0001061219-26-000006 | 10-K | XBRL Viewer | Enterprise Products Partners LP

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Supplemental Cash Flow Information - Schedule of Cash Proceeds from Asset Sales and Other Matters (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales and other matters	$ 82	$ 14	$ 42
Recovery of construction costs
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales and other matters	0	0	25
Sale of Transport 4
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales and other matters	8	0	0
Sale of Bahia NGL Pipeline ownership interest
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales and other matters	60	0	0
Other asset sales
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales and other matters	$ 14	$ 14	$ 17

Supplemental Cash Flow Information - Schedule of Net Effect of Changes in Operating Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Decrease (increase) in:
Accounts receivable – trade	$ 2,748	$ (1,453)	$ (810)
Accounts receivable – related parties	3	2	4
Inventories	122	(598)	(714)
Prepaid and other current assets	27	(152)	(651)
Other assets	58	38	31
Increase (decrease) in:
Accounts payable – trade	(147)	(182)	309
Accounts payable – related parties	19	(1)	(33)
Accrued product payables	(2,649)	1,867	849
Accrued interest	29	81	29
Other current liabilities	(182)	15	484
Other long-term liabilities	(152)	(123)	(53)
Net effect of changes in operating accounts	(124)	(506)	(555)
Cash payments for interest, net of $182, $121 and $106 capitalized in 2025, 2024 and 2023, respectively	1,352	1,255	1,228
Capitalized interest	$ 182	$ 121	$ 106

Intangible Assets and Goodwill - Schedule of Intangible Assets by Business Segment (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Gross Value	$ 6,709	$ 6,339
Accumulated Amortization	(2,550)	(2,334)
Carrying Value	4,159	4,005
Customer relationship intangibles
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Carrying Value	2,400
Contract-based intangibles
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Carrying Value	1,800
NGL Pipelines & Services
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Gross Value	1,499	1,203
Accumulated Amortization	(466)	(417)
Carrying Value	1,033	786
NGL Pipelines & Services \| Customer relationship intangibles
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Gross Value	449	449
Accumulated Amortization	(289)	(276)
Carrying Value	160	173
NGL Pipelines & Services \| Contract-based intangibles
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Gross Value	1,050	754
Accumulated Amortization	(177)	(141)
Carrying Value	873	613
Crude Oil Pipelines & Services
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Gross Value	2,478	2,478
Accumulated Amortization	(990)	(905)
Carrying Value	1,488	1,573
Crude Oil Pipelines & Services \| Customer relationship intangibles
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Gross Value	2,195	2,195
Accumulated Amortization	(710)	(627)
Carrying Value	1,485	1,568
Crude Oil Pipelines & Services \| Contract-based intangibles
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Gross Value	283	283
Accumulated Amortization	(280)	(278)
Carrying Value	3	5
Natural Gas Pipelines & Services
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Gross Value	2,501	2,432
Accumulated Amortization	(965)	(890)
Carrying Value	1,536	1,542
Natural Gas Pipelines & Services \| Customer relationship intangibles
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Gross Value	1,351	1,351
Accumulated Amortization	(700)	(663)
Carrying Value	651	688
Natural Gas Pipelines & Services \| Contract-based intangibles
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Gross Value	1,150	1,081
Accumulated Amortization	(265)	(227)
Carrying Value	885	854
Petrochemical & Refined Products Services
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Gross Value	231	226
Accumulated Amortization	(129)	(122)
Carrying Value	102	104
Petrochemical & Refined Products Services \| Customer relationship intangibles
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Gross Value	181	181
Accumulated Amortization	(99)	(92)
Carrying Value	82	89
Petrochemical & Refined Products Services \| Contract-based intangibles
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Gross Value	50	45
Accumulated Amortization	(30)	(30)
Carrying Value	$ 20	$ 15

Insider Trading Arrangements	3 Months Ended
Insider Trading Arrangements	Dec. 31, 2025
Trading Arrangements, by Individual
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

Inventories

12 Months Ended

Dec. 31, 2025

Inventory Disclosure [Abstract]

Inventories

Note 3. Inventories

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


	December 31,
	2025		2024

NGLs	$	2,923	$	2,768
Petrochemicals and refined products	665		652
Crude oil	288		523
Natural gas	8		12
Total	$	3,884	$	3,955

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,
		2025		2024		2023
Cost of sales (1)		$	38,566	$	42,580	$	37,023
Lower of cost or net realizable value adjustments recognized in cost of sales		19		9		31

(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.

Commitments and Contingent Liabilities - Schedule of Operating and Finance Leases (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Operating leases
ROU Asset Carrying Value	$ 437
Lease Liability Carrying Value	471
Finance leases
ROU Asset Carrying Value	16
Lease Liability Carrying Value	16
Total lease right of use asset	453
Total lease liability carrying value	$ 487
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other assets
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other assets
Operating lease liability, current	$ 94
Operating lease, liability, noncurrent	$ 377	$ 366
Lease liability, current, Consolidated Balance Sheet [Extensible Enumeration]	Other Liabilities, Current
Lease liability, noncurrent, Consolidated Balance Sheet [Extensible Enumeration]	Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Finance lease, liability, current	$ 3
Finance lease, liability, noncurrent	$ 13
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Current
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Noncurrent
Storage and pipeline facilities
Operating leases
ROU Asset Carrying Value	$ 247
Lease Liability Carrying Value	$ 246
Weighted- Average Remaining Term	10 years
Weighted-Average Discount Rate	4.80%
Transportation equipment
Operating leases
ROU Asset Carrying Value	$ 32
Lease Liability Carrying Value	$ 33
Weighted- Average Remaining Term	3 years
Weighted-Average Discount Rate	4.80%
Finance leases
ROU Asset Carrying Value	$ 16
Lease Liability Carrying Value	$ 16
Weighted- Average Remaining Term	4 years
Weighted-Average Discount Rate	4.80%
Office and warehouse space
Operating leases
ROU Asset Carrying Value	$ 158
Lease Liability Carrying Value	$ 192
Weighted- Average Remaining Term	11 years
Weighted-Average Discount Rate	3.30%

Property, Plant and Equipment - Schedule of Forecast of ARO-Related Accretion Expense (Details) $ in Millions	Dec. 31, 2025 USD ($)
Property, Plant and Equipment [Abstract]
2026	$ 17
2027	18
2028	19
2029	20
2030	$ 21

Cover Page - USD ($) $ in Millions	12 Months Ended
Cover Page - USD ($) $ in Millions	Dec. 31, 2025	Jan. 31, 2026	Jun. 30, 2025
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2025
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	1-14323
Entity Registrant Name	ENTERPRISE PRODUCTS PARTNERS L.P.
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	false
Entity Shell Company	false
Entity Public Float			$ 45,380
Entity Common Stock, Shares Outstanding		2,161,760,683
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2025
Entity Central Index Key	0001061219
Amendment Flag	false

Business Segments and Related Information - Schedule of Segment Assets (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Segment Reporting Information [Line Items]
Current assets	$ 13,360	$ 15,133
Other assets	1,127	997
Consolidated total assets	77,902	77,168
Operating Segments
Segment Reporting Information [Line Items]
Consolidated total assets	61,015	56,900
Operating Segments \| NGL Pipelines & Services
Segment Reporting Information [Line Items]
Consolidated total assets	24,999	21,900
Operating Segments \| Crude Oil Pipelines & Services
Segment Reporting Information [Line Items]
Consolidated total assets	11,097	11,390
Operating Segments \| Natural Gas Pipelines & Services
Segment Reporting Information [Line Items]
Consolidated total assets	13,194	12,260
Operating Segments \| Petrochemical & Refined Products Services
Segment Reporting Information [Line Items]
Consolidated total assets	11,725	11,350
Segment Reporting, Reconciling Item, Corporate Nonsegment
Segment Reporting Information [Line Items]
Construction in progress	2,400	4,138
Current assets	13,360	15,133
Other assets	$ 1,127	$ 997

Acquisitions (Tables)

12 Months Ended

Dec. 31, 2025

Business Combination, Asset Acquisition, Transaction between Entities under Common Control, and Joint Venture Formation [Abstract]

Schedule of Allocation of Total Cost to Assets Acquired and Liabilities Assumed

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


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

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

Schedule of Final Fair Value Allocation of Assets Acquired and Liabilities Assumed

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


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

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

Property, Plant and Equipment - Schedule of Information Regarding our Asset Retirement Obligations, or AROs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO liability beginning balance	$ 265	$ 225	$ 234
Liabilities incurred	10	1	5
Revisions in estimated cash flows	1	30	(12)
Liabilities settled	(6)	(4)	(13)
Accretion expense	20	13	11
ARO liability ending balance	$ 290	$ 265	$ 225

Significant Risks and Uncertainties (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
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	$ 52	$ 39

Revenues - Schedule of Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2025 USD ($)
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 27,106
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	$ 4,480
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	$ 4,270
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	$ 3,836
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	$ 2,999
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	$ 2,227
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2031-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 9,294
Expected timing of satisfaction, period

Intangible Assets and Goodwill - Schedule of Amortization Expense of our Intangible Assets by Business Segment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 216	$ 207	$ 201
NGL Pipelines & Services
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	49	44	40
Crude Oil Pipelines & Services
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	85	100	103
Natural Gas Pipelines & Services
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	75	56	51
Petrochemical & Refined Products Services
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 7	$ 7	$ 7

- Definition

The aggregate expense charged against earnings to allocate the cost of intangible assets (nonphysical assets not used in production) in a systematic and rational manner to the periods expected to benefit from such assets.

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+ Details

Earnings Per Unit (Tables)

12 Months Ended

Dec. 31, 2025

Earnings Per Unit [Abstract]

Schedule of 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,
		2025		2024		2023
BASIC EARNINGS PER COMMON UNIT
Net income attributable to common unitholders		$	5,810	$	5,897	$	5,529
Earnings allocated to phantom unit awards (1)		(55)		(56)		(50)
Net income allocated to common unitholders		$	5,755	$	5,841	$	5,479

Basic weighted-average number of common units outstanding		2,166		2,169		2,172

Basic earnings per common unit		$	2.66	$	2.69	$	2.52

DILUTED EARNINGS PER COMMON UNIT
Net income attributable to common unitholders		$	5,810	$	5,897	$	5,529
Net income attributable to preferred units		4		4		3
Net income attributable to limited partners		$	5,814	$	5,901	$	5,532

Diluted weighted-average number of units outstanding:
Distribution-bearing common units		2,166		2,169		2,172
Phantom units (2)		20		21		20
Preferred units (2)		2		2		2
Total		2,188		2,192		2,194

Diluted earnings per common unit		$	2.66	$	2.69	$	2.52

(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.

Commitments and Contingent Liabilities - Schedule of Contractual Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Scheduled maturities of debt obligations
Total	$ 34,707	$ 32,207
2026	1,625
2027	1,575
2028	1,800
2029	1,250
2030	1,250
Thereafter	27,207
Estimated cash interest payments
Total	28,309
2026	1,578
2027	1,509
2028	1,477
2029	1,409
2030	1,354
Thereafter	20,982
Operating lease obligations
Total	576
2026	111
2027	73
2028	52
2029	39
2030	36
Thereafter	265
Present value of future operating lease payments	105
Finance lease obligations
Total	18
2026	4
2027	4
2028	5
2029	3
2030	1
Thereafter	1
Present value of future finance lease payments	2
NGLs
Estimated payment obligations:
Total	2,836
2026	1,186
2027	1,186
2028	170
2029	131
2030	131
Thereafter	32
Crude oil
Estimated payment obligations:
Total	4,296
2026	1,226
2027	1,226
2028	965
2029	622
2030	257
Thereafter	0
Other
Estimated payment obligations:
Total	43
2026	7
2027	8
2028	8
2029	8
2030	7
Thereafter	5
Service payment commitments
Estimated payment obligations:
Total	271
2026	41
2027	38
2028	33
2029	25
2030	24
Thereafter	110
Capital expenditure commitments
Estimated payment obligations:
Total	51
2026	36
2027	15
2028	0
2029	0
2030	0
Thereafter	$ 0

Hedging Activities and Fair Value Measurements - Schedule of Gains and Losses on Derivative Instruments and Related Hedged Items (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Derivatives not designated as hedging instruments:
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative	$ 40	$ 22	$ 213
Commodity Derivative Instruments \| Revenue \| Derivatives not designated as hedging instruments:
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative	45	26	213
Commodity Derivative Instruments \| Operating costs and expenses \| Derivatives not designated as hedging instruments:
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative	(5)	(4)	0
Fair value hedge
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative	5	2	7
Gain (Loss) Recognized in Income on Hedged Item	(3)	9	(7)
Fair value hedge \| Commodity Derivative Instruments
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative	$ 5	$ 2	$ 7
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Revenues	Revenues	Revenues
Fair value hedge \| Commodity Derivative Instruments \| Revenue
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Hedged Item	$ (3)	$ 9	$ (7)
Cash flow hedge
Derivative Instruments, Gain (Loss) [Line Items]
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative	299	113	57
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income	199	184	115
Cash flow hedge \| Commodity Derivative Instruments \| Revenue
Derivative Instruments, Gain (Loss) [Line Items]
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative	321	182	81
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income	235	249	106
Cash flow hedge \| Commodity Derivative Instruments \| Operating costs and expenses
Derivative Instruments, Gain (Loss) [Line Items]
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative	(36)	(67)	12
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income	(43)	(71)	4
Cash flow hedge \| Interest Rate Derivative Instruments
Derivative Instruments, Gain (Loss) [Line Items]
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative	14	(2)	(36)
Cash flow hedge \| Interest Rate Derivative Instruments \| Interest expense
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income	$ 7	$ 6	$ 5

Supplemental Cash Flow Information - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Supplemental Cash Flow Information [Abstract]
Incurred liabilities for construction in progress	$ 401	$ 490	$ 400

Intangible Assets and Goodwill - Schedule of Customer Relationship Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Finite-Lived Intangible Assets [Line Items]
Gross Value	$ 6,709	$ 6,339
Accumulated Amortization	(2,550)	(2,334)
Carrying Value	4,159	$ 4,005
Customer relationship intangibles
Finite-Lived Intangible Assets [Line Items]
Carrying Value	$ 2,400
EFS Midstream (acquired 2015) \| Customer relationship intangibles
Finite-Lived Intangible Assets [Line Items]
Weighted Average Remaining Amortization Period	16 years 4 months 24 days
Gross Value	$ 1,410
Accumulated Amortization	(461)
Carrying Value	$ 949
State Line and Fairplay (acquired 2010) \| Customer relationship intangibles
Finite-Lived Intangible Assets [Line Items]
Weighted Average Remaining Amortization Period	21 years 2 months 12 days
Gross Value	$ 895
Accumulated Amortization	(356)
Carrying Value	$ 539
San Juan Gathering (acquired 2004) \| Customer relationship intangibles
Finite-Lived Intangible Assets [Line Items]
Weighted Average Remaining Amortization Period	13 years 9 months 18 days
Gross Value	$ 331
Accumulated Amortization	(280)
Carrying Value	$ 51
Oiltanking (acquired 2014) \| Customer relationship intangibles
Finite-Lived Intangible Assets [Line Items]
Weighted Average Remaining Amortization Period	18 years
Gross Value	$ 1,193
Accumulated Amortization	(386)
Carrying Value	$ 807

Income Taxes - Summary of Deferred Tax Assets and Deferred Tax Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Deferred tax liabilities:
Attributable to investment in OTA	$ 495	$ 462
Attributable to property, plant and equipment	172	151
Attributable to investments in other entities	4	5
Other	107	98
Total deferred tax liabilities	778	716
Deferred tax assets:
Net operating loss carryovers	73	56
Temporary differences related to Texas Margin Tax	3	4
Total deferred tax assets	76	60
Total net deferred tax liabilities	$ 702	$ 656

Investments in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2025

Equity Method Investments and Joint Ventures [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, 2025	December 31,
		2025		2024
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C. (“VESCO”)	13.1%	$	24	$	24
K/D/S Promix, L.L.C. (“Promix”)	50%	21		22
Baton Rouge Fractionators LLC (“BRF”)	32.2%	12		12
Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”)	50%	21		25
Texas Express Pipeline LLC (“Texas Express”)	35%	287		299
Texas Express Gathering LLC (“TEG”)	45%	32		33
Front Range Pipeline LLC (“Front Range”)	33.3%	175		183
Total NGL Pipelines & Services		572		598
Crude Oil Pipelines & Services:
Seaway Crude Holdings LLC (“Seaway”)	50%	1,120		1,147
Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”)	50%	351		368
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”)	50%	110		113
Total Crude Oil Pipelines & Services		1,581		1,628
Natural Gas Pipelines & Services:
White River Hub, LLC (“White River Hub”)	50%	16		16
Old Ocean Pipeline, LLC (“Old Ocean”)	50%	15		14
Total Natural Gas Pipelines & Services		31		30
Petrochemical & Refined Products Services:
Baton Rouge Propylene Concentrator LLC (“BRPC”)	30%	1		1
Transport 4, LLC (“Transport 4”) (1)		–		2
Total Petrochemical & Refined Products Services		1		3
Total investments in unconsolidated affiliates		$	2,185	$	2,259

(1)In June 2025, we sold our 25% membership interest in Transport 4 to third parties for cash proceeds of $8 million and recorded a $6 million gain.

NGL Pipelines & Services

The principal business activity of each investee included in our NGL Pipelines & Services segment is described as follows:

•VESCO owns the Venice natural gas processing facility and a related gathering system located in south Louisiana.

•Promix owns an NGL fractionation facility and a related gathering system located in south Louisiana.

•BRF owns an NGL fractionation facility located in south Louisiana.

•Skelly-Belvieu owns a pipeline that transports mixed NGLs from Skellytown, Texas to Chambers County, Texas.

•Texas Express owns an NGL pipeline that extends from Skellytown, Texas to our Chambers County NGL fractionation and storage complex. Mixed NGLs from the Rocky Mountains, Permian Basin and Mid-Continent regions are delivered to the Texas Express Pipeline via an interconnect with our Mid-America Pipeline System near Skellytown. In addition, the Texas Express Pipeline transports mixed NGLs gathered by Texas Express Gathering System. Also, mixed NGLs originating from the Denver-Julesburg (“DJ”) Basin in Colorado are transported to the Texas Express Pipeline using the Front Range Pipeline.

•TEG owns two NGL gathering systems that deliver mixed NGLs to the Texas Express Pipeline.

•Front Range owns an NGL pipeline that transports mixed NGLs from natural gas processing facilities located in the DJ Basin to an interconnect with our Texas Express Pipeline and Mid-America Pipeline System and other third party facilities near Skellytown, Texas.

Crude Oil Pipelines & Services

The principal business activity of each investee included in our Crude Oil Pipelines & Services segment is described as follows:

•Seaway owns a crude oil pipeline system that connects the Cushing, Oklahoma hub, which is a major industry trading hub and price settlement point for West Texas Intermediate on the NYMEX, with markets in Southeast Texas. The Seaway Pipeline is comprised of the Longhaul System, the Freeport System and the Texas City System.

•Eagle Ford Crude Oil Pipeline owns a pipeline that transports crude oil and condensate for producers in South Texas. The system originates in Gardendale, Texas and extends to Corpus Christi, Texas. The system interconnects with our South Texas Crude Oil Pipeline System and a marine terminal owned by Eagle Ford Corpus Christi.

•Eagle Ford Corpus Christi owns a marine crude oil terminal located in Corpus Christi, Texas that can load ocean-going vessels with either crude oil or condensate.

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 owns a natural gas hub facility serving producers in the Piceance Basin of northwest Colorado.

•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 the investee included in our Petrochemical & Refined Products Services segment is described as follows:

•BRPC owns a propylene fractionation facility located in south Louisiana.

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,
		2025		2024		2023
NGL Pipelines & Services		$	83	$	117	$	133
Crude Oil Pipelines & Services		271		285		320
Natural Gas Pipelines & Services		5		5		6
Petrochemical & Refined Products Services		2		1		3
Total		$	361	$	408	$	462

Debt Obligations - Narrative (Details) $ in Millions	1 Months Ended				12 Months Ended
Debt Obligations - Narrative (Details) $ in Millions	Feb. 27, 2026 USD ($)	Jan. 31, 2026 USD ($)	Nov. 30, 2025 USD ($)	Jun. 30, 2025 USD ($)	Dec. 31, 2025 USD ($) request	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Debt Instrument [Line Items]
Borrowings under debt agreements					$ 88,281	$ 53,715	$ 89,899
Repayments of debt					85,771	50,546	89,447
Letter of credit outstanding					35
Senior Notes
Debt Instrument [Line Items]
Borrowings under debt agreements					3,650	$ 4,500	$ 1,750
March 2025 $1.5 Billion 364-Day Revolving Credit Agreement, variable-rate, due March 2026 \| Senior Debt Obligations
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity					$ 1,500
Debt instrument, term					364 days
Maximum bank commitments increase					$ 200
Total maximum borrowing capacity					1,700
March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement, variable-rate, due March 2030 \| Senior Debt Obligations
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity					2,700
Maximum bank commitments increase					500
Total maximum borrowing capacity					$ 3,200
Variable interest rate term					5 years
Maturity date extension requests, maximum \| request					2
Debt instrument, extension term					1 year
364-Day $1.5 Billion & $2.7 Billion Revolving Credit Agreements \| Senior Debt Obligations \| Additional Spread Adjustment on Federal Funds Effective Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate					0.50%
364-Day $1.5 Billion & $2.7 Billion Revolving Credit Agreements \| Senior Debt Obligations \| Additional Spread Adjustment on Secured Overnight Financing Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate					1.00%
Commercial Paper Notes \| Senior Debt Obligations
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity					$ 3,000
Senior Notes June 2025 \| Senior Debt Obligations
Debt Instrument [Line Items]
Borrowings under debt agreements				$ 2,000
Senior Notes LLL, 4.30% fixed-rate, due June 2028 \| Senior Debt Obligations
Debt Instrument [Line Items]
Percent of principal amount of debt received			100.63%	99.869%
Borrowings under debt agreements			$ 300	$ 500
Debt instrument, interest rate, stated percentage					4.30%
Senior Notes November 2025 \| Senior Debt Obligations
Debt Instrument [Line Items]
Borrowings under debt agreements			$ 1,650
Senior Notes MMM, 4.60% fixed-rate, due January 2031 \| Senior Debt Obligations
Debt Instrument [Line Items]
Percent of principal amount of debt received			100.693%	99.816%
Borrowings under debt agreements			$ 600	$ 750
Debt instrument, interest rate, stated percentage					4.60%
Senior Notes NNN, 5.20% fixed-rate, due January 2036 \| Senior Debt Obligations
Debt Instrument [Line Items]
Percent of principal amount of debt received			101.185%	99.665%
Borrowings under debt agreements			$ 750	$ 750
Debt instrument, interest rate, stated percentage					5.20%
Senior Notes FFF, 5.05% fixed-rate, due January 2026 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage					5.05%
Senior Notes FFF, 5.05% fixed-rate, due January 2026 \| Senior Debt Obligations \| Subsequent Event
Debt Instrument [Line Items]
Repayments of debt		$ 750
Senior Notes PP, 3.70% fixed-rate, due February 2026 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage					3.70%
Senior Notes PP, 3.70% fixed-rate, due February 2026 \| Senior Debt Obligations \| Subsequent Event
Debt Instrument [Line Items]
Repayments of debt	$ 875

Capital Accounts

12 Months Ended

Dec. 31, 2025

Partners' Capital, Including Portion Attributable to Noncontrolling Interest [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, 2022:


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
Common unit repurchases under 2019 Buyback Program			(9,496,536)
Common units issued in connection with the vesting of phantom unit awards, net			5,346,387
Conversion of preferred units to common units			194,472
Other			16,398
Common units outstanding at December 31, 2025			2,161,760,683

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 Seventh Amended and Restated Agreement of Limited Partnership (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. EPO used the 2024 Shelf to issue $3.65 billion aggregate principal amount of senior notes during the year ended December 31, 2025 (see Note 7).

