Enterprise Products Partners (EPD) 10-K 28 Feb 25 2024 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Jan. 31, 2025	Jun. 28, 2024
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2024
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	FY
Document Transition Report	false
Entity File Number	1-14323
Entity Registrant Name	ENTERPRISE PRODUCTS PARTNERS L.P.
Entity Central Index Key	0001061219
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	76-0568219
Entity Address, Address Line One	1100 Louisiana Street, 10th Floor
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	381-6500
Title of 12(b) Security	Common Units
Trading Symbol	EPD
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Public Float			$ 42,550
Entity Common Stock, Shares Outstanding		2,165,699,962
Auditor Firm ID	34
Auditor Name	DELOITTE & TOUCHE LLP
Auditor Location	Houston, Texas

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Dec. 31, 2024	Dec. 31, 2023
Current assets:
Cash and cash equivalents		$ 583	$ 180
Restricted cash		255	140
Inventories		3,955	3,352
Derivative assets		534	347
Prepaid and other current assets		566	457
Total current assets		15,133	12,248
Property, plant and equipment, net		49,062	45,804
Investments in unconsolidated affiliates		2,259	2,330
Intangible assets, net		4,005	3,770
Goodwill	[1]	5,712	5,608
Other assets		997	1,222
Total assets		77,168	70,982
Current liabilities:
Current maturities of debt		1,150	1,300
Accrued product payables		10,777	8,911
Accrued interest		536	455
Derivative liabilities		471	396
Other current liabilities		818	675
Total current liabilities		15,177	13,131
Long-term debt		30,746	27,448
Deferred tax liabilities		656	611
Other long-term liabilities		950	984
Commitments and contingent liabilities
Redeemable preferred limited partner interests:
Series A cumulative convertible preferred units (50,687 units outstanding at December 31, 2024 and 50,412 units outstanding at December 31, 2023)		50	49
Partners' equity:
Common limited partner interests (2,165,699,962 units issued and outstanding at December 31, 2024 and 2,168,245,238 units issued and outstanding at December 31, 2023)		29,793	28,663
Treasury units, at cost		(1,297)	(1,297)
Accumulated other comprehensive income		236	307
Total partners' equity		28,732	27,673
Noncontrolling interests in consolidated subsidiaries		857	1,086
Total equity		29,589	28,759
Total liabilities, preferred units, and equity		77,168	70,982
Nonrelated Party [Member]
Current assets:
Accounts receivable, net		9,236	7,765
Current liabilities:
Accounts payable		1,227	1,195
Related Party [Member]
Current assets:
Accounts receivable, net		4	7
Current liabilities:
Accounts payable		$ 198	$ 199
[1]Balances are presented net of historical accumulated impairment losses of $296 million for the Natural Gas Pipelines & Service segment and $1 million for the Petrochemical & Refined Products Services segment.  There have been no goodwill impairment charges recognized for the reporting units within the NGL Pipelines & Services and Crude Oil Pipelines & Services segments.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
ASSETS
Accounts receivable, allowance for credit losses	$ 38	$ 35
Redeemable preferred limited partner interests:
Series A cumulative convertible preferred units outstanding (in units)	50,687	50,412
Limited partners:
Common units issued (in units)	2,165,699,962	2,168,245,238
Common units outstanding (in units)	2,165,699,962	2,168,245,238

STATEMENTS OF CONSOLIDATED OPER

STATEMENTS OF CONSOLIDATED OPERATIONS - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Revenues:
Total revenues		$ 56,219	$ 49,715	$ 58,186
Operating costs and expenses:
Third party and other costs		47,554	41,632	50,160
Related parties		1,491	1,385	1,342
Total operating costs and expenses		49,045	43,017	51,502
General and administrative costs:
Third party and other costs		78	75	85
Related parties		166	156	156
Total general and administrative costs		244	231	241
Total costs and expenses		49,289	43,248	51,743
Equity in income of unconsolidated affiliates		408	462	464
Operating income		7,338	6,929	6,907
Other income (expense):
Interest expense		(1,352)	(1,269)	(1,244)
Interest income		47	27	11
Other, net		2	14	23
Total other expense, net	[1]	(1,303)	(1,228)	(1,210)
Income before income taxes		6,035	5,701	5,697
Provision for income taxes		(65)	(44)	(82)
Net income		5,970	5,657	5,615
Net income attributable to noncontrolling interests		(69)	(125)	(125)
Net income attributable to preferred units		(4)	(3)	(3)
Net income attributable to common unitholders		$ 5,897	$ 5,529	$ 5,487
Earnings per unit:
Basic earnings per common unit (in dollars per unit)		$ 2.69	$ 2.52	$ 2.5
Diluted earnings per common unit (in dollars per unit)		$ 2.69	$ 2.52	$ 2.5
Nonrelated Party [Member]
Revenues:
Total revenues		$ 56,161	$ 49,654	$ 58,127
Related Party [Member]
Revenues:
Total revenues		$ 58	$ 61	$ 59
[1]As presented on our Statements of Consolidated Operations, Total other expense, net is comprised of Interest expense, Interest income and Other, net.

STATEMENTS OF CONSOLIDATED COMP

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
Net income	$ 5,970	$ 5,657	$ 5,615
Commodity hedging derivative instruments:
Changes in fair value of cash flow hedges	115	93	254
Reclassification of gains to net income	(178)	(110)	(220)
Interest rate hedging derivative instruments:
Changes in fair value of cash flow hedges	(2)	(36)	26
Reclassification of losses (gains) to net income	(6)	(5)	19
Total cash flow hedges	(71)	(58)	79
Total other comprehensive income (loss)	(71)	(58)	79
Comprehensive income	5,899	5,599	5,694
Comprehensive income attributable to noncontrolling interests	(69)	(125)	(125)
Comprehensive income attributable to preferred units	(4)	(3)	(3)
Comprehensive income attributable to common unitholders	$ 5,826	$ 5,471	$ 5,566

STATEMENTS OF CONSOLIDATED CASH

STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Operating activities:
Net income	$ 5,970	$ 5,657	$ 5,615
Reconciliation of net income to net cash flow provided by operating activities:
Depreciation and accretion	1,987	1,871	1,797
Amortization of intangible assets	207	201	177
Amortization of major maintenance costs for reaction-based plants	59	64	51
Other amortization expense	220	207	220
Impairment of assets other than goodwill	57	32	53
Equity in income of unconsolidated affiliates	(408)	(462)	(464)
Distributions received from unconsolidated affiliates attributable to earnings	406	446	446
Net losses (gains) attributable to asset sales and related matters	2	(10)	1
Deferred income tax expense	45	12	60
Change in fair market value of derivative instruments	(20)	33	78
Non-cash expense related to long-term operating leases	95	72	59
Net effect of changes in operating accounts	(506)	(555)	(54)
Other operating activities	1	1	0
Net cash flow provided by operating activities	8,115	7,569	8,039
Investing activities:
Capital expenditures	(4,544)	(3,266)	(1,964)
Cash used for business combinations, net of cash received	(949)	0	(3,204)
Investments in unconsolidated affiliates	0	(2)	(1)
Distributions received from unconsolidated affiliates attributable to the return of capital	77	42	98
Proceeds from asset sales and other matters	14	42	122
Other investing activities	(31)	(13)	(5)
Net cash flow used in investing activities	(5,433)	(3,197)	(4,954)
Financing activities:
Borrowings under debt agreements	53,715	89,899	96,140
Repayments of debt	(50,546)	(89,447)	(97,395)
Debt issuance costs	(44)	(17)	(1)
Monetization of interest rate derivative instruments	(33)	21	0
Cash distributions paid to common unitholders	(4,512)	(4,301)	(4,095)
Cash payments made in connection with distribution equivalent rights	(43)	(38)	(34)
Cash distributions paid to noncontrolling interests	(106)	(160)	(163)
Cash contributions from noncontrolling interests	90	44	7
Repurchase of common units under 2019 Buyback Program	(219)	(188)	(250)
Acquisition of noncontrolling interests	(400)	(10)	0
Other financing activities	(66)	(61)	(53)
Net cash flow used in financing activities	(2,164)	(4,258)	(5,844)
Net change in cash and cash equivalents, including restricted cash	518	114	(2,759)
Cash and cash equivalents, including restricted cash, at beginning of period	320	206	2,965
Cash and cash equivalents, including restricted cash, at end of period	$ 838	$ 320	$ 206

STATEMENTS OF CONSOLIDATED EQUI

STATEMENTS OF CONSOLIDATED EQUITY - USD ($) $ in Millions	Total	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interests in Consolidated Subsidiaries [Member]	Common Limited Partners Interests [Member]	Treasury Units [Member]
Balance at Dec. 31, 2021	$ 26,439	$ 286	$ 1,110	$ 26,340	$ (1,297)
Increase (Decrease) in Partners' Equity [Roll Forward]
Net income	5,612	0	125	5,487	0
Cash distributions paid to common unitholders	(4,095)	0	0	(4,095)	0
Cash payments made in connection with distribution equivalent rights	(34)	0	0	(34)	0
Cash distributions paid to noncontrolling interests	(163)	0	(163)	0	0
Cash contributions from noncontrolling interests	7	0	7	0	0
Repurchase and cancellation of common units under 2019 Buyback Program	(250)	0	0	(250)	0
Amortization of fair value of equity-based awards	156	0	0	156	0
Cash flow hedges	79	79	0	0	0
Other, net	(49)	0	0	(49)	0
Balance at Dec. 31, 2022	27,702	365	1,079	27,555	(1,297)
Increase (Decrease) in Partners' Equity [Roll Forward]
Net income	5,654	0	125	5,529	0
Cash distributions paid to common unitholders	(4,301)	0	0	(4,301)	0
Cash payments made in connection with distribution equivalent rights	(38)	0	0	(38)	0
Cash distributions paid to noncontrolling interests	(160)	0	(160)	0	0
Cash contributions from noncontrolling interests	44	0	44	0	0
Repurchase and cancellation of common units under 2019 Buyback Program	(188)	0	0	(188)	0
Amortization of fair value of equity-based awards	170	0	0	170	0
Acquisition of noncontrolling interests	(10)	0	(2)	(8)	0
Cash flow hedges	(58)	(58)	0	0	0
Other, net	(56)	0	0	(56)	0
Balance at Dec. 31, 2023	28,759	307	1,086	28,663	(1,297)
Increase (Decrease) in Partners' Equity [Roll Forward]
Net income	5,966	0	69	5,897	0
Cash distributions paid to common unitholders	(4,512)	0	0	(4,512)	0
Cash payments made in connection with distribution equivalent rights	(43)	0	0	(43)	0
Cash distributions paid to noncontrolling interests	(106)	0	(106)	0	0
Cash contributions from noncontrolling interests	90	0	90	0	0
Repurchase and cancellation of common units under 2019 Buyback Program	(219)	0	0	(219)	0
Amortization of fair value of equity-based awards	187	0	0	187	0
Acquisition of noncontrolling interests	(400)	0	(282)	(118)	0
Cash flow hedges	(71)	(71)	0	0	0
Other, net	(62)	0	0	(62)	0
Balance at Dec. 31, 2024	$ 29,589	$ 236	$ 857	$ 29,793	$ (1,297)

Partnership Organization and Op

Partnership Organization and Operations	12 Months Ended
	Dec. 31, 2024
Partnership Organization and Operations [Abstract]
Partnership Organization and Operations	KEY REFERENCES USED IN THESE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Unless the context requires otherwise, references to “we,” “us,” or “our” within these Notes to Consolidated Financial Statements are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. References to the “Partnership” or “Enterprise” mean Enterprise Products Partners L.P. on a standalone basis. References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of the Partnership, and its consolidated subsidiaries, through which the Partnership conducts its business. We are managed by our general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company. The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors of Enterprise GP (the “Board”); (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board; and (iii) W. Randall Fowler, who is also a director and a Co-Chief Executive Officer of Enterprise GP. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC. References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO; and (iii) Mr. Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO. We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. EPCO, together with its privately held affiliates, owned approximately 32.4% of the Partnership’s common units outstanding at December 31, 2024. All statistical data (e.g., pipeline mileage, processing capacity and similar operating metrics) in these notes to consolidated financial statements are unaudited. 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. 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 We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership. We conduct substantially all of our business operations through EPO and its consolidated subsidiaries. Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations include: • natural gas gathering, treating, processing, transportation and storage; • NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases (“LPG”) and ethane); • crude oil gathering, transportation, storage, and marine terminals; • propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities; • petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”)); and • a marine transportation business that operates on key U.S. inland and intracoastal waterway systems. Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers. See Note 15 for information regarding related party matters. Our operations are reported under four business segments: NGL Pipelines & Services, Crude Oil Pipelines & Services, Natural Gas Pipelines & Services and Petrochemical & Refined Products Services. See Note 10 for additional information regarding our business segments.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2024
Summary of Significant Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2. Summary of Significant Accounting Policies Our consolidated financial statements are prepared on the accrual basis of accounting in accordance with U.S. generally accepted accounting principles (“GAAP”). 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 for the years indicated: For the Year Ended December 31, 2024 2023 2022 Balance at beginning of period $ 35 $ 54 $ 53 Charged to costs and expenses 3 1 6 Charged to other accounts – – 1 Deductions – (20 ) (6 ) Balance at end of period $ 38 $ 35 $ 54 Cash, Cash Equivalents and Restricted Cash Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase. Restricted cash primarily represents amounts held in segregated bank accounts by our clearing brokers as margin in support of our commodity derivative instruments portfolio and related physical purchases and sales of natural gas, NGLs, crude oil, refined products and power. Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or margin requirements change. See Note 14 for information regarding our derivative instruments and hedging activities. The following table provides a reconciliation of cash and cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the amounts shown in the Statements of Consolidated Cash Flows. December 31, 2024 2023 Cash and cash equivalents $ 583 $ 180 Restricted cash 255 140 Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows $ 838 $ 320 Consolidation Policy Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the Partnership. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Third party or affiliate ownership interests in our controlled subsidiaries are presented as noncontrolling interests. See Note 8 for information regarding noncontrolling interests. If the entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50%, unless our interest is so minor that we have virtually no influence over the investee’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. In consolidation, we eliminate our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates to the extent such amounts remain on our Consolidated Balance Sheets (or those of our equity method investments) in inventory or similar accounts. Contingencies Certain conditions may exist as of the date our consolidated financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the need for accounting recognition or disclosure of these contingencies, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. We accrue an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 17 for additional information regarding our contingencies. Current Assets and Current Liabilities We present, as individual captions in our Consolidated Balance Sheets, all components of current assets and current liabilities that exceed 5% of total current assets and current liabilities, respectively. Derivative Instruments We use derivative instruments such as futures, swaps, forward contracts and other arrangements to manage price risks associated with inventories, firm commitments, interest rates and certain anticipated future commodity transactions. To qualify for hedge accounting, the hedged item must expose us to risk and the related derivative instrument must reduce the exposure to that risk and meet specific hedge documentation requirements related to designation dates, expectations for hedge effectiveness and the probability that hedged future transactions will occur as forecasted. We formally designate derivative instruments as hedges and document and assess their effectiveness at inception of the hedge and on a monthly basis thereafter. Forecasted transactions are evaluated for the probability of occurrence and are periodically back-tested once the forecasted period has passed to determine whether forecasted transactions are probable of occurring in the future. We are required to recognize derivative instruments at fair value as either assets or liabilities on our Consolidated Balance Sheets unless such instruments meet certain normal purchase/normal sale criteria. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. After meeting specified conditions, a qualified derivative may be designated as a total or partial hedge of: • Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment – In a fair value hedge, gains and losses for both the derivative instrument and the hedged item are recognized in income during the period of change. • Variable cash flows of a forecasted transaction – In a cash flow hedge, the change in the fair value of the hedge is reported in other comprehensive income (loss) and is reclassified to earnings when the forecasted transaction affects earnings. An effective hedge relationship is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of the changes in fair value of a hedged item at inception and throughout the life of the hedging relationship. The effective portion of a hedge relationship is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period. A contract designated as a cash flow hedge of an anticipated transaction that is not probable of occurring is immediately recognized in earnings. Certain of our derivative instruments do not qualify for hedge accounting treatment; therefore, these instruments are accounted for using mark-to-market accounting. For substantially all of our physical forward commodity derivative contracts, we apply the normal purchase/normal sale exception, whereby changes in the mark-to-market values of such contracts are not recognized in income. As a result, the revenues and expenses associated with such physical transactions are recognized during the period when volumes are physically delivered or received. Physical forward commodity contracts subject to this exception are evaluated for the probability of future delivery and certain of these physical forward commodity contracts are periodically back-tested once the forecasted period has passed to determine whether similar forward contracts are probable of physical delivery in the future. See Note 14 for additional information regarding our derivative instruments. Environmental Costs Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. For the year ended December 31, 2024 and 2023, our environmental reserves totaled $9 million and $4 million, respectively. Estimates Preparing our consolidated financial statements in conformity with GAAP requires us to make estimates that affect amounts presented in the financial statements. Our most significant estimates relate to (i) the useful lives and depreciation/amortization methods used for fixed and identifiable intangible assets; (ii) measurement of fair value and projections used in impairment testing of fixed and intangible assets (including goodwill); and (iii) revenue and expense accruals. Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our consolidated financial statements. Fair Value Measurements Our recurring and nonrecurring fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk, in the principal market of the asset or liability at a specified measurement date. Recognized valuation techniques (such as the income or market approaches) employ inputs such as contractual prices, quoted market prices or rates, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. A three-tier hierarchy has been established that classifies fair value amounts recognized in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2 fair value measures) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3 fair value measures). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. The characteristics of fair value amounts classified within each level of the hierarchy are described as follows: • Level 1 fair value measures • Level 2 fair value measures • Level 3 fair value measures With regards to commodity derivatives, our Level 3 fair values primarily consist of the following commodity derivative instruments used to hedge various inventories and transportation capacities: (i) NGL, crude, natural gas, refined products and commercial energy-based contracts with terms greater than 36 months; (ii) over-the-counter options; and (iii) exchange traded options with terms greater than one year. In addition, we often rely on price quotes from reputable brokers who publish price quotes on certain products and compare these prices to other reputable brokers for the same products in the same markets whenever possible. These prices, when combined with data from our commodity derivative instruments, are used in our models to determine the fair value of such instruments. Our nonrecurring fair value estimates are generally based on the income approach to fair value and reflect various Level 3 inputs. In many cases, there are no active markets (a Level 1 fair value measure) to rely on or other similar recent transactions (a Level 2 fair value measure) to compare to. Our nonrecurring fair value estimates often include management’s expectations of the residual market values for the underlying assets based on their knowledge and experience in the industry (a Level 3 fair value measure). Other examples of Level 3 inputs used in the valuation models include anticipated gross operating margins, throughput or processing volumes, utilization factors, sustaining capital expenditures, discount rates and business growth rates. When probability weights are used in cash flow modeling, the weights are generally obtained from management personnel having oversight responsibilities for the assets being tested. Impairment Testing The following table summarizes our asset impairment charges by type as presented on our Statements of Consolidated Cash Flows for the years indicated: For the Year Ended December 31, 2024 2023 2022 Impairment charges reflected in operating costs and expenses: Property, plant and equipment $ 50 $ 18 $ 41 Other (1) 7 12 12 Total asset impairment charges in operating costs and expenses (2) 57 30 53 Other property, plant and equipment impairment charges (3) – 2 – Total asset impairment charges $ 57 $ 32 $ 53 (1) Primarily represents the write-down of surplus materials classified as “Other assets” on our Consolidated Balance Sheets. (2) Amounts presented are a component of “Third party and other costs” within the “Operating costs and expenses” section of our Statements of Consolidated Operations. (3) Amounts presented are a component of “Third party and other costs” within the “General and administrative costs” section of our Statements of Consolidated Operations. The following information describes our accounting policies regarding impairment testing for major asset categories: • Impairment Testing for Long-Lived Assets. Long-lived assets, which consist of intangible assets with finite lives and property, plant and equipment, are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written down to their estimated fair values. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted estimated cash flows expected to result from the use and eventual disposition of the asset. If the asset’s carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques. See Note for information regarding impairment charges attributable to property, plant and equipment. • Impairment Testing for Investments in Unconsolidated Affiliates. • Impairment Testing for Goodwill. We determine the fair value of each reporting unit using accepted valuation techniques, primarily through the use of discounted cash flows (i.e., an income approach to fair value) supplemented by market-based assessments, if available. The estimated fair values of our reporting units incorporate assumptions regarding the future economic prospects of the assets and operations that comprise each reporting unit including: (i) discrete financial forecasts for the assets comprising the reporting unit, which, in turn, rely on management’s estimates of long-term operating margins, throughput volumes, capital investments and similar factors; (ii) long-term growth rates for the reporting unit’s cash flows beyond the discrete forecast period; and (iii) appropriate discount rates. The fair value estimates are based on Level 3 inputs of the fair value hierarchy. We believe that the assumptions we use in estimating reporting unit fair values are consistent with those that market participants would use in their fair value estimation process. However, due to uncertainties in the estimation process and volatility in the supply and demand for hydrocarbons and similar risk factors, actual results could differ significantly from our estimates. Based on our most recent goodwill impairment test at , the estimated fair value of each of our reporting units was substantially in excess of its carrying value (i.e., by at least 10%). We did not record any non-cash goodwill impairment charges during the years ended December 31, 2024, 2023 or 2022. See Note 6 for additional information regarding our goodwill. Inventories Inventories primarily consist of NGLs, petrochemicals, refined products, crude oil and natural gas volumes that are valued at the lower of cost or net realizable value. We capitalize, as a cost of inventory, shipping and handling charges (e.g., pipeline transportation and storage fees) and other related costs associated with purchased volumes. As volumes are sold and delivered out of inventory, the cost of these volumes (including freight-in charges that have been capitalized as part of inventory cost) are charged to operating costs and expenses. Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred. See Note 3 for additional information regarding our inventories. Leases We account for our leases under Accounting Standards Codification (“ASC”) 842, Leases The standard includes two lessee accounting models, which results in a lease being classified as either a “finance” or “operating” lease based on whether the lessee effectively obtains control of the underlying asset during the lease term. A lease would be classified as a finance lease if it meets one of five classification criteria. By default, a lease that does not meet the criteria to be classified as a finance lease will be deemed an operating lease. Regardless of classification, the initial measurement of both lease types will result in the balance sheet recognition of a right-of-use (“ROU”) asset (representing a company’s right to use the underlying asset for a specified period of time) and a corresponding lease liability. The lease liability will be recognized at the present value of the future lease payments, and the ROU asset will equal the lease liability adjusted for any prepaid rent, lease incentives provided by the lessor, and any indirect costs. The subsequent measurement of each type of lease varies. For finance leases, a lessee will amortize the ROU asset (generally on a straight-line basis in a manner similar to depreciation) and accrete the lease liability (as a component of interest expense) using the . Operating leases will result in the recognition of a single lease expense amount that is recorded on a straight-line basis. We do not recognize ROU assets and lease liabilities for short-term leases, which are leases with a maximum term of 12 months or less and do not include a purchase option that the lessee is reasonably certain to exercise, and instead recognize lease payments on a straight-line basis. In addition, we combine lease and non-lease components relating to our office and warehouse leases, as applicable. See Note 17 for our disclosures regarding our lease obligations. Property, Plant and Equipment Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized, and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in results of operations for the respective period. 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. In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management assumptions regarding the useful economic lives and residual values of our assets. Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes. Leasehold improvements are recorded as a component of property, plant and equipment. The cost of leasehold improvements is charged to earnings using the straight-line method over the shorter of (i) the remaining lease term or (ii) the estimated useful lives of the improvements. We consider renewal terms that are deemed reasonably assured when estimating remaining lease terms. Our assumptions regarding the useful economic lives and residual values of our assets may change in response to new facts and circumstances, which would prospectively impact our depreciation expense amounts. Examples of such circumstances include, but are not limited to: (i) changes in laws and regulations that limit the estimated economic life of an asset; (ii) changes in technology that render an asset obsolete; (iii) changes in expected salvage values or (iv) significant changes in the forecast life of the applicable resource basins, if any. Certain of our plant facilities undergo periodic planned outages for major maintenance activities. The method of accounting for these activities depends on whether the plant utilizes either a distillation-based or reaction-based process. Our natural gas processing plants, NGL fractionators, deisobutanizers, propylene splitters and similar facilities utilize thermal distillation processes to separate hydrocarbons into more useful components. Our reaction-based plants, which primarily include our PDH, isomerization and octane enhancement facilities, utilize catalysts to facilitate chemical reactions that convert lower value hydrocarbons into higher value products. We use the expense-as-incurred method to account for the planned major maintenance activities of distillation-based plants. 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. With regard to the planned major maintenance activities of our marine transportation assets and underground storage caverns, we continue to use the deferral method to account for such costs. Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the ARO liability is accreted to its present value (through accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts. See Note 4 for additional information regarding our property, plant and equipment and AROs. Revenues Substantially all of our revenues are accounted for under ASC 606, Revenue from Contracts with Customers, Leases, Nonmonetary Transactions, Derivatives and Hedging Activities The core principle of ASC 606 is that a company should recognize revenue in a manner that fairly depicts the transfer of goods or services to customers in amounts that reflect the consideration the company expects to receive for those goods or services. We apply this core principle by following five key steps outlined in ASC 606: (i) identify the contract; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management judgment and an analysis of the contract’s material terms and conditions. Under ASC 606, we recognize revenue when or as we satisfy our performance obligation to the customer. In situations where we have recognized revenue, but have a conditional right to consideration (based on something other than the passage of time) from the customer, we recognize unbilled revenue (a contract asset) on our consolidated balance sheet. Unbilled revenue is reclassified to accounts receivable when we have an unconditional right of payment from the customer. Payments received from customers in advance of the period in which we satisfy a performance obligation are recorded as deferred revenue (a contract liability) on our consolidated balance sheet. Our revenue streams are derived from the sale of products and providing midstream services. Revenues from the sale of products are recognized at a point in time, which represents the transfer of control (and the satisfaction of our performance obligation under the contract) to the customer. From that point forward, the customer is able to direct the use of, and obtain substantially all the benefits from its use of, the products. With respect to midstream services (e.g., interruptible transportation), we satisfy our performance obligations over time and recognize revenues when the services are provided and the customer receives the benefits based on an output measure of volumes redelivered. We believe this measure is a faithful depiction of the transfer of control for midstream services since there is (i) an insignificant period of time between the receipt of customers’ volumes and their subsequent redelivery, and (ii) it is not possible to individually track and differentiate customers’ inventories as they traverse our facilities. For stand-ready performance obligations (e.g., a storage capacity reservation contract), we recognize revenues over time on a straight-line basis as time elapses over the term of the contract. We believe that these approaches accurately depict the transfer of benefits to the customer. Customers are invoiced for products purchased or services rendered when we have an unconditional right to consideration under the associated contract. The consideration we are entitled to invoice may be either fixed, variable or a combination of both. Examples of fixed consideration would be fixed payments from customers under take-or-pay arrangements, storage capacity reservation agreements and firm transportation contracts. Variable consideration represents payments from customers that are based on factors that fluctuate (or vary) based on volumes, prices or both. Examples of variable consideration include interruptible transportation agreements, market-indexed product sales contracts and the value of NGLs we retain under natural gas processing agreements. The terms of our billings are typical of the industry for the products we sell. Under certain midstream service agreements, customers are required to provide a minimum volume over an agreed-upon period with a provision that allows the customer to make-up any volume shortfalls over an agreed-upon period (referred to as “make-up rights”). Revenue pursuant to such agreements is initially deferred and subsequently recognized when either the make-up rights are exercised, the likelihood of the customer exercising the rights becomes remote, or we are otherwise released from the performance obligation. Customers may contribute funds to us to help offset the construction costs related to pipeline construction activities and production well tie-ins. These receipts are recognized as additional service revenues over the term of the associated midstream services provided to the customer. For those contracts under which we have the ability to invoice the customer in an amount that corresponds directly with the value of the performance obligation completed to date, we recognize revenue as we have the right to invoice. See Note 9 regarding our revenue disclosures.

Inventories

Inventories	12 Months Ended
	Dec. 31, 2024
Inventories [Abstract]
Inventories	Note 3. Inventories Our inventory amounts by product type were as follows at the dates indicated: December 31, 2024 2023 NGLs $ 2,768 $ 2,392 Petrochemicals and refined products 652 536 Crude oil 523 419 Natural gas 12 5 Total $ 3,955 $ 3,352 In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to outright purchases from third parties for cash), these volumes are valued at market-based prices during the month in which they are acquired. The following table presents our total cost of sales amounts and lower of cost or net realizable value adjustments for the years indicated: For the Year Ended December 31, 2024 2023 2022 Cost of sales (1) $ 42,580 $ 37,023 $ 45,836 Lower of cost or net realizable value adjustments recognized in cost of sales 9 31 19 (1) Cost of sales is a component of “Operating costs and expenses,” as presented on our 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. 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. These non-cash charges are a component of cost of sales in the period they are recognized. To the extent our commodity hedging strategies address inventory-related price risks and are successful, these inventory valuation adjustments are mitigated or offset. See Note 14 for a description of our commodity hedging activities.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2024
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	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 December 31, in Years 2024 2023 Plants, pipelines and facilities (1)(5) 3-45 $ 60,716 $ 57,983 Underground and other storage facilities (2)(6) 5-40 4,704 4,401 Transportation equipment (3) 3-10 272 242 Marine vessels (4) 15-30 949 935 Land 424 411 Construction in progress 4,138 2,245 Subtotal 71,203 66,217 Less accumulated depreciation 22,330 20,462 Subtotal property, plant and equipment, net 48,873 45,755 Capitalized major maintenance costs for reaction-based plants, net of accumulated amortization (7) 189 49 Property, plant and equipment, net $ 49,062 $ 45,804 (1) Plants, pipelines and facilities include distillation-based and reaction-based plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; buildings; office furniture and equipment; laboratory and shop equipment and related assets. (2) Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets. (3) Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations. (4) Marine vessels include tow boats, barges and related equipment used in our marine transportation business. (5) In general, the estimated useful lives of major assets within this category are: distillation-based and reaction-based plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; buildings, 20-40 years; office furniture and equipment, 3-20 years; and laboratory and shop equipment, 5-35 years. (6) In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years. (7) For reaction-based plants, we use the deferral method when accounting for major maintenance activities. Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. On a weighted-average basis, the expected remaining amortization period for these costs is 3.4 years. The following table summarizes our depreciation expense and capitalized interest amounts for the years indicated: For the Year Ended December 31, 2024 2023 2022 Depreciation expense (1) $ 1,974 $ 1,860 $ 1,779 Capitalized interest (2) 121 106 90 (1) Depreciation expense is a component of “Third party and other costs” within “Costs and expenses” as presented on our Statements of Consolidated Operations. (2) Capitalized interest is a component of “Interest expense” as presented on our Statements of Consolidated Operations. Asset Retirement Obligations We record AROs in connection with legal requirements to perform specified retirement activities under contractual arrangements and/or governmental regulations. Our contractual AROs primarily result from right-of-way agreements associated with our pipeline operations and property leases associated with our plant sites. In addition, we record AROs in connection with governmental regulations associated with the abandonment or retirement of above-ground brine storage pits and certain marine vessels. We also record AROs in connection with regulatory requirements associated with the renovation or demolition of certain assets containing hazardous substances such as asbestos. We typically fund our AROs using cash flow from operations. Property, plant and equipment at December 31, 2024 and 2023 includes $134 million and $109 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset. The following table presents information regarding our AROs for the years indicated: For the Year Ended December 31, 2024 2023 2022 ARO liability beginning balance $ 225 $ 234 $ 176 Liabilities incurred (1) 1 5 20 Revisions in estimated cash flows (2) 30 (12 ) 30 Liabilities settled (3) (4 ) (13 ) (10 ) Accretion expense (4) 13 11 18 ARO liability ending balance $ 265 $ 225 $ 234 (1) Represents the initial recognition of estimated ARO liabilities during the period. (2) Represents subsequent adjustments to estimated ARO liabilities during the period. (3) Represents cash payments to settle ARO liabilities during the period. (4) Represents 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 $265 million total ARO liability recorded at December 31, 2024, $6 million was reflected as a current liability and $259 million as a long-term liability. The following table presents our forecast of ARO-related accretion expense for the years indicated: 2025 2026 2027 2028 2029 $ 15 $ 16 $ 17 $ 18 $ 19 Impairments of Property, Plant and Equipment The following table presents our non-cash asset impairment charges involving property, plant and equipment by business segment for the years indicated: For the Year Ended December 31, 2024 2023 2022 NGL Pipelines & Services $ 28 $ 12 $ 23 Crude Oil Pipelines & Services – 1 3 Natural Gas Pipelines & Services 7 5 6 Petrochemical & Refined Products Services 15 2 9 Total impairment charges for property, plant and equipment $ 50 $ 20 $ 41 Our impairment charges for the years ended December 31, 2024, 2023 and 2022 are attributable to the complete write-off of assets that are no longer expected to be used or constructed.

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2024
Investments in Unconsolidated Affiliates [Abstract]
Investments in Unconsolidated Affiliates	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. Ownership Interest at December 31, December 31, 2024 2024 2023 NGL Pipelines & Services: Venice Energy Service Company, L.L.C. (“VESCO”) 13.1% $ 24 $ 24 K/D/S Promix, L.L.C. (“Promix”) 50% 22 25 Baton Rouge Fractionators LLC (“BRF”) 32.2% 12 13 Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”) 50% 25 26 Texas Express Pipeline LLC (“Texas Express”) 35% 299 303 Texas Express Gathering LLC (“TEG”) 45% 33 35 Front Range Pipeline LLC (“Front Range”) 33.3% 183 186 Total NGL Pipelines & Services 598 612 Crude Oil Pipelines & Services: Seaway Crude Holdings LLC (“Seaway”) 50% 1,147 1,192 Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”) 50% 368 373 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”) 50% 113 116 Total Crude Oil Pipelines & Services 1,628 1,681 Natural Gas Pipelines & Services: White River Hub, LLC (“White River Hub”) 50% 16 17 Old Ocean Pipeline, LLC (“Old Ocean”) 50% 14 16 Total Natural Gas Pipelines & Services 30 33 Petrochemical & Refined Products Services: Baton Rouge Propylene Concentrator LLC (“BRPC”) 30% 1 2 Transport 4, LLC (“Transport 4”) 25% 2 2 Total Petrochemical & Refined Products Services 3 4 T otal investments in unconsolidated affiliates $ 2,259 $ 2,330 NGL Pipelines & Services The principal business activity of each investee included in our NGL Pipelines & Services segment is described as follows: • VESCO • Promix • BRF • Skelly-Belvieu • Texas Express • TEG • Front Range Crude Oil Pipelines & Services The principal business activity of each investee included in our Crude Oil Pipelines & Services segment is described as follows: • Seaway • Eagle Ford Crude Oil Pipeline • Eagle Ford Corpus Christi Natural Gas Pipelines & Services The principal business activity of each investee included in our Natural Gas Pipelines & Services segment is described as follows: • White River Hub • Old Ocean owns a natural gas pipeline that extends from near Maypearl, Texas to Sweeny, Texas. Petrochemical & Refined Products Services The principal business activity of each investee included in our Petrochemical & Refined Products Services segment is described as follows: • BRPC • Transport 4 Equity Earnings The following table presents our equity in income of unconsolidated affiliates by business segment for the years indicated: For the Year Ended December 31, 2024 2023 2022 NGL Pipelines & Services $ 117 $ 133 $ 149 Crude Oil Pipelines & Services 285 320 308 Natural Gas Pipelines & Services 5 6 5 Petrochemical & Refined Products Services 1 3 2 Total $ 408 $ 462 $ 464

Intangible Assets and Goodwill

Intangible Assets and Goodwill	12 Months Ended
	Dec. 31, 2024
Intangible Assets and Goodwill [Abstract]
Intangible Assets and Goodwill	Note 6. Intangible Assets and Goodwill Identifiable Intangible Assets The following table summarizes our intangible assets by business segment at the dates indicated: December 31, 2024 December 31, 2023 Gross Value Accumulated Amortization Carrying Value Gross Value Accumulated Amortization Carrying Value NGL Pipelines & Services: Customer relationship intangibles $ 449 $ (276 ) $ 173 $ 449 $ (263 ) $ 186 Contract-based intangibles 754 (141 ) 613 752 (110 ) 642 Segment total 1,203 (417 ) 786 1,201 (373 ) 828 Crude Oil Pipelines & Services: Customer relationship intangibles 2,195 (627 ) 1,568 2,195 (530 ) 1,665 Contract-based intangibles 283 (278 ) 5 283 (275 ) 8 Segment total 2,478 (905 ) 1,573 2,478 (805 ) 1,673 Natural Gas Pipelines & Services: Customer relationship intangibles 1,351 (663 ) 688 1,351 (625 ) 726 Contract-based intangibles 1,081 (227 ) 854 641 (209 ) 432 Segment total 2,432 (890 ) 1,542 1,992 (834 ) 1,158 Petrochemical & Refined Products Services: Customer relationship intangibles 181 (92 ) 89 181 (86 ) 95 Contract-based intangibles 45 (30 ) 15 45 (29 ) 16 Segment total 226 (122 ) 104 226 (115 ) 111 Total intangible assets $ 6,339 $ (2,334 ) $ 4,005 $ 5,897 $ (2,127 ) $ 3,770 The following table presents the amortization expense of our intangible assets by business segment for the years indicated: For the Year Ended December 31, 2024 2023 2022 NGL Pipelines & Services $ 44 $ 40 $ 36 Crude Oil Pipelines & Services 100 103 84 Natural Gas Pipelines & Services 56 51 50 Petrochemical & Refined Products Services 7 7 7 Total $ 207 $ 201 $ 177 The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated: 2025 2026 2027 2028 2029 $ 218 $ 215 $ 209 $ 198 $ 199 Customer relationship intangible assets Customer relationship intangible assets represent the estimated economic value assigned to commercial relationships acquired in connection with business combinations. Our customer relationship intangible assets are classified as either (i) basin-specific or (ii) general. Basin-specific customer relationships represent access to customers associated with a defined resource basin (e.g., customers using a natural gas gathering system serving a specific production field) and is analogous to having a franchise in a particular area. General customer relationships are associated with customers whose hydrocarbon volumes are not attributable to specific resource basins (e.g., customers at a marine terminal that handles volumes originating from multiple sources). The estimated fair value of each customer relationship intangible asset was determined at the time of acquisition using a discounted cash flow analysis, which incorporates various assumptions regarding the acquired business. The assumptions may include Level 3 fair value inputs, including long-range cash flow forecasts that extend for the estimated economic life of the hydrocarbon resource base served by the asset network, anticipated service contract renewals, resource base depletion rates and expected customer attrition rates. The recognition of customer relationships are supported by a variety of factors. In general, midstream infrastructure requires a significant investment, both in terms of initial construction costs and ongoing maintenance, and is generally supported by long-term contracts that establish a customer base. The level of expenditures and regulatory requirements involved in constructing new midstream asset networks can create significant economic barriers to entry that may limit potential competition. Furthermore, efficient, continuous operation of the acquired fixed assets not only supports the commercial relationships existing at the time of the acquisition, but it provides us with opportunities to establish new ones. These factors support the long-term value attributed to our customer relationship intangible assets. With respect to amortization periods, the duration of a basin-specific customer relationship is limited to the estimated economic life of the associated resource basin. The duration of our other customer relationships is typically limited to the term of the underlying service contracts, including assumed renewals. Amortization expense attributable to customer relationships is recorded in a manner that closely resembles the pattern in which we expect to benefit from such relationships. At December 31, 2024, the carrying value of our portfolio of customer relationship intangible assets was $2.5 billion, the principal components of which were as follows: a Weighted Average Remaining Amortization Period December 31, 2024 Gross Value Accumulated Amortization Carrying Value Basin-specific customer relationships: EFS Midstream (acquired 2015) 17.4 years $ 1,410 $ (407) $ 1,003 State Line and Fairplay (acquired 2010) 22.2 years 895 (328) 567 San Juan Gathering (acquired 2004) 14.8 years 331 (274) 57 General customer relationships: Oiltanking (acquired 2014) 19.0 years 1,193 (340) 853 • EFS Midstream . The EFS Midstream System provides condensate gathering and processing services along with gathering, treating and compression services for associated natural gas. • The State Line and Fairplay The Haynesville Gathering System gathers and treats natural gas produced from the Haynesville and Bossier Shale supply basins and the Cotton Valley and Taylor Sand formations in Louisiana and East Texas. The Fairplay Gathering System gathers natural gas produced from the Cotton Valley formation in East Texas. • The San Juan Gathering • The Oiltanking Contract-based intangible assets Contract-based intangible assets represent specific commercial rights we acquired in connection with business combinations. These intangible assets are typically valued using an income approach that incorporate the terms of the agreements. At December 31, 2024, the carrying value of our portfolio of contract-based intangible assets was $1.5 billion, the principal components of which were as follows: a Weighted Average Remaining Amortization Period December 31, 2024 Gross Value Accumulated Amortization Carrying Value Midland Basin customer contracts 27.0 years $ 989 $ (77) $ 912 Pinon Midstream customer contracts 24.0 years 435 (2) 433 Jonah natural gas gathering agreements 17.0 years 224 (187) 37 Delaware Basin natural gas processing contracts 1.9 years 82 (58) 24 • Midland Basin customer contracts represents the estimated value we assigned to the acquired long-term contracts with customers that dedicate future lease production to our system. The estimated fair value of the acquired contract-based intangible assets was determined using an income approach, specifically a discounted cash flow analysis. The fair value estimate incorporates Level 3 inputs including: (i) management’s long-term forecast of cash flows generated by the Midland Basin System based on the estimated economic life of the hydrocarbon resource basin served and resource depletion rates; and (ii) a discount rate of , which is based on a benchmarking analysis with reference to the implied rate of return on the Navitas Midstream acquisition and a market participant weighted average cost of capital. The estimated useful life of the acquired contract-based intangible asset is years. • The Pinon Midstream customer contracts represents the estimated value we assigned to the acquired long-term contracts with customers t . • The Jonah natural gas gathering agreements • The Delaware Basin natural gas processing contracts Goodwill Goodwill represents the cost of acquired businesses in excess of the fair value of their net assets at acquisition. The following table presents changes in the carrying amount of goodwill by business segment during the periods indicated: NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Consolidated Total Balance at December 31, 2022 $ 2,811 $ 1,841 $ – $ 956 $ 5,608 Balance at December 31, 2023 2,811 1,841 – 956 5,608 Goodwill related to acquisition (2) 29 – 75 – 104 Balance at December 31, 2024 $ 2,840 $ 1,841 $ 75 $ 956 $ 5,712 (1) Balances are presented net of historical accumulated impairment losses of $296 million for the Natural Gas Pipelines & Service segment and $1 million for the Petrochemical & Refined Products Services segment. There have been no goodwill impairment charges recognized for the reporting units within the NGL Pipelines & Services and Crude Oil Pipelines & Services segments. (2) This amount represents the goodwill recognized in connection with our acquisition of Pinon Midstream in October 2024. In general, we attribute this goodwill to our ability to expand the acquired sour gas gathering and treating system as well as our ability to leverage the acquired business with our existing NGL asset base to create future business opportunities.

