313	$	25.82		1,647,313	$	1,177,244
Vesting of phantom unit awards:
May 2023 (2)		48,645	$	26.26		n/a		n/a
June 2023 (3)		277	$	25.95		n/a		n/a

(1)	In January 2019, we announced the 2019 Buyback Program, which authorized the repurchase of up to $2 billion of EPD’s common units. Units repurchased under this program are cancelled immediately upon acquisition.
(2)	Of the 190,599 phantom unit awards that vested in May 2023 and converted to common units, 48,645 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 11,825 phantom unit awards that vested in June 2023 and converted to common units, 277 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.

None.

ITEM 6. EXHIBITS.

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

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2.9	Agreement and Plan of Merger, dated as of September 3, 2010, by and among Enterprise Products GP, LLC, Enterprise GP Holdings L.P. and EPE Holdings, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed September 7, 2010).
2.10	Contribution Agreement, dated as of September 30, 2010, by and between Enterprise Products Company and Enterprise Products Partners L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K filed October 1, 2010).
2.11	Agreement and Plan of Merger, dated as of April 28, 2011, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPD MergerCo LLC, Duncan Energy Partners L.P. and DEP Holdings, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 29, 2011).
2.12	Contribution and Purchase Agreement, dated as of October 1, 2014, by and among Enterprise Products Partners L.P., Oiltanking Holding Americas, Inc. and OTB Holdco, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed October 1, 2014).
2.13	Agreement and Plan of Merger, dated as of November 11, 2014, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPOT MergerCo LLC, Oiltanking Partners, L.P. and OTLP GP, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed November 12, 2014).
2.14	Amendment No. 1 dated as of June 6, 2018 to Contribution and Purchase Agreement, by and among Enterprise Products Partners L.P., Oiltanking Holding Americas, Inc., Enterprise Products Holdings LLC and Marquard & Bahls, AG (incorporated by reference to Exhibit 2.2 to Form 8-K filed June 12, 2018).
3.1	Certificate of Limited Partnership of Enterprise Products Partners L.P. (incorporated by reference to Exhibit 3.6 to Form 10-Q filed November 9, 2007).
3.2	Certificate of Amendment to Certificate of Limited Partnership of Enterprise Products Partners L.P., filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.6 to Form 8-K filed November 23, 2010).
3.3	Seventh Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated as of September 30, 2020 (incorporated by reference to Exhibit 3.1 to Form 8-K filed October 1, 2020).
3.4	Certificate of Formation of Enterprise Products Holdings LLC (formerly named EPE Holdings, LLC) (incorporated by reference to Exhibit 3.3 to Form S-1/A Registration Statement, Reg. No. 333-124320, filed by Enterprise GP Holdings L.P. on July 22, 2005).
3.5	Certificate of Amendment to Certificate of Formation of Enterprise Products Holdings LLC (formerly named EPE Holdings, LLC), filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.5 to Form 8-K filed November 23, 2010).
3.6	Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC dated effective as of September 7, 2011 (incorporated by reference to Exhibit 3.1 to Form 8-K filed September 8, 2011).
3.7	Amendment No. 1 to Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC, dated effective as of April 26, 2017 (incorporated by reference to Exhibit 3.1 to Form 8-K filed May 2, 2017).
3.8	Amendment No. 2 to Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC, dated effective as of November 6, 2019 (incorporated by reference to Exhibit 3.12 to Form 10-Q filed November 8, 2019).
3.9	Sixth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC dated effective as of August 9, 2022 (incorporated by reference to Exhibit 3.9 to Form 10-Q filed August 9, 2022).
3.10	Company Agreement of Enterprise Products Operating LLC dated June 30, 2007 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed August 8, 2007).
3.11	Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).

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3.12	Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
4.1	Form of Common Unit certificate (incorporated by reference to Exhibit A to Exhibit 3.1 to Form 8-K filed October 1, 2020).
4.2	Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated by reference to Exhibit 4.2 to Form 10-K filed February 28, 2020).
4.3	Indenture, dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 14, 2000).
4.4	Second Supplemental Indenture, dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.5	Third Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and U.S. Bank National Association, as successor Trustee (incorporated by reference to Exhibit 4.55 to Form 10-Q filed August 8, 2007).
4.6	Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 6, 2004).
4.7	Fourth Supplemental Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Form 8-K filed October 6, 2004).
4.8	Sixth Supplemental Indenture, dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed March 3, 2005).
4.9	Tenth Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8, 2007).
4.10	Sixteenth Supplemental Indenture, dated as of October 5, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.11	Seventeenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 28, 2009).
4.12	Eighteenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed October 28, 2009).
4.13	Nineteenth Supplemental Indenture, dated as of May 20, 2010, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed May 20, 2010).