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, 2025. The Partnership’s capacity to issue additional common units under the ATM program remains at $2.5 billion as of December 31, 2025.

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

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. In October 2025, we announced that the Board approved an increase to the authorized maximum aggregate purchase price (excluding fees, commissions and other ancillary expenses) of the Partnership’s common units that may be repurchased under the 2019 Buyback Program from $2.0 billion to $5.0 billion. 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 9,496,536, 7,556,210 and 7,244,540 common units under the 2019 Buyback Program during the years ended December 31, 2025, 2024 and 2023, respectively. The total cost of these repurchases, including commissions and fees, was $300 million, $219 million and $188 million, respectively. Common units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition. At December 31, 2025, the remaining available capacity under the 2019 Buyback Program was $3.6 billion.

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 23,000,000 of 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, 2025, 2024 and 2023, 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 4,684,726, 6,538,068 and 6,560,588 common units on the open market and delivered them to participants in the DRIP and EUPP during the years ended December 31, 2025, 2024 and 2023, respectively. Apart from $4 million, $3 million and $3 million attributable to the plan discount available to all participants in the EUPP during the years ended December 31, 2025, 2024 and 2023, respectively, the funds used to effect these purchases were sourced from the DRIP and EUPP participants. No other Partnership funds were used to satisfy these obligations. We used open market purchases to satisfy DRIP and EUPP reinvestments in connection with the distribution paid on February 13, 2026.

After taking into account the number of common units delivered under the DRIP through December 31, 2025, we have the capacity to deliver an additional 25,862,040 common units under this plan. Likewise, we have the capacity to deliver an additional 12,532,388 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 5,346,387, 4,990,360 and 4,662,539 new common units to employees in connection with the vesting of phantom unit awards during the years ended December 31, 2025, 2024 and 2023, respectively. See Note 13 for information regarding our phantom unit awards.

Redeemable Preferred Limited Partner Interests

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


Preferred units outstanding at December 31, 2022			50,412
Preferred units outstanding at December 31, 2023			50,412
Paid in-kind distribution to third party			275
Preferred units outstanding at December 31, 2024			50,687
Paid in-kind distribution to third party			291
Conversion of preferred units to common units			(5,566)
Preferred units outstanding at December 31, 2025			45,412

In September 2020, the Partnership issued and sold an aggregate of 50,000 Series A Cumulative Convertible Preferred Units in a private placement transaction. The preferred units represent a new class of limited partner interests authorized under the Partnership Agreement. The stated value of each preferred unit is $1,000 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, 2025, the Partnership made quarterly distributions to its preferred unitholders valued at $4 million, consisting of PIK distributions of 291 new preferred units and $3 million in cash. 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 year ended December 31, 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:

•$1,010 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 December 31, 2025 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. The preferred units held by OTA are presented as treasury units in consolidation since their ultimate disposition remains under the control of the Partnership.

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				Other		Total
	Commodity Derivative Instruments		Interest Rate Derivative Instruments
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
Other comprehensive income (loss) for period, before reclassifications	285		14		–		299
Reclassification of losses (gains) to net income during period	(192)		(7)		–		(199)
Total other comprehensive income (loss) for period	93		7		–		100
Accumulated Other Comprehensive Income (Loss), December 31, 2025	$	184	$	150	$	2	$	336

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		2025		2024
Interest rate derivatives	Interest expense		$	(7)	$	(6)
Commodity derivatives	Revenue		(235)		(249)
Commodity derivatives	Operating costs and expenses		43		71
Total			$	(199)	$	(184)

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:


	December 31,
Consolidated Subsidiary	2025		2024
Breviloba LLC (“Breviloba”)(1)	$	411	$	423

Enterprise Navigator Ethylene Terminal LLC (“ENET”)(2)	240		245
Other (3)	180		189
Total noncontrolling interests in consolidated subsidiaries	$	831	$	857

(1)An affiliate of Kinetik Holdings Inc. owns a noncontrolling 33% equity interest in Breviloba, which owns the Shin Oak NGL Pipeline.

(2)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.

(3)Primarily represents noncontrolling equity interests in NGL fractionation and pipeline businesses.

Net income attributable to noncontrolling interests was $62 million, $69 million and $125 million for the years ended December 31, 2025, 2024 and 2023, respectively.

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
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
2025:
1st Quarter	$	0.5350	4/30/2025	5/14/2025
2nd Quarter	$	0.5450	7/31/2025	8/14/2025
3rd Quarter	$	0.5450	10/31/2025	11/14/2025
4th Quarter	$	0.5500	1/30/2026	2/13/2026

On January 8, 2026, we announced that the Board declared a quarterly cash distribution of $0.55 per common unit, or $2.20 per common unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the fourth quarter of 2025. The quarterly distribution was paid on February 13, 2026 to unitholders of record as of the close of business on January 30, 2026. The total amount paid was $1.2 billion, which includes $11 million for distribution equivalent rights (“DERs”) on phantom unit awards.

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

- Definition

The entire disclosure for equity.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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Reference 19: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2025

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,
	2025		2024		2023
Balance at beginning of period	$	38	$	35	$	54
Charged to costs and expenses	–		3		1

Deductions	(3)		–		(20)
Balance at end of period	$	35	$	38	$	35

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,
	2025		2024
Cash and cash equivalents	$	969	$	583
Restricted cash	276		255
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows	$	1,245	$	838

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, 2025 and 2024, our environmental reserves totaled $36 million and $9 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 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur with sufficient frequency so as to provide pricing information on an ongoing basis (e.g., transactions on the New York Mercantile Exchange (“NYMEX”) and Intercontinental Exchange (“ICE”)). Our Level 1 fair values consist of financial assets and liabilities such as exchange-traded commodity derivative instruments.

•Level 2 fair value measures. Level 2 fair values are based on pricing inputs other than quoted prices in active markets (a Level 1 fair value measure) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and other relevant economic measures. Substantially all of these assumptions (i) are observable in the marketplace throughout the full term of the instrument; (ii) can be derived from observable data; or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Our Level 2 fair values primarily consist of commodity derivative instruments such as forwards, swaps and other instruments transacted on an exchange or over-the-counter and interest rate derivative instruments. The fair values of these derivative instruments are based on observable price quotes for similar products and locations. The fair value of our interest rate derivatives are determined using financial models that incorporate third-party yield curves for the same period as the future interest rate derivative settlements.

•Level 3 fair value measures. Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect management’s ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available to us in the circumstances, which might include our internally developed forecasts. Level 3 inputs are typically used in connection with internally developed valuation methodologies where we make our best estimate of fair value. Valuations using Level 3 inputs are reviewed and approved by members of senior management.

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,
	2025		2024		2023
Impairment charges reflected in operating costs and expenses:
Property, plant and equipment	$	45	$	50	$	18
Other (1)	5		7		12
Total asset impairment charges in operating costs and expenses (2)	50		57		30
Other property, plant and equipment impairment charges (3)	–		–		2
Total asset impairment charges	$	50	$	57	$	32

(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 4 for information regarding impairment charges attributable to property, plant and equipment.

•Impairment Testing for Investments in Unconsolidated Affiliates. We evaluate our equity method investments for impairment when there are events or changes in circumstances that indicate there is a potential loss in value of the investment attributable to an other-than-temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity’s industry. In the event we determine that the value of an investment is not recoverable due to an other-than-temporary decline, we record a non-cash impairment charge to adjust the carrying value of the investment to its estimated fair value. We did not record any non-cash impairment charges related to our equity method investments during the years ended December 31, 2025, 2024 or 2023. See Note 5 for information regarding our equity method investments.

•Impairment Testing for Goodwill. Goodwill, which represents the cost of an acquired business in excess of the fair value of its net assets at the acquisition date, is subject to annual impairment testing in the fourth quarter of each year or when events or changes in circumstances indicate that the carrying amount of the goodwill may not be recoverable. We test goodwill for impairment at the reporting unit (or operating segment) level following guidance in ASU 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” Goodwill impairment charges represent the amount by which a reporting unit’s carrying value (including its respective goodwill) exceeds its fair value, not to exceed the carrying amount of the reporting unit’s 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 December 31, 2025, 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, 2025, 2024 or 2023. 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, which requires substantially all leases be recorded on the balance sheet.

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 effective interest method. 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, however, to a limited extent, some revenues are accounted for under other guidance such as ASC 842, Leases, ASC 845, Nonmonetary Transactions, or ASC 815, 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.

Related Party Transactions

12 Months Ended

Dec. 31, 2025

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,
		2025		2024		2023
Revenues – related parties:
Unconsolidated affiliates		$	52	$	58	$	61
Costs and expenses – related parties:
EPCO and its privately held affiliates		$	1,604	$	1,472	$	1,353
Unconsolidated affiliates		159		185		188
Total		$	1,763	$	1,657	$	1,541

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


	December 31,
	2025		2024

Accounts receivable - related parties:
Unconsolidated affiliates	$	1	$	4

Accounts payable - related parties:
EPCO and its privately held affiliates	$	195	$	180
Unconsolidated affiliates	22		18
Total	$	217	$	198

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

Relationship with EPCO and Affiliates

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

At December 31, 2025, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us:


Total Number of Limited Partner Interests Held			Percentage of Common Units Outstanding
702,259,470 common units			32.5%

Of the total number of Partnership common units held by EPCO and its privately held affiliates, 59,976,464 have been pledged as security under the separate credit facilities of EPCO and its privately held affiliates at December 31, 2025. These credit facilities contain customary and other events of default, including defaults by us and other affiliates of EPCO. An event of default, followed by a foreclosure on the pledged collateral, could ultimately result in a change in ownership of these units and affect the market price of the Partnership’s common units.

The Partnership and Enterprise GP are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are also separate from those of EPCO and its other affiliates. EPCO and its privately held affiliates use cash on hand and cash distributions they receive from us and other investments to fund their other activities and to meet their respective debt obligations, if any. During the years ended December 31, 2025, 2024 and 2023, we paid EPCO and its privately held affiliates cash distributions totaling $1.5 billion, $1.4 billion and $1.3 billion, respectively.

We lease office space from privately held affiliates of EPCO. For the years ended December 31, 2025, 2024 and 2023, we recognized $25 million, $23 million and $13 million, respectively, of related party operating lease expense in connection with these office space leases.

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,
		2025		2024		2023
Operating costs and expenses		$	1,443	$	1,294	$	1,189
General and administrative expenses		134		152		141
Total costs and expenses		$	1,577	$	1,446	$	1,330

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, 2025, 2024 and 2023, we paid Seaway $26 million, $30 million and $27 million, respectively, for pipeline transportation and storage services in connection with our crude oil marketing activities. Revenues from Seaway were $17 million, $23 million and $25 million for the years ended December 31, 2025, 2024 and 2023, respectively.

•For the years ended December 31, 2025, 2024 and 2023, we purchased $72 million, $75 million and $80 million, respectively, of NGLs from VESCO.

•We pay Promix for the transportation, storage and fractionation of NGLs. Expenses with Promix were $39 million, $39 million and $36 million for the years ended December 31, 2025, 2024 and 2023, respectively. In addition, we sell natural gas to Promix for its plant fuel requirements. Revenues from Promix were $12 million, $9 million and $11 million for the years ended December 31, 2025, 2024 and 2023, respectively.

•For the years ended December 31, 2025, 2024 and 2023, we paid Texas Express $3 million, $10 million and $27 million, respectively, for pipeline transportation services.

•We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $15 million, $14 million and $11 million for the years ended December 31, 2025, 2024 and 2023, respectively.

- Definition

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483326/850-10-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480990/946-20-50-2

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480990/946-20-50-5

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480990/946-20-50-6

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477968/946-235-50-2

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477968/946-235-50-2

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.6-07(2)(g)(3))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-1

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.6-07(2)(c))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.6-07(2)(e))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/850/tableOfContent

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483326/850-10-50-6

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483326/850-10-50-1

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483326/850-10-50-1

+ Details

Business Segments and Related Information - Schedule of Total Segment Gross Operating Margin to Income Before Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Segment Reporting [Abstract]
Total segment gross operating margin	$ 10,054	$ 10,018	$ 9,376
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	(2,477)	(2,343)	(2,215)
Asset impairment charges in operating costs and expenses	(50)	(57)	(30)
Net gains (losses) attributable to asset sales and related matters in operating costs and expenses	14	(2)	10
General and administrative costs	(251)	(244)	(231)
Non-refundable payments received from shippers attributable to make-up rights	(55)	(75)	(52)
Subsequent recognition of revenues attributable to make-up rights	31	41	71
Total other expense, net	(1,367)	(1,303)	(1,228)
Income before income taxes	$ 5,899	$ 6,035	$ 5,701

Income Taxes - Schedule of Reconciliation of Provision for Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Pre-Tax Net Book Income (“NBI”)	$ 5,899	$ 6,035	$ 5,701
Tax Jurisdiction of Domicile [Extensible Enumeration]	UNITED STATES	UNITED STATES	UNITED STATES
Amount
Income tax provision at the U.S. federal income tax rate	$ (1,239)	$ (1,267)	$ (1,197)
Partnership income not subject to federal income tax	1,220	1,250	1,181
Texas Margin Tax	(3)	(44)	(49)
Change in valuation allowance	0	0	22
Other	(1)	(4)	(1)
Total provision for income taxes	$ (23)	$ (65)	$ (44)
Percent
Income tax provision at the U.S. federal income tax rate	(21.00%)	(21.00%)	(21.00%)
Partnership income not subject to federal income tax	20.70%	20.70%	20.70%
Texas Margin Tax	(0.10%)	(0.70%)	(0.90%)
Change in valuation allowance	0.00%	0.00%	0.40%
Other	0.00%	(0.10%)	0.00%
Provision for income taxes	(0.40%)	(1.10%)	(0.80%)
Effective income tax rate	(0.40%)	(1.10%)	(0.80%)

Commitments and Contingent Liabilities - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Loss Contingencies [Line Items]
Lessee, operating lease, renewal term	20 years
Operating lease, payments	$ 129	$ 110	$ 87
Finance lease, principal payments	3	0
Operating lease income	$ 16	$ 15	$ 16
Minimum
Loss Contingencies [Line Items]
Lessee, operating lease, term of contract	5 years
Lessee, finance lease, term of contract	4 years
Maximum
Loss Contingencies [Line Items]
Lessee, operating lease, term of contract	30 years
Lessee, finance lease, term of contract	6 years
Subordinated Debt Obligations
Loss Contingencies [Line Items]
Long-term debt	$ 2,300

Related Party Transactions - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Related Party Transaction [Line Items]
Costs and expenses	$ 45,691	$ 49,289	$ 43,248
Revenues	52,596	56,219	49,715
Related Party
Related Party Transaction [Line Items]
Costs and expenses	1,763	1,657	1,541
Revenues	52	58	61
EPCO and its privately held affiliates
Related Party Transaction [Line Items]
Total cash distributions	1,500	1,400	1,300
Operating lease, expense	25	23	13
Costs and expenses	$ 1,604	1,472	1,353
EPCO and its privately held affiliates \| Common Units
Related Party Transaction [Line Items]
Enterprise common units pledged as security (in units)	59,976,464
Unconsolidated affiliates
Related Party Transaction [Line Items]
Costs and expenses	$ 159	185	188
Revenues	52	58	61
Unconsolidated affiliates \| Management/Operator Fees
Related Party Transaction [Line Items]
Costs and expenses	(15)	(14)	(11)
Unconsolidated affiliates \| Seaway Crude Holdings LLC (“Seaway”)
Related Party Transaction [Line Items]
Costs and expenses	26	30	27
Revenues	17	23	25
Unconsolidated affiliates \| Venice Energy Service Company, L.L.C. (“VESCO”)
Related Party Transaction [Line Items]
Costs and expenses	72	75	80
Unconsolidated affiliates \| K/D/S Promix, L.L.C. (“Promix”)
Related Party Transaction [Line Items]
Costs and expenses	39	39	36
Revenues	12	9	11
Unconsolidated affiliates \| Texas Express Pipeline LLC (“Texas Express”)
Related Party Transaction [Line Items]
Costs and expenses	$ 3	$ 10	$ 27

Inventories - Summary of Cost of Sales and Lower of Cost/Net Realizable Value Adjustments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Inventory Disclosure [Abstract]
Cost of sales	$ 38,566	$ 42,580	$ 37,023
Lower of cost or net realizable value adjustments recognized in cost of sales	$ 19	$ 9	$ 31

- Definition

The aggregate costs related to goods produced and sold and services rendered by an entity during the reporting period. This excludes costs incurred during the reporting period related to financial services rendered and other revenue generating activities.

+ References + Details

Revenues (Tables)

12 Months Ended

Dec. 31, 2025

Revenue from Contract with Customer [Abstract]

Schedule of Revenues by Business Segment

The following table presents our revenues by business segment, and further by revenue type, for the years indicated:


	For the Year Ended December 31,
		2025		2024		2023
NGL Pipelines & Services:
Sales of NGLs and related products		$	14,415	$	17,397	$	14,846
Segment midstream services:
Natural gas processing and fractionation		1,261		1,349		1,278
Transportation		1,299		1,151		1,090
Storage and terminals		341		379		431
Total segment midstream services		2,901		2,879		2,799
Total NGL Pipelines & Services		17,316		20,276		17,645
Crude Oil Pipelines & Services:
Sales of crude oil		19,560		20,389		18,185
Segment midstream services:
Transportation		770		779		744
Storage and terminals		431		412		407
Total segment midstream services		1,201		1,191		1,151
Total Crude Oil Pipelines & Services		20,761		21,580		19,336
Natural Gas Pipelines & Services:
Sales of natural gas		2,355		1,458		2,373
Segment midstream services:
Transportation		1,812		1,546		1,403
Total segment midstream services		1,812		1,546		1,403
Total Natural Gas Pipelines & Services		4,167		3,004		3,776
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		9,010		10,013		7,689
Segment midstream services:
Fractionation and isomerization		354		371		282
Transportation, including marine logistics		668		663		660
Storage and terminals		320		312		327
Total segment midstream services		1,342		1,346		1,269
Total Petrochemical & Refined Products Services		10,352		11,359		8,958
Total consolidated revenues		$	52,596	$	56,219	$	49,715

Schedule of 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	2025		2024

Unbilled revenue (current amount)	Prepaid and other current assets	$	6	$	9
Total		$	6	$	9


		December 31,
Contract Liability	Location	2025		2024

Deferred revenue (current amount)	Other current liabilities	$	157	$	168
Deferred revenue (noncurrent)	Other long-term liabilities	261		284
Total		$	418	$	452

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, 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
Amount included in opening balance transferred to other accounts during period (1)	(9)		(192)
Amount recorded during period (2)	86		814
Amounts recorded during period transferred to other accounts (1)	(80)		(650)
Other changes	–		(6)
Balance at December 31, 2025	$	6	$	418

(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.

Schedule of 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, 2025.

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, 2026	$	4,480
One year ended December 31, 2027	4,270
One year ended December 31, 2028	3,836
One year ended December 31, 2029	2,999
One year ended December 31, 2030	2,227
Thereafter	9,294
Total	$	27,106

Investments in Unconsolidated Affiliates - Schedule of Equity Earnings (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Schedule of Equity Method Investments [Line Items]
Equity in income of unconsolidated affiliates	$ 361	$ 408	$ 462
NGL Pipelines & Services
Schedule of Equity Method Investments [Line Items]
Equity in income of unconsolidated affiliates	83	117	133
Crude Oil Pipelines & Services
Schedule of Equity Method Investments [Line Items]
Equity in income of unconsolidated affiliates	271	285	320
Natural Gas Pipelines & Services
Schedule of Equity Method Investments [Line Items]
Equity in income of unconsolidated affiliates	5	5	6
Petrochemical & Refined Products Services
Schedule of Equity Method Investments [Line Items]
Equity in income of unconsolidated affiliates	$ 2	$ 1	$ 3

- Definition

Amount of income (loss) for proportionate share of equity method investee's income (loss).