Debt Obligations

Debt Obligations	12 Months Ended
	Dec. 31, 2024
Debt Obligations [Abstract]
Debt Obligations	Note 7. Debt Obligations The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated: December 31, 2024 2023 EPO senior debt obligations: Commercial Paper Notes, variable-rates $ – $ 450 Senior Notes JJ, 3.90 – 850 Senior Notes MM, 3.75 1,150 1,150 March 2024 $1.5 Billion 364-Day Revolving Credit Agreement, variable-rate, due March 2025 (1) – – Senior Notes FFF, 5.05 750 750 Senior Notes PP, 3.70 875 875 Senior Notes HHH, 4.60 1,000 – Senior Notes SS, 3.95 575 575 March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement, variable-rate, due March 2028 (2) – – Senior Notes WW, 4.15 1,000 1,000 Senior Notes YY, 3.125 1,250 1,250 Senior Notes AAA, 2.80 1,250 1,250 Senior Notes GGG, 5.35 1,000 1,000 Senior Notes D, 6.875 500 500 Senior Notes III, 4.85 1,000 – Senior Notes H, 6.65 350 350 Senior Notes JJJ, 4.95 1,100 – Senior Notes J, 5.75 250 250 Senior Notes W, 7.55 400 400 Senior Notes R, 6.125 600 600 Senior Notes Z, 6.45 600 600 Senior Notes BB, 5.95 750 750 Senior Notes DD, 5.70 600 600 Senior Notes EE, 4.85 750 750 Senior Notes GG, 4.45 1,100 1,100 Senior Notes II, 4.85 1,400 1,400 Senior Notes KK, 5.10 1,150 1,150 Senior Notes QQ, 4.90 975 975 Senior Notes UU, 4.25 1,250 1,250 Senior Notes XX, 4.80 1,250 1,250 Senior Notes ZZ, 4.20 1,250 1,250 Senior Notes BBB, 3.70 1,000 1,000 Senior Notes DDD, 3.20 1,000 1,000 Senior Notes EEE, 3.30 1,000 1,000 Senior Notes NN, 4.95 400 400 Senior Notes KKK, 5.55 1,400 – Senior Notes CCC, 3.95 1,000 1,000 Total principal amount of senior debt obligations 29,925 26,725 EPO Junior Subordinated Notes C, variable-rate, due June 2067 232 232 EPO Junior Subordinated Notes D, variable-rate, due August 2077 350 350 EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 1,000 1,000 EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 700 700 TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 – 14 Total principal amount of senior and junior debt obligations 32,207 29,021 Other, non-principal amounts (311 ) (273 ) Less current maturities of debt (1,150 ) (1,300 ) Total long-term debt $ 30,746 $ 27,448 (1) Under the terms of the agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200 million to $1.7 billion at EPO’s election provided certain conditions are met). (2) Under the terms of the agreement, EPO may borrow up to $2.7 billion (which may be increased by up to $500 million to $3.2 billion at EPO’s election provided certain conditions are met). (3) Variable rate is reset quarterly and based on 3-month Chicago Mercantile Exchange (“CME”) Term Secured Overnight Financing Rate (“SOFR”) plus (a) a 0.26161% tenor spread adjustment and (b) 2.778%. (4) Variable rate is reset quarterly and based on 3-month CME Term SOFR plus (a) a 0.26161% tenor spread adjustment and (b) 2.986%. (5) Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month CME Term SOFR plus (a) a 0.26161% tenor spread adjustment and (b) 3.033%. (6) Fixed rate of 5.375% through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month CME Term SOFR plus (a) a 0.26161% tenor spread adjustment and (b) 2.57%. (7) Effective July 1, 2023, all series of our junior subordinated notes subject to a variable interest rate replaced the 3-month London Interbank Offered Rate (“LIBOR”) with 3-month CME Term SOFR plus a 0.26161% tenor spread adjustment. (8) In December 2024, an affiliate of Enterprise redeemed all of the $14 million outstanding principal amount of TEPPCO Junior Subordinated Notes at par (i.e. at a redemption price equal to the outstanding principal amount of such notes to be redeemed, plus accrued and unpaid interest thereon) using cash on hand. References to “TEPPCO” mean TEPPCO Partners, L.P. prior to its merger with one of our wholly owned subsidiaries in October 2009. Variable Interest Rates The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the year ended December 31, 2024: Range of Interest Rates Paid Weighted-Average Interest Rate Paid Commercial Paper Notes 4.68% to 5.50% 5.44% EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes 7.51% to 8.42% 8.23% EPO Junior Subordinated Notes D 7.73% to 8.64% 8.42% Amounts borrowed under EPO’s March 2024 $1.5 Billion 364-Day Revolving Credit Agreement and March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement bear interest, at EPO’s election, equal to: (i) SOFR, plus an additional variable spread; or (ii) an alternate base rate, which is the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 0.5%, or (c) Adjusted Term SOFR for an interest period of one month in effect on such day plus 1%, and a variable spread. The applicable spreads are determined based on EPO's debt ratings. Scheduled Maturities of Debt The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at December 31, 2024 for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2025 2026 2027 2028 2029 Thereafter Senior Notes $ 29,925 $ 1,150 $ 1,625 $ 1,575 $ 1,000 $ 1,250 $ 23,325 Junior Subordinated Notes 2,282 – – – – – 2,282 Total $ 32,207 $ 1,150 $ 1,625 $ 1,575 $ 1,000 $ 1,250 $ 25,607 EPO Debt Obligations Commercial Paper Notes EPO maintains a commercial paper program under which it may issue (and have outstanding at any time) up to $3.0 billion in aggregate principal amount of short-term notes. As a back-stop to the program, we intend to maintain a minimum aggregate available borrowing capacity under EPO’s revolving credit facilities equal to the aggregate amount outstanding under our commercial paper notes. All commercial paper notes issued under the program are senior unsecured obligations of EPO that are unconditionally guaranteed by the Partnership. As of December 31, 2024, EPO had no short-term notes outstanding under its commercial paper program. March 2024 $1.5 Billion 364-Day Revolving Credit Agreement In March 2024, EPO entered into a new $1.5 billion 364-Day Revolving Credit Agreement (the “March 2024 $1.5 Billion 364-Day Revolving Credit Agreement”) that replaced its prior 364-day revolving credit agreement. As of December 31, 2024, there were no principal amounts outstanding under the March 2024 $1.5 Billion 364-Day Revolving Credit Agreement. Under the terms of the March 2024 $1.5 Billion 364-Day Revolving Credit Agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200 million to $1.7 billion at EPO’s election, provided certain conditions are met) at a variable interest rate for a term of up to 364 days, subject to the terms and conditions set forth therein. To the extent that principal amounts are outstanding at the maturity date, EPO may elect to have the entire principal balance then outstanding continued as non-revolving term loans for a period of one additional year, payable in March 2026. Borrowings under the March 2024 $1.5 Billion 364-Day Revolving Credit Agreement may be used for working capital, capital expenditures, acquisitions and general company purposes. The March 2024 $1.5 Billion 364-Day Revolving Credit Agreement contains customary representations, warranties, covenants (affirmative and negative) and events of default, the occurrence of which would permit the lenders to accelerate the maturity date of any amounts borrowed under this credit agreement. The March 2024 $1.5 Billion 364-Day Revolving Credit Agreement also restricts EPO’s ability to pay cash distributions to the Partnership, if an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid or would result therefrom. EPO’s obligations under the March 2024 $1.5 Billion 364-Day Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by the Partnership. The March 2024 $1.5 Billion 364-Day Revolving Credit Agreement is scheduled to mature in March 2025. EPO expects to renew this credit agreement during the first quarter of 2025. 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. As of December 31, 2024, 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. Senior Notes EPO’s fixed-rate senior notes are unsecured obligations of EPO that rank equal with its existing and future unsecured and unsubordinated indebtedness. They are senior to any existing and future subordinated indebtedness of EPO. EPO’s senior notes are subject to make-whole redemption rights and were issued under indentures containing certain covenants, which generally restrict its ability (with certain exceptions) to incur debt secured by liens and engage in sale and leaseback transactions. In total, EPO issued $4.5 billion and $1.75 billion of senior notes during the years ended December 31, 2024 and 2023, respectively. EPO did not issue any senior notes during the year ended December 31, 2022. In January 2024, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of senior notes due January 2027 (“Senior Notes HHH”) and (ii) $1.0 billion principal amount of senior notes due January 2034 (“Senior Notes III”). Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of our $ million principal amount of Senior Notes JJ at their maturity in February 2024 and amounts outstanding under our commercial paper program). In August 2024, EPO issued $2.5 billion aggregate principal amount of senior notes comprised of (i) $1.1 billion principal amount of senior notes due February 2035 (“Senior Notes JJJ”) and (ii) $1.4 billion principal amount of senior notes due February 2055 (“Senior Notes KKK”). Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of our $ billion principal amount of Senior Notes MM at their maturity in February 2025). EPO Junior Subordinated Notes EPO’s payment obligations under its junior subordinated notes (“junior notes”) are subordinated to all of its current and future senior indebtedness. The indenture agreement governing the junior notes allows EPO to defer interest payments on one or more occasions for up to ten consecutive years subject to certain conditions. Subject to certain exceptions, during any period in which interest payments are deferred, neither the Partnership nor EPO can declare or make any distributions on any of our respective equity securities or make any payments on indebtedness or other obligations that rank equal In connection with the issuance of EPO’s Junior Subordinated Notes C, EPO entered into a Replacement Capital Covenant in favor of covered debt holders (as defined in the underlying documents) pursuant to which EPO agreed, for the benefit of such debt holders, that it would not redeem or repurchase such junior notes unless such redemption or repurchase is made using proceeds from the issuance of certain securities. EPO’s junior notes are unconditionally guaranteed on an unsecured and subordinated basis by the Partnership. Letters of Credit At December 31, 2024, EPO had $28 million of letters of credit outstanding primarily related to our insurance program. Lender Financial Covenants We were in compliance with the financial covenants of our consolidated debt agreements at December 31, 2024. Parent-Subsidiary Guarantor Relationships The Partnership acts as guarantor of the consolidated debt obligations of EPO. If EPO were to default on any of its guaranteed debt, the Partnership would be responsible for full and unconditional repayment of such obligations.

Capital Accounts

Capital Accounts	12 Months Ended
	Dec. 31, 2024
Capital Accounts [Abstract]
Capital Accounts	Note 8. Capital Accounts Common Limited Partner Interests The following table summarizes changes in the number of our common units outstanding since December 31, 2021: Common units outstanding at December 31, 2021 2,176,379,587 Common unit repurchases under 2019 Buyback Program (10,166,923 ) Common units issued in connection with the vesting of phantom unit awards, net 4,571,333 Other 22,350 Common units outstanding at December 31, 2022 2,170,806,347 Common unit repurchases under 2019 Buyback Program (7,244,540 ) Common units issued in connection with the vesting of phantom unit awards, net 4,662,539 Other 20,892 Common units outstanding at December 31, 2023 2,168,245,238 Common unit repurchases under 2019 Buyback Program (7,556,210 ) Common units issued in connection with the vesting of phantom unit awards, net 4,990,360 Other 20,574 Common units outstanding at December 31, 2024 2,165,699,962 The Partnership’s common units represent limited partner interests that give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under our (as amended from time to time, the “Partnership Agreement”). In accordance with the Partnership Agreement, capital accounts are maintained for our limited partners. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity balances presented in our consolidated financial statements prepared in accordance with GAAP. Partnership earnings and cash distributions are allocated to holders of our common units in accordance with their respective percentage interests. Registration Statements We have a universal shelf registration statement on file (the “2024 Shelf”) with the SEC which allows the Partnership and EPO (each on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. The 2024 Shelf replaced our prior universal shelf registration statement, which expired in November 2024. In addition, the Partnership has a registration statement on file with the SEC covering the issuance of up to $2.5 billion of its common units in amounts, at prices and on terms based on market conditions and other factors at the time of such offerings (referred to as the Partnership’s at-the-market (“ATM”) program). The Partnership did not issue any common units under its ATM program during the three years ended December 31, 2024. The Partnership’s capacity to issue additional common units under the ATM program remains at $2.5 billion as of December 31, 2024. We may issue additional equity and debt securities to assist us in meeting our future liquidity requirements, including those related to capital investments. Common Unit Repurchases Under 2019 Buyback Program In January 2019, we announced that the Board had approved a $2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides the Partnership with an additional method to return capital to investors. The 2019 Buyback Program authorizes the Partnership to repurchase its common units from time to time, including through open market purchases and negotiated transactions. No time limit has been set for completion of the program, and it may be suspended or discontinued at any time. The Partnership repurchased 2019 Buyback Program through open market purchases during the years ended , and , respectively. The total cost of these repurchases, including commissions and fees, was $ and $ million, respectively Common units 2019 Buyback Program was $ Common Units Delivered Under DRIP and EUPP The Partnership has a registration statement on file with the SEC authorizing the issuance or other delivery of our common units in connection with a distribution reinvestment plan (“DRIP”). The DRIP provides unitholders of record and beneficial owners of our common units a voluntary means by which they can increase the number of our common units they own by reinvesting the quarterly cash distributions they receive from us into the purchase of additional common units. In addition to the DRIP, we have registration statements on file with the SEC authorizing the issuance or other delivery of up to our common units in connection with an employee unit purchase plan (“EUPP”). We have the sole discretion to determine whether common units purchased under the DRIP and EUPP will come from our authorized but unissued common units or from common units purchased on the open market by each plan’s administrator. During each of the years ended December 31, , and , the Partnership used 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. Agents of the Partnership purchased million After taking into account the number of common units delivered under the DRIP through , we have the capacity to deliver an additional common units under this plan. Likewise, we have the capacity to deliver an additional common units under the EUPP. Common Units Issued in Connection With the Vesting of Phantom Unit Awards After taking into account tax withholding requirements, the Partnership issued new Redeemable Preferred Limited Partner Interests The following table summarizes changes in the number of our preferred units outstanding since December 31, 2021: Preferred units outstanding at December 31, 2021, December 31, 2022 and December 31, 2023 50,412 Paid in-kind distribution to third party 275 Preferred units outstanding at December 31, 2024 50,687 In September 2020, the Partnership issued and sold an aggregate of Series A Cumulative Convertible Preferred Units in a private placement transaction. The stated value of each preferred unit is $ per unit. Concurrently, the Partnership exchanged all of the 54,807,352 Partnership common units owned directly by a wholly owned subsidiary, OTA Holdings, Inc. (“OTA”) for 855,915 of the Partnership’s new preferred units having an equivalent value. The preferred units held by OTA, like the common units OTA held prior to the exchange, are accounted for as treasury units by the Partnership in consolidation. As described in the Partnership Agreement, key terms of the preferred units include the following: • With respect to distribution and liquidation rights, the preferred units rank senior to the Partnership’s common units. Preferred units held by persons other than the Partnership, its subsidiaries and its affiliates generally will vote on an as-converted basis with the Partnership’s common units and have certain class voting rights with respect to certain protective matters. • Holders of the preferred units are entitled to receive cumulative quarterly distributions at a rate of 7.25% per annum. The Partnership is prohibited from paying distributions on its common units unless full cumulative distributions on the preferred units are paid or set aside for payment. The Partnership may satisfy its 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 the Partnership Agreement. During the year ended December 31, 2024, the Partnership made quarterly distributions to its preferred unitholders valued at $4 million, consisting of PIK distributions of 275 new preferred units and $3 million in cash. During each of the years ended December 31, 2022 and 2023, the Partnership made quarterly cash distributions to its preferred unitholders for $3 million. • Subject to certain limitations, each preferred unitholder may elect to convert its preferred units on or after September 30, 2025 into a number of the Partnership’s common units equal to (a) the number of preferred units to be converted multiplied by (b) the quotient of (i) $1,000 plus any accrued and unpaid distributions per preferred unit, divided by (ii) 92.5% of the volume-weighted average price of the Partnership’s common units at the time of conversion (as defined in the underlying agreements). In addition, each preferred unitholder may convert its preferred units into common units if EPO’s senior notes cease to have an investment grade rating or a Change of Control (as defined in the Partnership Agreement) occurs, in each case based on the conversion ratio specified in the Partnership Agreement. • The Partnership may elect to redeem the preferred units for cash, in whole or in part, based on a redemption price outlined in the following schedule, plus any accrued and unpaid distributions at the redemption date: • $1,030 per preferred unit from September 30, 2024 through September 29, 2025; • $1,010 per preferred unit from September 30, 2025 through September 29, 2026; and • $1,000 per preferred unit on or after September 30, 2026; however, • if a Change of Control event occurs prior to September 30, 2026, the redemption price is $1,010 per preferred unit. In connection with a redemption at the Partnership’s election, the Partnership may convert up to 50% of the preferred units being redeemed into common units (and to pay cash with respect to the remainder), with each such preferred unit being converted on the applicable redemption date into a number of common units equal to (i) the then-applicable preferred unit redemption price divided by (ii) 92.5% of the volume-weighted average price of the Partnership’s common units at the time of conversion (as defined in the underlying agreements). The Partnership has agreed to prepare and file a registration statement that would permit or otherwise facilitate the public resale of any common units resulting from the conversion of the preferred units to common units. Our Consolidated Balance Sheet at presents the capital accounts of the third-party purchasers of the preferred units as mezzanine equity since the terms of the preferred units allow for cash redemption by the holders in a Change of Control event, without regard to the likelihood of such an event. Accumulated Other Comprehensive Income (Loss) Accumulated other comprehensive income (loss) primarily reflects cumulative gain or loss on derivative instruments designated and qualified as cash flow hedges from inception less gains or losses previously reclassified from accumulated other comprehensive income (loss) into earnings. Gain or loss amounts related to cash flow hedges recorded in accumulated other comprehensive income (loss) are reclassified to earnings in the same period(s) in which the underlying hedged forecasted transactions affect earnings. If it becomes probable that a forecasted transaction will not occur, the related net gain or loss in accumulated other comprehensive income (loss) is immediately reclassified into earnings. The following tables present the components of accumulated other comprehensive income (loss) as reported on our 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 93 (36 ) – 57 Reclassification of losses (gains) to net income during period (110 ) (5 ) – (115 ) Total other comprehensive income (loss) for period (17 ) (41 ) – (58 ) Accumulated Other Comprehensive Income (Loss), December 31, 2023 154 151 2 307 Other comprehensive income (loss) for period, before reclassifications 115 (2 ) – 113 Reclassification of losses (gains) to net income during period (178 ) (6 ) – (184 ) Total other comprehensive income (loss) for period (63 ) (8 ) – (71 ) Accumulated Other Comprehensive Income (Loss), December 31, 2024 $ 91 $ 143 $ 2 $ 236 The following table presents reclassifications of (income) loss out of accumulated other comprehensive income (loss) into net income during the years indicated: For the Year Ended December 31, Losses (gains) on cash flow hedges: Location 2024 2023 Interest rate derivatives Interest expense $ (6 ) $ (5 ) Commodity derivatives Revenue (249 ) (106 ) Commodity derivatives Operating costs and expenses 71 (4 ) Total $ (184 ) $ (115 ) For information regarding our interest rate and commodity derivative instruments, see Note 14. Noncontrolling Interests Noncontrolling interests represent third party ownership interests in our consolidated subsidiaries. The following table presents the components of noncontrolling interests as reported on our Consolidated Balance Sheets at the dates indicated: At December 31, Consolidated Subsidiary 2024 2023 Breviloba LLC (“Breviloba”)(1) $ 423 $ 436 Whitethorn Pipeline Company LLC (“Whitethorn”)(2) – 182 Enterprise Navigator Ethylene Terminal LLC (“ENET”)(3) 245 166 Other (4) 189 302 Total noncontrolling interests in consolidated subsidiaries $ 857 $ 1,086 (1) An affiliate of Kinetik Holdings Inc. owns a noncontrolling equity interest in Breviloba, which owns the Shin Oak NGL Pipeline (2) An affiliate of Western Midstream Partners, LP (“Western Midstream”) previously owned a noncontrolling 20% equity interest in Whitethorn, which owns the Midland-to-Sealy section of our Midland-to-ECHO 1 Pipeline. (3) Navigator Ethylene Terminals LLC owns a noncontrolling 50% equity interest in ENET, which owns our ethylene export terminal located at Morgan’s Point on the Houston Ship Channel. (4) Primarily represents noncontrolling equity interests in NGL fractionation and pipeline businesses. Net income attributable to noncontrolling interests was On February 16, 2024, we acquired the remaining 20% equity interest in Whitethorn and remaining 25% equity interest in Enterprise EF78 LLC (“EF78”) from affiliates of Western Midstream for total cash consideration of $375 million. We funded the cash consideration using cash on hand and proceeds from the issuance of short-term notes under our commercial paper program. As a result of these transactions, Whitethorn and EF78 are now our wholly owned subsidiaries. Additionally, on March 27, 2024, we acquired an additional 15% equity interest in Panola Pipeline Company, LLC (“Panola”) from an affiliate of Western Midstream for $25 million in cash consideration. We funded the cash consideration using cash on hand. As a result of this transaction, our equity interest in Panola increased to 70%. Since we had a controlling interest in each of these entities before and after the acquisitions, the increase in our ownership interest in each entity was accounted for as an equity transaction with no gain or loss recognized Cash Distributions The following table presents Enterprise’s declared quarterly cash distribution rates per common unit with respect to the quarter indicated. Actual cash distributions are paid by Enterprise within 45 days after the end of each fiscal quarter. Quarterly Distribution Per Common Unit Record Date Payment Date 2022 1st Quarter $ 0.4650 4/29/2022 5/12/2022 2nd Quarter $ 0.4750 7/29/2022 8/12/2022 3rd Quarter $ 0.4750 10/31/2022 11/14/2022 4th Quarter $ 0.4900 1/31/2023 2/14/2023 2023: 1st Quarter $ 0.4900 4/28/2023 5/12/2023 2nd Quarter $ 0.5000 7/31/2023 8/14/2023 3rd Quarter $ 0.5000 10/31/2023 11/14/2023 4th Quarter $ 0.5150 1/31/2024 2/14/2024 2024 1st Quarter $ 0.5150 4/30/2024 5/14/2024 2nd Quarter $ 0.5250 7/31/2024 8/14/2024 3rd Quarter $ 0.5250 10/31/2024 11/14/2024 4th Quarter $ 0.5350 1/31/2025 2/14/2025 On January 8, 2025, we announced that the Board declared a quarterly cash distribution of $0.535 per common unit, or $2.14 per common unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the fourth quarter of 2024. The quarterly distribution was paid on February to unitholders of record as of the close of business on January 31 . The total amount paid was $ billion, which includes $ 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.

Revenues

Revenues	12 Months Ended
	Dec. 31, 2024
Revenues [Abstract]
Revenues [Text Block]	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 years indicated: For the Year Ended December 31, 2024 2023 2022 NGL Pipelines & Services: Sales of NGLs and related products $ 17,397 $ 14,846 $ 21,307 Segment midstream services: Natural gas processing and fractionation 1,349 1,278 1,431 Transportation 1,151 1,090 987 Storage and terminals 379 431 534 Total segment midstream services 2,879 2,799 2,952 Total NGL Pipelines & Services 20,276 17,645 24,259 Crude Oil Pipelines & Services: Sales of crude oil 20,389 18,185 17,301 Segment midstream services: Transportation 779 744 807 Storage and terminals 412 407 453 Total segment midstream services 1,191 1,151 1,260 Total Crude Oil Pipelines & Services 21,580 19,336 18,561 Natural Gas Pipelines & Services: Sales of natural gas 1,458 2,373 5,019 Segment midstream services: Transportation 1,546 1,403 1,241 Total segment midstream services 1,546 1,403 1,241 Total Natural Gas Pipelines & Services 3,004 3,776 6,260 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 10,013 7,689 8,003 Segment midstream services: Fractionation and isomerization 371 282 222 Transportation, including marine logistics 663 660 585 Storage and terminals 312 327 296 Total segment midstream services 1,346 1,269 1,103 Total Petrochemical & Refined Products Services 11,359 8,958 9,106 Total consolidated revenues $ 56,219 $ 49,715 $ 58,186 Substantially all of our revenues are derived from contracts with customers as defined within ASC 606. The following information describes the nature of our significant revenue streams by segment and type: NGL Pipelines & Services Sales of NGLs and related products NGL marketing activities generate revenues from spot and term sales of NGLs and related products that we take title to through our natural gas processing activities (i.e., our equity NGL production) and open market and long-term contract purchases. Revenue from these sales contracts is recognized when the NGLs are sold and delivered to customers at market-based prices. Midstream services Natural gas processing utilizes service contracts that are either fee-based, commodity-based or a combination of the two. When a cash fee for natural gas processing services is stipulated by a contract, we record revenue when a producer’s natural gas has been processed and redelivered. Our commodity-based contracts include keepwhole, margin-band, percent-of-liquids, percent-of-proceeds and contracts featuring a combination of commodity and fee-based terms. We recognize midstream service revenues in connection with the equity NGL-equivalents we receive under commodity-based contracts (once the processing service has been performed and we are entitled to such volumes). The value assigned to this non-cash consideration and related inventory is based on the market value of the equity NGL-equivalents at the time the services are performed. As noted previously, we also recognize product sales revenue, along with a corresponding cost of sales, when these NGLs are delivered and sold to downstream customers under NGL marketing contracts. NGL fractionation generates revenue using fee-based arrangements. These fees are contractually subject to adjustment for changes in certain fractionation expenses (e.g., fuel costs) and are recognized in the period services are provided. NGL pipeline transportation contracts and tariffs generate revenue based on a fixed fee per gallon multiplied by the volume transported and delivered (or capacity reserved). Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. Under certain agreements, customers are required to ship a minimum volume with a provision that allows the shipper to make-up any volume shortfalls over an agreed-upon period (referred to as “make-up rights”). Revenue attributable to such agreements is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the likelihood of the shipper’s ability to meet the minimum volume commitment becomes remote, or when the pipeline is otherwise released from its performance obligation. NGL and related product storage contracts generate revenue from capacity reservations where we collect a fee for reserving storage capacity for customers in our underground storage wells and above-ground storage tanks. Under these agreements, revenue is recognized on a straight-line basis over the reservation period. In addition, we generally charge customers throughput fees based on volumes delivered into and subsequently withdrawn from storage, which are recognized as the service is provided. NGL import and export terminaling activities generate revenue in the period services are provided. Customers are typically billed a fee per unit of volume loaded or unloaded. Crude Oil Pipelines & Services Sales of crude oil Crude oil marketing activities generate revenues from the sale and delivery of crude oil purchased either directly from producers or on the open market. Revenue from these sales contracts is recognized when crude oil is sold and delivered to customers at market-based prices. Midstream services Crude oil transportation contracts and tariffs generate revenue based upon a fixed fee per barrel multiplied by the volume transported and delivered (or capacity reserved). Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. Under certain agreements, customers are required to ship a minimum volume over an agreed-upon period, with make-up rights. Revenue attributable to such agreements is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the likelihood of the shipper’s ability to meet the minimum volume commitment becomes remote, or when the pipeline is otherwise released from its performance obligation. Crude oil storage contracts generate revenue from capacity reservations where we collect a fee for reserving storage capacity for customers at our terminals. Under these agreements, revenue is recognized on a straight-line basis over the reservation period. In addition, customers are billed a fee per unit of volume handled at our terminals. Revenue is recognized as the terminaling service is provided. Natural Gas Pipelines & Services Sales of natural gas Natural gas marketing activities generate revenue from the sale and delivery of natural gas purchased from producers, natural gas processing facilities, and on the open market. Revenue from these sales contracts is recognized when natural gas is sold and delivered to customers at market-based prices. Midstream services Natural gas transportation contracts generate revenues based on a fee per unit of volume transported multiplied by the volume gathered or delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. Revenues under transportation contracts are recognized when the volumes are transported and delivered to customers. In addition, certain of our natural gas pipelines offer firm capacity reservation services whereby the shipper pays a contractual fee based on the level of throughput capacity reserved. Revenues are recognized when the firm capacity services are provided to the shipper. Petrochemical & Refined Products Services Sales of petrochemicals and refined products Our petrochemical and refined products marketing activities generate revenue from the sale and delivery of products to customers at market-based prices. The products handled by these marketing groups include polymer grade propylene, octane additives, high purity isobutylene and various refined products. Midstream services Propylene fractionation units and butane isomerization facilities generate revenue through fee-based tolling arrangements with customers. Revenue from such agreements is recognized in the period the services are provided. Petrochemical and refined products transportation contracts generate revenue based upon a fixed fee per volume multiplied by the volume transported and delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. Marine transportation contracts generate revenue based on set day rates or a set fee per cargo movement recognized over the transit time of individual tows. Additionally, we record revenue for the costs of fuel and other operating costs that are directly reimbursed by our marine customers. Petrochemicals and refined products storage contracts generate revenue from capacity reservations where we collect a fee for reserving storage capacity for customers at our terminals. Under these agreements, revenue is recognized on a straight-line basis over the reservation period. In addition, customers are billed a fee per unit of volume handled at our terminals. Revenue is recognized as the terminaling service is provided. Unbilled Revenue and Deferred Revenue The following table provides information regarding our contract assets and contract liabilities at the dates indicated: December 31, Contract Asset Location 2024 2023 Unbilled revenue (current amount) Prepaid and other current assets $ 9 $ 11 Total $ 9 $ 11 December 31, Contract Liability Location 2024 2023 Deferred revenue (current amount) Other current liabilities $ 168 $ 193 Deferred revenue (noncurrent) Other long-term liabilities 284 326 Total $ 452 $ 519 The following table presents significant changes in our unbilled revenue and deferred revenue balances during the years indicated: Unbilled Revenue Deferred Revenue Balance at December 31, 2021 $ 15 $ 446 Amount included in opening balance transferred to other accounts during period (1) (15 ) (203 ) Amount recorded during period (2) 155 950 Amounts recorded during period transferred to other accounts (1) (149 ) (687 ) Other changes – (5 ) Balance at December 31, 2022 $ 6 $ 501 Amount included in opening balance transferred to other accounts during period (1) (6 ) (271 ) Amount recorded during period (2) 81 956 Amounts recorded during period transferred to other accounts (1) (70 ) (656 ) Other changes – (11 ) Balance at December 31, 2023 $ 11 $ 519 Amount included in opening balance transferred to other accounts during period (1) (11 ) (242 ) Amount recorded during period (2) 79 853 Amounts recorded during period transferred to other accounts (1) (70 ) (672 ) Other changes – (6 ) Balance at December 31, 2024 $ 9 $ 452 (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 December 31, 2024. For a significant portion of our revenue, we bill customers a contractual rate for the services provided multiplied by the amount of volume handled in a given period. We have the right to invoice the customer in the amount that corresponds directly with the value of our performance completed to date. Therefore, we are not required to disclose information about the variable consideration of remaining performance obligations since we recognize revenue equal to the amount that we have the right to invoice. Period Fixed Consideration One Year Ended December 31, 2025 $ 4,077 One Year Ended December 31, 2026 3,791 One Year Ended December 31, 2027 3,537 One Year Ended December 31, 2028 3,085 One Year Ended December 31, 2029 2,256 Thereafte r 9,238 Total $ 25,984