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4.14	Twentieth Supplemental Indenture, dated as of January 13, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed January 13, 2011).
4.15	Twenty-First Supplemental Indenture, dated as of August 24, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 24, 2011).
4.16	Twenty-Second Supplemental Indenture, dated as of February 15, 2012, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.25 to Form 10-Q filed May 10, 2012).
4.17	Twenty-Third Supplemental Indenture, dated as of August 13, 2012, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 13, 2012).
4.18	Twenty-Fourth Supplemental Indenture, dated as of March 18, 2013, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.19	Twenty-Fifth Supplemental Indenture, dated as of February 12, 2014, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed February 12, 2014).
4.20	Twenty-Sixth Supplemental Indenture, dated as of October 14, 2014, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.21	Twenty-Seventh Supplemental Indenture, dated as of May 7, 2015, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.22	Twenty-Eighth Supplemental Indenture, dated as of April 13, 2016, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed April 13, 2016).
4.23	Twenty-Ninth Supplemental Indenture, dated as of August 16, 2017, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 16, 2017).
4.24	Thirtieth Supplemental Indenture, dated as of February 15, 2018, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed February 15, 2018).
4.25	Thirty-First Supplemental Indenture, dated as of February 15, 2018, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed February 15, 2018).
4.26	Thirty-Second Supplemental Indenture, dated as of October 11, 2018, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 11, 2018).

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4.27	Thirty-Third Supplemental Indenture, dated as of July 8, 2019, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed July 8, 2019).
4.28	Thirty-Fourth Supplemental Indenture, dated as of January 15, 2020, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.29	Thirty-Fifth Supplemental Indenture, dated as of August 7, 2020, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed August 7, 2020).
4.30	Thirty-Sixth Supplemental Indenture, dated as of September 15, 2021, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Wells Fargo Bank, National Association, as Original Trustee, and U.S. Bank National Association, as Series Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed September 15, 2021).
4.31	Thirty-Seventh Supplemental Indenture, dated as of January 10, 2023, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and U.S. Bank Trust Company, National Association, as Series Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed January 10, 2023).
4.32	Form of Global Note representing $500.0 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.33	Form of Global Note representing $350.0 million principal amount of 6.65% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
4.34	Form of Global Note representing $250.0 million principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed November 4, 2005).
4.35	Form of Global Note representing $600.0 million principal amount of 6.125% Senior Notes due 2039 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.36	Form of Global Note representing $399.6 million principal amount of 7.55% Senior Notes due 2038 with attached Guarantee (incorporated by reference to Exhibit E to Exhibit 4.1 to Form 8-K filed October 28, 2009).
4.37	Form of Global Note representing $285.8 million principal amount of Junior Subordinated Notes due 2067 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.2 to Form 8-K filed October 28, 2009).
4.38	Form of Global Note representing $600.0 million principal amount of 6.45% Senior Notes due 2040 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed May 20, 2010).
4.39	Form of Global Note representing $750.0 million principal amount of 5.95% Senior Notes due 2041 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed January 13, 2011).
4.40	Form of Global Note representing $650.0 million principal amount of 4.05% Senior Notes due 2022 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed August 24, 2011).
4.41	Form of Global Note representing $600.0 million principal amount of 5.70% Senior Notes due 2042 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed August 24, 2011).
4.42	Form of Global Note representing $750.0 million principal amount of 4.85% Senior Notes due 2042 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.25 to Form 10-Q filed May 10, 2012).

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4.43	Form of Global Note representing $1.1 billion principal amount of 4.45% Senior Notes due 2043 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed August 13, 2012).
4.44	Form of Global Note representing $1.25 billion principal amount of 3.35% Senior Notes due 2023 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.45	Form of Global Note representing $1.0 billion principal amount of 4.85% Senior Notes due 2044 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.46	Form of Global Note representing $850.0 million principal amount of 3.90% Senior Notes due 2024 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed February 12, 2014).
4.47	Form of Global Note representing $1.15 billion principal amount of 5.10% Senior Notes due 2045 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed February 12, 2014).
4.48	Form of Global Note representing $1.15 billion principal amount of 3.75% Senior Notes due 2025 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.49	Form of Global Note representing $400.0 million principal amount of 4.95% Senior Notes due 2054 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.50	Form of Global Note representing $400.0 million principal amount of 4.85% Senior Notes due 2044 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.51	Form of Global Note representing $875.0 million principal amount of 3.70% Senior Notes due 2026 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.52	Form of Global Note representing $875.0 million principal amount of 4.90% Senior Notes due 2046 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.53	Form of Global Note representing $575.0 million principal amount of 3.95% Senior Notes due 2027 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed April 13, 2016).
4.54	Form of Global Note representing $100.0 million principal amount of 4.90% Senior Notes due 2046 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.55	Form of Global Note representing $700 million principal amount of Junior Subordinated Notes D due 2077 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed August 16, 2017).
4.56	Form of Global Note representing $1.0 billion principal amount of Junior Subordinated Notes E due 2077 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed August 16, 2017).
4.57	Form of Global Note representing $1.25 billion principal amount of 4.25% Senior Notes due 2048 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed February 15, 2018).
4.58	Form of Global Note representing $700 million principal amount of Junior Subordinated Notes F due 2078 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed February 15, 2018).
4.59	Form of Global Note representing $750.0 million principal amount of 3.50% Senior Notes due 2022 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed October 11, 2018).
4.60	Form of Global Note representing $1.0 billion principal amount of 4.15% Senior Notes due 2028 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed October 11, 2018).