+ References + Details

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References + Details

STATEMENTS OF CONSOLIDATED OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Revenues:
Revenues	$ 52,596	$ 56,219	$ 49,715
Operating costs and expenses:
Total operating costs and expenses	45,440	49,045	43,017
General and administrative costs:
Total general and administrative costs	251	244	231
Total costs and expenses	45,691	49,289	43,248
Equity in income of unconsolidated affiliates	361	408	462
Operating income	7,266	7,338	6,929
Other income (expense):
Interest expense	(1,401)	(1,352)	(1,269)
Interest income	30	47	27
Other, net	4	2	14
Total other expense, net	(1,367)	(1,303)	(1,228)
Income before income taxes	5,899	6,035	5,701
Provision for income taxes (see Note 16)	(23)	(65)	(44)
Net income	5,876	5,970	5,657
Net income attributable to noncontrolling interests (see Note 8)	(62)	(69)	(125)
Net income attributable to preferred units (see Note 8)	(4)	(4)	(3)
Net income attributable to common unitholders	$ 5,810	$ 5,897	$ 5,529
Earnings per unit: (see Note 11)
Basic earnings per common unit (in dollars per unit)	$ 2.66	$ 2.69	$ 2.52
Diluted earnings per common unit (in dollars per unit)	$ 2.66	$ 2.69	$ 2.52
Nonrelated Party
Revenues:
Revenues	$ 52,544	$ 56,161	$ 49,654
Operating costs and expenses:
Total operating costs and expenses	43,825	47,554	41,632
General and administrative costs:
Total general and administrative costs	103	78	75
Related Party
Revenues:
Revenues	52	58	61
Operating costs and expenses:
Total operating costs and expenses	1,615	1,491	1,385
General and administrative costs:
Total general and administrative costs	148	166	156
Total costs and expenses	$ 1,763	$ 1,657	$ 1,541

Acquisitions - Schedule of Final Fair Value Allocation of Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Millions	Oct. 28, 2024	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Business Combination [Line Items]
Goodwill		$ 5,712	$ 5,712	$ 5,608
Pinon Midstream, LLC
Business Combination [Line Items]
Voting interest acquired	100.00%
Purchase price for 100% interest in Pinon Midstream	$ 953
Cash and cash equivalents	4
Property, plant and equipment	410
Contract-based intangible asset	435
Total identifiable net assets	849
Goodwill	$ 104

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

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+ Details

Income Taxes - Schedule of Income Taxes Paid, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Federal	$ 1	$ 2	$ 3
State	11	18	21
Total	$ 12	$ 20	$ 24

Hedging Activities and Fair Value Measurements - Schedule of Liability Balance Sheet Offsetting (Details) - Commodity derivatives - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	$ 363	$ 495
Gross Amounts Offset in the Balance Sheet	0	0
Amounts of Liabilities Presented in the Balance Sheet	363	495
Financial Instruments	(362)	(495)
Cash Collateral Received	0	0
Cash Collateral Paid	0	0
Amounts That Would Have Been Presented On Net Basis	$ 1	$ 0

- Definition

Amount of right to receive cash collateral under master netting arrangements that have not been offset against derivative liabilities.

+ References + Details

- Definition

Fair value, before effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes liabilities elected not to be offset. Excludes liabilities not subject to a master netting arrangement.

+ References + Details

- Definition

Fair value, after the effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes liabilities not subject to a master netting arrangement and not elected to be offset.

+ References

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+ Details

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

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+ Details

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

Schedule of Allowance for Credit Losses

The following table presents our allowance for credit losses activity for the years indicated:


	For the Year Ended December 31,
	2025		2024		2023
Balance at beginning of period	$	38	$	35	$	54
Charged to costs and expenses	–		3		1

Deductions	(3)		–		(20)
Balance at end of period	$	35	$	38	$	35

Schedule of Cash, Cash Equivalents and Restricted Cash



	December 31,
	2025		2024
Cash and cash equivalents	$	969	$	583
Restricted cash	276		255
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows	$	1,245	$	838

Schedule of 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,
	2025		2024		2023
Impairment charges reflected in operating costs and expenses:
Property, plant and equipment	$	45	$	50	$	18
Other (1)	5		7		12
Total asset impairment charges in operating costs and expenses (2)	50		57		30
Other property, plant and equipment impairment charges (3)	–		–		2
Total asset impairment charges	$	50	$	57	$	32

(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.

Equity-Based Awards - Schedule of Supplemental Information Regarding Phantom Unit Award Activity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Equity-Based Compensation Arrangement by Equity-Based Payment Award [Line Items]
Cash payments made in connection with DERs	$ 44	$ 43	$ 38
Phantom unit awards
Equity-Based Compensation Arrangement by Equity-Based Payment Award [Line Items]
Cash payments made in connection with DERs	44	43	38
Total intrinsic value of phantom unit awards that vested during period	$ 262	$ 199	$ 182

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

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+ Details

Business Segments and Related Information (Tables)

12 Months Ended

Dec. 31, 2025

Segment Reporting [Abstract]

Schedule of Total Segment Gross Operating Margin to Income Before Income Taxes

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,
		2025		2024		2023
Total segment gross operating margin		$	10,054	$	10,018	$	9,376
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)		(2,477)		(2,343)		(2,215)
Asset impairment charges in operating costs and expenses		(50)		(57)		(30)
Net gains (losses) attributable to asset sales and related matters in operating costs and expenses		14		(2)		10
General and administrative costs		(251)		(244)		(231)
Non-refundable payments received from shippers attributable to make-up rights (2)		(55)		(75)		(52)
Subsequent recognition of revenues attributable to make-up rights (3)		31		41		71
Total other expense, net (4)		(1,367)		(1,303)		(1,228)
Income before income taxes		$	5,899	$	6,035	$	5,701

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

(2)Since make-up rights entail a future performance obligation by the pipeline to the shipper, these receipts are recorded as deferred revenue for GAAP purposes; however, these receipts are included in gross operating margin in the period of receipt since they are non-refundable to the shipper.

(3)As deferred revenues attributable to make-up rights are subsequently recognized as revenue under GAAP, gross operating margin must be adjusted to remove such amounts to prevent duplication since the associated non-refundable payments were previously included in gross operating margin.

(4)As presented on our Statements of Consolidated Operations, Total other expense, net is comprised of Interest expense, Interest income and Other, net.

Schedule of 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, 2025
	NGL Pipelines & Services		Crude Oil Pipelines & Services		Natural Gas Pipelines & Services		Petrochemical & Refined Products Services		Segment Total
Segment revenues:
Revenues from third parties	$	17,308	$	20,735	$	4,149	$	10,352	$	52,544
Revenues from related parties	8		26		18		–		52
Intersegment and intrasegment revenues	67,059		42,375		960		21,146		131,540
Total segment revenues	84,375		63,136		5,127		31,498		184,136
Significant segment expenses:
Cost of sales	76,347		61,380		2,746		28,496		168,969
Variable operating costs and expenses (1)	844		140		77		453		1,514
Fixed operating costs and expenses (2)	1,750		408		758		1,129		4,045
Total significant segment expenses	78,941		61,928		3,581		30,078		174,528
Other segment income:
Equity in income of unconsolidated affiliates	83		271		5		2		361
Other segment items (3)	42		22		7		14		85
Total other segment income	125		293		12		16		446
Total segment gross operating margin	$	5,559	$	1,501	$	1,558	$	1,436	$	10,054

Other financial information:
Capital expenditures	$	3,326	$	112	$	1,628	$	554	$	5,620

(1)Variable operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally fluctuate based on utilization.

(2)Fixed operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally remain constant independent of utilization.

(3)Other segment items for each segment primarily represent the following:

•NGL Pipelines & Services – Non-refundable payments received from shippers attributable to make-up rights, subsequent recognition of revenues attributable to make-up rights, and other miscellaneous segment items.

•Crude Oil Pipelines & Services – Other miscellaneous segment items.

•Natural Gas Pipelines & Services – Other miscellaneous segment items.

•Petrochemical & Refined Products Services – Other miscellaneous segment items.


	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	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:

•Crude Oil Pipelines & Services – Other miscellaneous segment items.

•Natural Gas Pipelines & Services – Other miscellaneous segment items.

•Petrochemical & Refined Products Services – Other miscellaneous segment items.


	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:

•Crude Oil Pipelines & Services – Subsequent recognition of revenues attributable to make-up rights.

•Natural Gas Pipelines & Services – Other miscellaneous segment items.

•Petrochemical & Refined Products Services – Other miscellaneous segment items.

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,
		2025		2024		2023
Segment revenues:
NGL Pipelines & Services		$	84,375	$	69,098	$	63,135
Crude Oil Pipelines & Services		63,136		75,995		76,458
Natural Gas Pipelines & Services		5,127		3,671		4,303
Petrochemical & Refined Products Services		31,498		36,711		27,840
Total segment revenues		184,136		185,475		171,736
Elimination of intersegment and intrasegment revenues		(131,540)		(129,256)		(122,021)
Total consolidated revenues		$	52,596	$	56,219	$	49,715

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


	December 31,
	2025		2024

NGL Pipelines & Services	$	24,999	$	21,900
Crude Oil Pipelines & Services	11,097		11,390
Natural Gas Pipelines & Services	13,194		12,260
Petrochemical & Refined Products Services	11,725		11,350
Total segment assets	61,015		56,900
Construction in progress	2,400		4,138
Current assets	13,360		15,133
Other assets	1,127		997
Consolidated total assets	$	77,902	$	77,168

Schedule of Consolidated Revenues and Costs 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,
		2025		2024		2023
Consolidated revenues:
NGL Pipelines & Services		$	17,316	$	20,276	$	17,645
Crude Oil Pipelines & Services		20,761		21,580		19,336
Natural Gas Pipelines & Services		4,167		3,004		3,776
Petrochemical & Refined Products Services		10,352		11,359		8,958
Total consolidated revenues		$	52,596	$	56,219	$	49,715

Consolidated costs and expenses
Operating costs and expenses:
Cost of sales		$	38,566	$	42,580	$	37,023
Other operating costs and expenses (1)		4,287		4,004		3,695
Depreciation, amortization and accretion		2,551		2,402		2,279
Asset impairment charges		50		57		30
Net losses (gains) attributable to asset sales and related matters		(14)		2		(10)
General and administrative costs		251		244		231
Total consolidated costs and expenses		$	45,691	$	49,289	$	43,248

(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 (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
BASIC EARNINGS PER COMMON UNIT
Net income attributable to common unitholders	$ 5,810	$ 5,897	$ 5,529
Earnings allocated to phantom unit awards	(55)	(56)	(50)
Net income allocated to common unitholders	$ 5,755	$ 5,841	$ 5,479
Basic weighted-average number of common units outstanding (in units)	2,166	2,169	2,172
Basic earnings per common unit (in dollars per unit)	$ 2.66	$ 2.69	$ 2.52
DILUTED EARNINGS PER COMMON UNIT
Net income attributable to common unitholders	$ 5,810	$ 5,897	$ 5,529
Net income attributable to preferred units	4	4	3
Net income attributable to limited partners	$ 5,814	$ 5,901	$ 5,532
Diluted weighted-average number of units outstanding:
Distribution-bearing common units (in units)	2,166	2,169	2,172
Phantom units (in units)	20	21	20
Preferred units (in units)	2	2	2
Total (in units)	2,188	2,192	2,194
Diluted earnings per common unit (in dollars per unit)	$ 2.66	$ 2.69	$ 2.52

Capital Accounts - Schedule of Redeemable Preferred Limited Partner Interests (Details) - shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Increase (Decrease) in Temporary Equity [Roll Forward]
Preferred units outstanding, beginning balance (in units)	50,687	50,412
Paid in-kind distribution to third party (in units)	291	275
Conversion and reclassification of preferred units to common units (in units)	(5,566)
Preferred units outstanding, ending balance (in units)	45,412	50,687

Income Taxes - Schedule of Income Tax Provision (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Current portion of income tax provision:
Federal	$ (2)	$ (2)	$ (12)
State	25	(18)	(20)
Total current portion	23	(20)	(32)
Deferred portion of income tax provision:
Federal	(17)	(16)	17
State	(29)	(28)	(29)
Foreign	0	(1)	0
Total deferred portion	(46)	(45)	(12)
Total provision for income taxes	$ (23)	$ (65)	$ (44)

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2025

Supplemental Cash Flow Information [Abstract]

Schedule of Net Effect of Changes in Operating Assets and Liabilities

The following table presents income taxes paid, net of refunds received, during the periods indicated:


	For the Year Ended December 31,
		2025		2024		2023
Federal		$	1	$	2	$	3
State		11		18		21
Total		$	12	$	20	$	24

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


	For the Year Ended December 31,
	2025		2024		2023
Decrease (increase) in:
Accounts receivable – trade	$	2,748	$	(1,453)	$	(810)
Accounts receivable – related parties	3		2		4
Inventories	122		(598)		(714)
Prepaid and other current assets	27		(152)		(651)
Other assets	58		38		31
Increase (decrease) in:
Accounts payable – trade	(147)		(182)		309
Accounts payable – related parties	19		(1)		(33)
Accrued product payables	(2,649)		1,867		849
Accrued interest	29		81		29
Other current liabilities	(182)		15		484
Other long-term liabilities	(152)		(123)		(53)
Net effect of changes in operating accounts	$	(124)	$	(506)	$	(555)

Cash payments for interest, net of $182, $121 and $106 capitalized in 2025, 2024 and 2023, respectively	$	1,352	$	1,255	$	1,228

Schedule of Cash Proceeds from Asset Sales and Other Matters

The following table presents our cash proceeds from asset sales and other matters for the years indicated:


	For the Year Ended December 31,
	2025		2024		2023
Recovery of construction costs (1)	$	–	$	–	$	25
Sale of Transport 4	8		–		–
Sale of Bahia NGL Pipeline ownership interest	60		–		–
Other asset sales	14		14		17
Total	$	82	$	14	$	42

(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.

- Definition

Tabular disclosure of information related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-SubTopic 10
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Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
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+ Details

Commitments and Contingent Liabilities - Schedule of Other Long-Term Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Liabilities, Other than Long-Term Debt, Noncurrent [Abstract]
Noncurrent portion of AROs (see Note 4)	$ 285	$ 259
Deferred revenues – non-current portion (see Note 9)	261	284
Operating lease liability – non-current portion	377	366
Derivative liabilities	16	24
Other	45	17
Total	$ 984	$ 950

Hedging Activities and Fair Value Measurements - Schedule of Unrealized Mark-to-Market Gains (Losses) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Derivative [Line Items]
Total mark-to-market impact on gross operating margin	$ (16)	$ 20	$ (33)
NGL Pipelines & Services
Derivative [Line Items]
Total mark-to-market impact on gross operating margin	(3)	(8)	(25)
Crude Oil Pipelines & Services
Derivative [Line Items]
Total mark-to-market impact on gross operating margin	(4)	21	(5)
Natural Gas Pipelines & Services
Derivative [Line Items]
Total mark-to-market impact on gross operating margin	(10)	5	(1)
Petrochemical & Refined Products Services
Derivative [Line Items]
Total mark-to-market impact on gross operating margin	$ 1	$ 2	$ (2)

Debt Obligations - Schedule of Range of Interest Rates Paid and Weighted-Average Interest Rate Paid (Details)	12 Months Ended
	Dec. 31, 2025
Commercial Paper Notes \| Senior Debt Obligations
Debt Instrument [Line Items]
Weighted-Average Interest Rate Paid	4.50%
EPO Junior Subordinated Notes C \| Subordinated Debt Obligations
Debt Instrument [Line Items]
Weighted-Average Interest Rate Paid	7.30%
EPO Junior Subordinated Notes D \| Subordinated Debt Obligations
Debt Instrument [Line Items]
Weighted-Average Interest Rate Paid	7.50%
Minimum \| Commercial Paper Notes \| Senior Debt Obligations
Debt Instrument [Line Items]
Range of Interest Rates Paid	4.00%
Minimum \| EPO Junior Subordinated Notes C \| Subordinated Debt Obligations
Debt Instrument [Line Items]
Range of Interest Rates Paid	6.83%
Minimum \| EPO Junior Subordinated Notes D \| Subordinated Debt Obligations
Debt Instrument [Line Items]
Range of Interest Rates Paid	7.10%
Maximum \| Commercial Paper Notes \| Senior Debt Obligations
Debt Instrument [Line Items]
Range of Interest Rates Paid	4.68%
Maximum \| EPO Junior Subordinated Notes C \| Subordinated Debt Obligations
Debt Instrument [Line Items]
Range of Interest Rates Paid	7.51%
Maximum \| EPO Junior Subordinated Notes D \| Subordinated Debt Obligations
Debt Instrument [Line Items]
Range of Interest Rates Paid	7.73%

STATEMENTS OF CONSOLIDATED EQUITY - USD ($) $ in Millions	Total	Common Limited Partner Interests	Treasury Units	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests in Consolidated Subsidiaries
Beginning balance at Dec. 31, 2022	$ 27,702	$ 27,555	$ (1,297)	$ 365	$ 1,079
Increase (Decrease) in Partners' Equity [Roll Forward]
Net income	5,654	5,529	0	0	125
Cash distributions paid to common unitholders	(4,301)	(4,301)	0	0	0
Cash payments made in connection with distribution equivalent rights	(38)	(38)	0	0	0
Cash distributions paid to noncontrolling interests	(160)	0	0	0	(160)
Cash contributions from noncontrolling interests	44	0	0	0	44
Repurchase and cancellation of common units under 2019 Buyback Program	(188)	(188)	0	0	0
Amortization of fair value of equity-based awards	170	170	0	0	0
Acquisition of noncontrolling interests	(10)	(8)	0	0	(2)
Cash flow hedges	(58)	0	0	(58)	0
Other, net	(56)	(56)	0	0	0
Ending balance at Dec. 31, 2023	28,759	28,663	(1,297)	307	1,086
Increase (Decrease) in Partners' Equity [Roll Forward]
Net income	5,966	5,897	0	0	69
Cash distributions paid to common unitholders	(4,512)	(4,512)	0	0	0
Cash payments made in connection with distribution equivalent rights	(43)	(43)	0	0	0
Cash distributions paid to noncontrolling interests	(106)	0	0	0	(106)
Cash contributions from noncontrolling interests	90	0	0	0	90
Repurchase and cancellation of common units under 2019 Buyback Program	(219)	(219)	0	0	0
Amortization of fair value of equity-based awards	187	187	0	0	0
Acquisition of noncontrolling interests	(400)	(118)	0	0	(282)
Cash flow hedges	(71)	0	0	(71)	0
Other, net	(62)	(62)	0	0	0
Ending balance at Dec. 31, 2024	29,589	29,793	(1,297)	236	857
Increase (Decrease) in Partners' Equity [Roll Forward]
Net income	5,872	5,810	0	0	62
Cash distributions paid to common unitholders	(4,678)	(4,678)	0	0	0
Cash payments made in connection with distribution equivalent rights	(44)	(44)	0	0	0
Cash distributions paid to noncontrolling interests	(93)	0	0	0	(93)
Cash contributions from noncontrolling interests	5	0	0	0	5
Repurchase and cancellation of common units under 2019 Buyback Program	(300)	(300)	0	0	0
Amortization of fair value of equity-based awards	196	196	0	0	0
Cash flow hedges	100	0	0	100	0
Other, net	(77)	(77)	0	0	0
Ending balance at Dec. 31, 2025	$ 30,570	$ 30,700	$ (1,297)	$ 336	$ 831

Inventories - Inventory Amounts by Product Type (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Inventory Disclosure [Abstract]
NGLs	$ 2,923	$ 2,768
Petrochemicals and refined products	665	652
Crude oil	288	523
Natural gas	8	12
Total	$ 3,884	$ 3,955

Business Segments and Related Information

12 Months Ended

Dec. 31, 2025

Segment Reporting [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 business segment includes our natural gas processing and related NGL marketing activities, NGL pipelines, NGL fractionation facilities, NGL and related product storage facilities, and NGL marine terminals.

•Our Crude Oil Pipelines & Services business segment includes our crude oil pipelines, crude oil storage and marine terminals, and related crude oil marketing activities.

•Our Natural Gas Pipelines & Services business segment includes our natural gas pipeline systems that provide for the gathering, treating and transportation of natural gas. This segment also includes our natural gas marketing activities.

•Our Petrochemical & Refined Products Services business segment includes our (i) propylene production facilities, which include propylene fractionation units and PDH facilities, and related pipelines and marketing activities, (ii) butane isomerization complex and related deisobutanizer operations, (iii) octane enhancement, iBDH and HPIB production facilities, (iv) refined products pipelines, terminals and related marketing activities, (v) ethylene export terminal and related operations; and (vi) marine transportation business.

Our plants, pipelines and other fixed assets are located in the U.S.

Segment Gross Operating Margin

Our CODMs evaluate segment performance based on our financial measure of gross operating margin. Gross operating margin is an important performance measure of the core profitability of our operations, forms the basis of our internal financial reporting, and is used by our CODMs on a monthly basis to monitor budgeted versus actual results. Our CODMs also consider gross operating margin results, in part, when determining how to allocate resources (e.g., employees and capital investments) to each segment, primarily in the annual budget process. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. Gross operating margin is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests. Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies.