Business Segments and Related I

Business Segments and Related Information	12 Months Ended
	Dec. 31, 2024
Business Segments [Abstract]
Business Segments and Related Information	Note 10. Business Segments and Related Information Segment Overview Our operations are reported under four business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold. Financial information regarding these segments is evaluated regularly by our co-chief operating decision makers (“CODMs”) in deciding how to allocate resources and in assessing our operating and financial performance. The co-principal executive officers of our general partner have been identified as our CODMs. The following information summarizes the assets and operations of each business segment: • Our NGL Pipelines & Services . • Our Crude Oil Pipelines & Services business segment includes our crude oil pipelines, crude oil storage and marine terminals, and related crude oil marketing activities. • Our Natural Gas Pipelines & Services business segment includes our natural gas pipeline systems that provide for the gathering, treating and transportation of natural gas. This segment also includes our natural gas marketing activities. • Our Petrochemical & Refined Products Services business segment includes our (i) propylene production facilities, which include propylene fractionation units and PDH facilities, and related pipelines and marketing activities, (ii) butane isomerization complex and related deisobutanizer operations, (iii) octane enhancement, iBDH and HPIB production facilities, (iv) refined products pipelines, terminals and related marketing activities, (v) ethylene export terminal and related operations; and (vi) marine transportation business. Our plants, pipelines and other fixed assets are located in the U.S. Segment Gross Operating Margin Our CODMs evaluate segment performance based on our financial measure of gross operating margin. Gross operating margin is an important performance measure of the core profitability of our operations, forms the basis of our internal financial reporting, and is used by our CODMs on a monthly basis to monitor budgeted versus actual results. Our CODMs also consider gross operating margin results, in part, when determining how to allocate resources (e.g., employees and capital investments) to each segment, primarily in the annual budget process. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. Gross operating margin is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests. Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies. The following table presents a reconciliation of total segment gross operating margin to income before income taxes for the years indicated: For the Year Ended December 31, 2024 2023 2022 Total segment gross operating margin $ 10,018 $ 9,376 $ 9,356 Adjustments to reconcile total segment gross operating margin to income before income taxes (addition or subtraction indicated by sign): Depreciation, amortization and accretion expense in operating costs and expenses (1) (2,343 ) (2,215 ) (2,107 ) Asset impairment charges in operating costs and expenses (57 ) (30 ) (53 ) Net gains (losses) attributable to asset sales and related matters in operating costs and expenses (2 ) 10 (1 ) General and administrative costs (244 ) (231 ) (241 ) Non-refundable payments received from shippers attributable to make-up rights (2) (75 ) (52 ) (144 ) Subsequent recognition of revenues attributable to make-up rights (3) 41 71 97 Total other expense, net (4) (1,303 ) (1,228 ) (1,210 ) Income before income taxes $ 6,035 $ 5,701 $ 5,697 (1) Excludes amortization of major maintenance costs for reaction-based plants and amortization of finance lease right-of-use assets, 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. (4) As presented on our Statements of Consolidated Operations, Total other expense, net is comprised of Interest expense, Interest income and Other, net. The results of operations from our liquids pipelines are primarily dependent upon the volumes transported and the associated fees we charge for such transportation services. Typically, pipeline transportation revenue is recognized when volumes are re-delivered to customers. However, under certain pipeline transportation agreements, customers are required to ship a minimum volume over an agreed-upon period. These arrangements may entail the shipper paying a transportation fee based on a minimum volume commitment, with a provision that allows the shipper to make-up any volume shortfalls over the agreed-upon period (referred to as shipper “make-up rights”). Revenue pursuant to such agreements is initially deferred and subsequently recognized under GAAP at the earlier of when the deficiency volume is shipped, when the likelihood of the shipper’s ability to meet the minimum volume commitment becomes remote, or when the pipeline is otherwise released from its performance obligation. However, management includes deferred transportation revenues relating to the “make-up rights” of committed shippers when reviewing the financial results of certain pipelines (Texas Express Pipeline, Front Range Pipeline, ATEX, Aegis Ethane Pipeline, and Seaway Pipeline). From an internal (and segment) reporting standpoint, management considers the transportation fees paid by committed shippers on these pipelines, including any non-refundable revenues that may be deferred under GAAP related to make-up rights, to be important in assessing the financial performance of these pipeline assets. Although the adjustments for make-up rights are included in segment gross operating margin, our consolidated revenues do not reflect any deferred revenues until the conditions for recognizing such revenues are met in accordance with GAAP. Summarized Segment Financial Information The following tables present segment revenues and significant segment expenses by segment, together with a reconciliation to segment gross operating margin, for the periods indicated: For the Year Ended December 31, 2024 NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Segment Total Segment revenues: Revenues from third parties $ 20,264 $ 21,546 $ 2,992 $ 11,359 $ 56,161 Revenues from related parties 12 34 12 – 58 Intersegment and intrasegment revenues 48,822 54,415 667 25,352 129,256 Total segment revenues 69,098 75,995 3,671 36,711 185,475 Significant segment expenses: Cost of sales 61,260 74,098 1,656 33,755 170,769 Variable operating costs and expenses (1) 745 132 73 373 1,323 Fixed operating costs and expenses (2) 1,682 414 676 1,048 3,820 Total significant segment expenses 63,687 74,644 2,405 35,176 175,912 Other segment income (expense): Equity in income of unconsolidated affiliates 117 285 5 1 408 Other segment items (3) 20 10 6 11 47 Total other segment income (expense), net 137 295 11 12 455 Total segment gross operating margin $ 5,548 $ 1,646 $ 1,277 $ 1,547 $ 10,018 Other financial information: Capital expenditures $ 2,498 $ 161 $ 932 $ 953 $ 4,544 (1) Variable operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally fluctuate based on utilization. (2) Fixed operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally remain constant independent of utilization. (3) Other segment items for each segment primarily represent the following: • NGL Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights, and other segment expenses. • Crude Oil Pipelines & Services – Other segment expenses. • Natural Gas Pipelines & Services – Other segment expenses. • Petrochemical & Refined Products Services – Other segment expenses. For the Year Ended December 31, 2023 NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Segment Total Segment revenues: Revenues from third parties $ 17,635 $ 19,300 $ 3,761 $ 8,958 $ 49,654 Revenues from related parties 10 36 15 – 61 Intersegment and intrasegment revenues 45,490 57,122 527 18,882 122,021 Total segment revenues 63,135 76,458 4,303 27,840 171,736 Significant segment expenses: Cost of sales 56,143 74,437 2,583 24,810 157,973 Variable operating costs and expenses (1) 741 191 59 397 1,388 Fixed operating costs and expenses (2) 1,589 403 595 877 3,464 Total significant segment expenses 58,473 75,031 3,237 26,084 162,825 Other segment income (expense): Equity in income of unconsolidated affiliates 133 320 6 3 462 Other segment items (3) 103 (40 ) 5 (65 ) 3 Total other segment income (expense), net 236 280 11 (62 ) 465 Total segment gross operating margin $ 4,898 $ 1,707 $ 1,077 $ 1,694 $ 9,376 Other financial information: Capital expenditures $ 1,366 $ 119 $ 793 $ 988 $ 3,266 (1) Variable operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally fluctuate based on utilization. (2) Fixed operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally remain constant independent of utilization. (3) Other segment items for each segment primarily represent the following: • NGL Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights, and other segment expenses. • Crude Oil Pipelines & Services – Subsequent recognition of revenues attributable to make-up rights. • Natural Gas Pipelines & Services – Other segment expenses. • Petrochemical & Refined Products Services – Other segment expenses. For the Year Ended December 31, 2022 NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Segment Total Segment revenues: Revenues from third parties $ 24,244 $ 18,548 $ 6,229 $ 9,106 $ 58,127 Revenues from related parties 15 13 31 – 59 Intersegment and intrasegment revenues 65,760 46,625 888 18,304 131,577 Total segment revenues 90,019 65,186 7,148 27,410 189,763 Significant segment expenses: Cost of sales 82,957 63,325 5,532 24,556 176,370 Variable operating costs and expenses (1) 769 173 54 473 1,469 Fixed operating costs and expenses (2) 1,412 386 532 804 3,134 Total significant segment expenses 85,138 63,884 6,118 25,833 180,973 Other segment income (expense): Equity in income of unconsolidated affiliates 149 308 5 2 464 Other segment items (3) 112 45 7 (62 ) 102 Total other segment income (expense), net 261 353 12 (60 ) 566 Total segment gross operating margin $ 5,142 $ 1,655 $ 1,042 $ 1,517 $ 9,356 Other financial information: Capital expenditures $ 624 $ 84 $ 344 $ 912 $ 1,964 (1) Variable operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally fluctuate based on utilization. (2) Fixed operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally remain constant independent of utilization. (3) Other segment items for each segment primarily represent the following: • NGL Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights, and other segment expenses. • Crude Oil Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights, and other segment expenses. • Natural Gas Pipelines & Services – Other segment expenses. • Petrochemical & Refined Products Services – Other segment expenses. Segment revenues include intersegment and intrasegment transactions, which are generally based on transactions made at market-based rates. Our consolidated revenues reflect the elimination of intercompany transactions. The following table reconciles total segment revenues as reported in the preceding tables to consolidated revenues as presented on our Statements of Consolidated Operations: For the Year Ended December 31, 2024 2023 2022 Segment revenues: NGL Pipelines & Services $ 69,098 $ 63,135 $ 90,019 Crude Oil Pipelines & Services 75,995 76,458 65,186 Natural Gas Pipelines & Services 3,671 4,303 7,148 Petrochemical & Refined Products Services 36,711 27,840 27,410 Total segment revenues 185,475 171,736 189,763 Elimination of intersegment and intrasegment revenues (129,256 ) (122,021 ) (131,577 ) Total consolidated revenues $ 56,219 $ 49,715 $ 58,186 Segment expenses represent operating costs and expenses exclusive of (i) depreciation, amortization and accretion expenses (excluding amortization of major maintenance costs for reaction-based plants and amortization of finance lease right-of-use assets), (ii) impairment charges, and (iii) gains and losses attributable to asset sales and related matters. Segment expense presented in the tables above include intersegment and intrasegment transactions, which are generally based on transactions made at market-based rates. Additionally, the significant segment expense categories presented align with the manner in which our CODMs evaluate segment results. Our consolidated operating costs and expenses are inclusive of the aforementioned adjustments and reflect the elimination of intercompany transactions. We include equity in income of unconsolidated affiliates in our measurement of segment gross operating margin and operating income. Equity investments with industry partners are a significant component of our business strategy. They are a means by which we conduct our operations to align our interests with those of customers and/or suppliers. This method of operation enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed. Many of these businesses perform supporting or complementary roles to our other midstream business operations. Given the integral nature of these equity method investees to our operations, we believe the presentation of equity earnings from such investees as a component of gross operating margin and operating income is meaningful and appropriate. The following table presents our segment assets, together with a reconciliation to our consolidated total assets, at the dates indicated: December 31, 2024 2023 NGL Pipelines & Services $ 21,900 $ 21,792 Crude Oil Pipelines & Services 11,390 11,822 Natural Gas Pipelines & Services 12,260 11,210 Petrochemical & Refined Products Services 11,350 10,443 Total segment assets 56,900 55,267 Construction in progress 4,138 2,245 Current assets 15,133 12,248 Other assets 997 1,222 Consolidated total assets $ 77,168 $ 70,982 Segment assets consist of property, plant and equipment (excluding construction-in-progress), investments in unconsolidated affiliates, intangible assets and goodwill. The carrying values of such amounts are assigned to each segment based on each asset’s or investment’s principal operations and contribution to the gross operating margin of that particular segment. Since construction-in-progress (a component of property, plant and equipment) does not contribute to segment gross operating margin, such amounts are excluded from segment asset totals until the underlying assets are placed in service. The remainder of our consolidated total assets, which consist primarily of working capital assets, are excluded from segment assets since these amounts are not attributable to one specific segment. Supplemental Revenue and Expense Information The following table presents additional information regarding our consolidated revenues and costs and expenses for the years indicated: For the Year Ended December 31, 2024 2023 2022 Consolidated revenues: NGL Pipelines & Services $ 20,276 $ 17,645 $ 24,259 Crude Oil Pipelines & Services 21,580 19,336 18,561 Natural Gas Pipelines & Services 3,004 3,776 6,260 Petrochemical & Refined Products Services 11,359 8,958 9,106 Total consolidated revenues $ 56,219 $ 49,715 $ 58,186 Consolidated costs and expenses: Operating costs and expenses: Cost of sales $ 42,580 $ 37,023 $ 45,836 Other operating costs and expenses (1) 4,004 3,695 3,454 Depreciation, amortization and accretion 2,402 2,279 2,158 Impairment of assets other than goodwill 57 30 53 Ne t losses (g 2 (10 ) 1 General and administrative costs 244 231 241 Total consolidated costs and expenses $ 49,289 $ 43,248 $ 51,743 (1) Represents the cost of operating our plants, pipelines and other fixed assets excluding: depreciation, amortization and accretion; asset impairment charges; and net losses (gains) attributable to asset sales and related matters. Fluctuations in our product sales revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. In general, higher energy commodity prices result in an increase in our revenues attributable to product sales; however, these higher commodity prices would also be expected to increase the associated cost of sales as purchase costs are higher. The same type of relationship would be true in the case of lower energy commodity sales prices and purchase costs. Major Customer Information Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base. For the years ended December 31, 2024, 2023 and 2022, Vitol Holding B.V. and its affiliates (collectively, “ ”) accounted for $ billion, or , $ billion, or , and $ billion, or , respectively, of our consolidated revenues. is a global energy and commodity trading company. Revenues earned from Vitol during 2024, 2023 and 2022 are included within each of our business segments.

Earnings Per Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2024
Earnings Per Unit [Abstract]
Earnings Per Unit	Note 11. Earnings Per Unit The following table presents our calculation of basic and diluted earnings per common unit for the years indicated: For the Year Ended December 31, 2024 2023 2022 BASIC EARNINGS PER COMMON UNIT Net income attributable to common unitholders $ 5,897 $ 5,529 $ 5,487 Earnings allocated to phantom unit awards (1) (56 ) (50 ) (46 ) Net income allocated to common unitholders $ 5,841 $ 5,479 $ 5,441 Basic weighted-average number of common units outstanding 2,169 2,172 2,178 Basic earnings per common unit $ 2.69 $ 2.52 $ 2.50 DILUTED EARNINGS PER COMMON UNIT Net income attributable to common unitholders $ 5,897 $ 5,529 $ 5,487 Net income attributable to preferred units 4 3 3 Net income attributable to limited partners $ 5,901 $ 5,532 $ 5,490 Diluted weighted-average number of units outstanding: Distribution-bearing common units 2,169 2,172 2,178 Phantom units (2) 21 20 19 Preferred units (2) 2 2 2 Total 2,192 2,194 2,199 Diluted earnings per common unit $ 2.69 $ 2.52 $ 2.50 (1) Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding phantom units. (2) We use the “if-converted method” to determine the potential dilutive effect of the vesting of phantom unit awards and the conversion of preferred units outstanding. See Note 8 for information regarding preferred units.

Business Combinations

Business Combinations	12 Months Ended
	Dec. 31, 2024
Business Combinations [Abstract]
Business Combinations	Note 12. Business Combinations Acquisition of n On October 28, 2024, we acquired Pinon Midstream for $953 million in cash consideration. We funded this transaction using cash on hand. Pinon Midstream’s assets include 43 miles of natural gas gathering and redelivery pipelines, five 3-stage compressor stations, 270 million cubic feet per day (“MMcf/d”) of hydrogen sulfide and carbon dioxide treating facilities and two high capacity acid gas injection wells. The acquisition of Pinon Midstream was accounted for under the acquisition method in accordance with ASC 805, Business Combinations The following table presents the preliminary fair value allocation of assets acquired and liabilities assumed in the acquisition at October 28, 2024 (the effective date of the acquisition). The allocation is provisional and subject to ongoing efforts to clarify the values assigned to tangible and identifiable intangible assets. Purchase price for 100% interest in Pinon Midstream $ 953 Recognized amounts of identifiable assets acquired and liabilities assumed (1): Cash and cash equivalents $ 4 Property, plant and equipment 410 Contract-based intangible asset 435 Total identifiable net assets $ 849 Goodwill $ 104 (1) As part of this transaction, we acquired other assets and assumed liabilities that net to a negligible amount. Acquired other assets primarily included accounts receivable and ROU assets. Assumed liabilities primarily included accounts payable and operating lease liabilities. None of these amounts were considered individually significant. The estimated fair value of the acquired property, plant and equipment was determined using the cost approach. The fair value of the property, plant and equipment primarily consisted of personal property of $354 million, real property of $11 million and construction in progress of $45 million. See Note 4 for additional information regarding our property, plant and equipment. The contract-based intangible asset represents the estimated value we assigned to the acquired long-term contracts with customers that are expected to renew in approximately 10 years at similar commercial terms. The estimated fair value of the acquired contract-based intangible assets was determined using an income approach, specifically a discounted cash flow analysis. The fair value estimate incorporates Level 3 inputs including: (i) management’s long-term forecast of cash flows generated by Pinon Midstream based on the estimated economic life of the hydrocarbon resource basin served, resource depletion rates, and expected contract renewals; and (ii) a discount rate of 16.5%, which is based on a benchmarking analysis with reference to the implied rate of return on the Pinon Midstream acquisition and a market participant weighted average cost of capital. We will amortize the value assigned to this intangible asset using a units-of-production method. The estimated useful life of the acquired contract-based intangible asset is approximately 25 years. We recorded $104 million of goodwill in connection with this transaction. In general, we attribute this goodwill to our ability to expand the acquired sour gas gathering and treating system as well as our ability to leverage the acquired business with our existing NGL asset base to create future business opportunities. The financial results for the acquired business will be reported as a component of our Delaware Basin Gathering System under the Natural Gas Pipelines & Services business segment. The contribution of this newly acquired business to our consolidated revenues and net income was not material during the year ended December 31, 2024. Additionally, acquisition related costs were not material during the year ended December 31, 2024. On a historical pro forma basis, our revenues, costs and expenses, operating income, net income attributable to common unitholders and earnings per unit for the years ended December 31, 2024 and 2023 would not have differed materially from those we actually reported had the acquisition been completed on January 1, 2023 rather than October 28, 2024. Acquisition of Navitas Midstream On February 17, 2022, an affiliate of Enterprise acquired all of the member interests in Navitas Midstream Partners, LLC ( Navitas Midstream ) for $ billion in cash. We funded the cash consideration using proceeds from the issuance of short-term notes under EPO’s commercial paper program and cash on hand. Navitas Midstream's assets (the “Midland Basin System”) include approximately 1,750 miles of pipelines and over 1.0 Bcf/d of cryogenic natural gas processing capacity. The acquired business expands our natural gas processing and NGL businesses to the Midland Basin in West Texas. We engaged an independent third party business valuation expert to assist us in estimating the fair values of the tangible and intangible assets of Navitas Midstream. The following table summarizes the final fair value allocation of assets acquired and liabilities assumed in the acquisition at February 17, 2022 (the effective date of the acquisition). Purchase price for 100% interest in Navitas Midstream $ 3,231 Recognized amounts of identifiable assets acquired and liabilities assumed: Cash and cash equivalents $ 27 Property, plant and equipment 2,080 Contract-based intangible asset 989 Assumed liabilities, net of acquired other assets (1) (24 ) Total identifiable net assets $ 3,072 Goodwill $ 159 (1) Assumed liabilities primarily include accounts payable, other current liabilities, lease liabilities and asset retirement obligations. Acquired other assets primarily include accounts receivable, other current assets and ROU assets. None of these amounts were considered individually significant. The contribution of this newly acquired business to our consolidated revenues and net income was not material during the year ended December 31, 2022. Additionally, acquisition related costs were not material during the year ended December 31, 2022. On a historical pro forma basis, our revenues, costs and expenses, operating income, net income attributable to common unitholders and earnings per unit for the year ended December 31, 2022 would not have differed materially from those we actually reported had the acquisition been completed on January 1, 2022 rather than February 17, 2022.

Equity-Based Awards

Equity-Based Awards	12 Months Ended
	Dec. 31, 2024
Equity-based Awards [Abstract]
Equity-based Awards	Note 13. Equity-Based Awards An allocated portion of the fair value of EPCO’s equity-based awards is charged to us under the ASA. The following table summarizes compensation expense we recognized in connection with equity-based awards for the years indicated: For the Year Ended December 31, 2024 2023 2022 Equity-classified awards: Phantom unit awards $ 178 $ 166 $ 153 Profits interest awards 10 6 4 Total $ 188 $ 172 $ 157 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. The 2008 Enterprise Products Long-Term Incentive Plan (Fourth Amendment and Restatement) (referred to as the “2008 Plan”) is a plan under which any non-employee director, employee or consultants of EPCO, the Partnership or its affiliates providing services, directly or indirectly, for the Partnership or its subsidiaries may receive incentive compensation awards in the form of options, restricted units, phantom units, distribution equivalent rights, unit appreciation rights, unit awards, other unit-based awards or substitute awards. The maximum number of the Partnership’s common units authorized for issuance under the 2008 Plan was 165,000,000 at December 31, 2024. The 2008 Plan is effective until November 22, 2032 or, if earlier, until (i) the time that all available common units under the 2008 Plan have been delivered to participants or (ii) the time of termination of the 2008 Plan by the Board of Directors of EPCO or by the Incentive Plan Administration Subcommittee of the Governance Committee of the Board of Enterprise GP. After giving effect to awards granted under the 2008 Plan through December 31, 2024, a total of 103,056,553 additional common units were available for issuance. After taking into account tax withholding requirements, we issued 4,990,360, 4,662,539 and 4,571,333 common units in connection with the vesting of phantom unit awards in the years ended December 31, 2024, 2023 and 2022, respectively. 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). We expect phantom units to result in the issuance of common units upon vesting; therefore, these grants are accounted for as equity-classified awards. Phantom unit awards generally vest at a rate of 25% per year beginning one year after the grant date and are non-vested until the required service periods expire. The grant date fair value of a phantom unit award is based on the market price per unit of the Partnership’s common units on the date of grant. Compensation expense is recognized based on the grant date fair value, net of an allowance for estimated forfeitures, over the requisite service or vesting period. The following table presents phantom unit award activity for the years indicated: Number of Units Weighted- Average Grant Date Fair Value per Unit Phantom unit awards at December 31, 2021 17,170,919 $ 24.31 Granted (2) 7,968,880 $ 24.11 Vested (6,616,741 ) $ 25.08 Forfeited (540,113 ) $ 23.92 Phantom unit awards at December 31, 2022 17,982,945 $ 23.94 Granted (3) 8,904,445 $ 25.80 Vested (6,786,085 ) $ 24.81 Forfeited (544,054 ) $ 24.52 Phantom unit awards at December 31, 2023 19,557,251 $ 24.47 Granted (4) 8,881,820 $ 26.25 Vested (7,304,071 ) $ 24.51 Forfeited (542,749 ) $ 25.39 Phantom unit awards at December 31, 2024 20,592,251 $ 25.21 (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 2022 was $192 million based on a grant date market price of the Partnership’s common units ranging from $24.10 to $26.62 per unit. An estimated annual forfeiture rate of 2.1% was applied to these awards. (3) The aggregate grant date fair value of phantom unit awards issued during 2023 was $230 million based on a grant date market price of the Partnership’s common units ranging from $25.80 to $26.70 per unit. An estimated annual forfeiture rate of 2.0% was applied to these awards. (4) The aggregate grant date fair value of phantom unit awards issued during 2024 was $233 million based on a grant date market price of the Partnership’s common units ranging from $26.25 to $29.64 per unit. An estimated annual forfeiture rate of 2.0% was applied to these awards. The 2008 Plan provides for the issuance of DERs in connection with phantom unit awards. A DER 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 years indicated: For the Year Ended December 31, 2024 2023 2022 Cash payments made in connection with DERs $ 43 $ 38 $ 34 Total intrinsic value of phantom unit awards that vested during period $ 199 $ 182 $ 160 For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $195 million at December 31, 2024, of which our share of such cost is currently estimated to be $153 million. Due to the graded vesting provisions of these awards, we expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.1 years. Profits Interest Awards In 2018, EPCO Holdings Inc. (“EPCO Holdings”), a privately held affiliate of EPCO, contributed a portion of the Partnership’s common units it owned to form EPD 2018 Unit IV L.P. (“EPD IV”) and EPCO Unit II L.P. (“EPCO II”) (collectively referred to as “Employee Partnerships”) that served as long-term incentive arrangements for key employees of EPCO by providing them a “profits interest” (in the form of a Class B limited partner interest) in an Employee Partnership. In exchange for the contributions of the Partnership’s common units, EPCO Holdings was admitted as the Class A limited partner of each Employee Partnership. Also on the applicable contribution date, certain key EPCO employees were issued Class B limited partner interests (i.e., profits interest awards) and admitted as Class B limited partners of each Employee Partnership, all without any capital contribution by such employees. EPCO served as the general partner of each Employee Partnership. Each quarter, the Employee Partnerships, as owners of the Partnership’s common units, received a cash distribution from the Partnership as did the Partnership’s other common unitholders. The cash received by the Employee Partnership was first used to pay the Class A limited partner a cash distribution equal to the product of (i) the number of the Partnership’s common units owned by the Employee Partnership and (ii) the Class A Preference Return (subject to equitable adjustment in order to reflect any equity split, equity distribution or dividend, reverse split, combination, reclassification, recapitalization or other similar event affecting such common units). To the extent that the Employee Partnership had cash remaining after making the quarterly payment to the Class A limited partner, the residual cash was distributed to the Class B limited partners on a quarterly basis as a distribution. The Class B limited partner interests of these two Employee Partnerships vested on March 26, 2024 when the closing market price of the Partnership’s common units exceeded $29.02 per unit and the Employee Partnerships were subsequently liquidated. Upon liquidation of the Employee Partnerships, assets having a then current fair market value equal to the Class A limited partner’s capital base in each Employee Partnership were distributed to the Class A limited partner. The remaining assets of each Employee Partnership were distributed to the Class B limited partners as a residual profits interest, which represented the appreciation in value of the Employee Partnership’s assets since the date of EPCO Holdings’ contribution to it, as described above. The Employee Partnerships were terminated within 30 days following the vesting date. Compensation expense attributable to the profits interest awards was based on the estimated fair value of each award. A portion of the fair value of these equity-based awards was allocated to us under the ASA as a non-cash expense. We were not responsible for reimbursing EPCO for any expenses of the Employee Partnerships, including the value of any contributions of units made by EPCO Holdings.

Hedging Activities and Fair Val

Hedging Activities and Fair Value Measurements	12 Months Ended
	Dec. 31, 2024
Hedging Activities and Fair Value Measurements [Abstract]
Hedging Activities and Fair Value Measurements	Note 14. Hedging Activities and Fair Value Measurements In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with assets, liabilities and certain anticipated future transactions, we use derivative instruments such as futures, forward contracts, swaps, options and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities. Interest Rate Hedging Activities We may utilize interest rate swaps, forward-starting swaps, options to enter into forward-starting swaps (“swaptions”), treasury locks and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain consolidated debt agreements. This strategy may be used in controlling our overall cost of capital associated with such borrowings. Treasury Locks A treasury lock is an agreement that fixes the price (or yield) of a specified U.S. treasury security for an established period of time. We use treasury lock agreements to hedge our exposure to interest rate changes and to reduce the volatility of financing costs on an expected future debt issuance. Each of our treasury lock transactions was designated as a cash flow hedge of the interest payments associated with an anticipated debt issuance. In August 2024, we entered into two treasury lock transactions to fix the ten-year treasury rate at 3.98% on a notional amount of $1.0 billion and to fix the thirty-year treasury rate at 4.29% on a notional amount of $1.0 billion. The purpose of these transactions was to hedge the underlying interest rate risk associated with debt issuances in August 2024 (see Note 7). In August 2024, we terminated these treasury lock transactions simultaneously with our issuance of the ten-year and thirty-year notes and made total cash payments of $4 million. During the fourth quarter of 2023, we entered into three treasury lock transactions to fix the ten-year treasury rate at a weighted-average rate of approximately 4.48% on an aggregate notional amount of $600 million. In January 2024, we entered into two additional treasury lock transactions to fix the ten-year treasury rate at 3.97% on a notional amount of $400 million and to fix the three-year treasury rate at 4.11% on a notional amount of $750 million. The purpose of these transactions was to hedge the underlying interest rate risk associated with debt issuances in January 2024 (see Note 7). In January 2024, we terminated these treasury lock transactions simultaneously with our issuance of the three-year and ten-year notes and made total cash payments of $29 million. In January 2023, upon issuance of Senior Notes FFF and GGG (see Note 7), we terminated and settled treasury lock transactions with a combined notional amount of $1.5 billion and received total cash proceeds of $21 million. As cash flow hedges, gains or losses on these derivative instruments are reflected as a component of accumulated other comprehensive income and will be amortized to earnings as a component of interest expense over the full term of each issuance. Forward-Starting Swaps Forward-starting swaps hedge the risk of an increase in underlying benchmark interest rates during the period of time between the inception date of the swap agreement and the future date of a debt issuance. Under the terms of the forward-starting swaps, we pay to the counterparties (at the expected settlement dates of the instruments) amounts based on a fixed interest rate applied to a notional amount and receive from the counterparties an amount equal to a variable interest rate on the same notional amount. Commodity Hedging Activities The prices of natural gas, NGLs, crude oil, petrochemicals and refined products and power are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control. In order to manage such price risks, we enter into commodity derivative instruments such as physical forward contracts, futures contracts, fixed-for-float swaps and basis swaps. At December 31, 2024, our predominant commodity hedging strategies consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities, (ii) hedging natural gas processing margins, (iii) hedging the fair value of commodity products held in inventory and (iv) hedging anticipated future purchases of power for certain operations in Southeast Texas. • The objective of our anticipated future commodity purchases and sales hedging program is to hedge the margins of certain transportation, storage, blending and operational activities by locking in purchase and sale prices through the use of derivative instruments and related contracts. • The objective of our natural gas processing hedging program is to hedge an amount of earnings associated with these activities. We achieve this objective by executing fixed-price sales for a portion of our expected equity production using derivative instruments and related contracts. For certain natural gas processing contracts, the hedging of expected equity NGL production also involves the purchase of natural gas for plant thermal reduction, which is hedged using derivative instruments and related contracts. • The objective of our inventory hedging program is to hedge the fair value of commodity products currently held in inventory by locking in the sales price of the inventory through the use of derivative instruments and related contracts. • The objective of our commercial energy hedging program is to hedge anticipated future purchases of power for certain operations in Southeast Texas by locking in purchase prices through the use of derivative instruments and related contracts. The following table summarizes our portfolio of commodity derivative instruments outstanding at December 31, 2024 (volume measures as noted): Volume Accounting Derivative Purpose Current Long-Term Treatment Derivatives designated as hedging instruments: Natural gas processing: Forecasted sales of natural gas (Bcf) 37.7 36.5 Cash flow hedge Forecasted sales of NGLs (MMBbls) 3.2 n/a Cash flow hedge Octane enhancement: Forecasted sales of octane enhancement products (MMBbls) 3.8 0.1 Cash flow hedge Natural gas marketing: 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) 134.0 5.8 Cash flow hedge Forecasted sales of NGLs and related hydrocarbon products (MMBbls) 148.5 4.8 Cash flow hedge Refined products marketing: Forecasted sales of refined products (MMBbls) 0.1 n/a Cash flow hedge Crude oil marketing: Forecasted purchases of crude oil (MMBbls) 13.3 5.0 Cash flow hedge Forecasted sales of crude oil (MMBbls) 22.4 10.3 Cash flow hedge Petrochemical marketing: Forecasted sales of petrochemical products (MMBbls) 0.9 n/a Cash flow hedge Commercial energy: Forecasted purchases of power related to asset operations (terawatt hours (“TWh”)) 1.5 n/a Cash flow hedge Derivatives not designated as hedging instruments: Natural gas risk management activities (Bcf) (3) 16.6 n/a Mark-to-market NGL risk management activities (MMBbls) (3) 38.9 22.8 Mark-to-market Refined products risk management activities (MMBbls) (3) 7.2 n/a Mark-to-market Crude oil risk management activities (MMBbls) (3) 168.3 n/a Mark-to-market Commercial energy risk management activities (TWh) (3) 0.1 11.1 Mark-to-market (1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes. (2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2027, May 2025 and December 2027, respectively. (3) Reflects the use of derivative instruments to manage risks associated with our transportation, processing and storage assets. The carrying amount of our inventories subject to fair value hedges was $11 million and $2 million at December 31, 2024 and 2023, respectively. Certain basis swaps and other derivative instruments not designated as hedging instruments are used to manage market risks associated with anticipated purchases and sales of commodity products. There is some uncertainty involved in the timing of these transactions often due to the development of more favorable profit opportunities or when spreads are insufficient to cover variable costs thus reducing the likelihood that the transactions will occur during the periods originally forecasted. In accordance with derivatives accounting guidance, these instruments do not qualify for hedge accounting even though they are effective at managing the risk exposures of the underlying assets. Due to volatility in commodity prices, any non-cash, mark-to-market earnings variability cannot be predicted. 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 December 31, 2024 December 31, 2023 December 31, 2024 December 31, 2023 Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedging instruments Interest rate derivatives Current assets $ – Current assets $ – Current liabilities $ – Current liabilities $ 31 Commodity derivatives Current assets $ 210 Current assets $ 118 Current liabilities $ 178 Current liabilities $ 136 Commodity derivatives Other assets 22 Other assets 31 Other liabilities 4 Other liabilities 35 Total commodity derivatives 232 149 182 171 Total derivatives designated as hedging instruments $ 232 $ 149 $ 182 $ 202 Derivatives not designated as hedging instruments Commodity derivatives Current assets $ 324 Current assets $ 229 Current liabilities $ 293 Current liabilities $ 229 Commodity derivatives Other assets 19 Other assets 72 Other liabilities 20 Other liabilities 71 Total commodity derivatives 343 301 313 300 Total derivatives not designated as hedging instruments $ 343 $ 301 $ 313 $ 300 Certain of our commodity derivative instruments are subject to master netting arrangements or similar agreements. The following tables present our derivative instruments subject to such arrangements at the dates indicated: Offsetting of Financial Assets and Derivative Assets Gross Amounts Not Offset in the Balance Sheet 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 December 31, 2024: Commodity derivatives $ 575 $ – $ 575 $ (495 ) $ (79 ) $ – $ 1 As of December 31, 2023 Commodity derivatives $ 450 $ – $ 450 $ (450 ) $ – $ – $ – Offsetting of Financial Liabilities and Derivative Liabilities Gross Amounts Not Offset in the Balance Sheet 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 December 31, 2024 Commodity derivatives $ 495 $ – $ 495 $ (495 ) $ – $ – $ – As of December 31, 2023 Interest rate derivatives $ 31 $ – $ 31 $ – $ – $ – $ 31 Commodity derivatives 471 – 471 (450 ) 1 (21 ) 1 Derivative assets and liabilities recorded on our Consolidated Balance Sheets are presented on a gross basis and determined at the individual transaction level. This presentation method is applied regardless of whether the respective exchange clearing agreements, counterparty contracts or master netting agreements contain netting language often referred to as “rights of offset.” Although derivative amounts are presented on a gross basis, having rights of offset enable the settlement of a net as opposed to gross receivable or payable amount under a counterparty default or liquidation scenario. Cash is paid and received as collateral under certain agreements, particularly for those associated with exchange transactions. For any cash collateral payments or receipts, corresponding assets or liabilities are recorded to reflect the variation margin deposits or receipts with exchange clearing brokers and customers. These balances are also presented on a gross basis on our Consolidated Balance Sheets. 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 Statements of Consolidated Operations for the years indicated: Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Derivative For the Year Ended December 31, 2024 2023 2022 Commodity derivatives Revenue $ 2 $ 7 $ (103 ) Total $ 2 $ 7 $ (103 ) Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Hedged Item For the Year Ended December 31, 2024 2023 2022 Commodity derivatives Revenue $ 9 $ (7 ) $ 66 Total $ 9 $ (7 ) $ 66 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 Statements of Consolidated Operations and Statements of Consolidated Comprehensive Income for the years indicated: Derivatives in Cash Flow Hedging Relationships Change in Value Recognized in Other Comprehensive Income (Loss) On Derivative For the Year Ended December 31, 2024 2023 2022 Interest rate derivatives $ (2 ) $ (36 ) $ 26 Commodity derivatives – Revenue (1) 182 81 227 Commodity derivatives – Operating costs and expenses (1) (67 ) 12 27 Total $ 113 $ 57 $ 280 (1) The fair value of these derivative instruments will be reclassified to their respective locations on the 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 Year Ended December 31, 2024 2023 2022 Interest rate derivatives Interest expense $ 6 $ 5 $ (19 ) Commodity derivatives Revenue 249 106 181 Commodity derivatives Operating costs and expenses (71 ) 4 39 Total $ 184 $ 115 $ 201 Over the next twelve months, we expect to reclassify $6 million of gains attributable to interest rate derivative instruments from accumulated other comprehensive income to earnings as a decrease in interest expense. Likewise, we expect to reclassify $72 million of net gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, with $75 million as an increase in revenue and $3 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 Statements of Consolidated Operations for the years indicated: Derivatives Not Designated as Hedging Instruments Location Gain (Loss) Recognized in Income on Derivative For the Year Ended December 31, 2024 2023 2022 Commodity derivatives Revenue $ 26 $ 213 $ 74 Commodity derivatives Operating costs and expenses (4 ) – 14 Total $ 22 $ 213 $ 88 The $22 million net gain recognized for the year ended December 31, 2024 (as noted in the preceding table) from derivatives not designated as hedging instruments consists of $7 million of net realized gains and $15 million of net unrealized mark-to-market gains attributable to commodity derivatives. In total and inclusive of both fair value hedges and derivatives not designated as hedging instruments, unrealized mark-to-market gains (losses) included in gross operating margin were as follows for the years indicated: For the Year Ended December 31, 2024 2023 2022 Mark-to-market gains (losses) in gross operating margin: NGL Pipelines & Services $ (8 ) $ (25 ) $ (52 ) Crude Oil Pipelines & Services 21 (5 ) (30 ) Natural Gas Pipelines & Services 5 (1 ) (3 ) Petrochemical & Refined Products Services 2 (2 ) 7 Total mark-to-market impact on gross operating margin $ 20 $ (33 ) $ (78 ) Fair Value Measurements The following tables set forth, by level within the Level 1, 2 and 3 fair value hierarchy (see Note 2), the carrying values of our financial assets and liabilities at the dates indicated. These assets and liabilities are measured on a recurring basis and are classified based on the lowest level of input used to estimate their fair value. Our assessment of the relative significance of such inputs requires judgment. The values for commodity derivatives are presented before and after the application of CME Rule 814, which deems that financial instruments cleared by the CME are settled daily in connection with variation margin payments. As a result of this exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. Derivative transactions cleared on exchanges other than the CME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis. At December 31, 2024 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Financial assets: Commodity derivatives: Value before application of CME Rule 814 $ 355 $ 443 $ – $ 798 Impact of CME Rule 814 (56 ) (167 ) – (223 ) Total commodity derivatives 299 276 – 575 Total $ 299 $ 276 $ – $ 575 Financial liabilities: Commodity derivatives: Value before application of CME Rule 814 $ 291 $ 404 $ 21 $ 716 Impact of CME Rule 814 (43 ) (157 ) (21 ) (221 ) Total commodity derivatives 248 247 – 495 Total $ 248 $ 247 $ – $ 495 In the aggregate, the fair value of our commodity hedging portfolios at was a net derivative asset of $ At December 31, 2023 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Financial assets: Commodity derivatives: Value before application of CME Rule 814 $ 431 $ 297 $ – $ 728 Impact of CME Rule 814 (147 ) (131 ) – (278 ) Total commodity derivatives 284 166 – 450 Total $ 284 $ 166 $ – $ 450 Financial liabilities: Interest rate derivatives: $ – $ 31 $ – $ 31 Commodity derivatives: Value before application of CME Rule 814 317 308 – 625 Impact of CME Rule 814 (22 ) (132 ) – (154 ) Total commodity derivatives 295 176 – 471 Total $ 295 $ 207 $ – $ 502 Financial assets and liabilities recorded on the balance sheet at and using significant unobservable inputs (Level 3) and changes in the fair value of our recurring Level 3 financial assets and liabilities on a combined basis during the related periods were not material to the Consolidated Financial Statements. Other Fair Value Information The carrying amounts of cash and cash equivalents (including restricted cash balances), accounts receivable, commercial paper notes and accounts payable approximate their fair values based on their short-term nature. The estimated total fair value of our fixed-rate debt obligations was $28.9 billion and $26.7 billion at December 31, 2024 and 2023, respectively. The aggregate carrying value of these debt obligations was $31.6 billion and $28.0 billion at December 31, 2024 and 2023, respectively. These values are primarily based on quoted market prices for such debt or debt of similar terms and maturities (Level 2) and our credit standing. Changes in market rates of interest affect the fair value of our fixed-rate debt. The carrying values of our variable-rate long-term debt obligations approximate their fair values since the associated interest rates are market-based. We do not have any long-term investments in debt or equity securities recorded at fair value.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2024
Related Party Transactions [Abstract]
Related Party Transactions	Note 15. Related Party Transactions The following table summarizes our related party transactions for the years indicated: For the Year Ended December 31, 2024 2023 2022 Revenues – related parties: Unconsolidated affiliates $ 58 $ 61 $ 59 Costs and expenses – related parties: EPCO and its privately held affiliates $ 1,472 $ 1,353 $ 1,289 Unconsolidated affiliates 185 188 209 Total $ 1,657 $ 1,541 $ 1,498 The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated: December 31, 2024 2023 Accounts receivable - related parties: Unconsolidated affiliates $ 4 $ 7 Accounts payable - related parties: EPCO and its privately held affiliates $ 180 $ 183 Unconsolidated affiliates 18 16 Total $ 198 $ 199 We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties. Relationship with EPCO and Affiliates We have an extensive and ongoing relationship with EPCO and its privately held affiliates (including Enterprise GP, our general partner), which are not a part of our consolidated group of companies. At December 31, 2024, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us: Total Number of Limited Partner Interests Held Percentage of Common Units Outstanding 701,938,819 common units 32.4% 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 December 31, 2024. These credit facilities contain customary and other events of default, including defaults by us and other affiliates of EPCO. An event of default, followed by a foreclosure on the pledged collateral, could ultimately result in a change in ownership of these units and affect the market price of the Partnership’s common units. The Partnership and Enterprise GP are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are also separate from those of EPCO and its other affiliates. EPCO and its privately held affiliates use cash on hand and cash distributions they receive from us and other investments to fund their other activities and to meet their respective debt obligations, if any. During the years ended December 31, 2024, 2023 and 2022, we paid EPCO and its privately held affiliates cash distributions totaling $1.4 billion, $1.3 billion and $1.3 billion, respectively. We lease office space from privately held affiliates of EPCO. For the years ended December 31, , and , we recognized $ EPCO ASA 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. Under the ASA, EPCO provides us with the administrative and operating services deemed necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices). Our operating costs and expenses include amounts paid to EPCO for the actual direct and indirect costs it incurs to operate our facilities, including the compensation of its employees. Likewise, our general and administrative costs include amounts paid to EPCO for management and other administrative services, including the compensation of its employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to the ASA based on the estimated use of such services by each party (e.g., the allocation of legal or accounting salaries based on estimates of time spent on each entity’s business and affairs). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time with respect to the services provided to us by EPCO. The ASA allows us to participate as a named insured in EPCO’s overall insurance program, with the associated premiums and other costs being allocated to us. See Note 18 for additional information regarding our insurance programs. The following table presents our related party costs and expenses attributable to the ASA with EPCO for the years indicated: For the Year Ended December 31, 2024 2023 2022 Operating costs and expenses $ 1,294 $ 1,189 $ 1,124 General and administrative expenses 152 141 146 Total costs and expenses $ 1,446 $ 1,330 $ 1,270 Since the vast majority of such expenses are charged to us on an actual basis (i.e., no mark-up is charged or subsidy is received), we believe that such expenses are representative of what the amounts would have been on a standalone basis. With respect to allocated costs, we believe that the proportional direct allocation method employed by EPCO is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis. Relationships with Unconsolidated Affiliates Many of our unconsolidated affiliates perform supporting or complementary roles to our other business operations. The following information summarizes significant related party transactions with our unconsolidated affiliates: • For the years ended December 31, 2024, 2023 and 2022, we paid Seaway $30 million, $27 million and $20 million, respectively, for pipeline transportation and storage services in connection with our crude oil marketing activities. Revenues from Seaway were $23 million, $25 million and $15 million for the years ended December 31, 2024, 2023 and 2022, respectively. • For the years ended December 31, 2024, 2023 and 2022, we purchased $75 million, $80 million and $107 million, respectively, of NGLs from VESCO. • We pay Promix for the transportation, storage and fractionation of NGLs. Expenses with Promix were $39 million, $36 million and $41 million for the years ended December 31, 2024, 2023 and 2022, respectively. In addition, we sell natural gas to Promix for its plant fuel requirements. Revenues from Promix were $9 million, $11 million and $22 million for the years ended December 31, 2024, 2023 and 2022, respectively. • For the years ended December 31, 2024, 2023 and 2022, we paid Texas Express $10 million, $27 million and $31 million, respectively, for pipeline transportation services. • We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $14 million, $11 million and $12 million for the years ended December 31, 2024, 2023 and 2022, respectively.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2024
Income Taxes [Abstract]
Provision for Income Taxes	Note 16. Income Taxes Publicly traded partnerships like ours are treated as corporations unless they have 90% or more in “qualifying income” (as that term is defined in the Internal Revenue Code). We satisfied this requirement in each of the years ended December 31, 2024, 2023 and 2022 and, as a result, are not subject to federal income tax. However, our partners are individually responsible for paying federal income tax on their share of our taxable income. Net earnings for financial reporting purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and financial reporting basis of certain assets and liabilities and other factors. We do not have access to information regarding each partner’s individual tax basis in our limited partner interests. 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. Accounting guidance provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. We did not rely on any uncertain tax positions in recording our income tax-related amounts during the years ended December 31, , and . Tabular Disclosures Regarding Income Taxes Our federal, state and foreign income tax benefit (provision) is summarized below: For the Year Ended December 31, 2024 2023 2022 Current portion of income tax provision: Federal $ (2 ) $ (12 ) $ (2 ) State (18 ) (20 ) (18 ) Foreign – – (2 ) Total current portion (20 ) (32 ) (22 ) Deferred portion of income tax provision: Federal (16 ) 17 (20 ) State (28 ) (29 ) (40 ) Foreign (1 ) – – Total deferred portion (45 ) (12 ) (60 ) Total provision for income taxes $ (65 ) $ (44 ) $ (82 ) 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 Year Ended December 31, 2024 2023 2022 Pre-Tax Net Book Income (“NBI”) $ 6,035 $ 5,701 $ 5,697 Texas Margin Tax (1) (44 ) (49 ) (56 ) State income tax provision, net of federal benefit (2 ) (2 ) (1 ) Federal income tax provision computed by applying the federal statutory rate to NBI of corporate entities (17 ) (16 ) (15 ) Change in valuation allowance (2) – 22 (8 ) Other (2 ) 1 (2 ) Provision for income taxes $ (65 ) $ (44 ) $ (82 ) Effective income tax rate (1.1 )% (0.8 )% (1.4 )% (1) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses. (2) During 2023, management concluded that it is more likely than not that the deferred tax assets attributable to OTA will be fully realizable. As a result, for the year-end December 31, 2023, we recorded a full release of the valuation allowance against OTA’s deferred tax assets. Deferred income taxes are determined based on the temporary differences between the financial statement and income tax bases of assets and liabilities as measured by the enacted tax rates, which will be in effect when these differences reverse. The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated: December 31, 2024 2023 Deferred tax liabilities: Attributable to investment in OTA (1) $ 462 $ 436 Attributable to property, plant and equipment 151 138 Attributable to investments in other entities 5 4 Other 98 83 Total deferred tax liabilities 716 661 Deferred tax assets: Net operating loss carryovers (2) 56 46 Temporary differences related to Texas Margin Tax 4 4 Total deferred tax assets 60 50 Total net deferred tax liabilities $ 656 $ 611 (1) Represents the deferred tax liability balance held by our wholly owned subsidiary, OTA, which we acquired in March 2020. (2) The loss amount presented as of December 31, 2024 has an indefinite carryover period. All losses are subject to limitations on their utilization.