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4.61	Form of Global Note representing $1.25 billion principal amount of 4.80% Senior Notes due 2049 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed October 11, 2018).
4.62	Form of Global Note representing $1.25 billion principal amount of 3.125% Senior Notes due 2029 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed July 8, 2019).
4.63	Form of Global Note representing $1.25 billion principal amount of 4.200% Senior Notes due 2050 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed July 8, 2019).
4.64	Form of Global Note representing $1.0 billion principal amount of 2.800% Senior Notes due 2030 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.65	Form of Global Note representing $1.0 billion principal amount of 3.700% Senior Notes due 2051 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.66	Form of Global Note representing $1.0 billion principal amount of 3.950% Senior Notes due 2060 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.67	Form of Global Note representing $250.0 million principal amount of 2.800% Senior Notes due 2030 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.68	Form of Global Note representing $1.0 billion principal amount of 3.200% Senior Notes due 2052 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed August 7, 2020).
4.69	Form of Global Note representing $1.0 billion principal amount of 3.300% Senior Notes due 2053 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed September 15, 2021).
4.70	Form of Global Note representing $750.0 million principal amount of 5.050% Senior Notes due 2026 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed January 10, 2023).
4.71	Form of Global Note representing $1.0 billion principal amount of 5.350% Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed January 10, 2023).
4.72	Replacement Capital Covenant, dated October 27, 2009, executed by Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 4.9 to Form 8-K filed October 28, 2009).
4.73	Amendment to Replacement Capital Covenants, dated May 6, 2015, executed by Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 4.59 to Form 10-Q filed May 8, 2015).
4.74	Indenture, dated February 20, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Subsidiary Guarantors, and First Union National Bank, NA, as Trustee (incorporated by reference to Exhibit 99.2 to the Form 8-K filed by TEPPCO Partners, L.P. on February 20, 2002).
4.75	Supplemental Indenture, dated June 27, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.6 to the Form 10-Q filed by TEPPCO Partners, L.P. on August 14, 2002).

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4.76	Full Release of Guarantee, dated July 31, 2006, by Wachovia Bank, National Association, as Trustee, in favor of Jonah Gas Gathering Company (incorporated by reference to Exhibit 4.8 to the Form 10-Q filed by TEPPCO Partners, L.P. on November 7, 2006).
4.77	Seventh Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.13 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).
4.78	Eighth Supplemental Indenture, dated October 27, 2009, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by TEPPCO Partners, L.P. on October 28, 2009).
4.79	Full Release of Guarantee, dated November 23, 2009, of TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P. by U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.64 to Form 10-K filed March 1, 2010).
4.80	Indenture, dated May 14, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 99.1 of the Form 8-K filed by TEPPCO Partners, L.P. on May 15, 2007).
4.81	First Supplemental Indenture, dated May 18, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on May 18, 2007).
4.82	Second Supplemental Indenture, dated as of June 30, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Existing Subsidiary Guarantors, TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as New Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TE Products Pipeline Company, LLC on July 6, 2007).
4.83	Third Supplemental Indenture, dated as of October 27, 2009, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on October 28, 2009).
4.84	Full Release of Guarantee, dated as of November 23, 2009, of TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P. by The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.70 to Form 10-K filed March 1, 2010).
4.85	Registration Rights Agreement, dated as of March 5, 2020, between Enterprise Products Partners L.P. and Skyline North Americas, Inc. (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 5, 2020).
4.86	Equity Distribution Agreement, dated June 24, 2020, by and among Enterprise Products Partners L.P., Enterprise Products OLPGP, Inc., Enterprise Products Operating LLC, Skyline North Americas, Inc. and Morgan Stanley & Co. LLC. (incorporated by reference to Exhibit 1.1 to Form 8-K filed June 25, 2020).
4.87	Specimen Unit Certificate for the Series A Cumulative Convertible Preferred Units, (incorporated by reference to Exhibit B to Exhibit 3.1 to Form 8-K filed October 1, 2020).
4.88	Registration Rights Agreement, dated as of September 30, 2020, by and among Enterprise Products Partners L.P. and the Purchasers party thereto (incorporated by reference to Exhibit 4.2 to Form 8-K filed October 1, 2020).

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22.1#	List of Issuers of Debt Securities Guaranteed by Enterprise Products Partners L.P. and Associated Securities at June 30, 2023.
31.1#	Sarbanes-Oxley Section 302 certification of A. James Teague for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the six months ended June 30, 2023.
31.2#	Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the six months ended June 30, 2023.
32.1#	Sarbanes-Oxley Section 906 certification of A. James Teague for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the six months ended June 30, 2023.
32.2#	Sarbanes-Oxley Section 906 certification of W. Randall Fowler for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the six months ended June 30, 2023.
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 August 9, 2023.

		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 – Accounting, Risk Control and Information Technology of the General Partner