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,
		2025		2024		2023
Total segment gross operating margin		$	10,054	$	10,018	$	9,376
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)		(2,477)		(2,343)		(2,215)
Asset impairment charges in operating costs and expenses		(50)		(57)		(30)
Net gains (losses) attributable to asset sales and related matters in operating costs and expenses		14		(2)		10
General and administrative costs		(251)		(244)		(231)
Non-refundable payments received from shippers attributable to make-up rights (2)		(55)		(75)		(52)
Subsequent recognition of revenues attributable to make-up rights (3)		31		41		71
Total other expense, net (4)		(1,367)		(1,303)		(1,228)
Income before income taxes		$	5,899	$	6,035	$	5,701

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

(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, 2025
	NGL Pipelines & Services		Crude Oil Pipelines & Services		Natural Gas Pipelines & Services		Petrochemical & Refined Products Services		Segment Total
Segment revenues:
Revenues from third parties	$	17,308	$	20,735	$	4,149	$	10,352	$	52,544
Revenues from related parties	8		26		18		–		52
Intersegment and intrasegment revenues	67,059		42,375		960		21,146		131,540
Total segment revenues	84,375		63,136		5,127		31,498		184,136
Significant segment expenses:
Cost of sales	76,347		61,380		2,746		28,496		168,969
Variable operating costs and expenses (1)	844		140		77		453		1,514
Fixed operating costs and expenses (2)	1,750		408		758		1,129		4,045
Total significant segment expenses	78,941		61,928		3,581		30,078		174,528
Other segment income:
Equity in income of unconsolidated affiliates	83		271		5		2		361
Other segment items (3)	42		22		7		14		85
Total other segment income	125		293		12		16		446
Total segment gross operating margin	$	5,559	$	1,501	$	1,558	$	1,436	$	10,054

Other financial information:
Capital expenditures	$	3,326	$	112	$	1,628	$	554	$	5,620

(1)Variable operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally fluctuate based on utilization.

(2)Fixed operating costs and expenses represent the cost of operating our plants, pipelines and other fixed assets that generally remain constant independent of utilization.

(3)Other segment items for each segment primarily represent the following:

•Crude Oil Pipelines & Services – Other miscellaneous segment items.

•Natural Gas Pipelines & Services – Other miscellaneous segment items.

•Petrochemical & Refined Products Services – Other miscellaneous segment items.


	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	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:

•Crude Oil Pipelines & Services – Other miscellaneous segment items.

•Natural Gas Pipelines & Services – Other miscellaneous segment items.

•Petrochemical & Refined Products Services – Other miscellaneous segment items.


	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:

•Crude Oil Pipelines & Services – Subsequent recognition of revenues attributable to make-up rights.

•Natural Gas Pipelines & Services – Other miscellaneous segment items.

•Petrochemical & Refined Products Services – Other miscellaneous segment items.

Segment revenues include intersegment and intrasegment transactions, which are generally based on transactions made at market-based rates. Our consolidated revenues reflect the elimination of intercompany transactions. The following table reconciles total segment revenues as reported in the preceding tables to consolidated revenues as presented on our Statements of Consolidated Operations:


	For the Year Ended December 31,
		2025		2024		2023
Segment revenues:
NGL Pipelines & Services		$	84,375	$	69,098	$	63,135
Crude Oil Pipelines & Services		63,136		75,995		76,458
Natural Gas Pipelines & Services		5,127		3,671		4,303
Petrochemical & Refined Products Services		31,498		36,711		27,840
Total segment revenues		184,136		185,475		171,736
Elimination of intersegment and intrasegment revenues		(131,540)		(129,256)		(122,021)
Total consolidated revenues		$	52,596	$	56,219	$	49,715

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,
	2025		2024

NGL Pipelines & Services	$	24,999	$	21,900
Crude Oil Pipelines & Services	11,097		11,390
Natural Gas Pipelines & Services	13,194		12,260
Petrochemical & Refined Products Services	11,725		11,350
Total segment assets	61,015		56,900
Construction in progress	2,400		4,138
Current assets	13,360		15,133
Other assets	1,127		997
Consolidated total assets	$	77,902	$	77,168

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,
		2025		2024		2023
Consolidated revenues:
NGL Pipelines & Services		$	17,316	$	20,276	$	17,645
Crude Oil Pipelines & Services		20,761		21,580		19,336
Natural Gas Pipelines & Services		4,167		3,004		3,776
Petrochemical & Refined Products Services		10,352		11,359		8,958
Total consolidated revenues		$	52,596	$	56,219	$	49,715

Consolidated costs and expenses
Operating costs and expenses:
Cost of sales		$	38,566	$	42,580	$	37,023
Other operating costs and expenses (1)		4,287		4,004		3,695
Depreciation, amortization and accretion		2,551		2,402		2,279
Asset impairment charges		50		57		30
Net losses (gains) attributable to asset sales and related matters		(14)		2		(10)
General and administrative costs		251		244		231
Total consolidated costs and expenses		$	45,691	$	49,289	$	43,248

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. No single customer accounted for 10% or more of our consolidated revenues (thus constituting a “major customer”) for the year ended December 31, 2025. However, for the years ended December 31, 2024 and 2023, Vitol Holding B.V. and its affiliates (collectively, “Vitol”) accounted for $6.45 billion, or 11.5%, and $7.87 billion, or 15.8%, respectively, of our consolidated revenues. Vitol is a global energy and commodity trading company. Revenues earned from Vitol during 2024 and 2023 are included within each of our four business segments.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

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Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 26B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-26B

Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 40
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-40

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/280/tableOfContent

Reference 24: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 26
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-26

Reference 25: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 41
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-41

+ Details

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
ASSETS
Accounts receivable, allowance for credit losses	$ 35	$ 38
Temporary Equity, Other Disclosure
Series A cumulative convertible preferred units outstanding (in units)	45,412	50,687
Limited Partners' Capital Account
Common units issued (in units)	2,161,760,683	2,165,699,962
Common units outstanding (in units)	2,161,760,683	2,165,699,962

Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2025

Equity Method Investments and Joint Ventures [Abstract]

Schedule of 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, 2025	December 31,
		2025		2024
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C. (“VESCO”)	13.1%	$	24	$	24
K/D/S Promix, L.L.C. (“Promix”)	50%	21		22
Baton Rouge Fractionators LLC (“BRF”)	32.2%	12		12
Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”)	50%	21		25
Texas Express Pipeline LLC (“Texas Express”)	35%	287		299
Texas Express Gathering LLC (“TEG”)	45%	32		33
Front Range Pipeline LLC (“Front Range”)	33.3%	175		183
Total NGL Pipelines & Services		572		598
Crude Oil Pipelines & Services:
Seaway Crude Holdings LLC (“Seaway”)	50%	1,120		1,147
Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”)	50%	351		368
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”)	50%	110		113
Total Crude Oil Pipelines & Services		1,581		1,628
Natural Gas Pipelines & Services:
White River Hub, LLC (“White River Hub”)	50%	16		16
Old Ocean Pipeline, LLC (“Old Ocean”)	50%	15		14
Total Natural Gas Pipelines & Services		31		30
Petrochemical & Refined Products Services:
Baton Rouge Propylene Concentrator LLC (“BRPC”)	30%	1		1
Transport 4, LLC (“Transport 4”) (1)		–		2
Total Petrochemical & Refined Products Services		1		3
Total investments in unconsolidated affiliates		$	2,185	$	2,259

(1)In June 2025, we sold our 25% membership interest in Transport 4 to third parties for cash proceeds of $8 million and recorded a $6 million gain.

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


	For the Year Ended December 31,
		2025		2024		2023
NGL Pipelines & Services		$	83	$	117	$	133
Crude Oil Pipelines & Services		271		285		320
Natural Gas Pipelines & Services		5		5		6
Petrochemical & Refined Products Services		2		1		3
Total		$	361	$	408	$	462

Intangible Assets and Goodwill

12 Months Ended

Dec. 31, 2025

Goodwill and Intangible Assets Disclosure [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, 2025						December 31, 2024
	Gross Value		Accumulated Amortization		Carrying Value		Gross Value		Accumulated Amortization		Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	449	$	(289)	$	160	$	449	$	(276)	$	173
Contract-based intangibles	1,050		(177)		873		754		(141)		613
Segment total	1,499		(466)		1,033		1,203		(417)		786
Crude Oil Pipelines & Services:
Customer relationship intangibles	2,195		(710)		1,485		2,195		(627)		1,568
Contract-based intangibles	283		(280)		3		283		(278)		5
Segment total	2,478		(990)		1,488		2,478		(905)		1,573
Natural Gas Pipelines & Services:
Customer relationship intangibles	1,351		(700)		651		1,351		(663)		688
Contract-based intangibles	1,150		(265)		885		1,081		(227)		854
Segment total	2,501		(965)		1,536		2,432		(890)		1,542
Petrochemical & Refined Products Services:
Customer relationship intangibles	181		(99)		82		181		(92)		89
Contract-based intangibles	50		(30)		20		45		(30)		15
Segment total	231		(129)		102		226		(122)		104
Total intangible assets	$	6,709	$	(2,550)	$	4,159	$	6,339	$	(2,334)	$	4,005

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


	For the Year Ended December 31,
		2025		2024		2023
NGL Pipelines & Services		$	49	$	44	$	40
Crude Oil Pipelines & Services		85		100		103
Natural Gas Pipelines & Services		75		56		51
Petrochemical & Refined Products Services		7		7		7
Total		$	216	$	207	$	201

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


2026		2027		2028		2029		2030
$	224	$	225	$	221	$	217	$	217

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, 2025, the carrying value of our portfolio of customer relationship intangible assets was $2.4 billion, the principal components of which were as follows:


	Weighted Average Remaining Amortization Period	December 31, 2025
		Gross Value		Accumulated Amortization		Carrying Value
Basin-specific customer relationships:
EFS Midstream (acquired 2015)	16.4 years	$	1,410	$	(461)	$	949
State Line and Fairplay (acquired 2010)	21.2 years	895		(356)		539
San Juan Gathering (acquired 2004)	13.8 years	331		(280)		51
General customer relationships:
Oiltanking (acquired 2014)	18.0 years	1,193		(386)		807

•The EFS Midstream customer relationships provide us with long-term access to condensate and natural gas producers in the Eagle Ford Shale served by our EFS Midstream System. 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 customer relationships provide us with long-term access to natural gas producers served by our Haynesville and Fairplay Gathering Systems. 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 customer relationships provide us with long-term access to natural gas producers in the San Juan Basin served by our San Juan Gathering System.

•The Oiltanking customer relationships provide us with long-term access to crude oil and refined products storage and terminal customers served at our Houston Ship Channel and Beaumont, Texas terminals.

Contract-based intangible assets

Contract-based intangible assets represent specific commercial rights we acquired in connection with acquisitions. These intangible assets are typically valued using an income approach that incorporate the terms of the agreements. At December 31, 2025, the carrying value of our portfolio of contract-based intangible assets was $1.8 billion, the principal components of which were as follows:


	Weighted Average Remaining Amortization Period	December 31, 2025
		Gross Value		Accumulated Amortization		Carrying Value
Midland Basin customer contracts (acquired 2022)	26.0 years	$	989	$	(113)	$	876
Pinon Midstream customer contracts (acquired 2024)	23.0 years	435		(19)		416
Midland Basin Oxy customer contract (acquired 2025)	23.0 years	360		(5)		355
Jonah natural gas gathering agreements (acquired 2001)	16.0 years	224		(189)		35
Delaware Basin natural gas processing contracts (acquired 2018)	2.1 years	82		(66)		16

•The Midland Basin customer contracts, which we acquired in connection with our acquisition of Navitas Midstream Partners, LLC (“Navitas Midstream”) in February 2022, represents the estimated value we assigned to the acquired long-term contracts with customers that dedicate future lease production to our system. Amortization expense attributable to these contracts is recorded using a units-of-production method based on gathering volumes.

•The Pinon Midstream customer contracts, which we acquired in connection with our acquisition of Pinon Midstream, LLC (“Pinon Midstream”) in October 2024, represents the estimated value we assigned to the acquired long-term contracts with customers that are expected to renew at similar commercial terms. Amortization expense attributable to these contracts is recorded using a units-of-production method based on gathering volumes.

•The Midland Basin Oxy customer contract, which we acquired in connection with our acquisition of an affiliate of Occidental Petroleum Corporation (“Oxy”) in August 2025, represents the estimated value we assigned to the long-term gathering and processing services agreement with Oxy that is expected to renew at similar commercial terms. Amortization expense attributable to this agreement is recorded on a straight-line basis over the expected term of the underlying contract.

•The Jonah natural gas gathering agreements represent the estimated value we assigned to natural gas gathering contracts acquired in 2001 associated with the Jonah Gathering System. Amortization expense attributable to these intangible assets is recorded using a units-of-production method based on gathering volumes.

•The Delaware Basin natural gas processing contracts represent the estimated value we assigned to natural gas processing contracts we acquired in 2018 in connection with our step acquisition of the remaining 50% member interest in Delaware Basin Gas Processing LLC. Amortization expense attributable to these contracts is recorded using a straight-line approach over the terms of the underlying 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 years indicated:


	NGL Pipelines & Services		Crude Oil Pipelines & Services		Natural Gas Pipelines & Services		Petrochemical & Refined Products Services		Consolidated Total
Balance at December 31, 2023 (1)	$	2,811	$	1,841	$	–	$	956	$	5,608
Goodwill related to acquisition (2)	29		–		75		–		104
Balance at December 31, 2024 (1)	2,840		1,841		75		956		5,712

Balance at December 31, 2025 (1)	$	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.

Revenues

12 Months Ended

Dec. 31, 2025

Revenue from Contract with Customer [Abstract]

Revenues

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,
		2025		2024		2023
NGL Pipelines & Services:
Sales of NGLs and related products		$	14,415	$	17,397	$	14,846
Segment midstream services:
Natural gas processing and fractionation		1,261		1,349		1,278
Transportation		1,299		1,151		1,090
Storage and terminals		341		379		431
Total segment midstream services		2,901		2,879		2,799
Total NGL Pipelines & Services		17,316		20,276		17,645
Crude Oil Pipelines & Services:
Sales of crude oil		19,560		20,389		18,185
Segment midstream services:
Transportation		770		779		744
Storage and terminals		431		412		407
Total segment midstream services		1,201		1,191		1,151
Total Crude Oil Pipelines & Services		20,761		21,580		19,336
Natural Gas Pipelines & Services:
Sales of natural gas		2,355		1,458		2,373
Segment midstream services:
Transportation		1,812		1,546		1,403
Total segment midstream services		1,812		1,546		1,403
Total Natural Gas Pipelines & Services		4,167		3,004		3,776
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		9,010		10,013		7,689
Segment midstream services:
Fractionation and isomerization		354		371		282
Transportation, including marine logistics		668		663		660
Storage and terminals		320		312		327
Total segment midstream services		1,342		1,346		1,269
Total Petrochemical & Refined Products Services		10,352		11,359		8,958
Total consolidated revenues		$	52,596	$	56,219	$	49,715

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	2025		2024

Unbilled revenue (current amount)	Prepaid and other current assets	$	6	$	9
Total		$	6	$	9


		December 31,
Contract Liability	Location	2025		2024

Deferred revenue (current amount)	Other current liabilities	$	157	$	168
Deferred revenue (noncurrent)	Other long-term liabilities	261		284
Total		$	418	$	452

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, 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
Amount included in opening balance transferred to other accounts during period (1)	(9)		(192)
Amount recorded during period (2)	86		814
Amounts recorded during period transferred to other accounts (1)	(80)		(650)
Other changes	–		(6)
Balance at December 31, 2025	$	6	$	418

Remaining Performance Obligations


Period	Fixed Consideration
One year ended December 31, 2026	$	4,480
One year ended December 31, 2027	4,270
One year ended December 31, 2028	3,836
One year ended December 31, 2029	2,999
One year ended December 31, 2030	2,227
Thereafter	9,294
Total	$	27,106

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-7

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 9
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-9

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 10
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-10

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-15

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-13

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
-Topic 606
-Publisher FASB
-URI https://asc.fasb.org/606/tableOfContent

+ Details

Cybersecurity Risk Management and Strategy Disclosure	12 Months Ended
Cybersecurity Risk Management and Strategy Disclosure	Dec. 31, 2025
Cybersecurity Risk Management, Strategy, and Governance [Line Items]
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.” and “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

Capital Accounts - Schedule of Noncontrolling Interests (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Noncontrolling Interest [Line Items]
Noncontrolling interests in consolidated subsidiaries	$ 831	$ 857
Breviloba LLC
Noncontrolling Interest [Line Items]
Noncontrolling interests in consolidated subsidiaries	$ 411	423
Breviloba LLC \| Altus Midstream Processing LP
Noncontrolling Interest [Line Items]
Subsidiary, ownership percentage, noncontrolling owner	33.00%
Enterprise Navigator Ethylene Terminal LLC
Noncontrolling Interest [Line Items]
Noncontrolling interests in consolidated subsidiaries	$ 240	245
Enterprise Navigator Ethylene Terminal LLC \| Navigator Ethylene Terminals LLC
Noncontrolling Interest [Line Items]
Subsidiary, ownership percentage, noncontrolling owner	50.00%
Other
Noncontrolling Interest [Line Items]
Noncontrolling interests in consolidated subsidiaries	$ 180	$ 189

Commitments and Contingent Liabilities

12 Months Ended

Dec. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingent Liabilities

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, 2025 and 2024, 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, 2025. A description of each type of contractual obligation follows:


	Payment or Settlement due by Period
Contractual Obligations	Total		2026		2027		2028		2029		2030		Thereafter
Scheduled maturities of debt obligations	$	34,707	$	1,625	$	1,575	$	1,800	$	1,250	$	1,250	$	27,207
Estimated cash interest payments	$	28,309	$	1,578	$	1,509	$	1,477	$	1,409	$	1,354	$	20,982
Operating lease obligations (1)	$	576	$	111	$	73	$	52	$	39	$	36	$	265
Finance lease obligations (2)	$	18	$	4	$	4	$	5	$	3	$	1	$	1
Purchase obligations:
Product purchase commitments:
Estimated payment obligations:
NGLs	$	2,836	$	1,186	$	1,186	$	170	$	131	$	131	$	32
Crude oil	$	4,296	$	1,226	$	1,226	$	965	$	622	$	257	$	–
Other	$	43	$	7	$	8	$	8	$	8	$	7	$	5
Service payment commitments	$	271	$	41	$	38	$	33	$	25	$	24	$	110

Capital expenditure commitments	$	51	$	36	$	15	$	–	$	–	$	–	$	–

(1)As of December 31, 2025, 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 $105 million.

(2)As of December 31, 2025, the difference between the total payments for finance lease obligations and the carrying value of our finance lease liabilities, which represents the present value of future finance lease payments, was $2 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, 2025, 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 2025, 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 2025.

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 agreements to lease office space from affiliates of EPCO and those relating to underground NGL storage caverns we lease from a third party include renewal options that could extend these contracts for up to an additional 20 years. The remainder of our significant operating lease agreements do not provide for additional renewal terms.

Our finance lease agreements consist of leases of certain transportation equipment used in our trucking operations that include options to purchase the leased equipment, which we are reasonably certain to exercise. These lease agreements have terms that range from 4 to 6 years.

The following table presents information regarding operating and finance leases where we are the lessee at December 31, 2025:


Asset Category	ROU Asset Carrying Value (1)		Lease Liability Carrying Value (2)		Weighted- Average Remaining Term	Weighted- Average Discount Rate (3)
Operating leases
Storage and pipeline facilities	$	247	$	246	10 years	4.8	%
Transportation equipment	32		33		3 years	4.8	%
Office and warehouse space	158		192		11 years	3.3	%
Total operating leases	437		471
Finance leases
Transportation equipment	16		16		4 years	4.8	%
Total finance leases	16		16
Total leases	$	453	$	487

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

(2)At December 31, 2025, operating lease liabilities of $94 million and $377 million were included within “Other current liabilities” and “Other long-term liabilities,” respectively. Additionally, at December 31, 2025, finance lease liabilities of $3 million and $13 million were included within “Other current liabilities” and “Other long-term liabilities,” respectively.

(3)The discount rate for each category of assets represents the weighted average of either (i) the implicit rate applicable to the underlying leases (where determinable) or (ii) our incremental borrowing rate adjusted for collateralization (if the implicit rate is not determinable). In general, the discount rates are based on either information available at the lease commencement date or January 1, 2019 for leases existing at the adoption date for ASC 842.