Commitments and Contingent Liab

Commitments and Contingent Liabilities	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies [Abstract]
Commitments and Contingencies	Note 17. Commitments and Contingent Liabilities Litigation As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from future legal proceedings. We will vigorously defend the Partnership in litigation matters. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the possible need for accounting recognition and disclosure of these contingencies. We accrue an undiscounted liability for those contingencies where the loss is probable and the amount can be reasonably estimated. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount in the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Based on a consideration of all relevant known facts and circumstances, we do not believe that the ultimate outcome of any currently pending litigation directed against us will have a material impact on our consolidated financial statements either individually at the claim level or in the aggregate. There were no accruals for litigation contingencies at December 31, 2024 and 2023, respectively. We classify our accruals for litigation contingencies in our Consolidated Balance Sheets as a component of “Other current liabilities” or “Other long-term liabilities” based on management’s estimate regarding the timing of settlement. Our evaluation of litigation contingencies is based on the facts and circumstances of each case and predicting the outcome of these matters involves uncertainties. In the event the assumptions we use to evaluate these matters change in future periods or new information becomes available, we may be required to record additional accruals. In an effort to mitigate expenses associated with litigation, we may settle legal proceedings out of court. Commitments Under Equity Compensation Plans of EPCO In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense attributable to employees who perform management, administrative and operating functions for us. See Notes 13 and 15 for additional information regarding our accounting for equity-based awards and related party information, respectively. Contractual Obligations The following table summarizes our various contractual obligations at December 31, 2024. A description of each type of contractual obligation follows: Payment or Settlement due by Period Contractual Obligations Total 2025 2026 2027 2028 2029 Thereafter Scheduled maturities of debt obligations $ 32,207 $ 1,150 $ 1,625 $ 1,575 $ 1,000 $ 1,250 $ 25,607 Estimated cash interest payments $ 28,769 $ 1,476 $ 1,407 $ 1,338 $ 1,323 $ 1,272 $ 21,953 Operating lease obligations (1) $ 561 $ 121 $ 91 $ 54 $ 37 $ 30 $ 228 Finance lease obligations $ 4 $ 1 $ 1 $ 1 $ 1 $ – $ – Purchase obligations: Product purchase commitments: Estimated payment obligations: NGLs $ 1,322 $ 275 $ 248 $ 239 $ 205 $ 158 $ 197 Crude oil $ 7,197 $ 1,872 $ 1,584 $ 1,490 $ 1,177 $ 760 $ 314 Other $ 14 $ 2 $ 2 $ 2 $ 2 $ 2 $ 4 Service payment commitments $ 307 $ 46 $ 40 $ 40 $ 27 $ 22 $ 132 Capital expenditure commitments $ 99 $ 99 $ – $ – $ – $ – $ – (1) As of December 31, 2024, the difference between the total payments for operating lease obligations and the carrying value of our operating lease liabilities, which represents the present value of future operating lease payments, was $90 million. Scheduled Maturities of Debt We have long-term and short-term payment obligations under debt agreements. Amounts shown in the preceding table represent our scheduled future maturities of debt principal for the years indicated. See Note 7 for additional information regarding our consolidated debt obligations. Estimated Cash Interest Payments Our estimated cash payments for interest are based on the principal amount of our consolidated debt obligations outstanding at December 31, 2024, the contractually scheduled maturities of such balances, and the applicable interest rates. Our estimated cash payments for interest are influenced by the long-term maturities of our $2.3 billion in junior subordinated notes (due June 2067 through February 2078). The estimated cash payments assume that (i) the junior subordinated notes are not repaid prior to their respective maturity dates and (ii) the amount of interest paid on the junior subordinated notes is based on either (a) the current fixed interest rate charged or (b) the weighted-average variable rate paid in 2024, as applicable, for each note through the respective maturity date. See Note 7 for information regarding fixed and weighted-average variable interest rates charged in 2024. Operating and Finance Lease Obligations We lease certain property, plant and equipment under noncancelable and cancelable leases. Amounts shown in the preceding table represent minimum cash lease payment obligations under our leases with terms in excess of one year. Our significant operating lease agreements consist of (i) land held pursuant to property leases, (ii) the lease of underground storage caverns for natural gas, NGLs and ethylene, (iii) the lease of compressors and transportation equipment used in our operations and (iv) office space leased from affiliates of EPCO. These lease agreements have terms that range from 5 to 30 years. The During the fourth quarter of 2024, we entered into agreements to lease certain transportation equipment used in our trucking operations that include an option to purchase the leased equipment. As we are reasonably certain to exercise the purchase option at the end of the lease term, we classified these leases as finance leases. These lease agreements have terms of 4 years. The following table presents information regarding operating and finance leases where we are the lessee at December 31, 2024: Asset Category ROU Asset Carrying Value Lease Liability Carrying Value Weighted- Average Remaining Term Weighted- Average Discount Rate Operating leases Storage and pipeline facilities $ 222 $ 222 8 years 4.5% Transportation equipment 43 44 4 years 4.8% Office and warehouse space 170 205 12 years 3.4% Total operating leases 435 471 Finance leases Transportation equipment 4 4 4 years 4.7% Total finance leases 4 4 Total leases $ 439 $ 475 (1) ROU asset amounts are a component of “ Other assets (2) At December 31, 2024, operating lease liabilities of $105 million and $366 million were included within “ Other current liabilities ” and “ Other long-term liabilities ,” Other current liabilities Other long-term liabilities (3) The discount rate for each category of assets represents the weighted average incremental borrowing rate adjusted for collateralization (if the implicit rate is not determinable). In general, the discount rates are based on either (i) information available at the lease commencement date or (ii) January 1, 2019 for leases existing at the adoption date for ASC 842. The following table disaggregates our total operating and finance lease expense for the years indicated: For the Year Ended December, 2024 2023 2022 Long-term leases: Fixed operating lease expense: Non-cash lease expense (amortization of ROU assets) $ 95 $ 72 $ 59 Related accretion expense on lease liability balances 17 14 12 Total fixed operating lease expense 112 86 71 Fixed finance lease expense: Amortization of ROU assets (1) – * – – Interest on finance lease liabilities (1) – * – – Total fixed finance lease expense (1) – * – – Variable lease expense 17 13 6 Total long-term lease expense 129 99 77 Short-term leases 121 111 91 Total lease expense $ 250 $ 210 $ 168 (1) For the year ended December 31, 2024, total fixed finance lease expense, which include amortization of finance lease ROU assets and interest on finance lease liabilities, was less than $1 million. * Amount is negligible. Fixed operating lease expense for storage, pipeline, transportation equipment and warehouse are charged to operating costs and expenses, while those for our office buildings are charged to general and administrative costs. Fixed finance lease expense includes interest on the finance lease liabilities and amortization of the ROU assets, which are charged to interest expense and operating costs and expenses, respectively. Variable lease payments and short-term lease expense are expensed as incurred. Cash paid for operating lease liabilities recorded on our balance sheet was $110 million, $87 million and $65 million for the years ended December 31, 2024, 2023 and 2022, respectively. There were no cash payments for finance lease liabilities during the year ended December 31, 2024. We do not have any significant operating leases where we are the lessor. Our operating lease income for the years ended December 31, 2024, 2023 and 2022 was $ million, $ million and $ million, respectively. We do not have any direct financing or sales-type leases. Purchase Obligations We define purchase obligations as agreements with remaining terms in excess of one year to purchase goods or services that are enforceable and legally binding (i.e., unconditional) on us that specify all significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions and (iii) the approximate timing of the transactions. We classify our unconditional purchase obligations into the following categories: • Product purchase commitments – We have long-term product purchase obligations for natural gas, NGLs, crude oil, and petrochemicals and refined products with third party suppliers. The prices that we are obligated to pay under these contracts approximate market prices at the time we take delivery of the volumes. The preceding table presents our estimated future payment obligations under these contracts based on the contractual price in each agreement at December 31, 2024 applied to all future volume commitments. Actual future payment obligations may vary depending on prices at the time of delivery. • Service payment commitments – We have long-term commitments to pay service providers, including those attributable to obligations under firm pipeline transportation contracts. Payment obligations vary by contract, but generally represent a price per unit of volume multiplied by a firm transportation volume commitment. • We have short-term payment obligations relating to our capital expenditures, including our share of the capital expenditures of unconsolidated affiliates. These commitments represent unconditional payment obligations for services to be rendered or products to be delivered in connection with capital projects. Other Long-Term Liabilities The following table summarizes the components of “Other long-term liabilities” as presented on our Consolidated Balance Sheets at the dates indicated: December 31, 2024 2023 Noncurrent portion of AROs (see Note 4) $ 259 $ 221 Deferred revenues – non-current portion (see Note 9) 284 326 Operating lease liability – non-current portion 366 323 Derivative liabilities 24 106 Other 17 8 Total $ 950 $ 984

Significant Risks and Uncertain

Significant Risks and Uncertainties	12 Months Ended
	Dec. 31, 2024
Significant Risks and Uncertainties [Abstract]
Significant Risks and Uncertainties	Note 18. Significant Risks and Uncertainties Nature of Operations We operate predominantly in the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, crude oil, and petrochemical and refined products. As such, changes in the prices of hydrocarbon products and in the relative price levels among hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows. Changes in prices may impact demand for hydrocarbon products, which in turn may impact production, demand and the volumes of products for which we provide services. In addition, decreases in demand may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, adverse weather conditions, public health emergencies and government regulations affecting prices and production levels. The natural gas, NGL and crude oil volumes currently transported, gathered or processed at our facilities originate primarily from existing domestic resource basins, which naturally deplete over time. To offset this natural decline, our facilities need access to production from newly discovered properties. Many economic and business factors beyond our control can adversely affect the decision by producers to explore for and develop new reserves. These factors could include relatively low crude oil and natural gas prices, cost and availability of equipment and labor, regulatory changes, capital budget limitations, the lack of available capital or the probability of success in finding hydrocarbons. A decrease in exploration and development activities in the regions where our facilities and other energy logistics assets are located could result in a decrease in volumes handled by our assets, which could have a material adverse effect on our financial position, results of operations and cash flows. Even if crude oil and natural gas reserves exist in the areas served by our assets, we may not be chosen by producers in these areas to gather, transport, process, fractionate, store or otherwise handle the hydrocarbons extracted. We compete with other companies for such production on the basis of many factors, including, but not limited to, geographic proximity to the production, costs of connection, available capacity, rates and access to markets. Credit Risk We may incur credit risk to the extent counterparties do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, crude oil, and petrochemicals and refined products and under long-term contracts with minimum volume commitments or fixed demand charges. Risks of nonpayment and nonperformance by customers are a major consideration in our businesses, and our credit procedures and policies may not be adequate to sufficiently eliminate customer credit risk. Further, adverse economic conditions in our industry, such as those experienced in connection with the COVID-19 pandemic in 2020, may increase the risk of nonpayment and nonperformance by customers, particularly customers that have sub-investment grade credit ratings or small-scale companies. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments, net out agreements and guarantees. However, these procedures and policies do not fully eliminate customer credit risk. The primary markets for our services are the Gulf Coast, Southwest, Rocky Mountain, Northeast and Midwest regions of the U.S. We have a concentration of trade receivables due from independent and major integrated oil and gas companies and other pipelines and wholesalers operating in these markets. These concentrations may affect our overall credit risk in that these energy industry customers may be similarly affected by adverse changes in economic, regulatory or other factors. In those situations where we are exposed to credit risk in our derivative instrument transactions, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis. Generally, we do not require collateral for such transactions nor do we currently anticipate nonperformance by our material counterparties. Insurance Matters We participate as a named insured in EPCO’s insurance program, which provides us with property damage, business interruption and other insurance coverage, the scope and amounts of which we believe are customary and prudent for the nature and extent of our operations. While we believe EPCO maintains adequate insurance coverage on our behalf, insurance may not fully cover every type of damage, interruption or other loss that might occur. If we were to incur a significant loss for which we were not fully insured, it could have a material adverse impact on our financial position, results of operations and cash flows. In addition, there may be timing differences between amounts we accrue related to property damage expense, amounts we are required to pay in connection with a loss, and amounts we subsequently receive from insurance carriers as reimbursements. Any event that materially interrupts the revenues generated by our consolidated operations, or other losses that require us to make material expenditures not reimbursed by insurance, could reduce our ability to pay distributions to our unitholders and, accordingly, adversely affect the market price of the Partnership’s common units. Involuntary conversions result from the loss of an asset due to some unforeseen event (e.g., destruction due to a fire). Some of these events are covered by insurance, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related to the covered event. We record a receivable from insurance to the extent we recognize a loss from an involuntary conversion event and the likelihood of our recovering such loss is deemed probable. To the extent that any of our insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. We recognize gains on involuntary conversions when the amount received from insurance exceeds the net book value of the retired assets. In addition, we do not recognize gains related to insurance recoveries until all contingencies related to such proceeds have been resolved, that is, a non-refundable cash payment is received from the insurance carrier or we have a binding settlement agreement with the carrier that clearly states that a non-refundable payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, on our Consolidated Balance Sheets and presented as “Capital expenditures” on our Statements of Consolidated Cash Flows. Under our current insurance program, the standalone deductible for property damage claims is $30 million. We also have business interruption protection; however, such claims must involve physical damage and have a combined loss value in excess of $30 million and the period of interruption must exceed 60 days. With respect to named windstorm claims, the maximum amount of insurance coverage available to us for any single event is $200 million, after applying the appropriate deductibles. A named windstorm is a hurricane, typhoon, tropical storm or cyclone as declared by the U.S. National Weather Service. Beginning in April 2023, we maintain insurance coverage for general liability, excess liability, automotive liability and workers’ compensation that is separate from EPCO’s insurance program. For these policies, we are responsible to the extent that losses are within policy limits. We have reserves for both open claims asserted, and an estimate of claims incurred but not reported (“IBNR”). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material adverse impact on our financial position, results of operations and cash flows. Our reserve balance, which is a component of “Other current liabilities” on our Consolidated Balance Sheets, was $39 million and $22 million at December 31, 2024 and 2023, respectively.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2024
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Note 19. 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 years indicated: For the Year Ended December 31, 2024 2023 2022 Decrease (increase) in: Accounts receivable – trade $ (1,453 ) $ (810 ) $ 108 Accounts receivable – related parties 2 4 10 Inventories (598 ) (714 ) 131 Prepaid and other current assets (152 ) (651 ) (97 ) Other assets 38 31 (42 ) Increase (decrease) in: Accounts payable – trade (182 ) 309 (174 ) Accounts payable – related parties (1 ) (33 ) 65 Accrued product payables 1,867 849 (190 ) Accrued interest 81 29 (26 ) Other current liabilities 15 484 124 Other long-term liabilities (123 ) (53 ) 37 Net effect of changes in operating accounts $ (506 ) $ (555 ) $ (54 ) Cash payments for interest, net of $ 121 106 90 capitalized in 2024 2023 2022 $ 1,255 $ 1,228 $ 1,232 Cash payments for federal and state income taxes $ 20 $ 24 $ – We incurred liabilities for construction in progress that had not been paid at December 31, 2024, 2023 and 2022 of $490 million, $400 million and $238 million, respectively. Such amounts are not included under the caption “Capital expenditures” on the Statements of Consolidated Cash Flows. The following table presents our cash proceeds from asset sales and other matters for the years indicated: For the Year Ended December 31, 2024 2023 2022 Recovery of construction costs (1) $ – $ 25 $ 99 Other asset sales 14 17 23 Total $ 14 $ 42 $ 122 (1) Amounts presented reflect the portion of cash receipts from the settlement of claims attributable to the partial recovery of construction costs incurred on the associated capital project.

Cybersecurity Risk Management a

Cybersecurity Risk Management and Strategy Disclosure	12 Months Ended
	Dec. 31, 2024
Cybersecurity Risk Management, Strategy, and Governance [Abstract]
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]	Cybersecurity Risk Management and Strategy We consider the risks from cybersecurity threats to include, without limitation, disruptions to our business operations, theft of protected information or intellectual property, destruction of our control systems and data, losses from remedial actions, damage to our reputation, and exposure to lawsuits and regulatory actions. In general, such risks are based on the capabilities and intent of known bad actors as well as threat information gathered from multiple sources, including industry groups, government agencies, publications and third-party service providers. Our processes for managing these risks generally involve (i) the use of tools and technologies to continuously monitor for and identify system vulnerabilities and attacks; (ii) adherence to policies and procedures designed to protect our critical IT and OT systems; (iii) the use of an employee awareness program to promote cybersecurity education and company-wide support; and (iv) periodic reassessment of areas of focus to maintain continued preparedness relative to changes in tools and technologies as well as emerging threats. Our processes for identifying, assessing and managing the risks from cybersecurity threats are a key component of our overall cybersecurity strategy, which is designed to safeguard technology critical to providing services for our customers, and protecting business-sensitive and personal information that is entrusted to us. To help execute our cybersecurity strategy, we have adopted a risk-based, layered, defense-in-depth approach, which, among other measures, includes: (i) the segregation of our critical industrial control systems (Operational Technology or OT systems) from our corporate network; (ii) multiple layers of preventative and detective measures; (iii) a cybersecurity incident response plan to promote preparedness; and (iv) a cross-functional cybersecurity steering committee (the “Cybersecurity Committee”) to provide guidance around cybersecurity risk management. Our overall cybersecurity program is based on various industry-recognized frameworks and standards developed and issued by leading international, domestic and energy-industry standard-setting organizations. As part of our overall cybersecurity strategy, we also engage third-party service providers to: (i) assist in our cybersecurity risk assessment procedures; (ii) perform penetration testing on external facing IT systems; (iii) perform security assessments on our IT and OT systems; (iv) assist in our incident response procedures; and (v) share information on industry-specific cybersecurity threats. With respect to our use of third-party systems, we oversee our risks from cybersecurity threats by working with our third-party vendors to evaluate their cybersecurity program for alignment with our own policies and procedures, including notification of and coordination during any incidents that might affect us. To the extent our processes for overseeing risks are effective in eliminating cybersecurity threats or mitigating the impact of an unforeseen incident, we generally do not expect these risks to have a material impact on our business strategy, financial position, or results of operations. However, as mentioned in Part I, Item 1A. Risk Factors, we do not carry insurance specifically for cybersecurity incidents. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows. For information on the risks we face from cybersecurity threats, please see the risk factors included under Part I, Item 1A titled “ A cyber-attack on our IT or OT systems could affect our business and assets, and have a material adverse effect on our financial position, results of operations and cash flows. Failure of our critical IT or OT systems could have an adverse impact on our business, financial condition, results of operations and cash flows, as well as our ability to pay cash distributions.
Cybersecurity Risk Management Processes Integrated [Flag]	true
Cybersecurity Risk Management Processes Integrated [Text Block]	Our processes for identifying, assessing and managing the risks from cybersecurity threats are a key component of our overall cybersecurity strategy, which is designed to safeguard technology critical to providing services for our customers, and protecting business-sensitive and personal information that is entrusted to us. To help execute our cybersecurity strategy, we have adopted a risk-based, layered, defense-in-depth approach, which, among other measures, includes: (i) the segregation of our critical industrial control systems (Operational Technology or OT systems) from our corporate network; (ii) multiple layers of preventative and detective measures; (iii) a cybersecurity incident response plan to promote preparedness; and (iv) a cross-functional cybersecurity steering committee (the “Cybersecurity Committee”) to provide guidance around cybersecurity risk management. Our overall cybersecurity program is based on various industry-recognized frameworks and standards developed and issued by leading international, domestic and energy-industry standard-setting organizations.
Cybersecurity Risk Management Third Party Engaged [Flag]	true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]	true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]	false
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Text Block]	To the extent our processes for overseeing risks are effective in eliminating cybersecurity threats or mitigating the impact of an unforeseen incident, we generally do not expect these risks to have a material impact on our business strategy, financial position, or results of operations. However, as mentioned in Part I, Item 1A. Risk Factors, we do not carry insurance specifically for cybersecurity incidents. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows.
Cybersecurity Risk Board of Directors Oversight [Text Block]	Cybersecurity Governance Our Cybersecurity Committee is comprised of senior representatives from our legal, IT and OT, engineering, corporate security, risk, human resources, finance, accounting, public relations, investor relations and executive management teams. This committee plays a key role in assessing and managing our risks from cybersecurity threats. In particular, our Cybersecurity Committee is responsible for: (i) establishing and promoting company-wide support for the management of cybersecurity risk; (ii) providing oversight and ensuring alignment between our cybersecurity strategy and business objectives; (iii) reviewing and advising on cybersecurity policy and governance; (iv ) providing a forum for review of cybersecurity risk in alignment with our business objectives and risk tolerance; (v) promoting cross-company alignment of cybersecurity programs and actions; and (vi) reviewing our cybersecurity incident response plan (“CIRP”). Our Cybersecurity Committee meets at least quarterly with senior representatives from our cybersecurity team and outside experts to discuss cybersecurity threat updates, new cybersecurity regulations, cybersecurity projects and entity-wide results of cybersecurity preparedness initiatives. If a cybersecurity incident occurs, our Cybersecurity Incident Response Team, which includes several members of our Cybersecurity Committee, will oversee the execution of our CIRP. Our Board has oversight of all material risks relevant to Enterprise, including those related to cybersecurity threats. To help keep our Board informed about such risks, senior representatives from our IT and OT department provide quarterly updates to our Board regarding significant developments in: (i) cyberattacks and other cybersecurity threats targeting critical infrastructure; (ii) governmental enforcement actions and investigations against cyber criminals; (iii) the regulatory landscape impacting the midstream energy industry; (iv) improvements to our cybersecurity programs, including our CIRP and related response procedures, and the progress of ongoing cybersecurity projects. We recognize that effective cybersecurity governance is an on-going process, and thus, encourage those individuals with oversight responsibilities to stay abreast of emerging cybersecurity threats as well as pursue cybersecurity education opportunities. To this end, a number of our Cybersecurity Committee members, particularly the IT and OT representatives, hold one or more industry-recognized information security certifications such as the CISSP, CISM and CISA.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]	Our Cybersecurity Committee is comprised of senior representatives from our legal, IT and OT, engineering, corporate security, risk, human resources, finance, accounting, public relations, investor relations and executive management teams. This committee plays a key role in assessing and managing our risks from cybersecurity threats. In particular, our Cybersecurity Committee is responsible for: (i) establishing and promoting company-wide support for the management of cybersecurity risk; (ii) providing oversight and ensuring alignment between our cybersecurity strategy and business objectives; (iii) reviewing and advising on cybersecurity policy and governance; (iv ) providing a forum for review of cybersecurity risk in alignment with our business objectives and risk tolerance; (v) promoting cross-company alignment of cybersecurity programs and actions; and (vi) reviewing our cybersecurity incident response plan (“CIRP”). Our Cybersecurity Committee meets at least quarterly with senior representatives from our cybersecurity team and outside experts to discuss cybersecurity threat updates, new cybersecurity regulations, cybersecurity projects and entity-wide results of cybersecurity preparedness initiatives. If a cybersecurity incident occurs, our Cybersecurity Incident Response Team, which includes several members of our Cybersecurity Committee, will oversee the execution of our CIRP.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	Our Board has oversight of all material risks relevant to Enterprise, including those related to cybersecurity threats. To help keep our Board informed about such risks, senior representatives from our IT and OT department provide quarterly updates to our Board regarding significant developments in: (i) cyberattacks and other cybersecurity threats targeting critical infrastructure; (ii) governmental enforcement actions and investigations against cyber criminals; (iii) the regulatory landscape impacting the midstream energy industry; (iv) improvements to our cybersecurity programs, including our CIRP and related response procedures, and the progress of ongoing cybersecurity projects.
Cybersecurity Risk Role of Management [Text Block]	Our Cybersecurity Committee is comprised of senior representatives from our legal, IT and OT, engineering, corporate security, risk, human resources, finance, accounting, public relations, investor relations and executive management teams. This committee plays a key role in assessing and managing our risks from cybersecurity threats. In particular, our Cybersecurity Committee is responsible for: (i) establishing and promoting company-wide support for the management of cybersecurity risk; (ii) providing oversight and ensuring alignment between our cybersecurity strategy and business objectives; (iii) reviewing and advising on cybersecurity policy and governance; (iv ) providing a forum for review of cybersecurity risk in alignment with our business objectives and risk tolerance; (v) promoting cross-company alignment of cybersecurity programs and actions; and (vi) reviewing our cybersecurity incident response plan (“CIRP”). Our Cybersecurity Committee meets at least quarterly with senior representatives from our cybersecurity team and outside experts to discuss cybersecurity threat updates, new cybersecurity regulations, cybersecurity projects and entity-wide results of cybersecurity preparedness initiatives. If a cybersecurity incident occurs, our Cybersecurity Incident Response Team, which includes several members of our Cybersecurity Committee, will oversee the execution of our CIRP.
Cybersecurity Risk Management Positions or Committees Responsible [Flag]	true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	Our Cybersecurity Committee is comprised of senior representatives from our legal, IT and OT, engineering, corporate security, risk, human resources, finance, accounting, public relations, investor relations and executive management teams. This committee plays a key role in assessing and managing our risks from cybersecurity threats. In particular, our Cybersecurity Committee is responsible for: (i) establishing and promoting company-wide support for the management of cybersecurity risk; (ii) providing oversight and ensuring alignment between our cybersecurity strategy and business objectives; (iii) reviewing and advising on cybersecurity policy and governance; (iv ) providing a forum for review of cybersecurity risk in alignment with our business objectives and risk tolerance; (v) promoting cross-company alignment of cybersecurity programs and actions; and (vi) reviewing our cybersecurity incident response plan (“CIRP”). Our Cybersecurity Committee meets at least quarterly with senior representatives from our cybersecurity team and outside experts to discuss cybersecurity threat updates, new cybersecurity regulations, cybersecurity projects and entity-wide results of cybersecurity preparedness initiatives. If a cybersecurity incident occurs, our Cybersecurity Incident Response Team, which includes several members of our Cybersecurity Committee, will oversee the execution of our CIRP.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	We recognize that effective cybersecurity governance is an on-going process, and thus, encourage those individuals with oversight responsibilities to stay abreast of emerging cybersecurity threats as well as pursue cybersecurity education opportunities. To this end, a number of our Cybersecurity Committee members, particularly the IT and OT representatives, hold one or more industry-recognized information security certifications such as the CISSP, CISM and CISA.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	Our Board has oversight of all material risks relevant to Enterprise, including those related to cybersecurity threats. To help keep our Board informed about such risks, senior representatives from our IT and OT department provide quarterly updates to our Board regarding significant developments in: (i) cyberattacks and other cybersecurity threats targeting critical infrastructure; (ii) governmental enforcement actions and investigations against cyber criminals; (iii) the regulatory landscape impacting the midstream energy industry; (iv) improvements to our cybersecurity programs, including our CIRP and related response procedures, and the progress of ongoing cybersecurity projects.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2024
Insider Trading Arrangements [Line Items]
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Insider Trading Policies and Pr