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


	For the Year Ended December 31,
		2025		2024			2023
Long-term leases:
Fixed operating lease expense:
Non-cash lease expense (amortization of ROU assets)		$	109	$	95		$	72
Related accretion expense on lease liability balances		17		17			14
Total fixed operating lease expense		126		112			86
Fixed finance lease expense:
Amortization of ROU assets (1)		2		–		*	–
Interest on finance lease liabilities (1)		1		–		*	–
Total fixed finance lease expense (1)		3		–		*	–
Variable lease expense		18		17			13
Total long-term lease expense		147		129			99
Short-term leases		163		121			111
Total lease expense		$	310	$	250		$	210

(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 $129 million, $110 million and $87 million for the years ended December 31, 2025, 2024 and 2023, respectively. Cash paid for finance leases was $3 million for the year ended December 31, 2025. 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, 2025, 2024 and 2023 was $16 million, $15 million and $16 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, 2025 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 long-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,
	2025		2024
Noncurrent portion of AROs (see Note 4)	$	285	$	259
Deferred revenues – non-current portion (see Note 9)	261		284
Operating lease liability – non-current portion	377		366
Derivative liabilities	16		24
Other	45		17
Total	$	984	$	950

Business Segments and Related Information - Schedule of Segment Financial Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Segment revenues:
Revenues	$ 52,596	$ 56,219	$ 49,715
Significant segment expenses:
Cost of sales	38,566	42,580	37,023
Other segment income:
Equity in income of unconsolidated affiliates	361	408	462
NGL Pipelines & Services
Segment revenues:
Revenues	17,316	20,276	17,645
Other segment income:
Equity in income of unconsolidated affiliates	83	117	133
Crude Oil Pipelines & Services
Segment revenues:
Revenues	20,761	21,580	19,336
Other segment income:
Equity in income of unconsolidated affiliates	271	285	320
Natural Gas Pipelines & Services
Segment revenues:
Revenues	4,167	3,004	3,776
Other segment income:
Equity in income of unconsolidated affiliates	5	5	6
Petrochemical & Refined Products Services
Segment revenues:
Revenues	10,352	11,359	8,958
Other segment income:
Equity in income of unconsolidated affiliates	2	1	3
Nonrelated Party
Segment revenues:
Revenues	52,544	56,161	49,654
Related Party
Segment revenues:
Revenues	52	58	61
Operating Segments
Segment revenues:
Revenues	184,136	185,475	171,736
Significant segment expenses:
Cost of sales	168,969	170,769	157,973
Variable operating costs and expenses	1,514	1,323	1,388
Fixed operating costs and expenses	4,045	3,820	3,464
Total operating costs and expenses	174,528	175,912	162,825
Other segment income:
Equity in income of unconsolidated affiliates	361	408	462
Other segment items	85	47	3
Total other segment income (expense), net	446	455	465
Total segment gross operating margin	10,054	10,018	9,376
Other financial information:
Capital expenditures	5,620	4,544	3,266
Operating Segments \| NGL Pipelines & Services
Segment revenues:
Revenues	84,375	69,098	63,135
Significant segment expenses:
Cost of sales	76,347	61,260	56,143
Variable operating costs and expenses	844	745	741
Fixed operating costs and expenses	1,750	1,682	1,589
Total operating costs and expenses	78,941	63,687	58,473
Other segment income:
Equity in income of unconsolidated affiliates	83	117	133
Other segment items	42	20	103
Total other segment income (expense), net	125	137	236
Total segment gross operating margin	5,559	5,548	4,898
Other financial information:
Capital expenditures	3,326	2,498	1,366
Operating Segments \| Crude Oil Pipelines & Services
Segment revenues:
Revenues	63,136	75,995	76,458
Significant segment expenses:
Cost of sales	61,380	74,098	74,437
Variable operating costs and expenses	140	132	191
Fixed operating costs and expenses	408	414	403
Total operating costs and expenses	61,928	74,644	75,031
Other segment income:
Equity in income of unconsolidated affiliates	271	285	320
Other segment items	22	10	(40)
Total other segment income (expense), net	293	295	280
Total segment gross operating margin	1,501	1,646	1,707
Other financial information:
Capital expenditures	112	161	119
Operating Segments \| Natural Gas Pipelines & Services
Segment revenues:
Revenues	5,127	3,671	4,303
Significant segment expenses:
Cost of sales	2,746	1,656	2,583
Variable operating costs and expenses	77	73	59
Fixed operating costs and expenses	758	676	595
Total operating costs and expenses	3,581	2,405	3,237
Other segment income:
Equity in income of unconsolidated affiliates	5	5	6
Other segment items	7	6	5
Total other segment income (expense), net	12	11	11
Total segment gross operating margin	1,558	1,277	1,077
Other financial information:
Capital expenditures	1,628	932	793
Operating Segments \| Petrochemical & Refined Products Services
Segment revenues:
Revenues	31,498	36,711	27,840
Significant segment expenses:
Cost of sales	28,496	33,755	24,810
Variable operating costs and expenses	453	373	397
Fixed operating costs and expenses	1,129	1,048	877
Total operating costs and expenses	30,078	35,176	26,084
Other segment income:
Equity in income of unconsolidated affiliates	2	1	3
Other segment items	14	11	(65)
Total other segment income (expense), net	16	12	(62)
Total segment gross operating margin	1,436	1,547	1,694
Other financial information:
Capital expenditures	554	953	988
Operating Segments \| Nonrelated Party
Segment revenues:
Revenues	52,544	56,161	49,654
Operating Segments \| Nonrelated Party \| NGL Pipelines & Services
Segment revenues:
Revenues	17,308	20,264	17,635
Operating Segments \| Nonrelated Party \| Crude Oil Pipelines & Services
Segment revenues:
Revenues	20,735	21,546	19,300
Operating Segments \| Nonrelated Party \| Natural Gas Pipelines & Services
Segment revenues:
Revenues	4,149	2,992	3,761
Operating Segments \| Nonrelated Party \| Petrochemical & Refined Products Services
Segment revenues:
Revenues	10,352	11,359	8,958
Operating Segments \| Related Party
Segment revenues:
Revenues	52	58	61
Operating Segments \| Related Party \| NGL Pipelines & Services
Segment revenues:
Revenues	8	12	10
Operating Segments \| Related Party \| Crude Oil Pipelines & Services
Segment revenues:
Revenues	26	34	36
Operating Segments \| Related Party \| Natural Gas Pipelines & Services
Segment revenues:
Revenues	18	12	15
Operating Segments \| Related Party \| Petrochemical & Refined Products Services
Segment revenues:
Revenues	0	0	0
Eliminations
Segment revenues:
Revenues	(131,540)	(129,256)	(122,021)
Eliminations \| NGL Pipelines & Services
Segment revenues:
Revenues	(67,059)	(48,822)	(45,490)
Eliminations \| Crude Oil Pipelines & Services
Segment revenues:
Revenues	(42,375)	(54,415)	(57,122)
Eliminations \| Natural Gas Pipelines & Services
Segment revenues:
Revenues	(960)	(667)	(527)
Eliminations \| Petrochemical & Refined Products Services
Segment revenues:
Revenues	$ (21,146)	$ (25,352)	$ (18,882)

Summary of Significant Accounting Policies - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Accounting Policies [Abstract]
Environmental reserves	$ 36	$ 9
Environmental reserves, financial position not disclosed	environmental reserves

Equity-Based Awards (Tables)

12 Months Ended

Dec. 31, 2025

Share-Based Payment Arrangement [Abstract]

Schedule of Equity-Based Award Compensation Expense

The following table summarizes compensation expense we recognized in connection with equity-based awards for the years indicated:


	For the Year Ended December 31,
		2025		2024		2023
Equity-classified awards:
Phantom unit awards		$	197	$	178	$	166
Profits interest awards		–		10		6
Total		$	197	$	188	$	172

Schedule of Phantom Unit Award Activity

The following table presents phantom unit award activity for the years indicated:


	Number of Units	Weighted- Average Grant Date Fair Value per Unit (1)
Phantom unit awards at December 31, 2022	17,982,945	$	23.94
Granted (2)	8,904,445	$	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 (3)	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
Granted (4)	8,370,315	$	33.08
Vested	(7,815,940)	$	24.46
Forfeited	(564,660)	$	28.44
Phantom unit awards at December 31, 2025	20,581,966	$	28.60

(1)Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.

(2)The aggregate grant date fair value of phantom unit awards issued during 2023 was $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 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.

(4)The aggregate grant date fair value of phantom unit awards issued during 2025 was $277 million based on a grant date market price of the Partnership’s common units ranging from $30.56 to $33.21 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,
		2025		2024		2023
Cash payments made in connection with DERs		$	44	$	43	$	38
Total intrinsic value of phantom unit awards that vested during period		262		199		182

Debt Obligations (Tables)

12 Months Ended

Dec. 31, 2025

Debt Disclosure [Abstract]

Schedule of Consolidated Debt Obligations

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


	December 31,
	2025		2024

EPO senior debt obligations:
Commercial Paper Notes, variable-rates	$	–	$	–
Senior Notes MM, 3.75% fixed-rate, due February 2025	–		1,150
Senior Notes FFF, 5.05% fixed-rate, due January 2026	750		750
Senior Notes PP, 3.70% fixed-rate, due February 2026	875		875
March 2025 $1.5 Billion 364-Day Revolving Credit Agreement, variable-rate, due March 2026 (1)	–		–
Senior Notes HHH, 4.60% fixed-rate, due January 2027	1,000		1,000
Senior Notes SS, 3.95% fixed-rate, due February 2027	575		575
Senior Notes LLL, 4.30% fixed-rate, due June 2028	800		–
Senior Notes WW, 4.15% fixed-rate, due October 2028	1,000		1,000
Senior Notes YY, 3.125% fixed-rate, due July 2029	1,250		1,250
Senior Notes AAA, 2.80% fixed-rate, due January 2030	1,250		1,250
March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement, variable-rate, due March 2030 (2)	–		–
Senior Notes MMM, 4.60% fixed-rate, due January 2031	1,350		–
Senior Notes GGG, 5.35% fixed-rate, due January 2033	1,000		1,000
Senior Notes D, 6.875% fixed-rate, due March 2033	500		500
Senior Notes III, 4.85% fixed-rate, due January 2034	1,000		1,000
Senior Notes H, 6.65% fixed-rate, due October 2034	350		350
Senior Notes JJJ 4.95% fixed-rate, due February 2035	1,100		1,100
Senior Notes J, 5.75% fixed-rate, due March 2035	250		250
Senior Notes NNN, 5.20% fixed-rate, due January 2036	1,500		–
Senior Notes W, 7.55% fixed-rate, due April 2038	400		400
Senior Notes R, 6.125% fixed-rate, due October 2039	600		600
Senior Notes Z, 6.45% fixed-rate, due September 2040	600		600
Senior Notes BB, 5.95% fixed-rate, due February 2041	750		750
Senior Notes DD, 5.70% fixed-rate, due February 2042	600		600
Senior Notes EE, 4.85% fixed-rate, due August 2042	750		750
Senior Notes GG, 4.45% fixed-rate, due February 2043	1,100		1,100
Senior Notes II, 4.85% fixed-rate, due March 2044	1,400		1,400
Senior Notes KK, 5.10% fixed-rate, due February 2045	1,150		1,150
Senior Notes QQ, 4.90% fixed-rate, due May 2046	975		975
Senior Notes UU, 4.25% fixed-rate, due February 2048	1,250		1,250
Senior Notes XX, 4.80% fixed-rate, due February 2049	1,250		1,250
Senior Notes ZZ, 4.20% fixed-rate, due January 2050	1,250		1,250
Senior Notes BBB, 3.70% fixed-rate, due January 2051	1,000		1,000
Senior Notes DDD, 3.20% fixed-rate, due February 2052	1,000		1,000
Senior Notes EEE, 3.30% fixed-rate, due February 2053	1,000		1,000
Senior Notes NN, 4.95% fixed-rate, due October 2054	400		400
Senior Notes KKK, 5.55% fixed-rate, due February 2055	1,400		1,400
Senior Notes CCC, 3.95% fixed-rate, due January 2060	1,000		1,000
Total principal amount of senior debt obligations	32,425		29,925
EPO Junior Subordinated Notes C, variable-rate, due June 2067 (3)	232		232
EPO Junior Subordinated Notes D, variable-rate, due August 2077 (4)	350		350
EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 (5)	1,000		1,000
EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 (6)	700		700
Total principal amount of senior and junior debt obligations	34,707		32,207
Other, non-principal amounts	(312)		(311)
Less current maturities of debt	(1,625)		(1,150)
Total long-term debt	$	32,770	$	30,746

(1)Under the terms of the agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200 million to $1.7 billion at EPO’s election provided certain conditions are met).

(2)Under the terms of the agreement, EPO may borrow up to $2.7 billion (which may be increased by up to $500 million to $3.2 billion at EPO’s election provided certain conditions are met).

(3)Variable rate is reset quarterly and based on 3-month Chicago Mercantile Exchange (“CME”) Term Secured Overnight Financing Rate (“SOFR”) plus (a) a 0.26161% tenor spread adjustment and (b) 2.778%.

(4)Variable rate is reset quarterly and based on 3-month CME Term SOFR plus (a) a 0.26161% tenor spread adjustment and (b) 2.986%.

(5)Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month CME Term SOFR plus (a) a 0.26161% tenor spread adjustment and (b) 3.033%.

(6)Fixed rate of 5.375% through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month CME Term SOFR plus (a) a 0.26161% tenor spread adjustment and (b) 2.57%.

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, 2025:


	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
Commercial Paper Notes	4.00% to 4.68%	4.50%
EPO Junior Subordinated Notes C	6.83% to 7.51%	7.30%
EPO Junior Subordinated Notes D	7.10% to 7.73%	7.50%

Schedule of Maturities of Debt

Scheduled Maturities of Debt

The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at December 31, 2025 for the next five years, and in total thereafter:


			Scheduled Maturities of Debt
	Total		2026		2027		2028		2029		2030		Thereafter

Senior Notes	$	32,425	$	1,625	$	1,575	$	1,800	$	1,250	$	1,250	$	24,925
Junior Subordinated Notes	2,282		–		–		–		–		–		2,282
Total	$	34,707	$	1,625	$	1,575	$	1,800	$	1,250	$	1,250	$	27,207

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(22))
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Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
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-Paragraph 2
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-URI https://asc.fasb.org/1943274/2147477314/942-235-S99-2

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
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+ Details

Equity-Based Awards - Schedule of Equity-Based Award Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Equity-Based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Equity-based payment arrangement, expense	$ 197	$ 188	$ 172
Phantom unit awards
Equity-Based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Equity-based payment arrangement, expense	197	178	166
Profits interest awards
Equity-Based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Equity-based payment arrangement, expense	$ 0	$ 10	$ 6

Summary of Significant Accounting Policies - Schedule of Cash, Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Accounting Policies [Abstract]
Cash and cash equivalents	$ 969	$ 583
Restricted cash	276	255
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows	$ 1,245	$ 838	$ 320	$ 206

Significant Risks and Uncertainties	12 Months Ended
Significant Risks and Uncertainties	Dec. 31, 2025
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 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 $52 million and $39 million at December 31, 2025 and 2024, respectively.

- Definition

The entire disclosure for any concentrations existing at the date of the financial statements that make an entity vulnerable to a reasonably possible, near-term, severe impact. This disclosure informs financial statement users about the general nature of the risk associated with the concentration, and may indicate the percentage of concentration risk as of the balance sheet date.

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-Name Accounting Standards Codification
-Section 50
-Paragraph 21
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2009/role/commonPracticeRef
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+ Details

Capital Accounts - Schedule of Declared Quarterly Cash Distribution Rates (Details) - $ / shares	3 Months Ended
	Dec. 31, 2025	Sep. 30, 2025	Jun. 30, 2025	Mar. 31, 2025	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023
Partners' Capital, Including Portion Attributable to Noncontrolling Interest [Abstract]
Quarterly Distribution Per Common Unit (in dollars per unit)	$ 0.5500	$ 0.5450	$ 0.5450	$ 0.5350	$ 0.5350	$ 0.5250	$ 0.5250	$ 0.5150	$ 0.5150	$ 0.5000	$ 0.5000	$ 0.4900

Partnership Organization and Operations (Details)	12 Months Ended
Partnership Organization and Operations (Details)	Dec. 31, 2025 segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of reportable segments	4

Capital Accounts - Schedule of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	$ 29,589	$ 28,759	$ 27,702
Total other comprehensive income (loss)	100	(71)	(58)
Ending balance	30,570	29,589	28,759
Interest expense	1,401	1,352	1,269
Revenue	(52,596)	(56,219)	(49,715)
Operating costs and expenses	45,440	49,045	43,017
Total	(5,876)	(5,970)	(5,657)
Cash Flow Hedges \| Commodity Derivative Instruments
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	91	154
Other comprehensive income (loss) for period, before reclassifications	285	115
Reclassification of losses (gains) to net income during period	(192)	(178)
Total other comprehensive income (loss)	93	(63)
Ending balance	184	91	154
Cash Flow Hedges \| Interest Rate Derivative Instruments
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	143	151
Other comprehensive income (loss) for period, before reclassifications	14	(2)
Reclassification of losses (gains) to net income during period	(7)	(6)
Total other comprehensive income (loss)	7	(8)
Ending balance	150	143	151
Other
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
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)	0	0
Ending balance	2	2	2
Accumulated Other Comprehensive Income (Loss)
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	236	307
Other comprehensive income (loss) for period, before reclassifications	299	113
Reclassification of losses (gains) to net income during period	(199)	(184)
Total other comprehensive income (loss)	100	(71)
Ending balance	336	236	$ 307
Losses (gains) on cash flow hedges: \| Cash Flow Hedges
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Total	(199)	(184)
Losses (gains) on cash flow hedges: \| Cash Flow Hedges \| Commodity Derivative Instruments
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Revenue	(235)	(249)
Operating costs and expenses	43	71
Losses (gains) on cash flow hedges: \| Cash Flow Hedges \| Interest Rate Derivative Instruments
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Interest expense	$ (7)	$ (6)

Related Party Transactions - Schedule of Accounts Receivable and Accounts Payable (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Related Party
Related Party Transaction [Line Items]
Accounts receivable	$ 1	$ 4
Accounts payable	217	198
Unconsolidated affiliates
Related Party Transaction [Line Items]
Accounts receivable	1	4
Accounts payable	22	18
EPCO and its privately held affiliates
Related Party Transaction [Line Items]
Accounts payable	$ 195	$ 180

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483326/850-10-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483326/850-10-50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
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-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483326/850-10-50-3

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
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-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(k)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
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-Name Accounting Standards Codification
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 310
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-Name Accounting Standards Codification
-Section 45
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481990/310-10-45-13

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.6-07(2)(c)(2)(i))
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
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-Paragraph 1
-Subparagraph (SX 210.6-07(2)(c)(2)(ii))
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-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
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-Name Accounting Standards Codification
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-Paragraph 1
-Subparagraph (SX 210.6-07(2)(g)(3))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-1

+ Details

Hedging Activities and Fair Value Measurements - Schedule of Hedging Instruments Under the FASB's Derivative and Hedging Guidance (Details)	12 Months Ended
	Dec. 31, 2025 TWh Bcf MMBbls
Derivatives designated as hedging instruments: \| Forecasted sales of natural gas (Bcf) \| Cash flow hedge \| Current
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume \| Bcf	45.3
Derivatives designated as hedging instruments: \| Forecasted sales of natural gas (Bcf) \| Cash flow hedge \| Long-Term
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume \| Bcf	18.0
Derivatives designated as hedging instruments: \| Forecasted sales of NGLs (MMBbls) \| Cash flow hedge \| Current
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	0.9
Derivatives designated as hedging instruments: \| Forecasted sales of octane enhancement products (MMBbls) \| Cash flow hedge \| Current
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	2.3
Derivatives designated as hedging instruments: \| Forecasted sales of octane enhancement products (MMBbls) \| Cash flow hedge \| Long-Term
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	0.2
Derivatives designated as hedging instruments: \| Natural gas storage inventory management activities (Bcf) \| Fair value hedge \| Current
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume \| Bcf	1.8
Derivatives designated as hedging instruments: \| Forecasted purchases of NGLs and related hydrocarbon products (MMBbls) \| Cash flow hedge \| Current
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	208.3
Derivatives designated as hedging instruments: \| Forecasted purchases of NGLs and related hydrocarbon products (MMBbls) \| Cash flow hedge \| Long-Term
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	16.9
Derivatives designated as hedging instruments: \| Forecasted sales of NGLs and related hydrocarbon products (MMBbls) \| Cash flow hedge \| Current
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	212.9
Derivatives designated as hedging instruments: \| Forecasted sales of NGLs and related hydrocarbon products (MMBbls) \| Cash flow hedge \| Long-Term
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	27.0
Derivatives designated as hedging instruments: \| Forecasted purchases of refined products (MMBbls) \| Cash flow hedge \| Current
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	3.0
Derivatives designated as hedging instruments: \| Forecasted sales of refined products (MMBbls) \| Cash flow hedge \| Current
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	6.1
Derivatives designated as hedging instruments: \| Forecasted sales of refined products (MMBbls) \| Cash flow hedge \| Long-Term
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	0.1
Derivatives designated as hedging instruments: \| Forecasted purchases of crude oil (MMBbls) \| Cash flow hedge \| Current
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	19.5
Derivatives designated as hedging instruments: \| Forecasted purchases of crude oil (MMBbls) \| Cash flow hedge \| Long-Term
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	7.3
Derivatives designated as hedging instruments: \| Forecasted sales of crude oil (MMBbls) \| Cash flow hedge \| Current
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	28.1
Derivatives designated as hedging instruments: \| Forecasted sales of crude oil (MMBbls) \| Cash flow hedge \| Long-Term
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	14.1
Derivatives designated as hedging instruments: \| Forecasted sales of petrochemical products (MMBbls) \| Cash flow hedge \| Current
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	0.3
Derivatives designated as hedging instruments: \| Forecasted purchases of power related to asset operations (terawatt hours (“TWh”)) \| Cash flow hedge \| Current
Derivative [Line Items]
Volume \| TWh	1.0
Derivatives designated as hedging instruments: \| Forecasted purchases of power related to asset operations (terawatt hours (“TWh”)) \| Cash flow hedge \| Long-Term
Derivative [Line Items]
Volume \| TWh	0.3
Derivatives not designated as hedging instruments: \| Natural gas risk management activities (Bcf) \| Mark-to-market \| Current
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume \| Bcf	39.4
Derivatives not designated as hedging instruments: \| NGL risk management activities (MMBbls) \| Mark-to-market \| Current
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	58.3
Derivatives not designated as hedging instruments: \| NGL risk management activities (MMBbls) \| Mark-to-market \| Long-Term
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	6.4
Derivatives not designated as hedging instruments: \| Refined products risk management activities (MMBbls) \| Mark-to-market \| Current
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	7.8
Derivatives not designated as hedging instruments: \| Crude oil risk management activities (MMBbls) \| Mark-to-market \| Current
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume	4.6

Insider Trading Policies and Procedures	12 Months Ended
Insider Trading Policies and Procedures	Dec. 31, 2025
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

Investments in Unconsolidated Affiliates - Narrative (Details)	Dec. 31, 2025 gatheringSystem
Texas Express Gathering LLC (“TEG”) \| NGL Pipelines & Services
Schedule of Equity Method Investments [Line Items]
Number of NGL gathering systems owned by investee	2

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References + Details

Business Segments and Related Information - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2025 USD ($) segment	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments \| segment	4
Revenues	$ 52,596	$ 56,219	$ 49,715
Vitol Holding B.V.
Segment Reporting Information [Line Items]
Revenues		$ 6,450	$ 7,870
Vitol Holding B.V. \| Revenue Benchmark \| Customer Concentration Risk
Segment Reporting Information [Line Items]
Percent of revenues		11.50%	15.80%

- Definition

For an entity that discloses a concentration risk in relation to quantitative amount, which serves as the "benchmark" (or denominator) in the equation, this concept represents the concentration percentage derived from the division.

+ References + Details

- Definition

Amount of revenue recognized from goods sold, services rendered, insurance premiums, or other activities that constitute an earning process. Includes, but is not limited to, investment and interest income before deduction of interest expense when recognized as a component of revenue, and sales and trading gain (loss).