Insider Trading Policies and Procedures	12 Months Ended
	Dec. 31, 2024
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2024
Summary of Significant Accounting Policies [Abstract]
Allowance for Credit Losses	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 for the years indicated: For the Year Ended December 31, 2024 2023 2022 Balance at beginning of period $ 35 $ 54 $ 53 Charged to costs and expenses 3 1 6 Charged to other accounts – – 1 Deductions – (20 ) (6 ) Balance at end of period $ 38 $ 35 $ 54
Cash, Cash Equivalents and Restricted Cash	Cash, Cash Equivalents and Restricted Cash Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase. Restricted cash primarily represents amounts held in segregated bank accounts by our clearing brokers as margin in support of our commodity derivative instruments portfolio and related physical purchases and sales of natural gas, NGLs, crude oil, refined products and power. Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or margin requirements change. See Note 14 for information regarding our derivative instruments and hedging activities. The following table provides a reconciliation of cash and cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the amounts shown in the Statements of Consolidated Cash Flows. December 31, 2024 2023 Cash and cash equivalents $ 583 $ 180 Restricted cash 255 140 Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows $ 838 $ 320
Consolidation Policy	Consolidation Policy Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the Partnership. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Third party or affiliate ownership interests in our controlled subsidiaries are presented as noncontrolling interests. See Note 8 for information regarding noncontrolling interests. If the entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50%, unless our interest is so minor that we have virtually no influence over the investee’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. In consolidation, we eliminate our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates to the extent such amounts remain on our Consolidated Balance Sheets (or those of our equity method investments) in inventory or similar accounts.
Contingencies	Contingencies Certain conditions may exist as of the date our consolidated financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the need for accounting recognition or disclosure of these contingencies, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. We accrue an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 17 for additional information regarding our contingencies.
Current Assets and Current Liabilities	Current Assets and Current Liabilities We present, as individual captions in our Consolidated Balance Sheets, all components of current assets and current liabilities that exceed 5% of total current assets and current liabilities, respectively.
Derivative Instruments	Derivative Instruments We use derivative instruments such as futures, swaps, forward contracts and other arrangements to manage price risks associated with inventories, firm commitments, interest rates and certain anticipated future commodity transactions. To qualify for hedge accounting, the hedged item must expose us to risk and the related derivative instrument must reduce the exposure to that risk and meet specific hedge documentation requirements related to designation dates, expectations for hedge effectiveness and the probability that hedged future transactions will occur as forecasted. We formally designate derivative instruments as hedges and document and assess their effectiveness at inception of the hedge and on a monthly basis thereafter. Forecasted transactions are evaluated for the probability of occurrence and are periodically back-tested once the forecasted period has passed to determine whether forecasted transactions are probable of occurring in the future. We are required to recognize derivative instruments at fair value as either assets or liabilities on our Consolidated Balance Sheets unless such instruments meet certain normal purchase/normal sale criteria. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. After meeting specified conditions, a qualified derivative may be designated as a total or partial hedge of: • Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment – In a fair value hedge, gains and losses for both the derivative instrument and the hedged item are recognized in income during the period of change. • Variable cash flows of a forecasted transaction – In a cash flow hedge, the change in the fair value of the hedge is reported in other comprehensive income (loss) and is reclassified to earnings when the forecasted transaction affects earnings. An effective hedge relationship is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of the changes in fair value of a hedged item at inception and throughout the life of the hedging relationship. The effective portion of a hedge relationship is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period. A contract designated as a cash flow hedge of an anticipated transaction that is not probable of occurring is immediately recognized in earnings. Certain of our derivative instruments do not qualify for hedge accounting treatment; therefore, these instruments are accounted for using mark-to-market accounting. For substantially all of our physical forward commodity derivative contracts, we apply the normal purchase/normal sale exception, whereby changes in the mark-to-market values of such contracts are not recognized in income. As a result, the revenues and expenses associated with such physical transactions are recognized during the period when volumes are physically delivered or received. Physical forward commodity contracts subject to this exception are evaluated for the probability of future delivery and certain of these physical forward commodity contracts are periodically back-tested once the forecasted period has passed to determine whether similar forward contracts are probable of physical delivery in the future. See Note 14 for additional information regarding our derivative instruments.
Environmental Costs	Environmental Costs Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. For the year ended December 31, 2024 and 2023, our environmental reserves totaled $9 million and $4 million, respectively.
Estimates	Estimates Preparing our consolidated financial statements in conformity with GAAP requires us to make estimates that affect amounts presented in the financial statements. Our most significant estimates relate to (i) the useful lives and depreciation/amortization methods used for fixed and identifiable intangible assets; (ii) measurement of fair value and projections used in impairment testing of fixed and intangible assets (including goodwill); and (iii) revenue and expense accruals. Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our consolidated financial statements.
Fair Value Measurements	Fair Value Measurements Our recurring and nonrecurring fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk, in the principal market of the asset or liability at a specified measurement date. Recognized valuation techniques (such as the income or market approaches) employ inputs such as contractual prices, quoted market prices or rates, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. A three-tier hierarchy has been established that classifies fair value amounts recognized in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2 fair value measures) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3 fair value measures). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. The characteristics of fair value amounts classified within each level of the hierarchy are described as follows: • Level 1 fair value measures • Level 2 fair value measures • Level 3 fair value measures With regards to commodity derivatives, our Level 3 fair values primarily consist of the following commodity derivative instruments used to hedge various inventories and transportation capacities: (i) NGL, crude, natural gas, refined products and commercial energy-based contracts with terms greater than 36 months; (ii) over-the-counter options; and (iii) exchange traded options with terms greater than one year. In addition, we often rely on price quotes from reputable brokers who publish price quotes on certain products and compare these prices to other reputable brokers for the same products in the same markets whenever possible. These prices, when combined with data from our commodity derivative instruments, are used in our models to determine the fair value of such instruments. Our nonrecurring fair value estimates are generally based on the income approach to fair value and reflect various Level 3 inputs. In many cases, there are no active markets (a Level 1 fair value measure) to rely on or other similar recent transactions (a Level 2 fair value measure) to compare to. Our nonrecurring fair value estimates often include management’s expectations of the residual market values for the underlying assets based on their knowledge and experience in the industry (a Level 3 fair value measure). Other examples of Level 3 inputs used in the valuation models include anticipated gross operating margins, throughput or processing volumes, utilization factors, sustaining capital expenditures, discount rates and business growth rates. When probability weights are used in cash flow modeling, the weights are generally obtained from management personnel having oversight responsibilities for the assets being tested.
Impairment Testing	Impairment Testing The following table summarizes our asset impairment charges by type as presented on our Statements of Consolidated Cash Flows for the years indicated: For the Year Ended December 31, 2024 2023 2022 Impairment charges reflected in operating costs and expenses: Property, plant and equipment $ 50 $ 18 $ 41 Other (1) 7 12 12 Total asset impairment charges in operating costs and expenses (2) 57 30 53 Other property, plant and equipment impairment charges (3) – 2 – Total asset impairment charges $ 57 $ 32 $ 53 (1) Primarily represents the write-down of surplus materials classified as “Other assets” on our Consolidated Balance Sheets. (2) Amounts presented are a component of “Third party and other costs” within the “Operating costs and expenses” section of our Statements of Consolidated Operations. (3) Amounts presented are a component of “Third party and other costs” within the “General and administrative costs” section of our Statements of Consolidated Operations. The following information describes our accounting policies regarding impairment testing for major asset categories: • Impairment Testing for Long-Lived Assets. Long-lived assets, which consist of intangible assets with finite lives and property, plant and equipment, are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written down to their estimated fair values. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted estimated cash flows expected to result from the use and eventual disposition of the asset. If the asset’s carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques. See Note for information regarding impairment charges attributable to property, plant and equipment. • Impairment Testing for Investments in Unconsolidated Affiliates. • Impairment Testing for Goodwill. We determine the fair value of each reporting unit using accepted valuation techniques, primarily through the use of discounted cash flows (i.e., an income approach to fair value) supplemented by market-based assessments, if available. The estimated fair values of our reporting units incorporate assumptions regarding the future economic prospects of the assets and operations that comprise each reporting unit including: (i) discrete financial forecasts for the assets comprising the reporting unit, which, in turn, rely on management’s estimates of long-term operating margins, throughput volumes, capital investments and similar factors; (ii) long-term growth rates for the reporting unit’s cash flows beyond the discrete forecast period; and (iii) appropriate discount rates. The fair value estimates are based on Level 3 inputs of the fair value hierarchy. We believe that the assumptions we use in estimating reporting unit fair values are consistent with those that market participants would use in their fair value estimation process. However, due to uncertainties in the estimation process and volatility in the supply and demand for hydrocarbons and similar risk factors, actual results could differ significantly from our estimates. Based on our most recent goodwill impairment test at , the estimated fair value of each of our reporting units was substantially in excess of its carrying value (i.e., by at least 10%). We did not record any non-cash goodwill impairment charges during the years ended December 31, 2024, 2023 or 2022. See Note 6 for additional information regarding our goodwill.
Inventories	Inventories Inventories primarily consist of NGLs, petrochemicals, refined products, crude oil and natural gas volumes that are valued at the lower of cost or net realizable value. We capitalize, as a cost of inventory, shipping and handling charges (e.g., pipeline transportation and storage fees) and other related costs associated with purchased volumes. As volumes are sold and delivered out of inventory, the cost of these volumes (including freight-in charges that have been capitalized as part of inventory cost) are charged to operating costs and expenses. Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred. See Note 3 for additional information regarding our inventories.
Leases	Leases We account for our leases under Accounting Standards Codification (“ASC”) 842, Leases The standard includes two lessee accounting models, which results in a lease being classified as either a “finance” or “operating” lease based on whether the lessee effectively obtains control of the underlying asset during the lease term. A lease would be classified as a finance lease if it meets one of five classification criteria. By default, a lease that does not meet the criteria to be classified as a finance lease will be deemed an operating lease. Regardless of classification, the initial measurement of both lease types will result in the balance sheet recognition of a right-of-use (“ROU”) asset (representing a company’s right to use the underlying asset for a specified period of time) and a corresponding lease liability. The lease liability will be recognized at the present value of the future lease payments, and the ROU asset will equal the lease liability adjusted for any prepaid rent, lease incentives provided by the lessor, and any indirect costs. The subsequent measurement of each type of lease varies. For finance leases, a lessee will amortize the ROU asset (generally on a straight-line basis in a manner similar to depreciation) and accrete the lease liability (as a component of interest expense) using the . Operating leases will result in the recognition of a single lease expense amount that is recorded on a straight-line basis. We do not recognize ROU assets and lease liabilities for short-term leases, which are leases with a maximum term of 12 months or less and do not include a purchase option that the lessee is reasonably certain to exercise, and instead recognize lease payments on a straight-line basis. In addition, we combine lease and non-lease components relating to our office and warehouse leases, as applicable. See Note 17 for our disclosures regarding our lease obligations.
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized, and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in results of operations for the respective period. 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. In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management assumptions regarding the useful economic lives and residual values of our assets. Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes. Leasehold improvements are recorded as a component of property, plant and equipment. The cost of leasehold improvements is charged to earnings using the straight-line method over the shorter of (i) the remaining lease term or (ii) the estimated useful lives of the improvements. We consider renewal terms that are deemed reasonably assured when estimating remaining lease terms. Our assumptions regarding the useful economic lives and residual values of our assets may change in response to new facts and circumstances, which would prospectively impact our depreciation expense amounts. Examples of such circumstances include, but are not limited to: (i) changes in laws and regulations that limit the estimated economic life of an asset; (ii) changes in technology that render an asset obsolete; (iii) changes in expected salvage values or (iv) significant changes in the forecast life of the applicable resource basins, if any. Certain of our plant facilities undergo periodic planned outages for major maintenance activities. The method of accounting for these activities depends on whether the plant utilizes either a distillation-based or reaction-based process. Our natural gas processing plants, NGL fractionators, deisobutanizers, propylene splitters and similar facilities utilize thermal distillation processes to separate hydrocarbons into more useful components. Our reaction-based plants, which primarily include our PDH, isomerization and octane enhancement facilities, utilize catalysts to facilitate chemical reactions that convert lower value hydrocarbons into higher value products. We use the expense-as-incurred method to account for the planned major maintenance activities of distillation-based plants. 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. With regard to the planned major maintenance activities of our marine transportation assets and underground storage caverns, we continue to use the deferral method to account for such costs. Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the ARO liability is accreted to its present value (through accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts. See Note 4 for additional information regarding our property, plant and equipment and AROs.
Revenue	Revenues Substantially all of our revenues are accounted for under ASC 606, Revenue from Contracts with Customers, Leases, Nonmonetary Transactions, Derivatives and Hedging Activities The core principle of ASC 606 is that a company should recognize revenue in a manner that fairly depicts the transfer of goods or services to customers in amounts that reflect the consideration the company expects to receive for those goods or services. We apply this core principle by following five key steps outlined in ASC 606: (i) identify the contract; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management judgment and an analysis of the contract’s material terms and conditions. Under ASC 606, we recognize revenue when or as we satisfy our performance obligation to the customer. In situations where we have recognized revenue, but have a conditional right to consideration (based on something other than the passage of time) from the customer, we recognize unbilled revenue (a contract asset) on our consolidated balance sheet. Unbilled revenue is reclassified to accounts receivable when we have an unconditional right of payment from the customer. Payments received from customers in advance of the period in which we satisfy a performance obligation are recorded as deferred revenue (a contract liability) on our consolidated balance sheet. Our revenue streams are derived from the sale of products and providing midstream services. Revenues from the sale of products are recognized at a point in time, which represents the transfer of control (and the satisfaction of our performance obligation under the contract) to the customer. From that point forward, the customer is able to direct the use of, and obtain substantially all the benefits from its use of, the products. With respect to midstream services (e.g., interruptible transportation), we satisfy our performance obligations over time and recognize revenues when the services are provided and the customer receives the benefits based on an output measure of volumes redelivered. We believe this measure is a faithful depiction of the transfer of control for midstream services since there is (i) an insignificant period of time between the receipt of customers’ volumes and their subsequent redelivery, and (ii) it is not possible to individually track and differentiate customers’ inventories as they traverse our facilities. For stand-ready performance obligations (e.g., a storage capacity reservation contract), we recognize revenues over time on a straight-line basis as time elapses over the term of the contract. We believe that these approaches accurately depict the transfer of benefits to the customer. Customers are invoiced for products purchased or services rendered when we have an unconditional right to consideration under the associated contract. The consideration we are entitled to invoice may be either fixed, variable or a combination of both. Examples of fixed consideration would be fixed payments from customers under take-or-pay arrangements, storage capacity reservation agreements and firm transportation contracts. Variable consideration represents payments from customers that are based on factors that fluctuate (or vary) based on volumes, prices or both. Examples of variable consideration include interruptible transportation agreements, market-indexed product sales contracts and the value of NGLs we retain under natural gas processing agreements. The terms of our billings are typical of the industry for the products we sell. Under certain midstream service agreements, customers are required to provide a minimum volume over an agreed-upon period with a provision that allows the customer to make-up any volume shortfalls over an agreed-upon period (referred to as “make-up rights”). Revenue pursuant to such agreements is initially deferred and subsequently recognized when either the make-up rights are exercised, the likelihood of the customer exercising the rights becomes remote, or we are otherwise released from the performance obligation. Customers may contribute funds to us to help offset the construction costs related to pipeline construction activities and production well tie-ins. These receipts are recognized as additional service revenues over the term of the associated midstream services provided to the customer. For those contracts under which we have the ability to invoice the customer in an amount that corresponds directly with the value of the performance obligation completed to date, we recognize revenue as we have the right to invoice. See Note 9 regarding our revenue disclosures.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2024
Summary of Significant Accounting Policies [Abstract]
Allowance for Credit Losses	The following table presents our allowance for credit losses activity for the years indicated: For the Year Ended December 31, 2024 2023 2022 Balance at beginning of period $ 35 $ 54 $ 53 Charged to costs and expenses 3 1 6 Charged to other accounts – – 1 Deductions – (20 ) (6 ) Balance at end of period $ 38 $ 35 $ 54
Cash, Cash Equivalents and Restricted Cash	The following table provides a reconciliation of cash and cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the amounts shown in the Statements of Consolidated Cash Flows. December 31, 2024 2023 Cash and cash equivalents $ 583 $ 180 Restricted cash 255 140 Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows $ 838 $ 320
Asset Impairment Charges	The following table summarizes our asset impairment charges by type as presented on our Statements of Consolidated Cash Flows for the years indicated: For the Year Ended December 31, 2024 2023 2022 Impairment charges reflected in operating costs and expenses: Property, plant and equipment $ 50 $ 18 $ 41 Other (1) 7 12 12 Total asset impairment charges in operating costs and expenses (2) 57 30 53 Other property, plant and equipment impairment charges (3) – 2 – Total asset impairment charges $ 57 $ 32 $ 53 (1) Primarily represents the write-down of surplus materials classified as “Other assets” on our Consolidated Balance Sheets. (2) Amounts presented are a component of “Third party and other costs” within the “Operating costs and expenses” section of our Statements of Consolidated Operations. (3) Amounts presented are a component of “Third party and other costs” within the “General and administrative costs” section of our Statements of Consolidated Operations.

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2024
Inventories [Abstract]
Inventory Amounts by Product Type	Our inventory amounts by product type were as follows at the dates indicated: December 31, 2024 2023 NGLs $ 2,768 $ 2,392 Petrochemicals and refined products 652 536 Crude oil 523 419 Natural gas 12 5 Total $ 3,955 $ 3,352
Cost of Sales and Lower of Cost or Market Adjustments	The following table presents our total cost of sales amounts and lower of cost or net realizable value adjustments for the years indicated: For the Year Ended December 31, 2024 2023 2022 Cost of sales (1) $ 42,580 $ 37,023 $ 45,836 Lower of cost or net realizable value adjustments recognized in cost of sales 9 31 19 (1) Cost of sales is a component of “Operating costs and expenses,” as presented on our 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.

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2024
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment and Accumulated Depreciation	The historical costs of our property, plant and equipment and related balances were as follows at the dates indicated: Estimated Useful Life December 31, in Years 2024 2023 Plants, pipelines and facilities (1)(5) 3-45 $ 60,716 $ 57,983 Underground and other storage facilities (2)(6) 5-40 4,704 4,401 Transportation equipment (3) 3-10 272 242 Marine vessels (4) 15-30 949 935 Land 424 411 Construction in progress 4,138 2,245 Subtotal 71,203 66,217 Less accumulated depreciation 22,330 20,462 Subtotal property, plant and equipment, net 48,873 45,755 Capitalized major maintenance costs for reaction-based plants, net of accumulated amortization (7) 189 49 Property, plant and equipment, net $ 49,062 $ 45,804 (1) Plants, pipelines and facilities include distillation-based and reaction-based plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; buildings; office furniture and equipment; laboratory and shop equipment and related assets. (2) Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets. (3) Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations. (4) Marine vessels include tow boats, barges and related equipment used in our marine transportation business. (5) In general, the estimated useful lives of major assets within this category are: distillation-based and reaction-based plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; buildings, 20-40 years; office furniture and equipment, 3-20 years; and laboratory and shop equipment, 5-35 years. (6) In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years. (7) For reaction-based plants, we use the deferral method when accounting for major maintenance activities. Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. On a weighted-average basis, the expected remaining amortization period for these costs is 3.4 years.
Depreciation and Capitalized Interest	The following table summarizes our depreciation expense and capitalized interest amounts for the years indicated: For the Year Ended December 31, 2024 2023 2022 Depreciation expense (1) $ 1,974 $ 1,860 $ 1,779 Capitalized interest (2) 121 106 90 (1) Depreciation expense is a component of “Third party and other costs” within “Costs and expenses” as presented on our Statements of Consolidated Operations. (2) Capitalized interest is a component of “Interest expense” as presented on our Statements of Consolidated Operations.
AROs	The following table presents information regarding our AROs for the years indicated: For the Year Ended December 31, 2024 2023 2022 ARO liability beginning balance $ 225 $ 234 $ 176 Liabilities incurred (1) 1 5 20 Revisions in estimated cash flows (2) 30 (12 ) 30 Liabilities settled (3) (4 ) (13 ) (10 ) Accretion expense (4) 13 11 18 ARO liability ending balance $ 265 $ 225 $ 234 (1) Represents the initial recognition of estimated ARO liabilities during the period. (2) Represents subsequent adjustments to estimated ARO liabilities during the period. (3) Represents cash payments to settle ARO liabilities during the period. (4) Represents net change in ARO liability balance attributable to the passage of time and other adjustments, including true-up amounts associated with revised closure estimates. The following table presents our forecast of ARO-related accretion expense for the years indicated: 2025 2026 2027 2028 2029 $ 15 $ 16 $ 17 $ 18 $ 19
Impairments of Property, Plant and Equipment	The following table presents our non-cash asset impairment charges involving property, plant and equipment by business segment for the years indicated: For the Year Ended December 31, 2024 2023 2022 NGL Pipelines & Services $ 28 $ 12 $ 23 Crude Oil Pipelines & Services – 1 3 Natural Gas Pipelines & Services 7 5 6 Petrochemical & Refined Products Services 15 2 9 Total impairment charges for property, plant and equipment $ 50 $ 20 $ 41

Investments in Unconsolidated_2

Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2024
Investments in Unconsolidated Affiliates [Abstract]
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. Ownership Interest at December 31, December 31, 2024 2024 2023 NGL Pipelines & Services: Venice Energy Service Company, L.L.C. (“VESCO”) 13.1% $ 24 $ 24 K/D/S Promix, L.L.C. (“Promix”) 50% 22 25 Baton Rouge Fractionators LLC (“BRF”) 32.2% 12 13 Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”) 50% 25 26 Texas Express Pipeline LLC (“Texas Express”) 35% 299 303 Texas Express Gathering LLC (“TEG”) 45% 33 35 Front Range Pipeline LLC (“Front Range”) 33.3% 183 186 Total NGL Pipelines & Services 598 612 Crude Oil Pipelines & Services: Seaway Crude Holdings LLC (“Seaway”) 50% 1,147 1,192 Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”) 50% 368 373 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”) 50% 113 116 Total Crude Oil Pipelines & Services 1,628 1,681 Natural Gas Pipelines & Services: White River Hub, LLC (“White River Hub”) 50% 16 17 Old Ocean Pipeline, LLC (“Old Ocean”) 50% 14 16 Total Natural Gas Pipelines & Services 30 33 Petrochemical & Refined Products Services: Baton Rouge Propylene Concentrator LLC (“BRPC”) 30% 1 2 Transport 4, LLC (“Transport 4”) 25% 2 2 Total Petrochemical & Refined Products Services 3 4 T otal investments in unconsolidated affiliates $ 2,259 $ 2,330 The following table presents our equity in income of unconsolidated affiliates by business segment for the years indicated: For the Year Ended December 31, 2024 2023 2022 NGL Pipelines & Services $ 117 $ 133 $ 149 Crude Oil Pipelines & Services 285 320 308 Natural Gas Pipelines & Services 5 6 5 Petrochemical & Refined Products Services 1 3 2 Total $ 408 $ 462 $ 464

Intangible Assets and Goodwill

Intangible Assets and Goodwill (Tables)	12 Months Ended
	Dec. 31, 2024
Intangible Assets and Goodwill [Abstract]
Intangible Assets by Segment	The following table summarizes our intangible assets by business segment at the dates indicated: December 31, 2024 December 31, 2023 Gross Value Accumulated Amortization Carrying Value Gross Value Accumulated Amortization Carrying Value NGL Pipelines & Services: Customer relationship intangibles $ 449 $ (276 ) $ 173 $ 449 $ (263 ) $ 186 Contract-based intangibles 754 (141 ) 613 752 (110 ) 642 Segment total 1,203 (417 ) 786 1,201 (373 ) 828 Crude Oil Pipelines & Services: Customer relationship intangibles 2,195 (627 ) 1,568 2,195 (530 ) 1,665 Contract-based intangibles 283 (278 ) 5 283 (275 ) 8 Segment total 2,478 (905 ) 1,573 2,478 (805 ) 1,673 Natural Gas Pipelines & Services: Customer relationship intangibles 1,351 (663 ) 688 1,351 (625 ) 726 Contract-based intangibles 1,081 (227 ) 854 641 (209 ) 432 Segment total 2,432 (890 ) 1,542 1,992 (834 ) 1,158 Petrochemical & Refined Products Services: Customer relationship intangibles 181 (92 ) 89 181 (86 ) 95 Contract-based intangibles 45 (30 ) 15 45 (29 ) 16 Segment total 226 (122 ) 104 226 (115 ) 111 Total intangible assets $ 6,339 $ (2,334 ) $ 4,005 $ 5,897 $ (2,127 ) $ 3,770
Amortization Expense of Intangible Assets by Segment	The following table presents the amortization expense of our intangible assets by business segment for the years indicated: For the Year Ended December 31, 2024 2023 2022 NGL Pipelines & Services $ 44 $ 40 $ 36 Crude Oil Pipelines & Services 100 103 84 Natural Gas Pipelines & Services 56 51 50 Petrochemical & Refined Products Services 7 7 7 Total $ 207 $ 201 $ 177
Forecasted Amortization Expense	The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated: 2025 2026 2027 2028 2029 $ 218 $ 215 $ 209 $ 198 $ 199
Significant Acquired Intangible Assets	At December 31, 2024, the carrying value of our portfolio of customer relationship intangible assets was $2.5 billion, the principal components of which were as follows: a Weighted Average Remaining Amortization Period December 31, 2024 Gross Value Accumulated Amortization Carrying Value Basin-specific customer relationships: EFS Midstream (acquired 2015) 17.4 years $ 1,410 $ (407) $ 1,003 State Line and Fairplay (acquired 2010) 22.2 years 895 (328) 567 San Juan Gathering (acquired 2004) 14.8 years 331 (274) 57 General customer relationships: Oiltanking (acquired 2014) 19.0 years 1,193 (340) 853 At December 31, 2024, the carrying value of our portfolio of contract-based intangible assets was $1.5 billion, the principal components of which were as follows: a Weighted Average Remaining Amortization Period December 31, 2024 Gross Value Accumulated Amortization Carrying Value Midland Basin customer contracts 27.0 years $ 989 $ (77) $ 912 Pinon Midstream customer contracts 24.0 years 435 (2) 433 Jonah natural gas gathering agreements 17.0 years 224 (187) 37 Delaware Basin natural gas processing contracts 1.9 years 82 (58) 24
Schedule of Goodwill	The following table presents changes in the carrying amount of goodwill by business segment during the periods indicated: NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Consolidated Total Balance at December 31, 2022 $ 2,811 $ 1,841 $ – $ 956 $ 5,608 Balance at December 31, 2023 2,811 1,841 – 956 5,608 Goodwill related to acquisition (2) 29 – 75 – 104 Balance at December 31, 2024 $ 2,840 $ 1,841 $ 75 $ 956 $ 5,712 (1) Balances are presented net of historical accumulated impairment losses of $296 million for the Natural Gas Pipelines & Service segment and $1 million for the Petrochemical & Refined Products Services segment. There have been no goodwill impairment charges recognized for the reporting units within the NGL Pipelines & Services and Crude Oil Pipelines & Services segments. (2) This amount represents the goodwill recognized in connection with our acquisition of Pinon Midstream in October 2024. In general, we attribute this goodwill to our ability to expand the acquired sour gas gathering and treating system as well as our ability to leverage the acquired business with our existing NGL asset base to create future business opportunities.

Debt Obligations (Tables)

Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2024
Debt Obligations [Abstract]
Consolidated Debt Obligations	The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated: December 31, 2024 2023 EPO senior debt obligations: Commercial Paper Notes, variable-rates $ – $ 450 Senior Notes JJ, 3.90 – 850 Senior Notes MM, 3.75 1,150 1,150 March 2024 $1.5 Billion 364-Day Revolving Credit Agreement, variable-rate, due March 2025 (1) – – Senior Notes FFF, 5.05 750 750 Senior Notes PP, 3.70 875 875 Senior Notes HHH, 4.60 1,000 – Senior Notes SS, 3.95 575 575 March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement, variable-rate, due March 2028 (2) – – Senior Notes WW, 4.15 1,000 1,000 Senior Notes YY, 3.125 1,250 1,250 Senior Notes AAA, 2.80 1,250 1,250 Senior Notes GGG, 5.35 1,000 1,000 Senior Notes D, 6.875 500 500 Senior Notes III, 4.85 1,000 – Senior Notes H, 6.65 350 350 Senior Notes JJJ, 4.95 1,100 – Senior Notes J, 5.75 250 250 Senior Notes W, 7.55 400 400 Senior Notes R, 6.125 600 600 Senior Notes Z, 6.45 600 600 Senior Notes BB, 5.95 750 750 Senior Notes DD, 5.70 600 600 Senior Notes EE, 4.85 750 750 Senior Notes GG, 4.45 1,100 1,100 Senior Notes II, 4.85 1,400 1,400 Senior Notes KK, 5.10 1,150 1,150 Senior Notes QQ, 4.90 975 975 Senior Notes UU, 4.25 1,250 1,250 Senior Notes XX, 4.80 1,250 1,250 Senior Notes ZZ, 4.20 1,250 1,250 Senior Notes BBB, 3.70 1,000 1,000 Senior Notes DDD, 3.20 1,000 1,000 Senior Notes EEE, 3.30 1,000 1,000 Senior Notes NN, 4.95 400 400 Senior Notes KKK, 5.55 1,400 – Senior Notes CCC, 3.95 1,000 1,000 Total principal amount of senior debt obligations 29,925 26,725 EPO Junior Subordinated Notes C, variable-rate, due June 2067 232 232 EPO Junior Subordinated Notes D, variable-rate, due August 2077 350 350 EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 1,000 1,000 EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 700 700 TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 – 14 Total principal amount of senior and junior debt obligations 32,207 29,021 Other, non-principal amounts (311 ) (273 ) Less current maturities of debt (1,150 ) (1,300 ) Total long-term debt $ 30,746 $ 27,448 (1) Under the terms of the agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200 million to $1.7 billion at EPO’s election provided certain conditions are met). (2) Under the terms of the agreement, EPO may borrow up to $2.7 billion (which may be increased by up to $500 million to $3.2 billion at EPO’s election provided certain conditions are met). (3) Variable rate is reset quarterly and based on 3-month Chicago Mercantile Exchange (“CME”) Term Secured Overnight Financing Rate (“SOFR”) plus (a) a 0.26161% tenor spread adjustment and (b) 2.778%. (4) Variable rate is reset quarterly and based on 3-month CME Term SOFR plus (a) a 0.26161% tenor spread adjustment and (b) 2.986%. (5) Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month CME Term SOFR plus (a) a 0.26161% tenor spread adjustment and (b) 3.033%. (6) Fixed rate of 5.375% through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month CME Term SOFR plus (a) a 0.26161% tenor spread adjustment and (b) 2.57%. (7) Effective July 1, 2023, all series of our junior subordinated notes subject to a variable interest rate replaced the 3-month London Interbank Offered Rate (“LIBOR”) with 3-month CME Term SOFR plus a 0.26161% tenor spread adjustment. (8) In December 2024, an affiliate of Enterprise redeemed all of the $14 million outstanding principal amount of TEPPCO Junior Subordinated Notes at par (i.e. at a redemption price equal to the outstanding principal amount of such notes to be redeemed, plus accrued and unpaid interest thereon) using cash on hand. The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the year ended December 31, 2024: Range of Interest Rates Paid Weighted-Average Interest Rate Paid Commercial Paper Notes 4.68% to 5.50% 5.44% EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes 7.51% to 8.42% 8.23% EPO Junior Subordinated Notes D 7.73% to 8.64% 8.42%
Consolidated Debt Maturities	Scheduled Maturities of Debt The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at December 31, 2024 for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2025 2026 2027 2028 2029 Thereafter Senior Notes $ 29,925 $ 1,150 $ 1,625 $ 1,575 $ 1,000 $ 1,250 $ 23,325 Junior Subordinated Notes 2,282 – – – – – 2,282 Total $ 32,207 $ 1,150 $ 1,625 $ 1,575 $ 1,000 $ 1,250 $ 25,607

Capital Accounts (Tables)

Capital Accounts (Tables)	12 Months Ended
	Dec. 31, 2024
Capital Accounts [Abstract]
Summary of Changes in Outstanding Common Units	The following table summarizes changes in the number of our common units outstanding since December 31, 2021: Common units outstanding at December 31, 2021 2,176,379,587 Common unit repurchases under 2019 Buyback Program (10,166,923 ) Common units issued in connection with the vesting of phantom unit awards, net 4,571,333 Other 22,350 Common units outstanding at December 31, 2022 2,170,806,347 Common unit repurchases under 2019 Buyback Program (7,244,540 ) Common units issued in connection with the vesting of phantom unit awards, net 4,662,539 Other 20,892 Common units outstanding at December 31, 2023 2,168,245,238 Common unit repurchases under 2019 Buyback Program (7,556,210 ) Common units issued in connection with the vesting of phantom unit awards, net 4,990,360 Other 20,574 Common units outstanding at December 31, 2024 2,165,699,962
Summary of Changes in Outstanding Preferred Units	The following table summarizes changes in the number of our preferred units outstanding since December 31, 2021: Preferred units outstanding at December 31, 2021, December 31, 2022 and December 31, 2023 50,412 Paid in-kind distribution to third party 275 Preferred units outstanding at December 31, 2024 50,687
Components of Accumulated Other Comprehensive Income (Loss)	The following tables present the components of accumulated other comprehensive income (loss) as reported on our 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 93 (36 ) – 57 Reclassification of losses (gains) to net income during period (110 ) (5 ) – (115 ) Total other comprehensive income (loss) for period (17 ) (41 ) – (58 ) Accumulated Other Comprehensive Income (Loss), December 31, 2023 154 151 2 307 Other comprehensive income (loss) for period, before reclassifications 115 (2 ) – 113 Reclassification of losses (gains) to net income during period (178 ) (6 ) – (184 ) Total other comprehensive income (loss) for period (63 ) (8 ) – (71 ) Accumulated Other Comprehensive Income (Loss), December 31, 2024 $ 91 $ 143 $ 2 $ 236
Reclassifications out of Accumulated Other Comprehensive Income (Loss) Into Net Income	The following table presents reclassifications of (income) loss out of accumulated other comprehensive income (loss) into net income during the years indicated: For the Year Ended December 31, Losses (gains) on cash flow hedges: Location 2024 2023 Interest rate derivatives Interest expense $ (6 ) $ (5 ) Commodity derivatives Revenue (249 ) (106 ) Commodity derivatives Operating costs and expenses 71 (4 ) Total $ (184 ) $ (115 )
Noncontrolling Interests	The following table presents the components of noncontrolling interests as reported on our Consolidated Balance Sheets at the dates indicated: At December 31, Consolidated Subsidiary 2024 2023 Breviloba LLC (“Breviloba”)(1) $ 423 $ 436 Whitethorn Pipeline Company LLC (“Whitethorn”)(2) – 182 Enterprise Navigator Ethylene Terminal LLC (“ENET”)(3) 245 166 Other (4) 189 302 Total noncontrolling interests in consolidated subsidiaries $ 857 $ 1,086 (1) An affiliate of Kinetik Holdings Inc. owns a noncontrolling equity interest in Breviloba, which owns the Shin Oak NGL Pipeline (2) An affiliate of Western Midstream Partners, LP (“Western Midstream”) previously owned a noncontrolling 20% equity interest in Whitethorn, which owns the Midland-to-Sealy section of our Midland-to-ECHO 1 Pipeline. (3) Navigator Ethylene Terminals LLC owns a noncontrolling 50% equity interest in ENET, which owns our ethylene export terminal located at Morgan’s Point on the Houston Ship Channel. (4) Primarily represents noncontrolling equity interests in NGL fractionation and pipeline businesses.
Declared Quarterly Cash Distribution Rates	The following table presents Enterprise’s declared quarterly cash distribution rates per common unit with respect to the quarter indicated. Actual cash distributions are paid by Enterprise within 45 days after the end of each fiscal quarter. Quarterly Distribution Per Common Unit Record Date Payment Date 2022 1st Quarter $ 0.4650 4/29/2022 5/12/2022 2nd Quarter $ 0.4750 7/29/2022 8/12/2022 3rd Quarter $ 0.4750 10/31/2022 11/14/2022 4th Quarter $ 0.4900 1/31/2023 2/14/2023 2023: 1st Quarter $ 0.4900 4/28/2023 5/12/2023 2nd Quarter $ 0.5000 7/31/2023 8/14/2023 3rd Quarter $ 0.5000 10/31/2023 11/14/2023 4th Quarter $ 0.5150 1/31/2024 2/14/2024 2024 1st Quarter $ 0.5150 4/30/2024 5/14/2024 2nd Quarter $ 0.5250 7/31/2024 8/14/2024 3rd Quarter $ 0.5250 10/31/2024 11/14/2024 4th Quarter $ 0.5350 1/31/2025 2/14/2025

Revenues (Tables)

Revenues (Tables)	12 Months Ended
	Dec. 31, 2024
Revenues [Abstract]
Revenues by Business Segment and Revenue Type	For the Year Ended December 31, 2024 2023 2022 NGL Pipelines & Services: Sales of NGLs and related products $ 17,397 $ 14,846 $ 21,307 Segment midstream services: Natural gas processing and fractionation 1,349 1,278 1,431 Transportation 1,151 1,090 987 Storage and terminals 379 431 534 Total segment midstream services 2,879 2,799 2,952 Total NGL Pipelines & Services 20,276 17,645 24,259 Crude Oil Pipelines & Services: Sales of crude oil 20,389 18,185 17,301 Segment midstream services: Transportation 779 744 807 Storage and terminals 412 407 453 Total segment midstream services 1,191 1,151 1,260 Total Crude Oil Pipelines & Services 21,580 19,336 18,561 Natural Gas Pipelines & Services: Sales of natural gas 1,458 2,373 5,019 Segment midstream services: Transportation 1,546 1,403 1,241 Total segment midstream services 1,546 1,403 1,241 Total Natural Gas Pipelines & Services 3,004 3,776 6,260 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 10,013 7,689 8,003 Segment midstream services: Fractionation and isomerization 371 282 222 Transportation, including marine logistics 663 660 585 Storage and terminals 312 327 296 Total segment midstream services 1,346 1,269 1,103 Total Petrochemical & Refined Products Services 11,359 8,958 9,106 Total consolidated revenues $ 56,219 $ 49,715 $ 58,186
Unbilled Revenue and Deferred Revenue	The following table provides information regarding our contract assets and contract liabilities at the dates indicated: December 31, Contract Asset Location 2024 2023 Unbilled revenue (current amount) Prepaid and other current assets $ 9 $ 11 Total $ 9 $ 11 December 31, Contract Liability Location 2024 2023 Deferred revenue (current amount) Other current liabilities $ 168 $ 193 Deferred revenue (noncurrent) Other long-term liabilities 284 326 Total $ 452 $ 519 The following table presents significant changes in our unbilled revenue and deferred revenue balances during the years indicated: Unbilled Revenue Deferred Revenue Balance at December 31, 2021 $ 15 $ 446 Amount included in opening balance transferred to other accounts during period (1) (15 ) (203 ) Amount recorded during period (2) 155 950 Amounts recorded during period transferred to other accounts (1) (149 ) (687 ) Other changes – (5 ) Balance at December 31, 2022 $ 6 $ 501 Amount included in opening balance transferred to other accounts during period (1) (6 ) (271 ) Amount recorded during period (2) 81 956 Amounts recorded during period transferred to other accounts (1) (70 ) (656 ) Other changes – (11 ) Balance at December 31, 2023 $ 11 $ 519 Amount included in opening balance transferred to other accounts during period (1) (11 ) (242 ) Amount recorded during period (2) 79 853 Amounts recorded during period transferred to other accounts (1) (70 ) (672 ) Other changes – (6 ) Balance at December 31, 2024 $ 9 $ 452 (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	Period Fixed Consideration One Year Ended December 31, 2025 $ 4,077 One Year Ended December 31, 2026 3,791 One Year Ended December 31, 2027 3,537 One Year Ended December 31, 2028 3,085 One Year Ended December 31, 2029 2,256 Thereafte r 9,238 Total $ 25,984

Business Segments and Related_2

Business Segments and Related Information (Tables)	12 Months Ended
	Dec. 31, 2024
Business Segments [Abstract]
Measurement of Total Segment Gross Operating Margin	The following table presents a reconciliation of total segment gross operating margin to income before income taxes for the years indicated: For the Year Ended December 31, 2024 2023 2022 Total segment gross operating margin $ 10,018 $ 9,376 $ 9,356 Adjustments to reconcile total segment gross operating margin to income before income taxes (addition or subtraction indicated by sign): Depreciation, amortization and accretion expense in operating costs and expenses (1) (2,343 ) (2,215 ) (2,107 ) Asset impairment charges in operating costs and expenses (57 ) (30 ) (53 ) Net gains (losses) attributable to asset sales and related matters in operating costs and expenses (2 ) 10 (1 ) General and administrative costs (244 ) (231 ) (241 ) Non-refundable payments received from shippers attributable to make-up rights (2) (75 ) (52 ) (144 ) Subsequent recognition of revenues attributable to make-up rights (3) 41 71 97 Total other expense, net (4) (1,303 ) (1,228 ) (1,210 ) Income before income taxes $ 6,035 $ 5,701 $ 5,697 (1) Excludes amortization of major maintenance costs for reaction-based plants and amortization of finance lease right-of-use assets, 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. (4) As presented on our Statements of Consolidated Operations, Total other expense, net is comprised of Interest expense, Interest income and Other, net.
Information by Business Segments	The following tables present segment revenues and significant segment expenses by segment, together with a reconciliation to segment gross operating margin, for the periods indicated: For the Year Ended December 31, 2024 NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Segment Total Segment revenues: Revenues from third parties $ 20,264 $ 21,546 $ 2,992 $ 11,359 $ 56,161 Revenues from related parties 12 34 12 – 58 Intersegment and intrasegment revenues 48,822 54,415 667 25,352 129,256 Total segment revenues 69,098 75,995 3,671 36,711 185,475 Significant segment expenses: Cost of sales 61,260 74,098 1,656 33,755 170,769 Variable operating costs and expenses (1) 745 132 73 373 1,323 Fixed operating costs and expenses (2) 1,682 414 676 1,048 3,820 Total significant segment expenses 63,687 74,644 2,405 35,176 175,912 Other segment income (expense): Equity in income of unconsolidated affiliates 117 285 5 1 408 Other segment items (3) 20 10 6 11 47 Total other segment income (expense), net 137 295 11 12 455 Total segment gross operating margin $ 5,548 $ 1,646 $ 1,277 $ 1,547 $ 10,018 Other financial information: Capital expenditures $ 2,498 $ 161 $ 932 $ 953 $ 4,544 (1) Variable operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally fluctuate based on utilization. (2) Fixed operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally remain constant independent of utilization. (3) Other segment items for each segment primarily represent the following: • NGL Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights, and other segment expenses. • Crude Oil Pipelines & Services – Other segment expenses. • Natural Gas Pipelines & Services – Other segment expenses. • Petrochemical & Refined Products Services – Other segment expenses. For the Year Ended December 31, 2023 NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Segment Total Segment revenues: Revenues from third parties $ 17,635 $ 19,300 $ 3,761 $ 8,958 $ 49,654 Revenues from related parties 10 36 15 – 61 Intersegment and intrasegment revenues 45,490 57,122 527 18,882 122,021 Total segment revenues 63,135 76,458 4,303 27,840 171,736 Significant segment expenses: Cost of sales 56,143 74,437 2,583 24,810 157,973 Variable operating costs and expenses (1) 741 191 59 397 1,388 Fixed operating costs and expenses (2) 1,589 403 595 877 3,464 Total significant segment expenses 58,473 75,031 3,237 26,084 162,825 Other segment income (expense): Equity in income of unconsolidated affiliates 133 320 6 3 462 Other segment items (3) 103 (40 ) 5 (65 ) 3 Total other segment income (expense), net 236 280 11 (62 ) 465 Total segment gross operating margin $ 4,898 $ 1,707 $ 1,077 $ 1,694 $ 9,376 Other financial information: Capital expenditures $ 1,366 $ 119 $ 793 $ 988 $ 3,266 (1) Variable operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally fluctuate based on utilization. (2) Fixed operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally remain constant independent of utilization. (3) Other segment items for each segment primarily represent the following: • NGL Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights, and other segment expenses. • Crude Oil Pipelines & Services – Subsequent recognition of revenues attributable to make-up rights. • Natural Gas Pipelines & Services – Other segment expenses. • Petrochemical & Refined Products Services – Other segment expenses. For the Year Ended December 31, 2022 NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Segment Total Segment revenues: Revenues from third parties $ 24,244 $ 18,548 $ 6,229 $ 9,106 $ 58,127 Revenues from related parties 15 13 31 – 59 Intersegment and intrasegment revenues 65,760 46,625 888 18,304 131,577 Total segment revenues 90,019 65,186 7,148 27,410 189,763 Significant segment expenses: Cost of sales 82,957 63,325 5,532 24,556 176,370 Variable operating costs and expenses (1) 769 173 54 473 1,469 Fixed operating costs and expenses (2) 1,412 386 532 804 3,134 Total significant segment expenses 85,138 63,884 6,118 25,833 180,973 Other segment income (expense): Equity in income of unconsolidated affiliates 149 308 5 2 464 Other segment items (3) 112 45 7 (62 ) 102 Total other segment income (expense), net 261 353 12 (60 ) 566 Total segment gross operating margin $ 5,142 $ 1,655 $ 1,042 $ 1,517 $ 9,356 Other financial information: Capital expenditures $ 624 $ 84 $ 344 $ 912 $ 1,964 (1) Variable operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally fluctuate based on utilization. (2) Fixed operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally remain constant independent of utilization. (3) Other segment items for each segment primarily represent the following: • NGL Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights, and other segment expenses. • Crude Oil Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights, and other segment expenses. • Natural Gas Pipelines & Services – Other segment expenses. • Petrochemical & Refined Products Services – Other segment expenses. The following table reconciles total segment revenues as reported in the preceding tables to consolidated revenues as presented on our Statements of Consolidated Operations: For the Year Ended December 31, 2024 2023 2022 Segment revenues: NGL Pipelines & Services $ 69,098 $ 63,135 $ 90,019 Crude Oil Pipelines & Services 75,995 76,458 65,186 Natural Gas Pipelines & Services 3,671 4,303 7,148 Petrochemical & Refined Products Services 36,711 27,840 27,410 Total segment revenues 185,475 171,736 189,763 Elimination of intersegment and intrasegment revenues (129,256 ) (122,021 ) (131,577 ) Total consolidated revenues $ 56,219 $ 49,715 $ 58,186 The following table presents our segment assets, together with a reconciliation to our consolidated total assets, at the dates indicated: December 31, 2024 2023 NGL Pipelines & Services $ 21,900 $ 21,792 Crude Oil Pipelines & Services 11,390 11,822 Natural Gas Pipelines & Services 12,260 11,210 Petrochemical & Refined Products Services 11,350 10,443 Total segment assets 56,900 55,267 Construction in progress 4,138 2,245 Current assets 15,133 12,248 Other assets 997 1,222 Consolidated total assets $ 77,168 $ 70,982
Consolidated Revenues and Expenses	The following table presents additional information regarding our consolidated revenues and costs and expenses for the years indicated: For the Year Ended December 31, 2024 2023 2022 Consolidated revenues: NGL Pipelines & Services $ 20,276 $ 17,645 $ 24,259 Crude Oil Pipelines & Services 21,580 19,336 18,561 Natural Gas Pipelines & Services 3,004 3,776 6,260 Petrochemical & Refined Products Services 11,359 8,958 9,106 Total consolidated revenues $ 56,219 $ 49,715 $ 58,186 Consolidated costs and expenses: Operating costs and expenses: Cost of sales $ 42,580 $ 37,023 $ 45,836 Other operating costs and expenses (1) 4,004 3,695 3,454 Depreciation, amortization and accretion 2,402 2,279 2,158 Impairment of assets other than goodwill 57 30 53 Ne t losses (g 2 (10 ) 1 General and administrative costs 244 231 241 Total consolidated costs and expenses $ 49,289 $ 43,248 $ 51,743 (1) Represents the cost of operating our plants, pipelines and other fixed assets excluding: depreciation, amortization and accretion; asset impairment charges; and net losses (gains) attributable to asset sales and related matters.

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2024
Earnings Per Unit [Abstract]
Basic and Diluted Earnings Per Unit	The following table presents our calculation of basic and diluted earnings per common unit for the years indicated: For the Year Ended December 31, 2024 2023 2022 BASIC EARNINGS PER COMMON UNIT Net income attributable to common unitholders $ 5,897 $ 5,529 $ 5,487 Earnings allocated to phantom unit awards (1) (56 ) (50 ) (46 ) Net income allocated to common unitholders $ 5,841 $ 5,479 $ 5,441 Basic weighted-average number of common units outstanding 2,169 2,172 2,178 Basic earnings per common unit $ 2.69 $ 2.52 $ 2.50 DILUTED EARNINGS PER COMMON UNIT Net income attributable to common unitholders $ 5,897 $ 5,529 $ 5,487 Net income attributable to preferred units 4 3 3 Net income attributable to limited partners $ 5,901 $ 5,532 $ 5,490 Diluted weighted-average number of units outstanding: Distribution-bearing common units 2,169 2,172 2,178 Phantom units (2) 21 20 19 Preferred units (2) 2 2 2 Total 2,192 2,194 2,199 Diluted earnings per common unit $ 2.69 $ 2.52 $ 2.50 (1) Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding phantom units. (2) We use the “if-converted method” to determine the potential dilutive effect of the vesting of phantom unit awards and the conversion of preferred units outstanding. See Note 8 for information regarding preferred units.

Business Combinations (Tables)

Business Combinations (Tables)	12 Months Ended
	Dec. 31, 2024
Business Combinations [Abstract]
Allocation of Total Purchase Prices Paid in Connection with Business Combinations	The following table presents the preliminary fair value allocation of assets acquired and liabilities assumed in the acquisition at October 28, 2024 (the effective date of the acquisition). The allocation is provisional and subject to ongoing efforts to clarify the values assigned to tangible and identifiable intangible assets. Purchase price for 100% interest in Pinon Midstream $ 953 Recognized amounts of identifiable assets acquired and liabilities assumed (1): Cash and cash equivalents $ 4 Property, plant and equipment 410 Contract-based intangible asset 435 Total identifiable net assets $ 849 Goodwill $ 104 (1) As part of this transaction, we acquired other assets and assumed liabilities that net to a negligible amount. Acquired other assets primarily included accounts receivable and ROU assets. Assumed liabilities primarily included accounts payable and operating lease liabilities. None of these amounts were considered individually significant. The following table summarizes the final fair value allocation of assets acquired and liabilities assumed in the acquisition at February 17, 2022 (the effective date of the acquisition). Purchase price for 100% interest in Navitas Midstream $ 3,231 Recognized amounts of identifiable assets acquired and liabilities assumed: Cash and cash equivalents $ 27 Property, plant and equipment 2,080 Contract-based intangible asset 989 Assumed liabilities, net of acquired other assets (1) (24 ) Total identifiable net assets $ 3,072 Goodwill $ 159 (1) Assumed liabilities primarily include accounts payable, other current liabilities, lease liabilities and asset retirement obligations. Acquired other assets primarily include accounts receivable, other current assets and ROU assets. None of these amounts were considered individually significant.

Equity-Based Awards (Tables)

Equity-Based Awards (Tables)	12 Months Ended
	Dec. 31, 2024
Equity-based Awards [Abstract]
Equity-based Award Expense	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 years indicated: For the Year Ended December 31, 2024 2023 2022 Equity-classified awards: Phantom unit awards $ 178 $ 166 $ 153 Profits interest awards 10 6 4 Total $ 188 $ 172 $ 157
Other Share-based Compensation Plans	The following table presents phantom unit award activity for the years indicated: Number of Units Weighted- Average Grant Date Fair Value per Unit Phantom unit awards at December 31, 2021 17,170,919 $ 24.31 Granted (2) 7,968,880 $ 24.11 Vested (6,616,741 ) $ 25.08 Forfeited (540,113 ) $ 23.92 Phantom unit awards at December 31, 2022 17,982,945 $ 23.94 Granted (3) 8,904,445 $ 25.80 Vested (6,786,085 ) $ 24.81 Forfeited (544,054 ) $ 24.52 Phantom unit awards at December 31, 2023 19,557,251 $ 24.47 Granted (4) 8,881,820 $ 26.25 Vested (7,304,071 ) $ 24.51 Forfeited (542,749 ) $ 25.39 Phantom unit awards at December 31, 2024 20,592,251 $ 25.21 (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 2022 was $192 million based on a grant date market price of the Partnership’s common units ranging from $24.10 to $26.62 per unit. An estimated annual forfeiture rate of 2.1% was applied to these awards. (3) The aggregate grant date fair value of phantom unit awards issued during 2023 was $230 million based on a grant date market price of the Partnership’s common units ranging from $25.80 to $26.70 per unit. An estimated annual forfeiture rate of 2.0% was applied to these awards. (4) The aggregate grant date fair value of phantom unit awards issued during 2024 was $233 million based on a grant date market price of the Partnership’s common units ranging from $26.25 to $29.64 per unit. An estimated annual forfeiture rate of 2.0% was applied to these awards. The following table presents supplemental information regarding phantom unit awards for the years indicated: For the Year Ended December 31, 2024 2023 2022 Cash payments made in connection with DERs $ 43 $ 38 $ 34 Total intrinsic value of phantom unit awards that vested during period $ 199 $ 182 $ 160

Hedging Activities and Fair V_2

Hedging Activities and Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2024
Hedging Activities and Fair Value Measurements [Abstract]
Hedging Instruments Under the FASB's Derivative and Hedging Guidance	The following table summarizes our portfolio of commodity derivative instruments outstanding at December 31, 2024 (volume measures as noted): Volume Accounting Derivative Purpose Current Long-Term Treatment Derivatives designated as hedging instruments: Natural gas processing: Forecasted sales of natural gas (Bcf) 37.7 36.5 Cash flow hedge Forecasted sales of NGLs (MMBbls) 3.2 n/a Cash flow hedge Octane enhancement: Forecasted sales of octane enhancement products (MMBbls) 3.8 0.1 Cash flow hedge Natural gas marketing: 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) 134.0 5.8 Cash flow hedge Forecasted sales of NGLs and related hydrocarbon products (MMBbls) 148.5 4.8 Cash flow hedge Refined products marketing: Forecasted sales of refined products (MMBbls) 0.1 n/a Cash flow hedge Crude oil marketing: Forecasted purchases of crude oil (MMBbls) 13.3 5.0 Cash flow hedge Forecasted sales of crude oil (MMBbls) 22.4 10.3 Cash flow hedge Petrochemical marketing: Forecasted sales of petrochemical products (MMBbls) 0.9 n/a Cash flow hedge Commercial energy: Forecasted purchases of power related to asset operations (terawatt hours (“TWh”)) 1.5 n/a Cash flow hedge Derivatives not designated as hedging instruments: Natural gas risk management activities (Bcf) (3) 16.6 n/a Mark-to-market NGL risk management activities (MMBbls) (3) 38.9 22.8 Mark-to-market Refined products risk management activities (MMBbls) (3) 7.2 n/a Mark-to-market Crude oil risk management activities (MMBbls) (3) 168.3 n/a Mark-to-market Commercial energy risk management activities (TWh) (3) 0.1 11.1 Mark-to-market (1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes. (2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2027, May 2025 and December 2027, respectively. (3) Reflects the use of derivative instruments to manage risks associated with our transportation, processing and storage assets.
Derivative Assets and Liabilities Balance Sheet	The following table provides a balance sheet overview of our derivative assets and liabilities at the dates indicated: Asset Derivatives Liability Derivatives December 31, 2024 December 31, 2023 December 31, 2024 December 31, 2023 Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedging instruments Interest rate derivatives Current assets $ – Current assets $ – Current liabilities $ – Current liabilities $ 31 Commodity derivatives Current assets $ 210 Current assets $ 118 Current liabilities $ 178 Current liabilities $ 136 Commodity derivatives Other assets 22 Other assets 31 Other liabilities 4 Other liabilities 35 Total commodity derivatives 232 149 182 171 Total derivatives designated as hedging instruments $ 232 $ 149 $ 182 $ 202 Derivatives not designated as hedging instruments Commodity derivatives Current assets $ 324 Current assets $ 229 Current liabilities $ 293 Current liabilities $ 229 Commodity derivatives Other assets 19 Other assets 72 Other liabilities 20 Other liabilities 71 Total commodity derivatives 343 301 313 300 Total derivatives not designated as hedging instruments $ 343 $ 301 $ 313 $ 300
Offsetting Financial Assets	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 Not Offset in the Balance Sheet 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 December 31, 2024: Commodity derivatives $ 575 $ – $ 575 $ (495 ) $ (79 ) $ – $ 1 As of December 31, 2023 Commodity derivatives $ 450 $ – $ 450 $ (450 ) $ – $ – $ –
Offsetting Financial Liabilities	Offsetting of Financial Liabilities and Derivative Liabilities Gross Amounts Not Offset in the Balance Sheet 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 December 31, 2024 Commodity derivatives $ 495 $ – $ 495 $ (495 ) $ – $ – $ – As of December 31, 2023 Interest rate derivatives $ 31 $ – $ 31 $ – $ – $ – $ 31 Commodity derivatives 471 – 471 (450 ) 1 (21 ) 1
Derivative Instruments Effects on Statements of Operations	The following tables present the effect of our derivative instruments designated as fair value hedges on our Statements of Consolidated Operations for the years indicated: Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Derivative For the Year Ended December 31, 2024 2023 2022 Commodity derivatives Revenue $ 2 $ 7 $ (103 ) Total $ 2 $ 7 $ (103 ) Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Hedged Item For the Year Ended December 31, 2024 2023 2022 Commodity derivatives Revenue $ 9 $ (7 ) $ 66 Total $ 9 $ (7 ) $ 66
Derivative Instruments Effects on Statements of Comprehensive Income	The following tables present the effect of our derivative instruments designated as cash flow hedges on our Statements of Consolidated Operations and Statements of Consolidated Comprehensive Income for the years indicated: Derivatives in Cash Flow Hedging Relationships Change in Value Recognized in Other Comprehensive Income (Loss) On Derivative For the Year Ended December 31, 2024 2023 2022 Interest rate derivatives $ (2 ) $ (36 ) $ 26 Commodity derivatives – Revenue (1) 182 81 227 Commodity derivatives – Operating costs and expenses (1) (67 ) 12 27 Total $ 113 $ 57 $ 280 (1) The fair value of these derivative instruments will be reclassified to their respective locations on the Statement of Consolidated Operations when the forecasted transactions affect earnings.
Gain/(Loss) Reclassified from Accumulated Other Comprehensive Income/(Loss) to Income	Derivatives in Cash Flow Hedging Relationships Location Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income For the Year Ended December 31, 2024 2023 2022 Interest rate derivatives Interest expense $ 6 $ 5 $ (19 ) Commodity derivatives Revenue 249 106 181 Commodity derivatives Operating costs and expenses (71 ) 4 39 Total $ 184 $ 115 $ 201
Gain/(Loss) Recognized in Income on Derivative	The following table presents the effect of our derivative instruments not designated as hedging instruments on our Statements of Consolidated Operations for the years indicated: Derivatives Not Designated as Hedging Instruments Location Gain (Loss) Recognized in Income on Derivative For the Year Ended December 31, 2024 2023 2022 Commodity derivatives Revenue $ 26 $ 213 $ 74 Commodity derivatives Operating costs and expenses (4 ) – 14 Total $ 22 $ 213 $ 88
Unrealized mark-to-market gains (losses)	In total and inclusive of both fair value hedges and derivatives not designated as hedging instruments, unrealized mark-to-market gains (losses) included in gross operating margin were as follows for the years indicated: For the Year Ended December 31, 2024 2023 2022 Mark-to-market gains (losses) in gross operating margin: NGL Pipelines & Services $ (8 ) $ (25 ) $ (52 ) Crude Oil Pipelines & Services 21 (5 ) (30 ) Natural Gas Pipelines & Services 5 (1 ) (3 ) Petrochemical & Refined Products Services 2 (2 ) 7 Total mark-to-market impact on gross operating margin $ 20 $ (33 ) $ (78 )
Fair Value Measurements of Financial Assets and Liabilities Measured on a Recurring Basis	At December 31, 2024 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Financial assets: Commodity derivatives: Value before application of CME Rule 814 $ 355 $ 443 $ – $ 798 Impact of CME Rule 814 (56 ) (167 ) – (223 ) Total commodity derivatives 299 276 – 575 Total $ 299 $ 276 $ – $ 575 Financial liabilities: Commodity derivatives: Value before application of CME Rule 814 $ 291 $ 404 $ 21 $ 716 Impact of CME Rule 814 (43 ) (157 ) (21 ) (221 ) Total commodity derivatives 248 247 – 495 Total $ 248 $ 247 $ – $ 495 At December 31, 2023 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Financial assets: Commodity derivatives: Value before application of CME Rule 814 $ 431 $ 297 $ – $ 728 Impact of CME Rule 814 (147 ) (131 ) – (278 ) Total commodity derivatives 284 166 – 450 Total $ 284 $ 166 $ – $ 450 Financial liabilities: Interest rate derivatives: $ – $ 31 $ – $ 31 Commodity derivatives: Value before application of CME Rule 814 317 308 – 625 Impact of CME Rule 814 (22 ) (132 ) – (154 ) Total commodity derivatives 295 176 – 471 Total $ 295 $ 207 $ – $ 502

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2024
Related Party Transactions [Abstract]
Related Party Transactions	The following table summarizes our related party transactions for the years indicated: For the Year Ended December 31, 2024 2023 2022 Revenues – related parties: Unconsolidated affiliates $ 58 $ 61 $ 59 Costs and expenses – related parties: EPCO and its privately held affiliates $ 1,472 $ 1,353 $ 1,289 Unconsolidated affiliates 185 188 209 Total $ 1,657 $ 1,541 $ 1,498 The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated: December 31, 2024 2023 Accounts receivable - related parties: Unconsolidated affiliates $ 4 $ 7 Accounts payable - related parties: EPCO and its privately held affiliates $ 180 $ 183 Unconsolidated affiliates 18 16 Total $ 198 $ 199 At December 31, 2024, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us: Total Number of Limited Partner Interests Held Percentage of Common Units Outstanding 701,938,819 common units 32.4% The following table presents our related party costs and expenses attributable to the ASA with EPCO for the years indicated: For the Year Ended December 31, 2024 2023 2022 Operating costs and expenses $ 1,294 $ 1,189 $ 1,124 General and administrative expenses 152 141 146 Total costs and expenses $ 1,446 $ 1,330 $ 1,270

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2024
Income Taxes [Abstract]
Federal and State Income Tax Provision	Our federal, state and foreign income tax benefit (provision) is summarized below: For the Year Ended December 31, 2024 2023 2022 Current portion of income tax provision: Federal $ (2 ) $ (12 ) $ (2 ) State (18 ) (20 ) (18 ) Foreign – – (2 ) Total current portion (20 ) (32 ) (22 ) Deferred portion of income tax provision: Federal (16 ) 17 (20 ) State (28 ) (29 ) (40 ) Foreign (1 ) – – Total deferred portion (45 ) (12 ) (60 ) Total provision for income taxes $ (65 ) $ (44 ) $ (82 )
Reconciliation of Provision for Income Taxes	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 Year Ended December 31, 2024 2023 2022 Pre-Tax Net Book Income (“NBI”) $ 6,035 $ 5,701 $ 5,697 Texas Margin Tax (1) (44 ) (49 ) (56 ) State income tax provision, net of federal benefit (2 ) (2 ) (1 ) Federal income tax provision computed by applying the federal statutory rate to NBI of corporate entities (17 ) (16 ) (15 ) Change in valuation allowance (2) – 22 (8 ) Other (2 ) 1 (2 ) Provision for income taxes $ (65 ) $ (44 ) $ (82 ) Effective income tax rate (1.1 )% (0.8 )% (1.4 )% (1) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses. (2) During 2023, management concluded that it is more likely than not that the deferred tax assets attributable to OTA will be fully realizable. As a result, for the year-end December 31, 2023, we recorded a full release of the valuation allowance against OTA’s deferred tax assets.
Components of Deferred Tax Assets and Liabilities	The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated: December 31, 2024 2023 Deferred tax liabilities: Attributable to investment in OTA (1) $ 462 $ 436 Attributable to property, plant and equipment 151 138 Attributable to investments in other entities 5 4 Other 98 83 Total deferred tax liabilities 716 661 Deferred tax assets: Net operating loss carryovers (2) 56 46 Temporary differences related to Texas Margin Tax 4 4 Total deferred tax assets 60 50 Total net deferred tax liabilities $ 656 $ 611 (1) Represents the deferred tax liability balance held by our wholly owned subsidiary, OTA, which we acquired in March 2020. (2) The loss amount presented as of December 31, 2024 has an indefinite carryover period. All losses are subject to limitations on their utilization.

Commitments and Contingent Li_2

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies [Abstract]
Summary of Contractual Obligations	The following table summarizes our various contractual obligations at December 31, 2024. A description of each type of contractual obligation follows: Payment or Settlement due by Period Contractual Obligations Total 2025 2026 2027 2028 2029 Thereafter Scheduled maturities of debt obligations $ 32,207 $ 1,150 $ 1,625 $ 1,575 $ 1,000 $ 1,250 $ 25,607 Estimated cash interest payments $ 28,769 $ 1,476 $ 1,407 $ 1,338 $ 1,323 $ 1,272 $ 21,953 Operating lease obligations (1) $ 561 $ 121 $ 91 $ 54 $ 37 $ 30 $ 228 Finance lease obligations $ 4 $ 1 $ 1 $ 1 $ 1 $ – $ – Purchase obligations: Product purchase commitments: Estimated payment obligations: NGLs $ 1,322 $ 275 $ 248 $ 239 $ 205 $ 158 $ 197 Crude oil $ 7,197 $ 1,872 $ 1,584 $ 1,490 $ 1,177 $ 760 $ 314 Other $ 14 $ 2 $ 2 $ 2 $ 2 $ 2 $ 4 Service payment commitments $ 307 $ 46 $ 40 $ 40 $ 27 $ 22 $ 132 Capital expenditure commitments $ 99 $ 99 $ – $ – $ – $ – $ – (1) As of December 31, 2024, the difference between the total payments for operating lease obligations and the carrying value of our operating lease liabilities, which represents the present value of future operating lease payments, was $90 million.
Operating and Finance Leases	The following table presents information regarding operating and finance leases where we are the lessee at December 31, 2024: Asset Category ROU Asset Carrying Value Lease Liability Carrying Value Weighted- Average Remaining Term Weighted- Average Discount Rate Operating leases Storage and pipeline facilities $ 222 $ 222 8 years 4.5% Transportation equipment 43 44 4 years 4.8% Office and warehouse space 170 205 12 years 3.4% Total operating leases 435 471 Finance leases Transportation equipment 4 4 4 years 4.7% Total finance leases 4 4 Total leases $ 439 $ 475 (1) ROU asset amounts are a component of “ Other assets (2) At December 31, 2024, operating lease liabilities of $105 million and $366 million were included within “ Other current liabilities ” and “ Other long-term liabilities ,” Other current liabilities Other long-term liabilities (3) The discount rate for each category of assets represents the weighted average incremental borrowing rate adjusted for collateralization (if the implicit rate is not determinable). In general, the discount rates are based on either (i) information available at the lease commencement date or (ii) January 1, 2019 for leases existing at the adoption date for ASC 842.
Consolidated Lease Expense	The following table disaggregates our total operating and finance lease expense for the years indicated: For the Year Ended December, 2024 2023 2022 Long-term leases: Fixed operating lease expense: Non-cash lease expense (amortization of ROU assets) $ 95 $ 72 $ 59 Related accretion expense on lease liability balances 17 14 12 Total fixed operating lease expense 112 86 71 Fixed finance lease expense: Amortization of ROU assets (1) – * – – Interest on finance lease liabilities (1) – * – – Total fixed finance lease expense (1) – * – – Variable lease expense 17 13 6 Total long-term lease expense 129 99 77 Short-term leases 121 111 91 Total lease expense $ 250 $ 210 $ 168 (1) For the year ended December 31, 2024, total fixed finance lease expense, which include amortization of finance lease ROU assets and interest on finance lease liabilities, was less than $1 million. * Amount is negligible.
Schedule of Other Liabilities	The following table summarizes the components of “Other long-term liabilities” as presented on our Consolidated Balance Sheets at the dates indicated: December 31, 2024 2023 Noncurrent portion of AROs (see Note 4) $ 259 $ 221 Deferred revenues – non-current portion (see Note 9) 284 326 Operating lease liability – non-current portion 366 323 Derivative liabilities 24 106 Other 17 8 Total $ 950 $ 984

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2024
Supplemental Cash Flow Information [Abstract]
Net Effect of Changes in Operating Assets and Liabilities	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 years indicated: For the Year Ended December 31, 2024 2023 2022 Decrease (increase) in: Accounts receivable – trade $ (1,453 ) $ (810 ) $ 108 Accounts receivable – related parties 2 4 10 Inventories (598 ) (714 ) 131 Prepaid and other current assets (152 ) (651 ) (97 ) Other assets 38 31 (42 ) Increase (decrease) in: Accounts payable – trade (182 ) 309 (174 ) Accounts payable – related parties (1 ) (33 ) 65 Accrued product payables 1,867 849 (190 ) Accrued interest 81 29 (26 ) Other current liabilities 15 484 124 Other long-term liabilities (123 ) (53 ) 37 Net effect of changes in operating accounts $ (506 ) $ (555 ) $ (54 ) Cash payments for interest, net of $ 121 106 90 capitalized in 2024 2023 2022 $ 1,255 $ 1,228 $ 1,232 Cash payments for federal and state income taxes $ 20 $ 24 $ –
Schedule of Significant Acquisitions and Disposals	The following table presents our cash proceeds from asset sales and other matters for the years indicated: For the Year Ended December 31, 2024 2023 2022 Recovery of construction costs (1) $ – $ 25 $ 99 Other asset sales 14 17 23 Total $ 14 $ 42 $ 122 (1) Amounts presented reflect the portion of cash receipts from the settlement of claims attributable to the partial recovery of construction costs incurred on the associated capital project.

Partnership Organization and _2

Partnership Organization and Operations (Details)	12 Months Ended
	Dec. 31, 2024 Segment
Related Party Transaction [Line Items]
Number of reportable segments	4
EPCO and its privately held affiliates [Member] | Common Units [Member]
Related Party Transaction [Line Items]
Percentage of total units outstanding	32.40%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash, Cash Equivalents and Restricted Cash:
Cash and cash equivalents	$ 583	$ 180
Restricted cash	255	140
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows	838	320	$ 206	$ 2,965
Allowance for Credit Losses [Member]
Movement in valuation allowances and reserves [Roll Forward]
Balance at beginning of period	35	54	53
Charged to costs and expenses	3	1	6
Charged to other accounts	0	0	1
Deductions	0	(20)	(6)
Balance at end of period	$ 38	$ 35	$ 54
Minor Investment [Member] | Minimum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest	3%
Minor Investment [Member] | Maximum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest	50%
Major Investment [Member] | Minimum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest	20%
Major Investment [Member] | Maximum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest	50%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies, Part 2 (Details)	12 Months Ended
	Dec. 31, 2024
Current Assets and Current Liabilities [Abstract]
Threshold for components of total current assets and current liabilities to be presented as an individual caption on Consolidated Balance Sheet	5%
Minimum [Member]
Derivative Instruments [Abstract]
Expected offset percentage of change in fair value derivative instrument	80%
Maximum [Member]
Derivative Instruments [Abstract]
Expected offset percentage of change in fair value derivative instrument	125%

Summary of Significant Accoun_6

Summary of Significant Accounting Policies, Part 3 (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Environmental Reserves [Abstract]
Environmental reserves		$ 9	$ 4
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment		50	20	$ 41
Impairment charges in operating costs and expenses		57	30	53
Total asset impairment charges		57	32	53
Operating costs and expenses [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment		50	18	41
Other impairments	[1]	7	12	12
Impairment charges in operating costs and expenses	[2]	57	30	53
General and administrative costs [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	[3]	$ 0	$ 2	$ 0
[1]Primarily represents the write-down of surplus materials classified as “Other assets” on our Consolidated Balance Sheets.[2]Amounts presented are a component of “Third party and other costs” within the “Operating costs and expenses” section of our Statements of Consolidated Operations.[3]Amounts presented are a component of “Third party and other costs” within the “General and administrative costs” section of our Statements of Consolidated Operations.

Inventories (Details)

Inventories (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Inventory by Product Type [Abstract]
NGLs		$ 2,768	$ 2,392
Petrochemicals and refined products		652	536
Crude oil		523	419
Natural gas		12	5
Total		3,955	3,352
Summary of cost of sales and lower of cost or net realizable value adjustments [Abstract]
Cost of sales	[1]	42,580	37,023	$ 45,836
Lower of cost or net realizable value adjustments recognized in cost of sales		$ 9	$ 31	$ 19
[1]Cost of sales is a component of “Operating costs and expenses,” as presented on our 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.

Property, Plant and Equipment_2

Property, Plant and Equipment (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross		$ 71,203	$ 66,217
Less accumulated depreciation		22,330	20,462
Subtotal property, plant, and equipment, net		48,873	45,755
Capitalized major maintenance costs for reaction-based plants, net of accumulated amortization	[1]	189	49
Property, plant and equipment, net		49,062	45,804
Summary of depreciation expense and capitalized interest [Abstract]
Depreciation expense	[2]	1,974	1,860	$ 1,779
Capitalized interest	[3]	121	106	90
Asset Retirement Obligations [Roll Forward]
ARO liability beginning balance		225	234	176
Liabilities incurred	[4]	1	5	20
Revisions in estimated cash flows	[5]	30	(12)	30
Liabilities settled	[6]	(4)	(13)	(10)
Accretion expense	[7]	13	11	18
ARO liability ending balance		265	225	$ 234
Asset retirement obligation, current liability		6
Asset retirement obligations, long-term liability		259	221
Capitalized costs, asset retirement costs		134	109
Forecasted accretion expense [Abstract]
2025		15
2026		16
2027		17
2028		18
2029		19
Plants, pipelines and facilities [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross	[8]	$ 60,716	57,983
Plants, pipelines and facilities [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[8],[9]	3 years
Plants, pipelines and facilities [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[8],[9]	45 years
Underground and other storage facilities [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross	[10]	$ 4,704	4,401
Underground and other storage facilities [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[10],[11]	5 years
Underground and other storage facilities [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[10],[11]	40 years
Transportation equipment [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross	[12]	$ 272	242
Transportation equipment [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[12]	3 years
Transportation equipment [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[12]	10 years
Marine vessels [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross	[13]	$ 949	935
Marine vessels [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[13]	15 years
Marine vessels [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[13]	30 years
Land [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross		$ 424	411
Construction in progress [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross		$ 4,138	$ 2,245
Distillation-based and reaction-based plants [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		20 years
Distillation-based and reaction-based plants [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		35 years
Pipelines and related equipment [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		5 years
Pipelines and related equipment [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		45 years
Terminal facilities [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		10 years
Terminal facilities [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		35 years
Buildings [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		20 years
Buildings [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		40 years
Office furniture and equipment [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		3 years
Office furniture and equipment [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		20 years
Laboratory and shop equipment [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		5 years
Laboratory and shop equipment [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		35 years
Underground storage facilities [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		5 years
Underground storage facilities [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		35 years
Storage tanks [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		10 years
Storage tanks [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		40 years
Water wells [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		5 years
Water wells [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		35 years
Capitalized Major Maintenance [Member] | Weighted Average [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Expected remaining amortization period		3 years 4 months 24 days
[1]For reaction-based plants, we use the deferral method when accounting for major maintenance activities. Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. On a weighted-average basis, the expected remaining amortization period for these costs is 3.4 years.[2]Depreciation expense is a component of “Third party and other costs” within “Costs and expenses” as presented on our Statements of Consolidated Operations.

Property, Plant and Equipment,

Property, Plant and Equipment, Impairments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	$ 50	$ 20	$ 41
NGL Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	28	12	23
Crude Oil Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	0	1	3
Natural Gas Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	7	5	6
Petrochemical & Refined Products Services [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	$ 15	$ 2	$ 9

Investments in Unconsolidated_3

Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates	$ 2,259	$ 2,330
Equity in income of unconsolidated affiliates by business segment [Abstract]
Equity in income of unconsolidated affiliates	408	462	$ 464
NGL Pipelines & Services [Member]
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates	598	612
Equity in income of unconsolidated affiliates by business segment [Abstract]
Equity in income of unconsolidated affiliates	$ 117	133	149
NGL Pipelines & Services [Member] | Venice Energy Service Company, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	13.10%
Investments in unconsolidated affiliates	$ 24	24
NGL Pipelines & Services [Member] | K/D/S Promix, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	50%
Investments in unconsolidated affiliates	$ 22	25
NGL Pipelines & Services [Member] | Baton Rouge Fractionators LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	32.20%
Investments in unconsolidated affiliates	$ 12	13
NGL Pipelines & Services [Member] | Skelly-Belvieu Pipeline Company, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	50%
Investments in unconsolidated affiliates	$ 25	26
NGL Pipelines & Services [Member] | Texas Express Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	35%
Investments in unconsolidated affiliates	$ 299	303
NGL Pipelines & Services [Member] | Texas Express Gathering LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	45%
Investments in unconsolidated affiliates	$ 33	35
NGL Pipelines & Services [Member] | Front Range Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	33.30%
Investments in unconsolidated affiliates	$ 183	186
Crude Oil Pipelines & Services [Member]
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates	1,628	1,681
Equity in income of unconsolidated affiliates by business segment [Abstract]
Equity in income of unconsolidated affiliates	$ 285	320	308
Crude Oil Pipelines & Services [Member] | Seaway Crude Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	50%
Investments in unconsolidated affiliates	$ 1,147	1,192
Crude Oil Pipelines & Services [Member] | Eagle Ford Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	50%
Investments in unconsolidated affiliates	$ 368	373
Crude Oil Pipelines & Services [Member] | Eagle Ford Terminals Corpus Christi LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	50%
Investments in unconsolidated affiliates	$ 113	116
Natural Gas Pipelines & Services [Member]
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates	30	33
Equity in income of unconsolidated affiliates by business segment [Abstract]
Equity in income of unconsolidated affiliates	$ 5	6	5
Natural Gas Pipelines & Services [Member] | White River Hub, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	50%
Investments in unconsolidated affiliates	$ 16	17
Natural Gas Pipelines & Services [Member] | Old Ocean Pipeline, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	50%
Investments in unconsolidated affiliates	$ 14	16
Petrochemical & Refined Products Services [Member]
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates	3	4
Equity in income of unconsolidated affiliates by business segment [Abstract]
Equity in income of unconsolidated affiliates	$ 1	3	$ 2
Petrochemical & Refined Products Services [Member] | Baton Rouge Propylene Concentrator, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	30%
Investments in unconsolidated affiliates	$ 1	2
Petrochemical & Refined Products Services [Member] | Transport 4, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	25%
Investments in unconsolidated affiliates	$ 2	$ 2

Intangible Assets and Goodwill,

Intangible Assets and Goodwill, Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Identifiable intangible assets [Abstract]
Gross Value	$ 6,339	$ 5,897
Accumulated Amortization	(2,334)	(2,127)
Carrying Value	4,005	3,770
Amortization expense	207	201	$ 177
Forecasted amortization expense [Abstract]
2025	218
2026	215
2027	209
2028	198
2029	199
Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	2,500
Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	1,500
NGL Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,203	1,201
Accumulated Amortization	(417)	(373)
Carrying Value	786	828
Amortization expense	44	40	36
NGL Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	449	449
Accumulated Amortization	(276)	(263)
Carrying Value	173	186
NGL Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	754	752
Accumulated Amortization	(141)	(110)
Carrying Value	613	642
Crude Oil Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	2,478	2,478
Accumulated Amortization	(905)	(805)
Carrying Value	1,573	1,673
Amortization expense	100	103	84
Crude Oil Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	2,195	2,195
Accumulated Amortization	(627)	(530)
Carrying Value	1,568	1,665
Crude Oil Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	283	283
Accumulated Amortization	(278)	(275)
Carrying Value	5	8
Natural Gas Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	2,432	1,992
Accumulated Amortization	(890)	(834)
Carrying Value	1,542	1,158
Amortization expense	56	51	50
Natural Gas Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,351	1,351
Accumulated Amortization	(663)	(625)
Carrying Value	688	726
Natural Gas Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,081	641
Accumulated Amortization	(227)	(209)
Carrying Value	854	432
Petrochemical & Refined Products Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	226	226
Accumulated Amortization	(122)	(115)
Carrying Value	104	111
Amortization expense	7	7	$ 7
Petrochemical & Refined Products Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	181	181
Accumulated Amortization	(92)	(86)
Carrying Value	89	95
Petrochemical & Refined Products Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	45	45
Accumulated Amortization	(30)	(29)
Carrying Value	$ 15	$ 16

Intangible Assets and Goodwil_2

Intangible Assets and Goodwill, Significant Intangible Assets (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($)	Oct. 28, 2024	Dec. 31, 2023 USD ($)	Feb. 17, 2022
Identifiable intangible assets [Abstract]
Gross Value	$ 6,339		$ 5,897
Accumulated Amortization	(2,334)		(2,127)
Carrying Value	4,005		$ 3,770
Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	2,500
Customer relationship intangibles [Member] | EFS Midstream [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,410
Accumulated Amortization	(407)
Carrying Value	$ 1,003
Weighted Average Remaining Amortization Period	17 years 4 months 24 days
Customer relationship intangibles [Member] | State Line and Fairplay [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 895
Accumulated Amortization	(328)
Carrying Value	$ 567
Weighted Average Remaining Amortization Period	22 years 2 months 12 days
Customer relationship intangibles [Member] | San Juan Gathering [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 331
Accumulated Amortization	(274)
Carrying Value	$ 57
Weighted Average Remaining Amortization Period	14 years 9 months 18 days
Customer relationship intangibles [Member] | Oiltanking Partners L.P. [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 1,193
Accumulated Amortization	(340)
Carrying Value	$ 853
Weighted Average Remaining Amortization Period	19 years
Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	$ 1,500
Contract-based intangibles [Member] | Navitas Midstream Partners, LLC [Member]
Identifiable intangible assets [Abstract]
Gross Value	989
Accumulated Amortization	(77)
Carrying Value	$ 912
Weighted Average Remaining Amortization Period	27 years
Estimated useful life of acquired intangible asset	30 years
Contract-based intangibles [Member] | Pinon Midstream, LLC [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 435
Accumulated Amortization	(2)
Carrying Value	$ 433
Weighted Average Remaining Amortization Period	24 years
Estimated useful life of acquired intangible asset	25 years
Contract-based intangibles [Member] | Jonah Gas Gathering [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 224
Accumulated Amortization	(187)
Carrying Value	$ 37
Weighted Average Remaining Amortization Period	17 years
Contract-based intangibles [Member] | Delaware Basin Gas Processing LLC [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 82
Accumulated Amortization	(58)
Carrying Value	$ 24
Weighted Average Remaining Amortization Period	1 year 10 months 24 days
Measurement input, discount rate [Member] | Pinon Midstream, LLC [Member]
Identifiable intangible assets [Abstract]
Long-lived asset, measurement input		0.165
Measurement input, discount rate [Member] | Contract-based intangibles [Member] | Navitas Midstream Partners, LLC [Member]
Identifiable intangible assets [Abstract]
Long-lived asset, measurement input				0.155

Intangible Assets and Goodwil_3

Intangible Assets and Goodwill, Goodwill (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Changes in carrying amount of goodwill [Roll Forward]
Goodwill	[1]	$ 5,712	$ 5,608	$ 5,608
Goodwill related to acquisition	[2]	104
Balance at end of period	[1]	5,712
NGL Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Goodwill	[1]	2,840	2,811	2,811
Goodwill related to acquisition	[2]	29
Balance at end of period	[1]	2,840
Crude Oil Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Goodwill	[1]	1,841	1,841	1,841
Goodwill related to acquisition	[2]	0
Balance at end of period	[1]	1,841
Natural Gas Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Goodwill	[1]	75	0	0
Goodwill related to acquisition	[2]	75
Balance at end of period	[1]	75
Accumulated impairment charges		296
Petrochemical & Refined Products Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Goodwill	[1]	956	$ 956	$ 956
Goodwill related to acquisition	[2]	0
Balance at end of period	[1]	956
Accumulated impairment charges		$ 1
[1]Balances are presented net of historical accumulated impairment losses of $296 million for the Natural Gas Pipelines & Service segment and $1 million for the Petrochemical & Refined Products Services segment.  There have been no goodwill impairment charges recognized for the reporting units within the NGL Pipelines & Services and Crude Oil Pipelines & Services segments.[2]This amount represents the goodwill recognized in connection with our acquisition of Pinon Midstream in October 2024.  In general, we attribute this goodwill to our ability to expand the acquired sour gas gathering and treating system as well as our ability to leverage the acquired business with our existing NGL asset base to create future business opportunities.