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 815
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-Section 50
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+ Details

Revenues - Schedule of Significant Changes in Unbilled Revenue and Deferred Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Unbilled Revenue
Balance at beginning of period	$ 9	$ 11	$ 6
Amount included in opening balance transferred to other accounts during period	(9)	(11)	(6)
Amount recorded during period	86	79	81
Amounts recorded during period transferred to other accounts	(80)	(70)	(70)
Other changes	0	0	0
Balance at end of period	6	9	11
Deferred Revenue
Balance at beginning of period	452	519	501
Amount included in opening balance transferred to other accounts during period	(192)	(242)	(271)
Amount recorded during period	814	853	956
Amounts recorded during period transferred to other accounts	(650)	(672)	(656)
Other changes	(6)	(6)	(11)
Balance at end of period	$ 418	$ 452	$ 519

Business Segments and Related Information - Schedule of Segment Revenues as Reported (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Segment Reporting Information [Line Items]
Total consolidated revenues	$ 52,596	$ 56,219	$ 49,715
NGL Pipelines & Services
Segment Reporting Information [Line Items]
Total consolidated revenues	17,316	20,276	17,645
Crude Oil Pipelines & Services
Segment Reporting Information [Line Items]
Total consolidated revenues	20,761	21,580	19,336
Natural Gas Pipelines & Services
Segment Reporting Information [Line Items]
Total consolidated revenues	4,167	3,004	3,776
Petrochemical & Refined Products Services
Segment Reporting Information [Line Items]
Total consolidated revenues	10,352	11,359	8,958
Operating Segments
Segment Reporting Information [Line Items]
Total consolidated revenues	184,136	185,475	171,736
Operating Segments \| NGL Pipelines & Services
Segment Reporting Information [Line Items]
Total consolidated revenues	84,375	69,098	63,135
Operating Segments \| Crude Oil Pipelines & Services
Segment Reporting Information [Line Items]
Total consolidated revenues	63,136	75,995	76,458
Operating Segments \| Natural Gas Pipelines & Services
Segment Reporting Information [Line Items]
Total consolidated revenues	5,127	3,671	4,303
Operating Segments \| Petrochemical & Refined Products Services
Segment Reporting Information [Line Items]
Total consolidated revenues	31,498	36,711	27,840
Eliminations
Segment Reporting Information [Line Items]
Total consolidated revenues	(131,540)	(129,256)	(122,021)
Eliminations \| NGL Pipelines & Services
Segment Reporting Information [Line Items]
Total consolidated revenues	(67,059)	(48,822)	(45,490)
Eliminations \| Crude Oil Pipelines & Services
Segment Reporting Information [Line Items]
Total consolidated revenues	(42,375)	(54,415)	(57,122)
Eliminations \| Natural Gas Pipelines & Services
Segment Reporting Information [Line Items]
Total consolidated revenues	(960)	(667)	(527)
Eliminations \| Petrochemical & Refined Products Services
Segment Reporting Information [Line Items]
Total consolidated revenues	$ (21,146)	$ (25,352)	$ (18,882)

- Definition

+ References

+ Details

Inventories (Tables)

12 Months Ended

Dec. 31, 2025

Inventory Disclosure [Abstract]

Schedule of Inventory Amounts by Product Type

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


	December 31,
	2025		2024

NGLs	$	2,923	$	2,768
Petrochemicals and refined products	665		652
Crude oil	288		523
Natural gas	8		12
Total	$	3,884	$	3,955

Schedule of Cost of Sales and Lower of Cost or Net Realizable Value 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,
		2025		2024		2023
Cost of sales (1)		$	38,566	$	42,580	$	37,023
Lower of cost or net realizable value adjustments recognized in cost of sales		19		9		31

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2025

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 for the years indicated:


	For the Year Ended December 31,
	2025		2024		2023
Decrease (increase) in:
Accounts receivable – trade	$	2,748	$	(1,453)	$	(810)
Accounts receivable – related parties	3		2		4
Inventories	122		(598)		(714)
Prepaid and other current assets	27		(152)		(651)
Other assets	58		38		31
Increase (decrease) in:
Accounts payable – trade	(147)		(182)		309
Accounts payable – related parties	19		(1)		(33)
Accrued product payables	(2,649)		1,867		849
Accrued interest	29		81		29
Other current liabilities	(182)		15		484
Other long-term liabilities	(152)		(123)		(53)
Net effect of changes in operating accounts	$	(124)	$	(506)	$	(555)

Cash payments for interest, net of $182, $121 and $106 capitalized in 2025, 2024 and 2023, respectively	$	1,352	$	1,255	$	1,228

We incurred liabilities for construction in progress that had not been paid at December 31, 2025, 2024 and 2023 of $401 million, $490 million and $400 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,
	2025		2024		2023
Recovery of construction costs (1)	$	–	$	–	$	25
Sale of Transport 4	8		–		–
Sale of Bahia NGL Pipeline ownership interest	60		–		–
Other asset sales	14		14		17
Total	$	82	$	14	$	42

(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.

Hedging Activities and Fair Value Measurements

12 Months Ended

Dec. 31, 2025

Derivative Instruments and Hedges, Assets [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.

During 2025, we entered into four treasury lock transactions to fix the seven-year treasury rate at a weighted-average rate of approximately 3.98% on an aggregate notional amount of $750 million. The purpose of these transactions was to hedge the underlying interest rate risk associated with debt issuances that occurred in June 2025 (see Note 7). Upon settlement of these treasury lock transactions in May 2025, we received total cash proceeds of $14 million. As cash flow hedges, gains on these derivative instruments are reflected as a component of accumulated other comprehensive income and will be amortized to earnings as a component of interest expense over seven years.

During 2024, we terminated and settled treasury lock transactions with a combined notional amount of $3.75 billion and made total cash payments of $33 million.

During 2023, 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, 2025, our predominant commodity hedging strategies consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities, (ii) hedging natural gas processing margins, (iii) hedging the fair value of commodity products held in inventory and (iv) hedging anticipated future purchases of power for certain operations in Southeast Texas.

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

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

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

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

The following table summarizes our portfolio of commodity derivative instruments outstanding at December 31, 2025 (volume measures as noted):


	Volume (1)		Accounting Treatment
Derivative Purpose	Current (2)	Long-Term (2)
Derivatives designated as hedging instruments:
Natural gas processing:
Forecasted sales of natural gas (Bcf)	45.3	18.0	Cash flow hedge
Forecasted sales of NGLs (MMBbls)	0.9	n/a	Cash flow hedge
Octane enhancement:
Forecasted sales of octane enhancement products (MMBbls)	2.3	0.2	Cash flow hedge
Natural gas marketing:
Natural gas storage inventory management activities (Bcf)	1.8	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)	208.3	16.9	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)	212.9	27.0	Cash flow hedge
Refined products marketing:
Forecasted purchases of refined products (MMBbls)	3.0	n/a	Cash flow hedge
Forecasted sales of refined products (MMBbls)	6.1	0.1	Cash flow hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)	19.5	7.3	Cash flow hedge
Forecasted sales of crude oil (MMBbls)	28.1	14.1	Cash flow hedge
Petrochemical marketing:
Forecasted sales of petrochemical products (MMBbls)	0.3	n/a	Cash flow hedge
Commercial energy:
Forecasted purchases of power related to asset operations (terawatt hours (“TWh”))	1.0	0.3	Cash flow hedge

Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (3)	39.4	n/a	Mark-to-market
NGL risk management activities (MMBbls) (3)	58.3	6.4	Mark-to-market
Refined products risk management activities (MMBbls) (3)	7.8	n/a	Mark-to-market
Crude oil risk management activities (MMBbls) (3)	4.6	n/a	Mark-to-market

(1)Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.

(2)The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is March 2029, February 2026 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 $6 million and $11 million at December 31, 2025 and 2024, 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, 2025			December 31, 2024			December 31, 2025			December 31, 2024
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments

Commodity derivatives	Current assets	$	403	Current assets	$	210	Current liabilities	$	312	Current liabilities	$	178
Commodity derivatives	Other assets	26		Other assets	22		Other liabilities	13		Other liabilities	4
Total commodity derivatives		429			232			325			182
Total derivatives designated as hedging instruments		$	429		$	232		$	325		$	182

Derivatives not designated as hedging instruments
Commodity derivatives	Current assets	$	31	Current assets	$	324	Current liabilities	$	35	Current liabilities	$	293
Commodity derivatives	Other assets	–		Other assets	19		Other liabilities	3		Other liabilities	20
Total commodity derivatives		31			343			38			313
Total derivatives not designated as hedging instruments		$	31		$	343		$	38		$	313

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


	Offsetting of Financial Assets and Derivative Assets
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet		Amounts of Assets Presented in the Balance Sheet		Gross Amounts Not Offset in the Balance Sheet						Amounts That Would Have Been Presented On Net Basis
							Financial Instruments		Cash Collateral Received		Cash Collateral Paid
	(i)		(ii)		(iii) = (i) – (ii)		(iv)						(v) = (iii) + (iv)
As of December 31, 2025:

Commodity derivatives	$	460	$	–	$	460	$	(362)	$	(98)	$	–	$	–
As of December 31, 2024:
Commodity derivatives	$	575	$	–	$	575	$	(495)	$	(79)	$	–	$	1


	Offsetting of Financial Liabilities and Derivative Liabilities
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Balance Sheet		Amounts of Liabilities Presented in the Balance Sheet		Gross Amounts Not Offset in the Balance Sheet						Amounts That Would Have Been Presented On Net Basis
							Financial Instruments		Cash Collateral Received		Cash Collateral Paid
	(i)		(ii)		(iii) = (i) – (ii)		(iv)						(v) = (iii) + (iv)
As of December 31, 2025:
Commodity derivatives	$	363	$	–	$	363	$	(362)	$	–	$	–	$	1
As of December 31, 2024:
Commodity derivatives	$	495	$	–	$	495	$	(495)	$	–	$	–	$	–

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,
			2025		2024		2023
Commodity derivatives	Revenue		$	5	$	2	$	7
Total			$	5	$	2	$	7


Derivatives in Fair Value Hedging Relationships	Location		Gain (Loss) Recognized in Income on Hedged Item
		For the Year Ended December 31,
			2025		2024		2023
Commodity derivatives	Revenue		$	(3)	$	9	$	(7)
Total			$	(3)	$	9	$	(7)

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,
		2025		2024		2023
Interest rate derivatives		$	14	$	(2)	$	(36)
Commodity derivatives – Revenue (1)		321		182		81
Commodity derivatives – Operating costs and expenses (1)		(36)		(67)		12
Total		$	299	$	113	$	57

(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,
			2025		2024		2023
Interest rate derivatives	Interest expense		$	7	$	6	$	5
Commodity derivatives	Revenue		235		249		106
Commodity derivatives	Operating costs and expenses		(43)		(71)		4
Total			$	199	$	184	$	115

Over the next twelve months, we expect to reclassify $7 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 $163 million of net gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, with $169 million as an increase in revenue and $6 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,
			2025		2024		2023
Commodity derivatives	Revenue		$	45	$	26	$	213
Commodity derivatives	Operating costs and expenses		(5)		(4)		–
Total			$	40	$	22	$	213

The $40 million net gain recognized for the year ended December 31, 2025 (as noted in the preceding table) from derivatives not designated as hedging instruments consists of $52 million of net realized gains and $12 million of net unrealized mark-to-market losses 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,
	2025		2024		2023
Mark-to-market gains (losses) in gross operating margin:
NGL Pipelines & Services	$	(3)	$	(8)	$	(25)
Crude Oil Pipelines & Services	(4)		21		(5)
Natural Gas Pipelines & Services	(10)		5		(1)
Petrochemical & Refined Products Services	1		2		(2)
Total mark-to-market impact on gross operating margin	$	(16)	$	20	$	(33)

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, 2025 Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Financial assets:

Commodity derivatives:
Value before application of CME Rule 814	$	172	$	777	$	–	$	949
Impact of CME Rule 814	(170)		(319)		–		(489)
Total commodity derivatives	2		458		–		460
Total	$	2	$	458	$	–	$	460

Financial liabilities:
Commodity derivatives:
Value before application of CME Rule 814	$	32	$	710	$	–	$	742
Impact of CME Rule 814	(31)		(348)		–		(379)
Total commodity derivatives	1		362		–		363
Total	$	1	$	362	$	–	$	363

In the aggregate, the fair value of our commodity hedging portfolios at December 31, 2025 was a net derivative asset of $207 million prior to the impact of CME Rule 814.


	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

Financial assets and liabilities recorded on the balance sheet at December 31, 2025 and 2024 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 $32.2 billion and $28.9 billion at December 31, 2025 and 2024, respectively. The aggregate carrying value of these debt obligations was $34.1 billion and $31.6 billion at December 31, 2025 and 2024, respectively. These values are primarily based on quoted market prices for such debt or debt of similar terms and maturities (Level 2) and our credit standing. Changes in market rates of interest affect the fair value of our fixed-rate debt. The carrying values of our variable-rate long-term debt obligations approximate their fair values since the associated interest rates are market-based. We do not have any long-term investments in debt or equity securities recorded at fair value.

Equity-Based Awards - Schedule of Phantom Unit Award Activity (Details) - Phantom unit awards - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Number of Units
Beginning balance (in units)	20,592,251	19,557,251	17,982,945
Granted (in units)	8,370,315	8,881,820	8,904,445
Vested (in units)	(7,815,940)	(7,304,071)	(6,786,085)
Forfeited (in units)	(564,660)	(542,749)	(544,054)
Ending balance (in units)	20,581,966	20,592,251	19,557,251
Weighted-Average Grant Date Fair Value per Unit
Beginning balance (in dollars per unit)	$ 25.21	$ 24.47	$ 23.94
Granted (in dollars per unit)	33.08	26.25	25.80
Vested (in dollars per unit)	24.46	24.51	24.81
Forfeited (in dollars per unit)	28.44	25.39	24.52
Ending balance (in dollars per unit)	$ 28.60	$ 25.21	$ 24.47
Aggregate grant date fair value	$ 277	$ 233	$ 230
Estimated forfeiture rate	2.00%	2.00%	2.00%
Minimum
Weighted-Average Grant Date Fair Value per Unit
Grant date market price of common units (in dollars per unit)	$ 30.56	$ 26.25	$ 25.80
Maximum
Weighted-Average Grant Date Fair Value per Unit
Grant date market price of common units (in dollars per unit)	$ 33.21	$ 29.64	$ 26.70

Revenues - Schedule of Revenues by Business Segment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Disaggregation of Revenue [Line Items]
Revenues	$ 52,596	$ 56,219	$ 49,715
NGL Pipelines & Services
Disaggregation of Revenue [Line Items]
Revenues	17,316	20,276	17,645
NGL Pipelines & Services \| Sales of NGLs and related products
Disaggregation of Revenue [Line Items]
Revenues	14,415	17,397	14,846
NGL Pipelines & Services \| Total segment midstream services
Disaggregation of Revenue [Line Items]
Revenues	2,901	2,879	2,799
NGL Pipelines & Services \| Natural gas processing and fractionation
Disaggregation of Revenue [Line Items]
Revenues	1,261	1,349	1,278
NGL Pipelines & Services \| Transportation
Disaggregation of Revenue [Line Items]
Revenues	1,299	1,151	1,090
NGL Pipelines & Services \| Storage and terminals
Disaggregation of Revenue [Line Items]
Revenues	341	379	431
Crude Oil Pipelines & Services
Disaggregation of Revenue [Line Items]
Revenues	20,761	21,580	19,336
Crude Oil Pipelines & Services \| Sales of crude oil
Disaggregation of Revenue [Line Items]
Revenues	19,560	20,389	18,185
Crude Oil Pipelines & Services \| Total segment midstream services
Disaggregation of Revenue [Line Items]
Revenues	1,201	1,191	1,151
Crude Oil Pipelines & Services \| Transportation
Disaggregation of Revenue [Line Items]
Revenues	770	779	744
Crude Oil Pipelines & Services \| Storage and terminals
Disaggregation of Revenue [Line Items]
Revenues	431	412	407
Natural Gas Pipelines & Services
Disaggregation of Revenue [Line Items]
Revenues	4,167	3,004	3,776
Natural Gas Pipelines & Services \| Sales of natural gas
Disaggregation of Revenue [Line Items]
Revenues	2,355	1,458	2,373
Natural Gas Pipelines & Services \| Total segment midstream services
Disaggregation of Revenue [Line Items]
Revenues	1,812	1,546	1,403
Natural Gas Pipelines & Services \| Transportation
Disaggregation of Revenue [Line Items]
Revenues	1,812	1,546	1,403
Petrochemical & Refined Products Services
Disaggregation of Revenue [Line Items]
Revenues	10,352	11,359	8,958
Petrochemical & Refined Products Services \| Sales of petrochemicals and refined products
Disaggregation of Revenue [Line Items]
Revenues	9,010	10,013	7,689
Petrochemical & Refined Products Services \| Total segment midstream services
Disaggregation of Revenue [Line Items]
Revenues	1,342	1,346	1,269
Petrochemical & Refined Products Services \| Fractionation and isomerization
Disaggregation of Revenue [Line Items]
Revenues	354	371	282
Petrochemical & Refined Products Services \| Transportation
Disaggregation of Revenue [Line Items]
Revenues	668	663	660
Petrochemical & Refined Products Services \| Storage and terminals
Disaggregation of Revenue [Line Items]
Revenues	$ 320	$ 312	$ 327

Acquisitions - Narrative (Details) a in Thousands, $ in Millions			12 Months Ended
	Aug. 22, 2025 USD ($) a mi	Oct. 28, 2024 USD ($) compressorStation MMcf / d acidGasInjectionWell mi	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Business Combination [Line Items]
Cash consideration			$ 5,620	$ 4,544	$ 3,266
Pinon Midstream, LLC
Business Combination [Line Items]
Purchase price for 100% interest in Pinon Midstream		$ 953
Number of miles of natural gas gathering and redelivery pipelines acquired \| mi		43
Number of compressor stations acquired \| compressorStation		5
Hydrogen sulfide and carbon dioxide treating facilities capacity (in cubic feet per day) \| MMcf / d		270
Number of high capacity acid gas injection wells acquired \| acidGasInjectionWell		2
Oxy Natural Gas Gathering Affiliate
Business Combination [Line Items]
Miles of natural gas gathering pipelines acquired \| mi	200
Natural gas gathering and processing services, acres dedicated \| a	73
Cash consideration	$ 583
Cash consideration, excluding transaction costs	581
Transaction related costs	$ 2
Oxy Natural Gas Gathering Affiliate \| Contract-Based Intangible Assets
Business Combination [Line Items]
Underlying contract of acquired finite-lived intangible asset, period before renewal or extension	15 years
Contract based intangible asset estimate life (in years)	23 years

Revenues - Schedule of Unbilled Revenue and Deferred Revenue (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Unbilled revenue (current amount)	$ 6	$ 9
Total	6	9	$ 11	$ 6
Deferred revenue (current amount)	157	168
Deferred revenue (noncurrent)	261	284
Total	$ 418	$ 452	$ 519	$ 501

Income Taxes

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

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, 2025, 2024 and 2023 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, 2025, 2024 and 2023.

Tabular Disclosures Regarding Income Taxes

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


	For the Year Ended December 31,
		2025		2024		2023
Current portion of income tax provision:
Federal		$	(2)	$	(2)	$	(12)
State		25		(18)		(20)
Total current portion		23		(20)		(32)
Deferred portion of income tax provision:
Federal		(17)		(16)		17
State		(29)		(28)		(29)
Foreign		–		(1)		–
Total deferred portion		(46)		(45)		(12)
Total provision for income taxes		$	(23)	$	(65)	$	(44)

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,
		2025					2024					2023
Pre-Tax Net Book Income (“NBI”)		$	5,899				$	6,035				$	5,701

Income tax provision at the U.S. federal income tax rate		(1,239)			(21.0)	%	(1,267)			(21.0)	%	(1,197)			(21.0)	%
Reduction (increase) in provision for income taxes resulting from:
Partnership income not subject to federal income tax		1,220			20.7	%	1,250			20.7	%	1,181			20.7	%
Texas Margin Tax (1)		(3)			(0.1)	%	(44)			(0.7)	%	(49)			(0.9)	%
Change in valuation allowance (2)		–			–	%	–			–	%	22			0.4	%
Other		(1)			–	%	(4)			(0.1)	%	(1)			–	%
Provision for income taxes		$	(23)		(0.4)	%	$	(65)		(1.1)	%	$	(44)		(0.8)	%

Effective income tax rate		(0.4)		%			(1.1)		%			(0.8)		%

(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,
	2025		2024

Deferred tax liabilities:
Attributable to investment in OTA (1)	$	495	$	462
Attributable to property, plant and equipment	172		151
Attributable to investments in other entities	4		5
Other	107		98
Total deferred tax liabilities	778		716
Deferred tax assets:
Net operating loss carryovers (2)	73		56
Temporary differences related to Texas Margin Tax	3		4
Total deferred tax assets	76		60
Total net deferred tax liabilities	$	702	$	656

(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, 2025 has an indefinite carryover period. All losses are subject to limitations on their utilization.