Debt Obligations (Details)

Debt Obligations (Details) - USD ($) $ in Millions		1 Months Ended					12 Months Ended
		Feb. 28, 2025	Dec. 31, 2024	Aug. 31, 2024	Feb. 29, 2024	Jan. 31, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Principal outstanding			$ 32,207				$ 32,207	$ 29,021
Other, non-principal amounts			(311)				(311)	(273)
Less current maturities of debt			(1,150)				(1,150)	(1,300)
Total long-term debt			30,746				30,746	27,448
Debt Obligations Terms:
Repayment of debt obligations							50,546	89,447	$ 97,395
Letter of credit outstanding			28				28
Senior Debt Obligations [Member]
Debt Instrument [Line Items]
Principal outstanding			29,925				29,925	26,725
Senior Debt Obligations [Member] | Commercial Paper Notes [Member]
Debt Instrument [Line Items]
Principal outstanding			0				0	450
Debt Obligations Terms:
Maximum borrowing capacity			$ 3,000				$ 3,000
Information regarding variable interest rates paid:
Weighted-average interest rate paid							5.44%
Senior Debt Obligations [Member] | Commercial Paper Notes [Member] | Minimum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid			4.68%				4.68%
Senior Debt Obligations [Member] | Commercial Paper Notes [Member] | Maximum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid			5.50%				5.50%
Senior Debt Obligations [Member] | EPO Senior Notes JJ, due February 2024 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 0				$ 0	850
Debt Obligations Terms:
Interest rate, stated percentage			3.90%				3.90%
Repayment of debt obligations					$ 850
Senior Debt Obligations [Member] | EPO Senior Notes MM, due February 2025 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,150				$ 1,150	1,150
Debt Obligations Terms:
Interest rate, stated percentage			3.75%				3.75%
Senior Debt Obligations [Member] | EPO Senior Notes MM, due February 2025 [Member] | Subsequent Event [Member]
Debt Obligations Terms:
Repayment of debt obligations		$ 1,150
Senior Debt Obligations [Member] | March 2024 $1.5 Billion EPO 364-Day Revolving Credit Agreement, due March 2025 [Member]
Debt Instrument [Line Items]
Principal outstanding	[1]		$ 0				$ 0	0
Debt Obligations Terms:
Maximum borrowing capacity			1,500				1,500
Maximum bank commitments increase			200				200
Total maximum borrowing capacity			1,700				$ 1,700
Information regarding variable interest rates paid:
Credit facility interest rate description							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.
Senior Debt Obligations [Member] | EPO Senior Notes FFF, due January 2026 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 750				$ 750	750
Debt Obligations Terms:
Interest rate, stated percentage			5.05%				5.05%
Senior Debt Obligations [Member] | EPO Senior Notes PP, due February 2026 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 875				$ 875	875
Debt Obligations Terms:
Interest rate, stated percentage			3.70%				3.70%
Senior Debt Obligations [Member] | EPO Senior Notes HHH, due January 2027 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,000				$ 1,000	0
Debt Obligations Terms:
Interest rate, stated percentage			4.60%				4.60%
Aggregate debt principal issued						$ 1,000
Senior Debt Obligations [Member] | EPO Senior Notes SS, due February 2027[Member]
Debt Instrument [Line Items]
Principal outstanding			$ 575				$ 575	575
Debt Obligations Terms:
Interest rate, stated percentage			3.95%				3.95%
Senior Debt Obligations [Member] | March 2023 $2.7 Billion EPO Multi-Year Revolving Credit Agreement, due March 2028 [Member]
Debt Instrument [Line Items]
Principal outstanding	[2]		$ 0				$ 0	0
Debt Obligations Terms:
Maximum borrowing capacity			2,700				2,700
Maximum bank commitments increase			500				500
Total maximum borrowing capacity			3,200				$ 3,200
Information regarding variable interest rates paid:
Credit facility interest rate description							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.
Senior Debt Obligations [Member] | EPO Senior Notes WW, due October 2028 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,000				$ 1,000	1,000
Debt Obligations Terms:
Interest rate, stated percentage			4.15%				4.15%
Senior Debt Obligations [Member] | EPO Senior Notes YY, due July 2029 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,250				$ 1,250	1,250
Debt Obligations Terms:
Interest rate, stated percentage			3.125%				3.125%
Senior Debt Obligations [Member] | EPO Senior Notes AAA, due January 2030 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,250				$ 1,250	1,250
Debt Obligations Terms:
Interest rate, stated percentage			2.80%				2.80%
Senior Debt Obligations [Member] | EPO Senior Notes GGG, due January 2033 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,000				$ 1,000	1,000
Debt Obligations Terms:
Interest rate, stated percentage			5.35%				5.35%
Senior Debt Obligations [Member] | EPO Senior Notes D, due March 2033 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 500				$ 500	500
Debt Obligations Terms:
Interest rate, stated percentage			6.875%				6.875%
Senior Debt Obligations [Member] | EPO Senior Notes III, due January 2034 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,000				$ 1,000	0
Debt Obligations Terms:
Interest rate, stated percentage			4.85%				4.85%
Aggregate debt principal issued						1,000
Senior Debt Obligations [Member] | EPO Senior Notes H, due October 2034 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 350				$ 350	350
Debt Obligations Terms:
Interest rate, stated percentage			6.65%				6.65%
Senior Debt Obligations [Member] | EPO Senior Notes JJJ, due February 2035 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,100				$ 1,100	0
Debt Obligations Terms:
Interest rate, stated percentage			4.95%				4.95%
Aggregate debt principal issued				$ 1,100
Senior Debt Obligations [Member] | EPO Senior Notes J, due March 2035 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 250				$ 250	250
Debt Obligations Terms:
Interest rate, stated percentage			5.75%				5.75%
Senior Debt Obligations [Member] | EPO Senior Notes W, due April 2038 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 400				$ 400	400
Debt Obligations Terms:
Interest rate, stated percentage			7.55%				7.55%
Senior Debt Obligations [Member] | EPO Senior Notes R, due October 2039 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 600				$ 600	600
Debt Obligations Terms:
Interest rate, stated percentage			6.125%				6.125%
Senior Debt Obligations [Member] | EPO Senior Notes Z, due September 2040 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 600				$ 600	600
Debt Obligations Terms:
Interest rate, stated percentage			6.45%				6.45%
Senior Debt Obligations [Member] | EPO Senior Notes BB, due February 2041 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 750				$ 750	750
Debt Obligations Terms:
Interest rate, stated percentage			5.95%				5.95%
Senior Debt Obligations [Member] | EPO Senior Notes DD, due February 2042 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 600				$ 600	600
Debt Obligations Terms:
Interest rate, stated percentage			5.70%				5.70%
Senior Debt Obligations [Member] | EPO Senior Notes EE, due August 2042 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 750				$ 750	750
Debt Obligations Terms:
Interest rate, stated percentage			4.85%				4.85%
Senior Debt Obligations [Member] | EPO Senior Notes GG, due February 2043 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,100				$ 1,100	1,100
Debt Obligations Terms:
Interest rate, stated percentage			4.45%				4.45%
Senior Debt Obligations [Member] | EPO Senior Notes II, due March 2044 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,400				$ 1,400	1,400
Debt Obligations Terms:
Interest rate, stated percentage			4.85%				4.85%
Senior Debt Obligations [Member] | EPO Senior Notes KK, due February 2045 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,150				$ 1,150	1,150
Debt Obligations Terms:
Interest rate, stated percentage			5.10%				5.10%
Senior Debt Obligations [Member] | EPO Senior Notes QQ, due May 2046 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 975				$ 975	975
Debt Obligations Terms:
Interest rate, stated percentage			4.90%				4.90%
Senior Debt Obligations [Member] | EPO Senior Notes UU, due February 2048 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,250				$ 1,250	1,250
Debt Obligations Terms:
Interest rate, stated percentage			4.25%				4.25%
Senior Debt Obligations [Member] | EPO Senior Notes XX, due February 2049 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,250				$ 1,250	1,250
Debt Obligations Terms:
Interest rate, stated percentage			4.80%				4.80%
Senior Debt Obligations [Member] | EPO Senior Notes ZZ, due January 2050 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,250				$ 1,250	1,250
Debt Obligations Terms:
Interest rate, stated percentage			4.20%				4.20%
Senior Debt Obligations [Member] | EPO Senior Notes BBB, due January 2051 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,000				$ 1,000	1,000
Debt Obligations Terms:
Interest rate, stated percentage			3.70%				3.70%
Senior Debt Obligations [Member] | EPO Senior Notes DDD, due February 2052 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,000				$ 1,000	1,000
Debt Obligations Terms:
Interest rate, stated percentage			3.20%				3.20%
Senior Debt Obligations [Member] | EPO Senior Notes EEE, due February 2053 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,000				$ 1,000	1,000
Debt Obligations Terms:
Interest rate, stated percentage			3.30%				3.30%
Senior Debt Obligations [Member] | EPO Senior Notes NN, due October 2054 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 400				$ 400	400
Debt Obligations Terms:
Interest rate, stated percentage			4.95%				4.95%
Senior Debt Obligations [Member] | EPO Senior Notes KKK, due February 2055 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,400				$ 1,400	0
Debt Obligations Terms:
Interest rate, stated percentage			5.55%				5.55%
Aggregate debt principal issued				1,400
Senior Debt Obligations [Member] | EPO Senior Notes CCC, due January 2060 [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 1,000				$ 1,000	1,000
Debt Obligations Terms:
Interest rate, stated percentage			3.95%				3.95%
Junior Debt Obligations [Member]
Debt Obligations Terms:
Variable rate, Interest rate terms							Effective July 1, 2023, all series of our junior subordinated notes subject to a variable interest rate replaced the 3-month London Interbank Offered Rate (“LIBOR”) with 3-month CME Term SOFR plus a 0.26161% tenor spread adjustment.
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C, due June 2067 [Member]
Debt Instrument [Line Items]
Principal outstanding	[3],[4]		$ 232				$ 232	232
Debt Obligations Terms:
Variable annual interest rate thereafter, variable rate basis							3-month Chicago Mercantile Exchange (“CME”) Term Secured Overnight Financing Rate (“SOFR”) plus (a) a 0.26161% tenor spread adjustment
Variable interest rate							2.778%
Information regarding variable interest rates paid:
Weighted-average interest rate paid							8.23%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C, due June 2067 [Member] | Minimum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid			7.51%				7.51%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C, due June 2067 [Member] | Maximum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid			8.42%				8.42%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes D, due August 2077 [Member]
Debt Instrument [Line Items]
Principal outstanding	[3],[5]		$ 350				$ 350	350
Debt Obligations Terms:
Variable annual interest rate thereafter, variable rate basis							3-month CME Term SOFR plus (a) a 0.26161% tenor spread adjustment
Variable interest rate							2.986%
Information regarding variable interest rates paid:
Weighted-average interest rate paid							8.42%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes D, due August 2077 [Member] | Minimum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid			7.73%				7.73%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes D, due August 2077 [Member] | Maximum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid			8.64%				8.64%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes E, due August 2077 [Member]
Debt Instrument [Line Items]
Principal outstanding	[3],[6]		$ 1,000				$ 1,000	1,000
Debt Obligations Terms:
Interest rate, stated percentage			5.25%				5.25%
Variable annual interest rate thereafter, variable rate basis							3-month CME Term SOFR plus (a) a 0.26161% tenor spread adjustment
Variable interest rate							3.033%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes F, due February 2078 [Member]
Debt Instrument [Line Items]
Principal outstanding	[3],[7]		$ 700				$ 700	700
Debt Obligations Terms:
Interest rate, stated percentage			5.375%				5.375%
Variable annual interest rate thereafter, variable rate basis							3-month CME Term SOFR plus (a) a 0.26161% tenor spread adjustment
Variable interest rate							2.57%
Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes, due June 2067 [Member]
Debt Instrument [Line Items]
Principal outstanding	[3],[4],[8]		$ 0				$ 0	14
Debt Obligations Terms:
Repayment of debt obligations			$ 14
Variable annual interest rate thereafter, variable rate basis							3-month Chicago Mercantile Exchange (“CME”) Term Secured Overnight Financing Rate (“SOFR”) plus (a) a 0.26161% tenor spread adjustment
Variable interest rate							2.778%
Information regarding variable interest rates paid:
Weighted-average interest rate paid							8.23%
Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes, due June 2067 [Member] | Minimum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid			7.51%				7.51%
Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes, due June 2067 [Member] | Maximum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid			8.42%				8.42%
Senior Notes [Member]
Debt Instrument [Line Items]
Principal outstanding			$ 29,925				$ 29,925
Debt Obligations Terms:
Aggregate debt principal issued				$ 2,500		$ 2,000	$ 4,500	$ 1,750
[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]Effective July 1, 2023, all series of our junior subordinated notes subject to a variable interest rate replaced the 3-month London Interbank Offered Rate (“LIBOR”) with 3-month CME Term SOFR plus a 0.26161% tenor spread adjustment.[4]Variable rate is reset quarterly and based on 3-month Chicago Mercantile Exchange (“CME”) Term Secured Overnight Financing Rate (“SOFR”) plus (a) a 0.26161% tenor spread adjustment and (b) 2.778%. [5]Variable rate is reset quarterly and based on 3-month CME Term SOFR plus (a) a 0.26161% tenor spread adjustment and (b) 2.986%.[6]Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month CME Term SOFR plus (a) a 0.26161% tenor spread adjustment and (b) 3.033%.[7]Fixed rate of 5.375% through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month CME Term SOFR plus (a) a 0.26161% tenor spread adjustment and (b) 2.57%.[8]In December 2024, an affiliate of Enterprise redeemed all of the $14 million outstanding principal amount of TEPPCO Junior Subordinated Notes at par (i.e. at a redemption price equal to the outstanding principal amount of such notes to be redeemed, plus accrued and unpaid interest thereon) using cash on hand.

Debt Obligations, Debt Maturiti

Debt Obligations, Debt Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Scheduled Maturities of Debt [Abstract]
2025	$ 1,150
2026	1,625
2027	1,575
2028	1,000
2029	1,250
Thereafter	25,607
Total	32,207	$ 29,021
Senior Notes [Member]
Scheduled Maturities of Debt [Abstract]
2025	1,150
2026	1,625
2027	1,575
2028	1,000
2029	1,250
Thereafter	23,325
Total	29,925
Junior Subordinated Notes [Member]
Scheduled Maturities of Debt [Abstract]
2025	0
2026	0
2027	0
2028	0
2029	0
Thereafter	2,282
Total	$ 2,282

Capital Accounts, Summary of Ch

Capital Accounts, Summary of Changes in Outstanding Units (Details) - Common Units [Member] - shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Summary of changes in outstanding units [Roll Forward]
Common units outstanding, beginning balance (in units)	2,168,245,238	2,170,806,347	2,176,379,587
Common unit repurchases under 2019 Buyback Program (in units)	(7,556,210)	(7,244,540)	(10,166,923)
Common units issued in connection with the vesting of phantom unit awards, net (in units)	4,990,360	4,662,539	4,571,333
Other (in units)	20,574	20,892	22,350
Common units outstanding, ending balance (in units)	2,165,699,962	2,168,245,238	2,170,806,347

Capital Accounts, Issuances of

Capital Accounts, Issuances of Equity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Buyback Program:
Common units acquired in connection with buyback program	$ 219	$ 188	$ 250
Phantom Unit Awards [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Common units issued in connection with the vesting of phantom unit awards, net (in units)	4,990,360	4,662,539	4,571,333
2019 Buyback Program [Member]
Buyback Program:
Total of common units repurchased under a buyback program (in units)	7,556,210	7,244,540	10,166,923
Common units acquired in connection with buyback program	$ 219	$ 188	$ 250
Amount authorized under 2019 Buyback Program	2,000
Remaining available capacity under the 2019 Buyback Program	863
At-the-Market Registration [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance	2,500
Net Cash Proceeds from Sale of Common Units [Abstract]
Remaining units available for issuance	$ 2,500
Distribution Reinvestment Plan [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Remaining units available for issuance (in units)	29,296,008
Employee Unit Purchase Plan [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance (in units)	23,000,000
Net Cash Proceeds from Sale of Common Units [Abstract]
Employer contribution to EUPP	$ 3	$ 3	$ 3
Remaining units available for issuance (in units)	13,783,146
Distribution Reinvestment and Employee Unit Purchase Plans [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units purchased on the open market and delivered to participants (in units)	6,538,068	6,560,588	6,392,846

Capital Accounts, Redeemable Pr

Capital Accounts, Redeemable Preferred Limited Partner Interests (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2020	Dec. 31, 2021	Sep. 30, 2020
Temporary Equity [Line Items]
Series A cumulative convertible preferred units (in dollars per unit)						$ 1,000
Series A cumulative convertible preferred units, paid-in kind distribution (in units)	275
Series A cumulative convertible preferred units outstanding (in units)	50,687	50,412	50,412		50,412	50,000
Total distributions paid to convertible preferred unitholders	$ 4
Cash distributions paid to convertible preferred unitholders	$ 3	$ 3	$ 3
Preferred unit distribution rate	7.25%
Redemption price per preferred unit on or after September 30, 2025 at unitholder election (in dollars per unit)	$ 1,000
Redemption price per preferred unit from September 30, 2024 through September 29, 2025 (in dollars per unit)	1,030
Redemption price per preferred unit from September 30, 2025 through September 29, 2026 (in dollars per unit)	1,010
Redemption price per preferred unit on or after September 30, 2026 (in dollars per unit)	1,000
Redemption price per preferred unit if Change of Control event occurs (in dollars per unit)	$ 1,010
Percentage applied to the common unit market price in calculating the number of common units to be acquired upon the conversion of series A preferred units to common units	92.50%
Percentage of preferred units that may be converted into common units at unitholder option	50%
Preferred Units [Member]
Temporary Equity [Line Items]
Treasury units outstanding (preferred units) (in units)						855,915
Common Units [Member]
Temporary Equity [Line Items]
Treasury units acquired in connection with settlement of Liquidity Option in March 2020 (in units)				(54,807,352)

Capital Accounts, Accumulated O

Capital Accounts, Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	$ 307	$ 365
Other comprehensive income (loss) for period, before reclassifications	113	57
Reclassification of losses (gains) to net income during period	(184)	(115)
Total other comprehensive income (loss) for period	(71)	(58)	$ 79
Accumulated Other Comprehensive Income (Loss), Ending balance	236	307	365
Interest expense	1,352	1,269	1,244
Revenue	(56,219)	(49,715)	(58,186)
Operating costs and expenses	49,045	43,017	51,502
Total	(5,970)	(5,657)	(5,615)
Cash Flow Hedges [Member] | Commodity Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	154	171
Other comprehensive income (loss) for period, before reclassifications	115	93
Reclassification of losses (gains) to net income during period	(178)	(110)
Total other comprehensive income (loss) for period	(63)	(17)
Accumulated Other Comprehensive Income (Loss), Ending balance	91	154	171
Cash Flow Hedges [Member] | Interest Rate Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	151	192
Other comprehensive income (loss) for period, before reclassifications	(2)	(36)
Reclassification of losses (gains) to net income during period	(6)	(5)
Total other comprehensive income (loss) for period	(8)	(41)
Accumulated Other Comprehensive Income (Loss), Ending balance	143	151	192
Other [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	2	2
Other comprehensive income (loss) for period, before reclassifications	0	0
Reclassification of losses (gains) to net income during period	0	0
Total other comprehensive income (loss) for period	0	0
Accumulated Other Comprehensive Income (Loss), Ending balance	2	2	$ 2
Reclassification of Losses (Gains) out of Accumulated Other Comprehensive Income (Loss) [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Total	(184)	(115)
Reclassification of Losses (Gains) out of Accumulated Other Comprehensive Income (Loss) [Member] | Cash Flow Hedges [Member] | Commodity Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Revenue	(249)	(106)
Operating costs and expenses	71	(4)
Reclassification of Losses (Gains) out of Accumulated Other Comprehensive Income (Loss) [Member] | Cash Flow Hedges [Member] | Interest Rate Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Interest expense	$ (6)	$ (5)

Capital Accounts, Noncontrollin

Capital Accounts, Noncontrolling Interests (Details) - USD ($) $ in Millions				12 Months Ended
		Mar. 27, 2024	Feb. 16, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Noncontrolling Interest
Noncontrolling interests				$ 857	$ 1,086
Net income attributable to noncontrolling interests				69	125	$ 125
Payments To Acquire Additional Interest In Subsidiaries As An Equity Transaction			$ 375	400	10	$ 0
Breviloba LLC [Member]
Noncontrolling Interest
Noncontrolling interests	[1]			423	436
Whitethorn Pipeline Company LLC [Member]
Noncontrolling Interest
Noncontrolling interests	[2]			0	182
Percentage of Equity Interests Acquired			20%
Enterprise Navigator Ethylene Terminal LLC [Member]
Noncontrolling Interest
Noncontrolling interests	[3]			245	166
Other [Member]
Noncontrolling Interest
Noncontrolling interests	[4]			$ 189	$ 302
Enterprise EF78 LLC [Member]
Noncontrolling Interest
Percentage of Equity Interests Acquired			25%
Panola Pipeline Company, LLC [Member]
Noncontrolling Interest
Percentage of Equity Interests Acquired		15%
Payments To Acquire Additional Interest In Subsidiaries As An Equity Transaction		$ 25
Parent Company's Ownership Percentage of Subsidiary		70%
Altus Midstream Processing LP [Member] | Breviloba LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners				33%
Western Gas Partners, LP [Member] | Whitethorn Pipeline Company LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners					20%
Navigator Ethylene Terminals LLC [Member] | Enterprise Navigator Ethylene Terminal LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners				50%
[1] An affiliate of Kinetik Holdings Inc. owns a noncontrolling equity interest in Breviloba, which owns the Shin Oak NGL Pipeline

Capital Accounts, Distributions

Capital Accounts, Distributions (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
	Feb. 14, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Distributions to Partners [Abstract]
Number of days after quarter end to distribute available cash		45 days
Cash payments made in connection with distribution equivalent rights		$ 43	$ 38	$ 34
Subsequent Event [Member] | Fourth Quarter 2024 Distribution [Member]
Distributions to Partners [Abstract]
Cash distributions paid	$ 1,170
Cash payments made in connection with distribution equivalent rights	$ 11
Cash Distribution [Member] | First Quarter 2022 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)				$ 0.465
Record Date				Apr. 29, 2022
Payment Date				May 12, 2022
Cash Distribution [Member] | Second Quarter 2022 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)				$ 0.475
Record Date				Jul. 29, 2022
Payment Date				Aug. 12, 2022
Cash Distribution [Member] | Third Quarter 2022 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)				$ 0.475
Record Date				Oct. 31, 2022
Payment Date				Nov. 14, 2022
Cash Distribution [Member] | Fourth Quarter 2022 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)				$ 0.49
Record Date				Jan. 31, 2023
Payment Date				Feb. 14, 2023
Cash Distribution [Member] | First Quarter 2023 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.49
Record Date			Apr. 28, 2023
Payment Date			May 12, 2023
Cash Distribution [Member] | Second Quarter 2023 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.5
Record Date			Jul. 31, 2023
Payment Date			Aug. 14, 2023
Cash Distribution [Member] | Third Quarter 2023 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.5
Record Date			Oct. 31, 2023
Payment Date			Nov. 14, 2023
Cash Distribution [Member] | Fourth Quarter 2023 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.515
Record Date			Jan. 31, 2024
Payment Date			Feb. 14, 2024
Cash Distribution [Member] | First Quarter 2024 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.515
Record Date		Apr. 30, 2024
Payment Date		May 14, 2024
Cash Distribution [Member] | Second Quarter 2024 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.525
Record Date		Jul. 31, 2024
Payment Date		Aug. 14, 2024
Cash Distribution [Member] | Third Quarter 2024 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.525
Record Date		Oct. 31, 2024
Payment Date		Nov. 14, 2024
Cash Distribution [Member] | Fourth Quarter 2024 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.535
Record Date		Jan. 31, 2025
Payment Date		Feb. 14, 2025
Annualized Distribution Per Common Unit (in dollars per unit)	$ 2.14

Revenues, Revenues by Business

Revenues, Revenues by Business Segment and Revenue Type (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Revenue [Abstract]
Revenues	$ 56,219	$ 49,715	$ 58,186
NGL Pipelines & Services [Member]
Revenue [Abstract]
Revenues	20,276	17,645	24,259
NGL Pipelines & Services [Member] | Sales of NGLs and Related Products [Member]
Revenue [Abstract]
Revenues	17,397	14,846	21,307
NGL Pipelines & Services [Member] | Midstream Services [Member]
Revenue [Abstract]
Revenues	2,879	2,799	2,952
NGL Pipelines & Services [Member] | Midstream Services: Natural Gas Processing and Fractionation [Member]
Revenue [Abstract]
Revenues	1,349	1,278	1,431
NGL Pipelines & Services [Member] | Midstream Services: Transportation [Member]
Revenue [Abstract]
Revenues	1,151	1,090	987
NGL Pipelines & Services [Member] | Midstream Services: Storage and Terminals [Member]
Revenue [Abstract]
Revenues	379	431	534
Crude Oil Pipelines & Services [Member]
Revenue [Abstract]
Revenues	21,580	19,336	18,561
Crude Oil Pipelines & Services [Member] | Sales of Crude Oil [Member]
Revenue [Abstract]
Revenues	20,389	18,185	17,301
Crude Oil Pipelines & Services [Member] | Midstream Services [Member]
Revenue [Abstract]
Revenues	1,191	1,151	1,260
Crude Oil Pipelines & Services [Member] | Midstream Services: Transportation [Member]
Revenue [Abstract]
Revenues	779	744	807
Crude Oil Pipelines & Services [Member] | Midstream Services: Storage and Terminals [Member]
Revenue [Abstract]
Revenues	412	407	453
Natural Gas Pipelines & Services [Member]
Revenue [Abstract]
Revenues	3,004	3,776	6,260
Natural Gas Pipelines & Services [Member] | Sales of Natural Gas [Member]
Revenue [Abstract]
Revenues	1,458	2,373	5,019
Natural Gas Pipelines & Services [Member] | Midstream Services [Member]
Revenue [Abstract]
Revenues	1,546	1,403	1,241
Natural Gas Pipelines & Services [Member] | Midstream Services: Transportation [Member]
Revenue [Abstract]
Revenues	1,546	1,403	1,241
Petrochemical & Refined Products Services [Member]
Revenue [Abstract]
Revenues	11,359	8,958	9,106
Petrochemical & Refined Products Services [Member] | Sales of Petrochemicals and Refined Products [Member]
Revenue [Abstract]
Revenues	10,013	7,689	8,003
Petrochemical & Refined Products Services [Member] | Midstream Services [Member]
Revenue [Abstract]
Revenues	1,346	1,269	1,103
Petrochemical & Refined Products Services [Member] | Midstream Services: Fractionation and Isomerization [Member]
Revenue [Abstract]
Revenues	371	282	222
Petrochemical & Refined Products Services [Member] | Midstream Services: Transportation [Member]
Revenue [Abstract]
Revenues	663	660	585
Petrochemical & Refined Products Services [Member] | Midstream Services: Storage and Terminals [Member]
Revenue [Abstract]
Revenues	$ 312	$ 327	$ 296

Revenues, Unbilled Revenue and

Revenues, Unbilled Revenue and Deferred Revenue (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Contracts with Customers, Assets and Liabilities [Abstract]
Unbilled revenue	$ 9	$ 11	$ 6	$ 15
Deferred revenue	452	519	$ 501	$ 446
Prepaid and other current assets [Member]
Contracts with Customers, Assets and Liabilities [Abstract]
Unbilled revenue (current amount)	9	11
Other current liabilities [Member]
Contracts with Customers, Assets and Liabilities [Abstract]
Deferred revenue (current amount)	168	193
Other long-term liabilities [Member]
Contracts with Customers, Assets and Liabilities [Abstract]
Deferred revenue (noncurrent)	$ 284	$ 326

Revenues, Significant Changes i

Revenues, Significant Changes in Unbilled Revenue (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Significant Changes in Unbilled Revenue
Balance at beginning of period		$ 11	$ 6	$ 15
Unbilled revenue included in opening balance transferred to other accounts during period	[1]	(11)	(6)	(15)
Unbilled revenue recorded during period	[2]	79	81	155
Unbilled revenue recorded during period transferred to other accounts	[1]	(70)	(70)	(149)
Other changes		0	0	0
Balance at end of period		$ 9	$ 11	$ 6
[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.

Revenues, Significant Changes_2

Revenues, Significant Changes in Deferred Revenue (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Significant Changes in Deferred Revenue
Balance at beginning of period		$ 519	$ 501	$ 446
Deferred revenue included in opening balance transferred to other accounts during period	[1]	(242)	(271)	(203)
Deferred revenue recorded during period	[2]	853	956	950
Deferred revenue recorded during period transferred to other accounts	[1]	(672)	(656)	(687)
Other changes		(6)	(11)	(5)
Balance at end of period		$ 452	$ 519	$ 501
[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.

Revenues, Remaining Performance

Revenues, Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2024 USD ($)
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 25,984
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 4,077
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 3,791
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 3,537
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 3,085
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 2,256
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 9,238
Expected timing of satisfaction, period

Business Segments and Related_3

Business Segments and Related Information (Details)	12 Months Ended
	Dec. 31, 2024 Segment
Segment Reporting Information [Line Items]
Number of reportable segments	4

Business Segments and Related_4

Business Segments and Related Information, Gross Operating Margin (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Business Segments [Abstract]
Total segment gross operating margin		$ 10,018	$ 9,376	$ 9,356
Adjustments to reconcile total segment gross operating margin to income before income taxes (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expense in operating costs and expenses	[1]	(2,343)	(2,215)	(2,107)
Asset impairment charges in operating costs and expenses		(57)	(30)	(53)
Net gains (losses) attributable to asset sales and related matters in operating costs and expenses		(2)	10	(1)
General and administrative costs		(244)	(231)	(241)
Non-refundable payments received from shippers attributable to make-up rights	[2]	(75)	(52)	(144)
Subsequent recognition of revenues attributable to make-up rights	[3]	41	71	97
Total other expense, net	[4]	(1,303)	(1,228)	(1,210)
Income before income taxes		$ 6,035	$ 5,701	$ 5,697
[1]Excludes amortization of major maintenance costs for reaction-based plants and amortization of finance lease right-of-use assets, 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.[4]As presented on our Statements of Consolidated Operations, Total other expense, net is comprised of Interest expense, Interest income and Other, net.

Business Segments and Related_5

Business Segments and Related Information, Segment Reporting Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segment revenues [Abstract]
Total revenues		$ 56,219	$ 49,715	$ 58,186
Segment expenses [Abstract]
Cost of sales	[1]	42,580	37,023	45,836
Total operating costs and expenses		49,045	43,017	51,502
Other segment income (expense) [Abstract]
Equity in income of unconsolidated affiliates		408	462	464
Other financial information [Abstract]
Current assets		15,133	12,248
Other assets		997	1,222
Total assets		77,168	70,982
NGL Pipelines and Services [Member]
Segment revenues [Abstract]
Total revenues		20,276	17,645	24,259
Other segment income (expense) [Abstract]
Equity in income of unconsolidated affiliates		$ 117	$ 133	$ 149
Segment Reporting, Other Segment Item, Composition, Description		NGL Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights, and other segment expenses.	NGL Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights, and other segment expenses.	NGL Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights, and other segment expenses.
Crude Oil Pipelines & Services [Member]
Segment revenues [Abstract]
Total revenues		$ 21,580	$ 19,336	$ 18,561
Other segment income (expense) [Abstract]
Equity in income of unconsolidated affiliates		$ 285	$ 320	$ 308
Segment Reporting, Other Segment Item, Composition, Description		Crude Oil Pipelines & Services – Other segment expenses.	Crude Oil Pipelines & Services – Subsequent recognition of revenues attributable to make-up rights.	Crude Oil Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights, and other segment expenses.
Natural Gas Pipelines & Services [Member]
Segment revenues [Abstract]
Total revenues		$ 3,004	$ 3,776	$ 6,260
Other segment income (expense) [Abstract]
Equity in income of unconsolidated affiliates		$ 5	$ 6	$ 5
Segment Reporting, Other Segment Item, Composition, Description		Natural Gas Pipelines & Services – Other segment expenses.	Natural Gas Pipelines & Services – Other segment expenses.	Natural Gas Pipelines & Services – Other segment expenses.
Petrochemical & Refined Products Services [Member]
Segment revenues [Abstract]
Total revenues		$ 11,359	$ 8,958	$ 9,106
Other segment income (expense) [Abstract]
Equity in income of unconsolidated affiliates		$ 1	$ 3	$ 2
Segment Reporting, Other Segment Item, Composition, Description		Petrochemical & Refined Products Services – Other segment expenses.	Petrochemical & Refined Products Services – Other segment expenses.	Petrochemical & Refined Products Services – Other segment expenses.
Nonrelated Party [Member]
Segment revenues [Abstract]
Total revenues		$ 56,161	$ 49,654	$ 58,127
Related Party [Member]
Segment revenues [Abstract]
Total revenues		58	61	59
Reportable Business Segments [Member]
Segment revenues [Abstract]
Total revenues		185,475	171,736	189,763
Segment expenses [Abstract]
Cost of sales		170,769	157,973	176,370
Variable operating costs and expenses	[2]	1,323	1,388	1,469
Fixed operating costs and expenses	[3]	3,820	3,464	3,134
Total operating costs and expenses		175,912	162,825	180,973
Other segment income (expense) [Abstract]
Equity in income of unconsolidated affiliates		408	462	464
Other segment items		47	3	102
Total other segment income (expense), net		455	465	566
Total segment gross operating margin		10,018	9,376	9,356
Other financial information [Abstract]
Capital expenditures		4,544	3,266	1,964
Total assets		56,900	55,267
Reportable Business Segments [Member] | NGL Pipelines and Services [Member]
Segment revenues [Abstract]
Total revenues		69,098	63,135	90,019
Segment expenses [Abstract]
Cost of sales		61,260	56,143	82,957
Variable operating costs and expenses	[2]	745	741	769
Fixed operating costs and expenses	[3]	1,682	1,589	1,412
Total operating costs and expenses		63,687	58,473	85,138
Other segment income (expense) [Abstract]
Equity in income of unconsolidated affiliates		117	133	149
Other segment items		20	103	112
Total other segment income (expense), net		137	236	261
Total segment gross operating margin		5,548	4,898	5,142
Other financial information [Abstract]
Capital expenditures		2,498	1,366	624
Total assets		21,900	21,792
Reportable Business Segments [Member] | Crude Oil Pipelines & Services [Member]
Segment revenues [Abstract]
Total revenues		75,995	76,458	65,186
Segment expenses [Abstract]
Cost of sales		74,098	74,437	63,325
Variable operating costs and expenses	[2]	132	191	173
Fixed operating costs and expenses	[3]	414	403	386
Total operating costs and expenses		74,644	75,031	63,884
Other segment income (expense) [Abstract]
Equity in income of unconsolidated affiliates		285	320	308
Other segment items		10	(40)	45
Total other segment income (expense), net		295	280	353
Total segment gross operating margin		1,646	1,707	1,655
Other financial information [Abstract]
Capital expenditures		161	119	84
Total assets		11,390	11,822
Reportable Business Segments [Member] | Natural Gas Pipelines & Services [Member]
Segment revenues [Abstract]
Total revenues		3,671	4,303	7,148
Segment expenses [Abstract]
Cost of sales		1,656	2,583	5,532
Variable operating costs and expenses	[2]	73	59	54
Fixed operating costs and expenses	[3]	676	595	532
Total operating costs and expenses		2,405	3,237	6,118
Other segment income (expense) [Abstract]
Equity in income of unconsolidated affiliates		5	6	5
Other segment items		6	5	7
Total other segment income (expense), net		11	11	12
Total segment gross operating margin		1,277	1,077	1,042
Other financial information [Abstract]
Capital expenditures		932	793	344
Total assets		12,260	11,210
Reportable Business Segments [Member] | Petrochemical & Refined Products Services [Member]
Segment revenues [Abstract]
Total revenues		36,711	27,840	27,410
Segment expenses [Abstract]
Cost of sales		33,755	24,810	24,556
Variable operating costs and expenses	[2]	373	397	473
Fixed operating costs and expenses	[3]	1,048	877	804
Total operating costs and expenses		35,176	26,084	25,833
Other segment income (expense) [Abstract]
Equity in income of unconsolidated affiliates		1	3	2
Other segment items		11	(65)	(62)
Total other segment income (expense), net		12	(62)	(60)
Total segment gross operating margin		1,547	1,694	1,517
Other financial information [Abstract]
Capital expenditures		953	988	912
Total assets		11,350	10,443
Reportable Business Segments [Member] | Nonrelated Party [Member]
Segment revenues [Abstract]
Total revenues		56,161	49,654	58,127
Reportable Business Segments [Member] | Nonrelated Party [Member] | NGL Pipelines and Services [Member]
Segment revenues [Abstract]
Total revenues		20,264	17,635	24,244
Reportable Business Segments [Member] | Nonrelated Party [Member] | Crude Oil Pipelines & Services [Member]
Segment revenues [Abstract]
Total revenues		21,546	19,300	18,548
Reportable Business Segments [Member] | Nonrelated Party [Member] | Natural Gas Pipelines & Services [Member]
Segment revenues [Abstract]
Total revenues		2,992	3,761	6,229
Reportable Business Segments [Member] | Nonrelated Party [Member] | Petrochemical & Refined Products Services [Member]
Segment revenues [Abstract]
Total revenues		11,359	8,958	9,106
Reportable Business Segments [Member] | Related Party [Member]
Segment revenues [Abstract]
Total revenues		58	61	59
Reportable Business Segments [Member] | Related Party [Member] | NGL Pipelines and Services [Member]
Segment revenues [Abstract]
Total revenues		12	10	15
Reportable Business Segments [Member] | Related Party [Member] | Crude Oil Pipelines & Services [Member]
Segment revenues [Abstract]
Total revenues		34	36	13
Reportable Business Segments [Member] | Related Party [Member] | Natural Gas Pipelines & Services [Member]
Segment revenues [Abstract]
Total revenues		12	15	31
Reportable Business Segments [Member] | Related Party [Member] | Petrochemical & Refined Products Services [Member]
Segment revenues [Abstract]
Total revenues		0	0	0
Eliminations [Member]
Segment revenues [Abstract]
Total revenues		(129,256)	(122,021)	(131,577)
Eliminations [Member] | NGL Pipelines and Services [Member]
Segment revenues [Abstract]
Total revenues		(48,822)	(45,490)	(65,760)
Eliminations [Member] | Crude Oil Pipelines & Services [Member]
Segment revenues [Abstract]
Total revenues		(54,415)	(57,122)	(46,625)
Eliminations [Member] | Natural Gas Pipelines & Services [Member]
Segment revenues [Abstract]
Total revenues		(667)	(527)	(888)
Eliminations [Member] | Petrochemical & Refined Products Services [Member]
Segment revenues [Abstract]
Total revenues		(25,352)	(18,882)	$ (18,304)
Segment Reporting, Reconciling Item, Corporate Nonsegment [Member]
Other financial information [Abstract]
Construction in progress		4,138	2,245
Current assets		15,133	12,248
Other assets		$ 997	$ 1,222
[1]Cost of sales is a component of “Operating costs and expenses,” as presented on our 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.[2]Variable operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally fluctuate based on utilization. [3]Fixed operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally remain constant independent of utilization.