The following table presents income taxes paid, net of refunds received, during the periods indicated:


	For the Year Ended December 31,
		2025		2024		2023
Federal		$	1	$	2	$	3
State		11		18		21
Total		$	12	$	20	$	24

- Definition

The entire disclosure for income tax.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
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-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147478822/944-740-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12

Reference 5: http://www.xbrl.org/2003/role/exampleRef
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-URI https://asc.fasb.org/1943274/2147482663/740-10-55-231

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12B

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147477891/740-270-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147480990/946-20-50-13

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147482685/740-10-50-14

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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Reference 15: http://www.xbrl.org/2003/role/disclosureRef
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Reference 16: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Net income	$ 5,876	$ 5,970	$ 5,657
Cash flow hedges: (see Note 14)
Total cash flow hedges	100	(71)	(58)
Total other comprehensive income (loss)	100	(71)	(58)
Comprehensive income	5,976	5,899	5,599
Comprehensive income attributable to noncontrolling interests	(62)	(69)	(125)
Comprehensive income attributable to preferred units (see Note 8)	(4)	(4)	(3)
Comprehensive income attributable to common unitholders	5,910	5,826	5,471
Commodity Derivative Instruments
Cash flow hedges: (see Note 14)
Changes in fair value of cash flow hedges	285	115	93
Reclassification of gains to net income	(192)	(178)	(110)
Interest Rate Derivative Instruments
Cash flow hedges: (see Note 14)
Changes in fair value of cash flow hedges	14	(2)	(36)
Reclassification of gains to net income	$ (7)	$ (6)	$ (5)

Intangible Assets and Goodwill - Schedule of Contract-Based Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Finite-Lived Intangible Assets [Line Items]
Gross Value	$ 6,709	$ 6,339
Accumulated Amortization	(2,550)	(2,334)
Carrying Value	4,159	$ 4,005
Contract-based intangibles
Finite-Lived Intangible Assets [Line Items]
Carrying Value	$ 1,800
Midland Basin customer contracts (acquired 2022) \| Contract-based intangibles
Finite-Lived Intangible Assets [Line Items]
Weighted Average Remaining Amortization Period	26 years
Gross Value	$ 989
Accumulated Amortization	(113)
Carrying Value	$ 876
Pinon Midstream customer contracts (acquired 2024) \| Contract-based intangibles
Finite-Lived Intangible Assets [Line Items]
Weighted Average Remaining Amortization Period	23 years
Gross Value	$ 435
Accumulated Amortization	(19)
Carrying Value	$ 416
Midland Basin Oxy customer contract (acquired 2025) \| Contract-based intangibles
Finite-Lived Intangible Assets [Line Items]
Weighted Average Remaining Amortization Period	23 years
Gross Value	$ 360
Accumulated Amortization	(5)
Carrying Value	$ 355
Jonah natural gas gathering agreements (acquired 2001) \| Contract-based intangibles
Finite-Lived Intangible Assets [Line Items]
Weighted Average Remaining Amortization Period	16 years
Gross Value	$ 224
Accumulated Amortization	(189)
Carrying Value	$ 35
Delaware Basin natural gas processing contracts (acquired 2018) \| Contract-based intangibles
Finite-Lived Intangible Assets [Line Items]
Weighted Average Remaining Amortization Period	2 years 1 month 6 days
Gross Value	$ 82
Accumulated Amortization	(66)
Carrying Value	$ 16

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Current assets:
Cash and cash equivalents	$ 969	$ 583
Restricted cash	276	255
Inventories (see Note 3)	3,884	3,955
Derivative assets (see Note 14)	434	534
Prepaid and other current assets	1,302	566
Total current assets	13,360	15,133
Property, plant and equipment, net (see Note 4)	51,359	49,062
Investments in unconsolidated affiliates (see Note 5)	2,185	2,259
Intangible assets, net (see Note 6)	4,159	4,005
Goodwill (see Note 6)	5,712	5,712
Other assets	1,127	997
Total assets	77,902	77,168
Current liabilities:
Current maturities of debt (see Note 7)	1,625	1,150
Accrued product payables	8,183	10,777
Accrued interest	566	536
Derivative liabilities (see Note 14)	347	471
Other current liabilities	873	818
Total current liabilities	12,832	15,177
Long-term debt (see Note 7)	32,770	30,746
Deferred tax liabilities (see Note 16)	702	656
Other long-term liabilities	984	950
Commitments and contingent liabilities (see Note 17)
Redeemable preferred limited partner interests: (see Note 8)
Series A cumulative convertible preferred units (“preferred units”) (45,412 units outstanding at December 31, 2025 and 50,687 units outstanding at December 31, 2024	44	50
Partners’ equity:
Common limited partner interests (2,161,760,683 units issued and outstanding at December 31, 2025, 2,165,699,962 units issued and outstanding at December 31, 2024	30,700	29,793
Treasury units, at cost	(1,297)	(1,297)
Accumulated other comprehensive income	336	236
Total partners’ equity	29,739	28,732
Noncontrolling interests in consolidated subsidiaries	831	857
Total equity	30,570	29,589
Total liabilities, preferred units, and equity	77,902	77,168
Nonrelated Party
Current assets:
Accounts receivable, net	6,494	9,236
Current liabilities:
Accounts payable	1,021	1,227
Related Party
Current assets:
Accounts receivable, net	1	4
Current liabilities:
Accounts payable	$ 217	$ 198

Earnings Per Unit

12 Months Ended

Dec. 31, 2025

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,
		2025		2024		2023
BASIC EARNINGS PER COMMON UNIT
Net income attributable to common unitholders		$	5,810	$	5,897	$	5,529
Earnings allocated to phantom unit awards (1)		(55)		(56)		(50)
Net income allocated to common unitholders		$	5,755	$	5,841	$	5,479

Basic weighted-average number of common units outstanding		2,166		2,169		2,172

Basic earnings per common unit		$	2.66	$	2.69	$	2.52

DILUTED EARNINGS PER COMMON UNIT
Net income attributable to common unitholders		$	5,810	$	5,897	$	5,529
Net income attributable to preferred units		4		4		3
Net income attributable to limited partners		$	5,814	$	5,901	$	5,532

Diluted weighted-average number of units outstanding:
Distribution-bearing common units		2,166		2,169		2,172
Phantom units (2)		20		21		20
Preferred units (2)		2		2		2
Total		2,188		2,192		2,194

Diluted earnings per common unit		$	2.66	$	2.69	$	2.52

(1)Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding phantom units.

Hedging Activities and Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Details) - Fair Value, Recurring - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Commodity derivatives:
Impact of CME Rule 814	$ (489)	$ (223)
Total commodity derivatives	460	575
Total	460	575
Commodity derivatives:
Impact of CME Rule 814	(379)	(221)
Total commodity derivatives	363	495
Total	363	495
Value before application of CME Rule 814
Commodity derivatives:
Total commodity derivatives	949	798
Commodity derivatives:
Total commodity derivatives	742	716
Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)
Commodity derivatives:
Impact of CME Rule 814	(170)	(56)
Total commodity derivatives	2	299
Total	2	299
Commodity derivatives:
Impact of CME Rule 814	(31)	(43)
Total commodity derivatives	1	248
Total	1	248
Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) \| Value before application of CME Rule 814
Commodity derivatives:
Total commodity derivatives	172	355
Commodity derivatives:
Total commodity derivatives	32	291
Significant Other Observable Inputs (Level 2)
Commodity derivatives:
Impact of CME Rule 814	(319)	(167)
Total commodity derivatives	458	276
Total	458	276
Commodity derivatives:
Impact of CME Rule 814	(348)	(157)
Total commodity derivatives	362	247
Total	362	247
Significant Other Observable Inputs (Level 2) \| Value before application of CME Rule 814
Commodity derivatives:
Total commodity derivatives	777	443
Commodity derivatives:
Total commodity derivatives	710	404
Significant Unobservable Inputs (Level 3)
Commodity derivatives:
Impact of CME Rule 814	0	0
Total commodity derivatives	0	0
Total	0	0
Commodity derivatives:
Impact of CME Rule 814	0	(21)
Total commodity derivatives	0	0
Total	0	0
Significant Unobservable Inputs (Level 3) \| Value before application of CME Rule 814
Commodity derivatives:
Total commodity derivatives	0	0
Commodity derivatives:
Total commodity derivatives	$ 0	$ 21

Commitments and Contingent Liabilities - Schedule of Consolidated Lease Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Consolidated Lease Expense [Abstract]
Non-cash lease expense (amortization of ROU assets)	$ 109	$ 95	$ 72
Related accretion expense on lease liability balances	17	17	14
Total fixed operating lease expense	126	112	86
Amortization of ROU assets	2	0	0
Interest on finance lease liabilities	1	0	0
Total fixed finance lease expense	3	0	0
Variable lease expense	18	17	13
Total long-term lease expense	147	129	99
Short-term leases	163	121	111
Total lease expense	$ 310	$ 250	$ 210

Business Segments and Related Information - Schedule of Revenues and Costs and Expenses Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Consolidated revenues:
Total consolidated revenues	$ 52,596	$ 56,219	$ 49,715
Operating costs and expenses:
Cost of sales	38,566	42,580	37,023
Other operating costs and expenses	4,287	4,004	3,695
Depreciation, amortization and accretion	2,551	2,402	2,279
Asset impairment charges	50	57	30
Net losses (gains) attributable to asset sales and related matters	(14)	2	(10)
General and administrative costs	251	244	231
Total costs and expenses	45,691	49,289	43,248
NGL Pipelines & Services
Consolidated revenues:
Total consolidated revenues	17,316	20,276	17,645
Crude Oil Pipelines & Services
Consolidated revenues:
Total consolidated revenues	20,761	21,580	19,336
Natural Gas Pipelines & Services
Consolidated revenues:
Total consolidated revenues	4,167	3,004	3,776
Petrochemical & Refined Products Services
Consolidated revenues:
Total consolidated revenues	$ 10,352	$ 11,359	$ 8,958

Hedging Activities and Fair Value Measurements - Schedule of Asset Balance Sheet Offsetting (Details) - Commodity derivatives - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	$ 460	$ 575
Gross Amounts Offset in the Balance Sheet	0	0
Amounts of Assets Presented in the Balance Sheet	460	575
Financial Instruments	(362)	(495)
Cash Collateral Received	(98)	(79)
Cash Collateral Paid	0	0
Amounts That Would Have Been Presented On Net Basis	$ 0	$ 1

- Definition

Fair value, after the effects of master netting arrangements, of a financial asset or other contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes assets not subject to a master netting arrangement and not elected to be offset.

+ References

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+ Details

- Definition

Amount of obligation to return cash collateral under master netting arrangements that have not been offset against derivative assets.

+ References + Details

- Definition

Fair value, before effects of master netting arrangements, of a financial asset or other contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes assets elected not to be offset. Excludes assets not subject to a master netting arrangement.

+ References + Details

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

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+ Details

Debt Obligations

12 Months Ended

Dec. 31, 2025

Debt Disclosure [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,
	2025		2024

EPO senior debt obligations:
Commercial Paper Notes, variable-rates	$	–	$	–
Senior Notes MM, 3.75% fixed-rate, due February 2025	–		1,150
Senior Notes FFF, 5.05% fixed-rate, due January 2026	750		750
Senior Notes PP, 3.70% fixed-rate, due February 2026	875		875
March 2025 $1.5 Billion 364-Day Revolving Credit Agreement, variable-rate, due March 2026 (1)	–		–
Senior Notes HHH, 4.60% fixed-rate, due January 2027	1,000		1,000
Senior Notes SS, 3.95% fixed-rate, due February 2027	575		575
Senior Notes LLL, 4.30% fixed-rate, due June 2028	800		–
Senior Notes WW, 4.15% fixed-rate, due October 2028	1,000		1,000
Senior Notes YY, 3.125% fixed-rate, due July 2029	1,250		1,250
Senior Notes AAA, 2.80% fixed-rate, due January 2030	1,250		1,250
March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement, variable-rate, due March 2030 (2)	–		–
Senior Notes MMM, 4.60% fixed-rate, due January 2031	1,350		–
Senior Notes GGG, 5.35% fixed-rate, due January 2033	1,000		1,000
Senior Notes D, 6.875% fixed-rate, due March 2033	500		500
Senior Notes III, 4.85% fixed-rate, due January 2034	1,000		1,000
Senior Notes H, 6.65% fixed-rate, due October 2034	350		350
Senior Notes JJJ 4.95% fixed-rate, due February 2035	1,100		1,100
Senior Notes J, 5.75% fixed-rate, due March 2035	250		250
Senior Notes NNN, 5.20% fixed-rate, due January 2036	1,500		–
Senior Notes W, 7.55% fixed-rate, due April 2038	400		400
Senior Notes R, 6.125% fixed-rate, due October 2039	600		600
Senior Notes Z, 6.45% fixed-rate, due September 2040	600		600
Senior Notes BB, 5.95% fixed-rate, due February 2041	750		750
Senior Notes DD, 5.70% fixed-rate, due February 2042	600		600
Senior Notes EE, 4.85% fixed-rate, due August 2042	750		750
Senior Notes GG, 4.45% fixed-rate, due February 2043	1,100		1,100
Senior Notes II, 4.85% fixed-rate, due March 2044	1,400		1,400
Senior Notes KK, 5.10% fixed-rate, due February 2045	1,150		1,150
Senior Notes QQ, 4.90% fixed-rate, due May 2046	975		975
Senior Notes UU, 4.25% fixed-rate, due February 2048	1,250		1,250
Senior Notes XX, 4.80% fixed-rate, due February 2049	1,250		1,250
Senior Notes ZZ, 4.20% fixed-rate, due January 2050	1,250		1,250
Senior Notes BBB, 3.70% fixed-rate, due January 2051	1,000		1,000
Senior Notes DDD, 3.20% fixed-rate, due February 2052	1,000		1,000
Senior Notes EEE, 3.30% fixed-rate, due February 2053	1,000		1,000
Senior Notes NN, 4.95% fixed-rate, due October 2054	400		400
Senior Notes KKK, 5.55% fixed-rate, due February 2055	1,400		1,400
Senior Notes CCC, 3.95% fixed-rate, due January 2060	1,000		1,000
Total principal amount of senior debt obligations	32,425		29,925
EPO Junior Subordinated Notes C, variable-rate, due June 2067 (3)	232		232
EPO Junior Subordinated Notes D, variable-rate, due August 2077 (4)	350		350
EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 (5)	1,000		1,000
EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 (6)	700		700
Total principal amount of senior and junior debt obligations	34,707		32,207
Other, non-principal amounts	(312)		(311)
Less current maturities of debt	(1,625)		(1,150)
Total long-term debt	$	32,770	$	30,746

(1)Under the terms of the agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200 million to $1.7 billion at EPO’s election provided certain conditions are met).

(2)Under the terms of the agreement, EPO may borrow up to $2.7 billion (which may be increased by up to $500 million to $3.2 billion at EPO’s election provided certain conditions are met).

(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%.

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, 2025:


	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
Commercial Paper Notes	4.00% to 4.68%	4.50%
EPO Junior Subordinated Notes C	6.83% to 7.51%	7.30%
EPO Junior Subordinated Notes D	7.10% to 7.73%	7.50%

Amounts borrowed under EPO’s March 2025 $1.5 Billion 364-Day Revolving Credit Agreement and March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement bear interest, at EPO’s election, equal to: (i) SOFR, plus an additional variable spread; or (ii) an alternate base rate, which is the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 0.5%, or (c) Adjusted Term SOFR for an interest period of one month in effect on such day plus 1%, and a variable spread. The applicable spreads are determined based on EPO's debt ratings.

Scheduled Maturities of Debt

The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at December 31, 2025 for the next five years, and in total thereafter:


			Scheduled Maturities of Debt
	Total		2026		2027		2028		2029		2030		Thereafter

Senior Notes	$	32,425	$	1,625	$	1,575	$	1,800	$	1,250	$	1,250	$	24,925
Junior Subordinated Notes	2,282		–		–		–		–		–		2,282
Total	$	34,707	$	1,625	$	1,575	$	1,800	$	1,250	$	1,250	$	27,207

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, 2025, EPO had no short-term notes outstanding under its commercial paper program.

March 2025 $1.5 Billion 364-Day Revolving Credit Agreement

In March 2025, EPO entered into a new 364-Day Revolving Credit Agreement (the “March 2025 $1.5 Billion 364-Day Revolving Credit Agreement”) that replaced its prior 364-day revolving credit agreement. As of December 31, 2025, there were no principal amounts outstanding under the March 2025 $1.5 Billion 364-Day Revolving Credit Agreement.

Under the terms of the March 2025 $1.5 Billion 364-Day Revolving Credit Agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200 million to $1.7 billion at EPO’s election, provided certain conditions are met) at a variable interest rate for a term of up to 364 days, subject to the terms and conditions set forth therein. To the extent that principal amounts are outstanding at the maturity date, EPO may elect to have the entire principal balance then outstanding continued as non-revolving term loans for a period of one additional year, payable in March 2027. Borrowings under the March 2025 $1.5 Billion 364-Day Revolving Credit Agreement may be used for working capital, capital expenditures, acquisitions and general company purposes.

The March 2025 $1.5 Billion 364-Day Revolving Credit Agreement contains customary representations, warranties, covenants (affirmative and negative) and events of default, the occurrence of which would permit the lenders to accelerate the maturity date of any amounts borrowed under this credit agreement. The March 2025 $1.5 Billion 364-Day Revolving Credit Agreement also restricts EPO’s ability to pay cash distributions to the Partnership, if an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid or would result therefrom.

EPO’s obligations under the March 2025 $1.5 Billion 364-Day Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by the Partnership.

The March 2025 $1.5 Billion 364-Day Revolving Credit Agreement is scheduled to mature in March 2026. EPO expects to renew this credit agreement during the first quarter of 2026.

March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement

In March 2023, EPO entered into a new revolving credit agreement that we amended in March 2025 to extend its maturity date from March 2028 to March 2030 (the “March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement”). As of December 31, 2025, 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 2030, 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 $3.65 billion, $4.5 billion and $1.75 billion principal amount of senior notes during the years ended December 31, 2025, 2024 and 2023, respectively.

In June 2025, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $500 million principal amount of senior notes due June 2028 (“Senior Notes LLL”), (ii) $750 million principal amount of senior notes due January 2031 (“Senior Notes MMM”) and (iii) $750 million principal amount of senior notes due January 2036 (“Senior Notes NNN”). Senior Notes LLL were issued at 99.869% of their principal amount and have a fixed interest rate of 4.30% per year. Senior Notes MMM were issued at 99.816% of their principal amount and have a fixed interest rate of 4.60% per year. Senior Notes NNN were issued at 99.665% of their principal amount and have a fixed interest rate of 5.20%. Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of amounts outstanding under our commercial paper program.

In November 2025, EPO issued $1.65 billion aggregate principal amount of senior notes comprised of (i) $300 million principal amount of reopened Senior Notes LLL, (ii) $600 million principal amount of reopened Senior Notes MMM and (iii) $750 million principal amount of reopened Senior Notes NNN. The reopened Senior Notes LLL, reopened Senior Notes MMM and reopened Senior Notes NNN were issued at 100.630%, 100.693% and 101.185% of their respective principal amounts, plus accrued interest from June 20, 2025. Each of the reopened Senior Notes LLL, the reopened Senior Notes MMM and the reopened Senior Notes NNN constitutes a further issuance of, and forms a single series with, the original notes of the corresponding series issued in June 2025, trades under the same CUSIP number as the applicable original notes, and has the same terms as to interest, status, redemption or otherwise as such original notes. Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments and acquisitions, and the repayment of debt (including the repayment of all or a portion of $750 million principal amount of 5.05% Senior Notes FFF that matured in January 2026, $875 million principal amount of 3.70% Senior Notes PP that matured in February 2026 and amounts outstanding under our commercial paper program).

EPO’s senior notes are unconditionally guaranteed on an unsecured and unsubordinated basis by the Partnership.

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 with or are subordinate to the junior notes. Each series of EPO’s junior notes rank equal with each other and generally are not redeemable by EPO while such notes bear interest at a fixed annual rate.

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, 2025, EPO had $35 million of letters of credit outstanding primarily related to our insurance program.

Lender Financial Covenants

We were in compliance with the financial covenants of our consolidated debt agreements at December 31, 2025.