Business Segments and Related_6

Business Segments and Related Information, Consolidated Revenues and Expenses (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Consolidated Revenues [Abstract]
Total revenues		$ 56,219	$ 49,715	$ 58,186
Operating costs and expenses:
Cost of sales	[1]	42,580	37,023	45,836
Other operating costs and expenses	[2]	4,004	3,695	3,454
Depreciation, amortization and accretion		2,402	2,279	2,158
Impairment of assets other than goodwill		57	30	53
Net losses (gains) attributable to asset sales and related matters		2	(10)	1
General and administrative costs		244	231	241
Total costs and expenses		49,289	43,248	51,743
Vitol Holding B.V. [Member]
Consolidated Revenues [Abstract]
Total revenues		$ 6,450	$ 7,870	$ 5,920
Revenues [Member] | Customer Concentration Risk [Member] | Vitol Holding B.V. [Member]
Consolidated Revenues [Abstract]
Percent of revenues		11.50%	15.80%	10.20%
NGL Pipelines and Services [Member]
Consolidated Revenues [Abstract]
Total revenues		$ 20,276	$ 17,645	$ 24,259
Crude Oil Pipelines & Services [Member]
Consolidated Revenues [Abstract]
Total revenues		21,580	19,336	18,561
Natural Gas Pipelines & Services [Member]
Consolidated Revenues [Abstract]
Total revenues		3,004	3,776	6,260
Petrochemical and Refined Products Services [Member]
Consolidated Revenues [Abstract]
Total revenues		$ 11,359	$ 8,958	$ 9,106
[1]Cost of sales is a component of “Operating costs and expenses,” as presented on our 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.[2]Represents the cost of operating our plants, pipelines and other fixed assets excluding: depreciation, amortization and accretion; asset impairment charges; and net losses (gains) attributable to asset sales and related matters.

Earnings Per Unit (Details)

Earnings Per Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
BASIC EARNINGS PER COMMON UNIT
Net income attributable to common unitholders		$ 5,897	$ 5,529	$ 5,487
Earnings allocated to phantom unit awards	[1]	(56)	(50)	(46)
Net income allocated to common unitholders		$ 5,841	$ 5,479	$ 5,441
Basic weighted-average number of common units outstanding (in units)		2,169	2,172	2,178
Basic earnings per common unit (in dollars per unit)		$ 2.69	$ 2.52	$ 2.5
DILUTED EARNINGS PER COMMON UNIT
Net income attributable to common unitholders		$ 5,897	$ 5,529	$ 5,487
Net income attributable to preferred units		4	3	3
Net income attributable to limited partners		$ 5,901	$ 5,532	$ 5,490
Diluted weighted-average number of units outstanding:
Distribution-bearing common units (in units)		2,169	2,172	2,178
Phantom units (in units)	[2]	21	20	19
Preferred units (in units)	[2]	2	2	2
Total (in units)		2,192	2,194	2,199
Diluted earnings per common unit (in dollars per unit)		$ 2.69	$ 2.52	$ 2.5
[1]Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding phantom units. [2]We use the “if-converted method” to determine the potential dilutive effect of the vesting of phantom unit awards and the conversion of preferred units outstanding.  See Note 8 for information regarding preferred units.

Business Combinations (Details)

Business Combinations (Details) $ in Millions		12 Months Ended
		Dec. 31, 2024 USD ($)	Dec. 31, 2022 USD ($)	Oct. 28, 2024 USD ($)	Dec. 31, 2023 USD ($)	Feb. 17, 2022 USD ($)
Allocation of total purchase prices paid [Abstract]
Goodwill	[1]	$ 5,712	$ 5,608		$ 5,608
Pinon Midstream, LLC [Member]
Consideration:
Purchase price to acquire business		$ 953
Allocation of total purchase prices paid [Abstract]
Cash and cash equivalents				$ 4
Property, plant, and equipment				410
Total identifiable net assets				849
Goodwill				104
Business Combination [Abstract]
Business acquisition, description		Pinon Midstream’s assets include 43 miles of natural gas gathering and redelivery pipelines, five 3-stage compressor stations, 270 million cubic feet per day (“MMcf/d”) of hydrogen sulfide and carbon dioxide treating facilities and two high capacity acid gas injection wells.
Pinon Midstream, LLC [Member] | Personal Property [Member]
Allocation of total purchase prices paid [Abstract]
Property, plant, and equipment				354
Pinon Midstream, LLC [Member] | Real Property [Member]
Allocation of total purchase prices paid [Abstract]
Property, plant, and equipment				11
Pinon Midstream, LLC [Member] | Construction in progress [Member]
Allocation of total purchase prices paid [Abstract]
Property, plant, and equipment				45
Pinon Midstream, LLC [Member] | Contract-based intangibles [Member]
Allocation of total purchase prices paid [Abstract]
Intangible assets				$ 435
Estimated useful life of acquired intangible asset		25 years
Business Combination [Abstract]
Underlying Contract of Acquired Finite Lived Intangible Asset, Period Before Renewal Or Extension		10 years
Navitas Midstream Partners, LLC [Member]
Consideration:
Purchase price to acquire business			$ 3,231
Allocation of total purchase prices paid [Abstract]
Cash and cash equivalents						$ 27
Property, plant, and equipment						2,080
Assumed liabilities, net of acquired other assets	[2]					(24)
Total identifiable net assets						3,072
Goodwill						159
Business Combination [Abstract]
Business acquisition, description		Navitas Midstream's assets (the “Midland Basin System”) include approximately 1,750 miles of pipelines and over 1.0 Bcf/d of cryogenic natural gas processing capacity. The acquired business expands our natural gas processing and NGL businesses to the Midland Basin in West Texas.
Navitas Midstream Partners, LLC [Member] | Contract-based intangibles [Member]
Allocation of total purchase prices paid [Abstract]
Intangible assets						$ 989
Estimated useful life of acquired intangible asset		30 years
Measurement input, discount rate [Member] | Pinon Midstream, LLC [Member]
Allocation of total purchase prices paid [Abstract]
Long-lived asset, measurement input				0.165
Measurement input, discount rate [Member] | Navitas Midstream Partners, LLC [Member] | Contract-based intangibles [Member]
Allocation of total purchase prices paid [Abstract]
Long-lived asset, measurement input						0.155
[1]Balances are presented net of historical accumulated impairment losses of $296 million for the Natural Gas Pipelines & Service segment and $1 million for the Petrochemical & Refined Products Services segment.  There have been no goodwill impairment charges recognized for the reporting units within the NGL Pipelines & Services and Crude Oil Pipelines & Services segments.[2]Assumed liabilities primarily include accounts payable, other current liabilities, lease liabilities and asset retirement obligations.  Acquired other assets primarily include accounts receivable, other current assets and ROU assets.  None of these amounts were considered individually significant.

Equity-Based Awards (Details)

Equity-Based Awards (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Equity-based compensation expense [Abstract]
Total compensation expense	$ 188	$ 172	$ 157
Phantom Unit Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	178	166	153
Profits Interest Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	$ 10	$ 6	$ 4
Long-Term Incentive Plan (2008) [Member]
Equity-based compensation expense [Abstract]
Maximum number of common units that may be issued as awards (in units)	165,000,000
Remaining number of common units available to be issued as awards (in units)	103,056,553

Equity-Based Awards, Phantom Un

Equity-Based Awards, Phantom Unit Awards (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2024		Dec. 31, 2023		Dec. 31, 2022
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Cash payments made in connection with DERs		$ 43		$ 38		$ 34
Phantom Unit Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate of phantom unit awards		25%
Summary of awards activity, equity instruments other than options [Roll Forward]
Beginning of period (in units)		19,557,251		17,982,945		17,170,919
Granted (in units)		8,881,820	[1]	8,904,445	[2]	7,968,880	[3]
Vested (in units)		(7,304,071)		(6,786,085)		(6,616,741)
Forfeited (in units)		(542,749)		(544,054)		(540,113)
End of period (in units)		20,592,251		19,557,251		17,982,945
Common units issued in connection with the vesting of phantom unit awards, net (in units)		4,990,360		4,662,539		4,571,333
Phantom units outstanding, weighted-average grant date fair value [Roll Forward]
Weighted-average grant date fair value per unit, at beginning of period (in dollars per unit)	[4]	$ 24.47		$ 23.94		$ 24.31
Granted weighted-average grant date fair value per unit (in dollars per unit)	[4]	26.25	[1]	25.8	[2]	24.11	[3]
Vested weighted-average grant date fair value per unit (in dollars per unit)	[4]	24.51		24.81		25.08
Forfeited weighted-average grant date fair value per unit (in dollars per unit)	[4]	25.39		24.52		23.92
Weighted-average grant date fair value per unit, at end of period (in dollars per unit)	[4]	$ 25.21		$ 24.47		$ 23.94
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Aggregate grant date fair value		$ 233		$ 230		$ 192
Estimated forfeiture rate		2%		2%		2.10%
Cash payments made in connection with DERs		$ 43		$ 38		$ 34
Total intrinsic value of phantom unit awards that vested during period		199		$ 182		$ 160
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost		$ 195
Recognition period for total unrecognized compensation cost		2 years 1 month 6 days
Phantom Unit Awards [Member] | Minimum [Member]
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Grant date market price of common units (in dollars per unit)		$ 26.25		$ 25.8		$ 24.1
Phantom Unit Awards [Member] | Maximum [Member]
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Grant date market price of common units (in dollars per unit)		$ 29.64		$ 26.7		$ 26.62
Phantom Unit Awards [Member] | Enterprise [Member]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost		$ 153
[1]The aggregate grant date fair value of phantom unit awards issued during 2024 was $233 million based on a grant date market price of the Partnership’s common units ranging from $26.25 to $29.64 per unit.  An estimated annual forfeiture rate of 2.0% was applied to these awards.[2]The aggregate grant date fair value of phantom unit awards issued during 2023 was $230 million based on a grant date market price of the Partnership’s common units ranging from $25.80 to $26.70 per unit.  An estimated annual forfeiture rate of 2.0% was applied to these awards.[3]The aggregate grant date fair value of phantom unit awards issued during 2022 was $192 million based on a grant date market price of the Partnership’s common units ranging from $24.10 to $26.62 per unit.  An estimated annual forfeiture rate of 2.1% was applied to these awards.[4]Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.

Equity-Based Awards, Profits In

Equity-Based Awards, Profits Interest Awards (Details) - Profits Interest Awards [Member]	12 Months Ended
	Dec. 31, 2024 $ / shares
EPD 2018 Unit IV [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee partnership liquidation threshold (in dollars per unit)	$ 29.02
Vesting period	30 days
EPCO Unit II [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee partnership liquidation threshold (in dollars per unit)	$ 29.02
Vesting period	30 days

Hedging Activities and Fair V_3

Hedging Activities and Fair Value Measurements (Details) bbl in Millions, $ in Millions, ft³ in Billions		1 Months Ended			12 Months Ended
		Aug. 31, 2024 USD ($)	Jan. 31, 2024 USD ($)	Jan. 31, 2023 USD ($)	Dec. 31, 2024 USD ($) TWh bbl ft³	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Aug. 01, 2024 USD ($)	Jan. 02, 2024 USD ($)	Jan. 03, 2023 USD ($)
Derivative [Line Items]
Payments from the settlement of interest rate derivative instruments | $					$ (33)	$ 21	$ 0
Carrying amount of hedged asset | $					$ 11	2
Designated as Hedging Instrument [Member] | Treasury Lock - Settled January 2024 [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Payments from the settlement of interest rate derivative instruments | $			$ (29)
Designated as Hedging Instrument [Member] | Treasury Lock - Fourth Quarter 2023 [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Notional Amount | $						$ 600
Credit-risk related contingent features in derivative instruments [Abstract]
Treasury rate, fixed rate						4.48%
Designated as Hedging Instrument [Member] | Treasury Lock - January 2024 A [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Notional Amount | $									$ 400
Credit-risk related contingent features in derivative instruments [Abstract]
Treasury rate, fixed rate									3.97%
Designated as Hedging Instrument [Member] | Treasury Lock - January 2024 B [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Notional Amount | $									$ 750
Credit-risk related contingent features in derivative instruments [Abstract]
Treasury rate, fixed rate									4.11%
Designated as Hedging Instrument [Member] | Treasury Lock [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Notional Amount | $										$ 1,500
Payments from the settlement of interest rate derivative instruments | $		$ (4)		$ 21
Designated as Hedging Instrument [Member] | Treasury Lock - August 2024 A [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Notional Amount | $								$ 1,000
Credit-risk related contingent features in derivative instruments [Abstract]
Treasury rate, fixed rate								3.98%
Designated as Hedging Instrument [Member] | Treasury Lock - August 2024 B [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Notional Amount | $								$ 1,000
Credit-risk related contingent features in derivative instruments [Abstract]
Treasury rate, fixed rate								4.29%
Designated as Hedging Instrument [Member] | Natural gas processing: Forecasted sales of natural gas [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | ft³	[1],[2]				37.7
Designated as Hedging Instrument [Member] | Natural gas processing: Forecasted sales of natural gas [Member] | Derivatives in cash flow hedging relationships [Member] | Long-term [Member]
Derivative [Line Items]
Volume | ft³	[1],[2]				36.5
Designated as Hedging Instrument [Member] | Natural gas processing: Forecasted sales of NGLs [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume	[1],[2]				3.2
Designated as Hedging Instrument [Member] | Octane enhancement: Forecasted sales of octane enhancement products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume	[1],[2]				3.8
Designated as Hedging Instrument [Member] | Octane enhancement: Forecasted sales of octane enhancement products [Member] | Derivatives in cash flow hedging relationships [Member] | Long-term [Member]
Derivative [Line Items]
Volume	[1],[2]				0.1
Designated as Hedging Instrument [Member] | Natural gas marketing: Natural gas storage inventory management activities [Member] | Derivatives in fair value hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | ft³	[1],[2]				2.9
Designated as Hedging Instrument [Member] | NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume	[1],[2]				134
Designated as Hedging Instrument [Member] | NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products [Member] | Derivatives in cash flow hedging relationships [Member] | Long-term [Member]
Derivative [Line Items]
Volume	[1],[2]				5.8
Designated as Hedging Instrument [Member] | NGL marketing: Forecasted sales of NGLs and related hydrocarbon products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume	[1],[2]				148.5
Designated as Hedging Instrument [Member] | NGL marketing: Forecasted sales of NGLs and related hydrocarbon products [Member] | Derivatives in cash flow hedging relationships [Member] | Long-term [Member]
Derivative [Line Items]
Volume	[1],[2]				4.8
Designated as Hedging Instrument [Member] | Refined products marketing: Forecasted sales of refined products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume	[1],[2]				0.1
Designated as Hedging Instrument [Member] | Crude oil marketing: Forecasted purchases of crude oil [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume	[1],[2]				13.3
Designated as Hedging Instrument [Member] | Crude oil marketing: Forecasted purchases of crude oil [Member] | Derivatives in cash flow hedging relationships [Member] | Long-term [Member]
Derivative [Line Items]
Volume	[1],[2]				5
Designated as Hedging Instrument [Member] | Crude oil marketing: Forecasted sales of crude oil [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume	[1],[2]				22.4
Designated as Hedging Instrument [Member] | Crude oil marketing: Forecasted sales of crude oil [Member] | Derivatives in cash flow hedging relationships [Member] | Long-term [Member]
Derivative [Line Items]
Volume	[1],[2]				10.3
Designated as Hedging Instrument [Member] | Petrochemical marketing: Forecasted sales of petrochemical products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume	[1],[2]				0.9
Designated as Hedging Instrument [Member] | Commercial energy: Forecasted purchases of power related to asset operations [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | TWh	[1],[2]				1.5
Not Designated as Hedging Instrument [Member] | Natural gas risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | ft³	[1],[2],[3]				16.6
Not Designated as Hedging Instrument [Member] | NGL risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member]
Derivative [Line Items]
Volume	[1],[2],[3]				38.9
Not Designated as Hedging Instrument [Member] | NGL risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Long-term [Member]
Derivative [Line Items]
Volume	[1],[2],[3]				22.8
Not Designated as Hedging Instrument [Member] | Refined products risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member]
Derivative [Line Items]
Volume	[1],[2],[3]				7.2
Not Designated as Hedging Instrument [Member] | Crude oil risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member]
Derivative [Line Items]
Volume	[1],[2],[3]				168.3
Not Designated as Hedging Instrument [Member] | Commercial energy risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | TWh	[1],[2],[3]				0.1
Not Designated as Hedging Instrument [Member] | Commercial energy risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Long-term [Member]
Derivative [Line Items]
Volume | TWh	[1],[2],[3]				11.1
[1]The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2027, May 2025 and December 2027, respectively.[2]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.[3]Reflects the use of derivative instruments to manage risks associated with our transportation, processing and storage assets.

Hedging Activities and Fair V_4

Hedging Activities and Fair Value Measurements, Derivative Fair Value Amounts (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Interest rate derivatives [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives		$ 31
Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	$ 575	450
Liability Derivatives	495	471
Derivatives designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	232	149
Liability Derivatives	182	202
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	0
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	0	31
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	232	149
Liability Derivatives	182	171
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	210	118
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	22	31
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	178	136
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	4	35
Derivatives not designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	343	301
Liability Derivatives	313	300
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	343	301
Liability Derivatives	313	300
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	324	229
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	19	72
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	293	229
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ 20	$ 71

Hedging Activities and Fair V_5

Hedging Activities and Fair Value Measurements, Asset Balance Sheet Offsetting (Details) - Commodity Derivatives [Member] - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	$ 575	$ 450
Gross Amounts Offset in the Balance Sheet	0	0
Amounts of Assets Presented in the Balance Sheet	575	450
Financial Instruments	(495)	(450)
Cash Collateral Received	(79)	0
Cash Collateral Paid	0	0
Amounts That Would Have Been Presented On Net Basis	$ 1	$ 0

Hedging Activities and Fair V_6

Hedging Activities and Fair Value Measurements, Liability Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Interest rate derivatives [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities		$ 31
Gross Amounts Offset in the Balance Sheet		0
Amounts of Liabilities Presented in the Balance Sheet		31
Financial Instruments		0
Cash Collateral Received		0
Cash Collateral Paid		0
Amounts That Would Have Been Presented On Net Basis		31
Commodity Derivatives [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	$ 495	471
Gross Amounts Offset in the Balance Sheet	0	0
Amounts of Liabilities Presented in the Balance Sheet	495	471
Financial Instruments	(495)	(450)
Cash Collateral Received	0	1
Cash Collateral Paid	0	(21)
Amounts That Would Have Been Presented On Net Basis	$ 0	$ 1

Hedging Activities and Fair V_7

Hedging Activities and Fair Value Measurements, Gains and Losses on Derivative Instruments and Related Hedged Items (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses)		$ 20	$ (33)	$ (78)
NGL Pipelines & Services [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses)		(8)	(25)	(52)
Crude Oil Pipelines & Services [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses)		21	(5)	(30)
Natural Gas Pipelines & Services [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses)		5	(1)	(3)
Petrochemical & Refined Products Services [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses)		2	(2)	7
Derivatives in fair value hedging relationships [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		2	7	(103)
Gain (Loss) Recognized in Income on Hedged Item		9	(7)	66
Derivatives in fair value hedging relationships [Member] | Commodity derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		$ 2	$ 7	$ (103)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]		Total revenues	Total revenues	Total revenues
Derivatives in fair value hedging relationships [Member] | Commodity derivatives [Member] | Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Hedged Item		$ 9	$ (7)	$ 66
Derivatives in cash flow hedging relationships [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative		113	57	280
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income		184	115	201
Derivatives in cash flow hedging relationships [Member] | Interest rate derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative		(2)	(36)	26
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income		$ 6	$ 5	$ (19)
Derivative Instrument, Gain (Loss) Reclassified from AOCI into Income, Effective Portion, Statement of Income or Comprehensive Income [Extensible Enumeration]		Interest expense	Interest expense	Interest expense
Accumulated other comprehensive income related to interest rate derivative instruments expected to be reclassified to earnings in interest expense over the next twelve months		$ 6
Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to earnings over the next twelve months		72
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to revenue over the next twelve months		75
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to operating costs and expenses over the next twelve months		(3)
Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member] | Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative	[1]	182	$ 81	$ 227
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income		249	106	181
Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member] | Operating costs and expenses [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative	[1]	(67)	12	27
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income		(71)	4	39
Derivatives not designated as hedging instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		22	213	88
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses)		7
Unrealized gains (losses)		15
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		26	213	74
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Operating costs and expenses [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		$ (4)	$ 0	$ 14
[1]The fair value of these derivative instruments will be reclassified to their respective locations on the Statement of Consolidated Operations when the forecasted transactions affect earnings.

Hedging Activities and Fair V_8

Hedging Activities and Fair Value Measurements, Recurring Fair Value Measurements (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Financial assets [Abstract]
Value before application of CME Rule 814	$ 798	$ 728
Impact of CME Rule 814	(223)	(278)
Total commodity derivatives	575	450
Total	575	450
Financial liabilities [Abstract]
Interest rate derivatives		31
Commodity derivatives:
Value before application of CME Rule 814	716	625
Impact of CME Rule 814	(221)	(154)
Total commodity derivatives	495	471
Total	495	502
Net value before application of CME Rule 814 to commodity hedging portfolio	82
Level 1 [Member]
Financial assets [Abstract]
Value before application of CME Rule 814	355	431
Impact of CME Rule 814	(56)	(147)
Total commodity derivatives	299	284
Total	299	284
Financial liabilities [Abstract]
Interest rate derivatives		0
Commodity derivatives:
Value before application of CME Rule 814	291	317
Impact of CME Rule 814	(43)	(22)
Total commodity derivatives	248	295
Total	248	295
Level 2 [Member]
Financial assets [Abstract]
Value before application of CME Rule 814	443	297
Impact of CME Rule 814	(167)	(131)
Total commodity derivatives	276	166
Total	276	166
Financial liabilities [Abstract]
Interest rate derivatives		31
Commodity derivatives:
Value before application of CME Rule 814	404	308
Impact of CME Rule 814	(157)	(132)
Total commodity derivatives	247	176
Total	247	207
Level 3 [Member]
Financial assets [Abstract]
Value before application of CME Rule 814	0	0
Impact of CME Rule 814	0	0
Total commodity derivatives	0	0
Total	0	0
Financial liabilities [Abstract]
Interest rate derivatives		0
Commodity derivatives:
Value before application of CME Rule 814	21	0
Impact of CME Rule 814	(21)	0
Total commodity derivatives	0	0
Total	$ 0	$ 0

Hedging Activities and Fair V_9

Hedging Activities and Fair Value Measurements, Other Fair Value Measurements (Details) - USD ($) $ in Billions	Dec. 31, 2024	Dec. 31, 2023
Carrying Value [Member]
Financial Liabilities: [Abstract]
Fixed-rate debt obligations	$ 31.6	$ 28
Level 2 [Member] | Fair Value [Member]
Financial Liabilities: [Abstract]
Fixed-rate debt obligations	$ 28.9	$ 26.7

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Revenues - related parties:
Revenues	$ 56,219	$ 49,715	$ 58,186
Costs and expenses - related parties:
Operating costs and expenses	1,491	1,385	1,342
General and administrative expenses	166	156	156
Total costs and expenses - related parties	1,657	1,541	1,498
Related Party [Member]
Revenues - related parties:
Revenues	58	61	59
Costs and expenses - related parties:
Total accounts receivable - related parties	4	7
Total accounts payable - related parties	198	199
EPCO and its privately held affiliates [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	1,472	1,353	1,289
Total accounts payable - related parties	180	183
Distributions:
Total cash distributions	1,400	1,300	1,300
EPCO and its privately held affiliates [Member] | Administrative Services Agreement [Member]
Costs and expenses - related parties:
Operating costs and expenses	1,294	1,189	1,124
General and administrative expenses	152	141	146
Total costs and expenses - related parties	1,446	1,330	1,270
EPCO and its privately held affiliates [Member] | Related Party Operating Leases [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	$ 23	13	13
EPCO and its privately held affiliates [Member] | Common Units [Member]
Relationship with Affiliates [Abstract]
Number of Units (in units)	701,938,819
Percentage of total units outstanding	32.40%
Enterprise common units pledged as security (in units)	62,976,464
Unconsolidated affiliates [Member]
Revenues - related parties:
Revenues	$ 58	61	59
Costs and expenses - related parties:
Total costs and expenses - related parties	185	188	209
Total accounts receivable - related parties	4	7
Total accounts payable - related parties	18	16
Unconsolidated affiliates [Member] | Seaway Crude Holdings LLC [Member]
Revenues - related parties:
Revenues	23	25	15
Costs and expenses - related parties:
Total costs and expenses - related parties	30	27	20
Unconsolidated affiliates [Member] | Venice Energy Service Company, L.L.C. [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	75	80	107
Unconsolidated affiliates [Member] | K/D/S Promix, L.L.C. [Member]
Revenues - related parties:
Revenues	9	11	22
Costs and expenses - related parties:
Total costs and expenses - related parties	39	36	41
Unconsolidated affiliates [Member] | Texas Express Pipeline LLC [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	10	27	31
Unconsolidated affiliates [Member] | Management/Operator Fees [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	$ (14)	$ (11)	$ (12)

Income Taxes (Details)

Income Taxes (Details)	12 Months Ended
	Dec. 31, 2024
Components of Benefit From (Provision For) Income Taxes:
Qualifying income requirement for publicly traded partnerships to not be treated as corporations	90%
Threshold to recognize the effect of income tax positions	50%

Income Taxes, Benefit From (Pro

Income Taxes, Benefit From (Provision For) Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Current portion of income tax provision:
Federal	$ (2)	$ (12)	$ (2)
State	(18)	(20)	(18)
Foreign	0	0	(2)
Total current portion	(20)	(32)	(22)
Deferred portion of income tax provision:
Federal	(16)	17	(20)
State	(28)	(29)	(40)
Foreign	(1)	0	0
Total deferred portion	(45)	(12)	(60)
Total provision for income taxes	$ (65)	$ (44)	$ (82)

Income Taxes, Reconciliation of

Income Taxes, Reconciliation of the Benefit From (Provision For) Income Taxes (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Reconciliation of the provision for income taxes [Abstract]
Pre-Tax Net Book Income ("NBI")		$ 6,035	$ 5,701	$ 5,697
Texas Margin Tax	[1]	(44)	(49)	(56)
State income tax provision, net of federal benefit		(2)	(2)	(1)
Federal income tax provision computed by applying the federal statutory rate to NBI of corporate entities		(17)	(16)	(15)
Change in valuation allowance	[2]	0	22	(8)
Other		(2)	1	(2)
Total provision for income taxes		$ (65)	$ (44)	$ (82)
Effective income tax rate		(1.10%)	(0.80%)	(1.40%)
[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.[2]During 2023, management concluded that it is more likely than not that the deferred tax assets attributable to OTA will be fully realizable.  As a result, for the year-end December 31, 2023, we recorded a full release of the valuation allowance against OTA’s deferred tax assets.

Income Taxes, Deferred Tax Liab

Income Taxes, Deferred Tax Liabilities and Assets (Details) - USD ($) $ in Millions		Dec. 31, 2024	Dec. 31, 2023
Deferred tax liabilities:
Attributable to investment in OTA	[1]	$ 462	$ 436
Attributable to property, plant and equipment		151	138
Attributable to investments in other entities		5	4
Other		98	83
Total deferred tax liabilities		716	661
Deferred tax assets:
Net operating loss carryovers	[2]	56	46
Temporary differences related to Texas Margin Tax		4	4
Total deferred tax assets		60	50
Total net deferred tax liabilities		$ 656	$ 611
[1]Represents the deferred tax liability balance held by our wholly owned subsidiary, OTA, which we acquired in March 2020.[2]The loss amount presented as of December 31, 2024 has an indefinite carryover period.  All losses are subject to limitations on their utilization.

Commitments and Contingent Li_3

Commitments and Contingent Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Operating lease obligations:
Renewal option years for certain operating leases	20 years
Lessee, Finance Lease, Description [Abstract]
Term of material finance lease agreements	4 years
Liabilities, Other than Long-term Debt, Noncurrent [Abstract]
Noncurrent portion of AROs	$ 259	$ 221
Deferred revenues - non-current portion	284	326
Operating lease liability - non-current portion	366	323
Derivative liabilities	24	106
Other	17	8
Total	950	$ 984
Junior Subordinated Note [Member]
Debt Instrument [Line Items]
Debt obligations	$ 2,300
Minimum [Member]
Operating lease obligations:
Term of material operating lease agreements	5 years
Maximum [Member]
Operating lease obligations:
Term of material operating lease agreements	30 years

Commitments and Contingent Li_4

Commitments and Contingent Liabilities, Contractual Obligations (Details) - USD ($) $ in Millions		Dec. 31, 2024	Dec. 31, 2023
Scheduled maturities of debt obligations
2025		$ 1,150
2026		1,625
2027		1,575
2028		1,000
2029		1,250
Thereafter		25,607
Total		32,207	$ 29,021
Estimated cash interest payments
2025		1,476
2026		1,407
2027		1,338
2028		1,323
2029		1,272
Thereafter		21,953
Total		28,769
Operating lease obligations
2025	[1]	121
2026	[1]	91
2027	[1]	54
2028	[1]	37
2029	[1]	30
Thereafter	[1]	228
Total	[1]	561
Lessee, Operating Lease, Liability, Undiscounted Excess Amount		90
Finance lease obligations
2025		1
2026		1
2027		1
2028		1
2029		0
Thereafter		0
Total		4
NGLs [Member]
Estimated payment obligations:
2025		275
2026		248
2027		239
2028		205
2029		158
Thereafter		197
Total		1,322
Crude Oil [Member]
Estimated payment obligations:
2025		1,872
2026		1,584
2027		1,490
2028		1,177
2029		760
Thereafter		314
Total		7,197
Estimated Payment Obligations Other [Member]
Estimated payment obligations:
2025		2
2026		2
2027		2
2028		2
2029		2
Thereafter		4
Total		14
Service Payment Commitments [Member]
Estimated payment obligations:
2025		46
2026		40
2027		40
2028		27
2029		22
Thereafter		132
Total		307
Capital Expenditure Commitments [Member]
Estimated payment obligations:
2025		99
2026		0
2027		0
2028		0
2029		0
Thereafter		0
Total		$ 99
[1]As of December 31, 2024, the difference between the total payments for operating lease obligations and the carrying value of our operating lease liabilities, which represents the present value of future operating lease payments, was $90 million.

Commitments and Contingent Li_5

Commitments and Contingent Liabilities, Operating Leases (Details) - USD ($) $ in Millions		Dec. 31, 2024	Dec. 31, 2023
Operating and finance Leases [Abstract]
Operating lease ROU asset carrying value	[1]	$ 435
Operating lease ROU asset, Consolidated Balance Sheet line item		Other Assets, Noncurrent
Operating lease liability carrying value	[2]	$ 471
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]		Other Liabilities, Current
Operating lease liability, current		$ 105
Operating lease liability - non-current portion		$ 366	$ 323
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]		Other Liabilities, Noncurrent
Finance Lease, ROU Asset carrying value	[1]	$ 4
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]		Other Assets, Noncurrent
Finance Lease, Liability	[2]	$ 4
Finance Lease, Liability, Current		$ 1
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]		Other Liabilities, Current
Finance Lease, Liability, Noncurrent		$ 3
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Other Liabilities, Noncurrent
Total Lease Right Of Use Asset	[1]	$ 439
Total Lease Liability	[2]	475
Storage and Pipeline Facilities [Member]
Operating and finance Leases [Abstract]
Operating lease ROU asset carrying value	[1]	222
Operating lease liability carrying value	[2]	$ 222
Operating lease weighted-average remaining term		8 years
Operating lease weighted-average discount rate	[3]	4.50%
Transportation Equipment [Member]
Operating and finance Leases [Abstract]
Operating lease ROU asset carrying value	[1]	$ 43
Operating lease liability carrying value	[2]	$ 44
Operating lease weighted-average remaining term		4 years
Operating lease weighted-average discount rate	[3]	4.80%
Finance Lease, ROU Asset carrying value	[1]	$ 4
Finance Lease, Liability	[2]	$ 4
Finance Lease, Weighted Average Remaining Lease Term		4 years
Finance Lease, Weighted Average Discount Rate, Percent	[3]	4.70%
Office and Warehouse Space [Member]
Operating and finance Leases [Abstract]
Operating lease ROU asset carrying value	[1]	$ 170
Operating lease liability carrying value	[2]	$ 205
Operating lease weighted-average remaining term		12 years
Operating lease weighted-average discount rate	[3]	3.40%
[1]ROU asset amounts are a component of “ Other assets Other current liabilities ” and “ Other long-term liabilities ,” Other current liabilities Other long-term liabilities

Commitments and Contingent Li_6

Commitments and Contingent Liabilities, Consolidated Lease Expense (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Consolidated Lease Expense [Abstract]
Non-cash lease expense (amortization of ROU assets)		$ 95	$ 72	$ 59
Related accretion expense on lease liability balances		17	14	12
Total fixed operating lease expense		112	86	71
Amortization of ROU assets	[1]	0	0	0
Interest on finance lease liabilities	[1]	0	0	0
Total fixed finance lease expense	[1]	0	0	0
Variable lease expense		17	13	6
Total long-term lease expense		129	99	77
Short-term leases		121	111	91
Total lease expense		250	210	168
Cash payments for operating lease liabilities		110	87	65
Operating lease income		$ 15	$ 16	$ 14
[1]For the year ended December 31, 2024, total fixed finance lease expense, which include amortization of finance lease ROU assets and interest on finance lease liabilities, was less than $1 million.

Significant Risks and Uncerta_2

Significant Risks and Uncertainties (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Insurance Matters [Abstract]
Insurance deductible per incident	$ 30
Minimum business interruption period	60 days
Named windstorm insurance coverage	$ 200
Liability for Claims and Claims Adjustment Expense	$ 39	$ 22

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Decrease (increase) in:
Accounts receivable - trade		$ (1,453)	$ (810)	$ 108
Accounts receivable - related parties		2	4	10
Inventories		(598)	(714)	131
Prepaid and other current assets		(152)	(651)	(97)
Other assets		38	31	(42)
Increase (decrease) in:
Accounts payable - trade		(182)	309	(174)
Accounts payable - related parties		(1)	(33)	65
Accrued product payables		1,867	849	(190)
Accrued interest		81	29	(26)
Other current liabilities		15	484	124
Other long-term liabilities		(123)	(53)	37
Net effect of changes in operating accounts		(506)	(555)	(54)
Cash payments for interest, net of $121, $106 and $90 capitalized in 2024, 2023 and 2022, respectively		1,255	1,228	1,232
Capitalized interest	[1]	121	106	90
Cash payments for federal and state income taxes		20	24	0
Liability for construction in progress expenditures		490	400	238
Asset sales and related matters
Proceeds from asset sales and other matters		14	42	122
Recovery of construction costs [Member]
Asset sales and related matters
Proceeds from asset sales and other matters	[2]	0	25	99
Other Disposal of Assets [Member]
Asset sales and related matters
Proceeds from asset sales and other matters		$ 14	$ 17	$ 23
[1]Capitalized interest is a component of “Interest expense” as presented on our Statements of Consolidated Operations.[2]Amounts presented reflect the portion of cash receipts from the settlement of claims attributable to the partial recovery of construction costs incurred on the associated capital project.