Parent-Subsidiary Guarantor Relationships

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

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 8A
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-8A

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(c))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481544/470-10-50-6

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481544/470-10-50-6

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)(3)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
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-Paragraph 1
-Subparagraph (a)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (h)
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Reference 12: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 470
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/470/tableOfContent

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 835
-SubTopic 30
-Name Accounting Standards Codification
-Section 45
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482925/835-30-45-2

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1B

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (g)
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-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1B

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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-Name Accounting Standards Codification
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Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
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-Paragraph 1C
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1C

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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-Name Accounting Standards Codification
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1C

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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-Publisher FASB
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Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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-Publisher FASB
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Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1I
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1I

+ Details

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2025
Audit Information [Abstract]
Auditor Firm ID	34
Auditor Name	DELOITTE & TOUCHE LLP
Auditor Location	Houston, Texas

Intangible Assets and Goodwill - Schedule of Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2025
Goodwill [Roll Forward]
Balance at beginning of period	$ 5,608
Goodwill related to acquisition	104
Balance at end of period	5,712
Goodwill	5,712	$ 5,712
NGL Pipelines & Services
Goodwill [Roll Forward]
Balance at beginning of period	2,811
Goodwill related to acquisition	29
Balance at end of period	2,840
Goodwill	2,840	2,840
Goodwill, impaired, accumulated impairment loss		0
Crude Oil Pipelines & Services
Goodwill [Roll Forward]
Balance at beginning of period	1,841
Goodwill related to acquisition	0
Balance at end of period	1,841
Goodwill	1,841	1,841
Goodwill, impaired, accumulated impairment loss		0
Natural Gas Pipelines & Services
Goodwill [Roll Forward]
Balance at beginning of period	0
Goodwill related to acquisition	75
Balance at end of period	75
Goodwill	75	75
Goodwill, impaired, accumulated impairment loss		296
Petrochemical & Refined Products Services
Goodwill [Roll Forward]
Balance at beginning of period	956
Goodwill related to acquisition	0
Balance at end of period	956
Goodwill	$ 956	956
Goodwill, impaired, accumulated impairment loss		$ 1

- Definition

+ References

+ Details

Summary of Significant Accounting Policies - Schedule of Allowance for Credit Losses (Details) - Allowance for Credit Losses - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at beginning of period	$ 38	$ 35	$ 54
Charged to costs and expenses	0	3	1
Deductions	(3)	0	(20)
Balance at end of period	$ 35	$ 38	$ 35

Property, Plant and Equipment - Schedule of Historical Costs of our Property, Plant and Equipment and Related Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Property, Plant and Equipment, Net, by Type [Abstract]
Subtotal	$ 75,472	$ 71,203
Less accumulated depreciation	24,338	22,330
Subtotal property, plant and equipment, net	51,134	48,873
Capitalized major maintenance costs for reaction-based plants, net of accumulated amortization	225	189
Property, plant and equipment, net	51,359	49,062
Plants, pipelines and facilities
Property, Plant and Equipment, Net, by Type [Abstract]
Subtotal	$ 66,498	60,716
Plants, pipelines and facilities \| Minimum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	3 years
Plants, pipelines and facilities \| Maximum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	45 years
Underground and other storage facilities
Property, Plant and Equipment, Net, by Type [Abstract]
Subtotal	$ 4,871	4,704
Underground and other storage facilities \| Minimum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	5 years
Underground and other storage facilities \| Maximum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	40 years
Transportation equipment
Property, Plant and Equipment, Net, by Type [Abstract]
Subtotal	$ 294	272
Transportation equipment \| Minimum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	3 years
Transportation equipment \| Maximum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	10 years
Marine vessels
Property, Plant and Equipment, Net, by Type [Abstract]
Subtotal	$ 970	949
Marine vessels \| Minimum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	15 years
Marine vessels \| Maximum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	30 years
Land
Property, Plant and Equipment, Net, by Type [Abstract]
Subtotal	$ 439	424
Construction in progress
Property, Plant and Equipment, Net, by Type [Abstract]
Subtotal	$ 2,400	$ 4,138
Distillation-based and reaction-based plants \| Minimum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	20 years
Distillation-based and reaction-based plants \| Maximum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	35 years
Pipelines and related equipment \| Minimum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	5 years
Pipelines and related equipment \| Maximum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	45 years
Terminal facilities \| Minimum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	10 years
Terminal facilities \| Maximum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	35 years
Buildings \| Minimum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	20 years
Buildings \| Maximum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	40 years
Office furniture and equipment \| Minimum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	3 years
Office furniture and equipment \| Maximum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	20 years
Laboratory and shop equipment \| Minimum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	5 years
Laboratory and shop equipment \| Maximum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	35 years
Underground storage facilities \| Minimum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	5 years
Underground storage facilities \| Maximum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	35 years
Storage tanks \| Minimum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	10 years
Storage tanks \| Maximum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	40 years
Water wells \| Minimum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	5 years
Water wells \| Maximum
Property, Plant and Equipment, Net, by Type [Abstract]
Estimated Useful Life in Years	35 years
Capitalized Major Maintenance \| Weighted Average
Property, Plant and Equipment, Net, by Type [Abstract]
Expected remaining amortization period	2 years 6 months

Related Party Transactions - Schedule of Affiliates (Details) - EPCO and its privately held affiliates - Common Units	Dec. 31, 2025 shares
Related Party Transaction [Line Items]
Total Number of Limited Partner Interests Held (in units)	702,259,470
Percentage of Common Units Outstanding	32.50%

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483326/850-10-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483326/850-10-50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483326/850-10-50-3

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(k)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(k)(1))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 310
-SubTopic 10
-Name Accounting Standards Codification
-Section 45
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481990/310-10-45-13

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.6-07(2)(c)(2)(i))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.6-07(2)(c)(2)(ii))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.6-07(2)(g)(3))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-1

+ Details

Capital Accounts - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions				1 Months Ended	3 Months Ended												12 Months Ended
	Feb. 13, 2026	Mar. 27, 2024	Feb. 16, 2024	Sep. 30, 2020	Dec. 31, 2025	Sep. 30, 2025	Jun. 30, 2025	Mar. 31, 2025	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Oct. 31, 2025	Dec. 31, 2022
Registration Statements and Equity Offerings [Line Items]
Borrowings under debt agreements																	$ 88,281	$ 53,715	$ 89,899
Buyback Program:
Stock repurchased and retired during period, (in units)																	9,496,536	7,556,210	7,244,540
Common units acquired in connection with buyback program																	$ 300	$ 219	$ 188
Proceeds from Issuance or Sale of Equity [Abstract]
Common units issued in connection with the vesting of phantom unit awards, net (in units)																	5,346,387	4,990,360	4,662,539
Series A cumulative convertible preferred units outstanding (in units)				50,000	45,412				50,687				50,412				45,412	50,687	50,412		50,412
Temporary equity, par or stated value per share (in dollars per unit)				$ 1,000
Preferred unit distribution rate																	7.25%
Total distributions paid to convertible preferred unitholders																	$ 4	$ 4
Series A cumulative convertible preferred units, paid-in kind distribution (in units)																	291	275
Cash distributions paid to convertible preferred unitholders																	$ 3	$ 3	$ 3
Redemption price per preferred unit on or after September 30, 2025 at unitholder election (in dollars per unit)																	$ 1,000
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%
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 of preferred units that may be converted into common units at unitholder option																	50.00%
Net income attributable to noncontrolling interests																	$ 62	69	125
Payments to noncontrolling interests			$ 375														$ 0	400	10
Number of days after quarter end to distribute available cash																	45 days
Quarterly distribution per common unit (in units)					$ 0.5500	$ 0.5450	$ 0.5450	$ 0.5350	$ 0.5350	$ 0.5250	$ 0.5250	$ 0.5150	$ 0.5150	$ 0.5000	$ 0.5000	$ 0.4900
Annualized distribution per common unit (in dollars per unit)					$ 2.20
Cash payments made in connection with DERs																	$ 44	43	38
Senior Notes
Registration Statements and Equity Offerings [Line Items]
Borrowings under debt agreements																	$ 3,650	$ 4,500	$ 1,750
Subsequent Event
Proceeds from Issuance or Sale of Equity [Abstract]
Cash distributions paid	$ 1,200
Cash payments made in connection with DERs	$ 11
Whitethorn Pipeline Company LLC
Proceeds from Issuance or Sale of Equity [Abstract]
Equity interest acquired			20.00%
Enterprise EF78 LLC
Proceeds from Issuance or Sale of Equity [Abstract]
Equity interest acquired			25.00%
Panola Pipeline Company, LLC
Proceeds from Issuance or Sale of Equity [Abstract]
Equity interest acquired		15.00%
Payments to noncontrolling interests		$ 25
Subsidiary, ownership percentage, parent		70.00%
Common Units
Proceeds from Issuance or Sale of Equity [Abstract]
Partners' equity account, units, treasury units purchased (in units)				54,807,352
Preferred Units
Proceeds from Issuance or Sale of Equity [Abstract]
Treasury Stock, preferred, shares (in units)				855,915
Phantom unit awards
Proceeds from Issuance or Sale of Equity [Abstract]
Common units issued in connection with the vesting of phantom unit awards, net (in units)																	5,346,387	4,990,360	4,662,539
Cash payments made in connection with DERs																	$ 44	$ 43	$ 38
2019 Buyback Program
Buyback Program:
Share repurchase program, authorized, amount						$ 2,000														$ 5,000
Stock repurchased and retired during period, (in units)																	9,496,536	7,556,210	7,244,540
Common units acquired in connection with buyback program																	$ 300	$ 219	$ 188
Share repurchase program, remaining authorized, amount					$ 3,600												3,600
At-the-Market Registration
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance					2,500												2,500
Limited partners capital account remaining units available for issuance in dollars					$ 2,500												$ 2,500
Employee Unit Purchase Plan
Proceeds from Issuance or Sale of Equity [Abstract]
Limited partners' capital account, units authorized (in units)					23,000,000												23,000,000
Employer contribution to EUPP																	$ 4	$ 3	$ 3
Limited partners capital account remaining units available for issuance (in units)					12,532,388												12,532,388
Distribution Reinvestment and Employee Unit Purchase Plans
Proceeds from Issuance or Sale of Equity [Abstract]
Number of common units purchased on the open market and delivered to participants (in units)																	4,684,726	6,538,068	6,560,588
Distribution Reinvestment Plan
Proceeds from Issuance or Sale of Equity [Abstract]
Limited partners capital account remaining units available for issuance (in units)					25,862,040												25,862,040

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Schedule of Income Tax Benefit (Provision)

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


	For the Year Ended December 31,
		2025		2024		2023
Current portion of income tax provision:
Federal		$	(2)	$	(2)	$	(12)
State		25		(18)		(20)
Total current portion		23		(20)		(32)
Deferred portion of income tax provision:
Federal		(17)		(16)		17
State		(29)		(28)		(29)
Foreign		–		(1)		–
Total deferred portion		(46)		(45)		(12)
Total provision for income taxes		$	(23)	$	(65)	$	(44)

Schedule of Reconciliation of Benefit from (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,
		2025					2024					2023
Pre-Tax Net Book Income (“NBI”)		$	5,899				$	6,035				$	5,701

Income tax provision at the U.S. federal income tax rate		(1,239)			(21.0)	%	(1,267)			(21.0)	%	(1,197)			(21.0)	%
Reduction (increase) in provision for income taxes resulting from:
Partnership income not subject to federal income tax		1,220			20.7	%	1,250			20.7	%	1,181			20.7	%
Texas Margin Tax (1)		(3)			(0.1)	%	(44)			(0.7)	%	(49)			(0.9)	%
Change in valuation allowance (2)		–			–	%	–			–	%	22			0.4	%
Other		(1)			–	%	(4)			(0.1)	%	(1)			–	%
Provision for income taxes		$	(23)		(0.4)	%	$	(65)		(1.1)	%	$	(44)		(0.8)	%

Effective income tax rate		(0.4)		%			(1.1)		%			(0.8)		%

Schedule of 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,
	2025		2024

Deferred tax liabilities:
Attributable to investment in OTA (1)	$	495	$	462
Attributable to property, plant and equipment	172		151
Attributable to investments in other entities	4		5
Other	107		98
Total deferred tax liabilities	778		716
Deferred tax assets:
Net operating loss carryovers (2)	73		56
Temporary differences related to Texas Margin Tax	3		4
Total deferred tax assets	76		60
Total net deferred tax liabilities	$	702	$	656

(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, 2025 has an indefinite carryover period. All losses are subject to limitations on their utilization.

Schedule of Income Taxes Paid, Net

The following table presents income taxes paid, net of refunds received, during the periods indicated:


	For the Year Ended December 31,
		2025		2024		2023
Federal		$	1	$	2	$	3
State		11		18		21
Total		$	12	$	20	$	24

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


	For the Year Ended December 31,
	2025		2024		2023
Decrease (increase) in:
Accounts receivable – trade	$	2,748	$	(1,453)	$	(810)
Accounts receivable – related parties	3		2		4
Inventories	122		(598)		(714)
Prepaid and other current assets	27		(152)		(651)
Other assets	58		38		31
Increase (decrease) in:
Accounts payable – trade	(147)		(182)		309
Accounts payable – related parties	19		(1)		(33)
Accrued product payables	(2,649)		1,867		849
Accrued interest	29		81		29
Other current liabilities	(182)		15		484
Other long-term liabilities	(152)		(123)		(53)
Net effect of changes in operating accounts	$	(124)	$	(506)	$	(555)

Cash payments for interest, net of $182, $121 and $106 capitalized in 2025, 2024 and 2023, respectively	$	1,352	$	1,255	$	1,228

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2025

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 in Years	December 31,
		2025		2024

Plants, pipelines and facilities (1)(5)	3-45	$	66,498	$	60,716
Underground and other storage facilities (2)(6)	5-40	4,871		4,704
Transportation equipment (3)	3-10	294		272
Marine vessels (4)	15-30	970		949
Land		439		424
Construction in progress		2,400		4,138
Subtotal		75,472		71,203
Less accumulated depreciation		24,338		22,330
Subtotal property, plant and equipment, net		51,134		48,873
Capitalized major maintenance costs for reaction-based plants, net of accumulated amortization (7)		225		189
Property, plant and equipment, net		$	51,359	$	49,062

(1)Plants, pipelines and facilities include distillation-based and reaction-based plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; buildings; office furniture and equipment; laboratory and shop equipment and related assets.

(2)Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets.

(3)Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations.

(4)Marine vessels include tow boats, barges and related equipment used in our marine transportation business.

(5)In general, the estimated useful lives of major assets within this category are: distillation-based and reaction-based plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; buildings, 20-40 years; office furniture and equipment, 3-20 years; and laboratory and shop equipment, 5-35 years.

(6)In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.

(7)For reaction-based plants, we use the deferral method when accounting for major maintenance activities. Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. On a weighted-average basis, the expected remaining amortization period for these costs is 2.5 years.

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


	For the Year Ended December 31,
		2025		2024		2023
Depreciation expense (1)		$	2,087	$	1,974	$	1,860
Capitalized interest (2)		182		121		106

(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.

Sale of Undivided Joint Interest in Bahia NGL Pipeline

In December 2025, we completed the sale of a 40% undivided joint interest in our Bahia NGL Pipeline to ExxonMobil for approximately $655 million in cash. This divestiture will enhance the utilization of our Bahia NGL Pipeline and integrated value chain by connecting our Delaware Basin natural gas processing facilities and one of the largest producers in the basin to our downstream infrastructure, while simultaneously enabling us to optimize our capital spending program. As a result of this sale, we proportionately consolidate our 60% undivided joint interest in the Bahia NGL Pipeline, and the related operating results are reported within our NGL Pipelines & Services business segment.

No gain or loss was recorded on the disposal as the transaction price equaled the carrying value of the assets transferred to ExxonMobil. The cash consideration is payable in two installments, with $60 million received in December 2025 and the remaining approximately $595 million collected in January 2026. The amount due from ExxonMobil at December 31, 2025 is reflected as a component of “Prepaid and other current assets” on our Consolidated Balance Sheets.

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, 2025 and 2024 includes $141 million and $134 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.

The following table presents information regarding our AROs for the years indicated:


	For the Year Ended December 31,
	2025		2024		2023
ARO liability beginning balance	$	265	$	225	$	234
Liabilities incurred (1)	10		1		5
Revisions in estimated cash flows (2)	1		30		(12)
Liabilities settled (3)	(6)		(4)		(13)
Accretion expense (4)	20		13		11
ARO liability ending balance	$	290	$	265	$	225

(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 $290 million total ARO liability recorded at December 31, 2025, $5 million was reflected as a current liability and $285 million as a long-term liability.

The following table presents our forecast of ARO-related accretion expense for the years indicated:


2026		2027		2028		2029		2030
$	17	$	18	$	19	$	20	$	21

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,
	2025		2024		2023
NGL Pipelines & Services	$	14	$	28	$	12
Crude Oil Pipelines & Services	4		–		1
Natural Gas Pipelines & Services	11		7		5
Petrochemical & Refined Products Services	16		15		2
Total impairment charges for property, plant and equipment	$	45	$	50	$	20

Our impairment charges for the years ended December 31, 2025, 2024 and 2023 are attributable to the complete write-off of assets that are no longer expected to be used or constructed.

Partnership Organization and Operations	12 Months Ended
Partnership Organization and Operations	Dec. 31, 2025
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Partnership Organization and Operations	Note 1. Partnership Organization and Operations We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Our preferred units are not publicly traded. We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership. We conduct substantially all of our business operations through EPO and its consolidated subsidiaries. Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations include: •natural gas gathering, treating, processing, transportation and storage; •NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases (“LPG”) and ethane); •crude oil gathering, transportation, storage, and marine terminals; •propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities; •petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”)); and •a marine transportation business that operates on key U.S. inland and intracoastal waterway systems. Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers. See Note 15 for information regarding related party matters. Our 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.

Capital Accounts - Schedule of Changes in Outstanding Units (Details) - shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Increase (Decrease) in Partners' Capital [Roll Forward]
Common units outstanding, beginning balance (in units)	2,165,699,962	2,168,245,238	2,170,806,347
Common unit repurchases under 2019 Buyback Program (in units)	(9,496,536)	(7,556,210)	(7,244,540)
Common units issued in connection with the vesting of phantom unit awards, net (in units)	5,346,387	4,990,360	4,662,539
Conversion of preferred units to common units (in units)	194,472
Other (in units)	16,398	20,574	20,892
Common units outstanding, ending balance (in units)	2,161,760,683	2,165,699,962	2,168,245,238

Equity-Based Awards

12 Months Ended

Dec. 31, 2025

Share-Based Payment Arrangement [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,
		2025		2024		2023
Equity-classified awards:
Phantom unit awards		$	197	$	178	$	166
Profits interest awards		–		10		6
Total		$	197	$	188	$	172

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, 2025. 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, 2025, a total of 97,704,053 additional common units were available for issuance. After taking into account tax withholding requirements, we issued 5,346,387, 4,990,360 and 4,662,539 common units in connection with the vesting of phantom unit awards in the years ended December 31, 2025, 2024 and 2023, 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 (1)
Phantom unit awards at December 31, 2022	17,982,945	$	23.94
Granted (2)	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 (3)	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
Granted (4)	8,370,315	$	33.08
Vested	(7,815,940)	$	24.46
Forfeited	(564,660)	$	28.44
Phantom unit awards at December 31, 2025	20,581,966	$	28.60

(1)Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.

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,
		2025		2024		2023
Cash payments made in connection with DERs		$	44	$	43	$	38
Total intrinsic value of phantom unit awards that vested during period		262		199		182

For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $229 million at December 31, 2025, of which our share of such cost is currently estimated to be $181 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 2.2 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 EPD IV and EPCO II vested in March 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 residual profits, 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 Value Measurements (Tables)

12 Months Ended

Dec. 31, 2025

Derivative Instruments and Hedges, Assets [Abstract]

Schedule of Hedging Instruments Under the FASB's Derivative and Hedging Guidance

The following table summarizes our portfolio of commodity derivative instruments outstanding at December 31, 2025 (volume measures as noted):


	Volume (1)		Accounting Treatment
Derivative Purpose	Current (2)	Long-Term (2)
Derivatives designated as hedging instruments:
Natural gas processing:
Forecasted sales of natural gas (Bcf)	45.3	18.0	Cash flow hedge
Forecasted sales of NGLs (MMBbls)	0.9	n/a	Cash flow hedge
Octane enhancement:
Forecasted sales of octane enhancement products (MMBbls)	2.3	0.2	Cash flow hedge
Natural gas marketing:
Natural gas storage inventory management activities (Bcf)	1.8	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)	208.3	16.9	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)	212.9	27.0	Cash flow hedge
Refined products marketing:
Forecasted purchases of refined products (MMBbls)	3.0	n/a	Cash flow hedge
Forecasted sales of refined products (MMBbls)	6.1	0.1	Cash flow hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)	19.5	7.3	Cash flow hedge
Forecasted sales of crude oil (MMBbls)	28.1	14.1	Cash flow hedge
Petrochemical marketing:
Forecasted sales of petrochemical products (MMBbls)	0.3	n/a	Cash flow hedge
Commercial energy:
Forecasted purchases of power related to asset operations (terawatt hours (“TWh”))	1.0	0.3	Cash flow hedge

Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (3)	39.4	n/a	Mark-to-market
NGL risk management activities (MMBbls) (3)	58.3	6.4	Mark-to-market
Refined products risk management activities (MMBbls) (3)	7.8	n/a	Mark-to-market
Crude oil risk management activities (MMBbls) (3)	4.6	n/a	Mark-to-market

(3)Reflects the use of derivative instruments to manage risks associated with our transportation, processing and storage assets.

Schedule of 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, 2025			December 31, 2024			December 31, 2025			December 31, 2024
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments

Commodity derivatives	Current assets	$	403	Current assets	$	210	Current liabilities	$	312	Current liabilities	$	178
Commodity derivatives	Other assets	26		Other assets	22		Other liabilities	13		Other liabilities	4
Total commodity derivatives		429			232			325			182
Total derivatives designated as hedging instruments		$	429		$	232		$	325		$	182

Derivatives not designated as hedging instruments
Commodity derivatives	Current assets	$	31	Current assets	$	324	Current liabilities	$	35	Current liabilities	$	293
Commodity derivatives	Other assets	–		Other assets	19		Other liabilities	3		Other liabilities	20
Total commodity derivatives		31			343			38			313
Total derivatives not designated as hedging instruments		$	31		$	343		$	38		$	313

Schedule of Offsetting Financial Assets

The following tables present our derivative instruments subject to such arrangements at the dates indicated:


	Offsetting of Financial Assets and Derivative Assets
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet		Amounts of Assets Presented in the Balance Sheet		Gross Amounts Not Offset in the Balance Sheet						Amounts That Would Have Been Presented On Net Basis
							Financial Instruments		Cash Collateral Received		Cash Collateral Paid
	(i)		(ii)		(iii) = (i) – (ii)		(iv)						(v) = (iii) + (iv)
As of December 31, 2025:

Commodity derivatives	$	460	$	–	$	460	$	(362)	$	(98)	$	–	$	–
As of December 31, 2024:
Commodity derivatives	$	575	$	–	$	575	$	(495)	$	(79)	$	–	$	1

Schedule of Offsetting Financial Liabilities


	Offsetting of Financial Liabilities and Derivative Liabilities
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Balance Sheet		Amounts of Liabilities Presented in the Balance Sheet		Gross Amounts Not Offset in the Balance Sheet						Amounts That Would Have Been Presented On Net Basis
							Financial Instruments		Cash Collateral Received		Cash Collateral Paid
	(i)		(ii)		(iii) = (i) – (ii)		(iv)						(v) = (iii) + (iv)
As of December 31, 2025:
Commodity derivatives	$	363	$	–	$	363	$	(362)	$	–	$	–	$	1
As of December 31, 2024:
Commodity derivatives	$	495	$	–	$	495	$	(495)	$	–	$	–	$	–

Schedule of 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,
			2025		2024		2023
Commodity derivatives	Revenue		$	5	$	2	$	7
Total			$	5	$	2	$	7


Derivatives in Fair Value Hedging Relationships	Location		Gain (Loss) Recognized in Income on Hedged Item
		For the Year Ended December 31,
			2025		2024		2023
Commodity derivatives	Revenue		$	(3)	$	9	$	(7)
Total			$	(3)	$	9	$	(7)

Schedule of Derivative Instruments Effects on Statements of Comprehensive Income


Derivatives in Cash Flow Hedging Relationships		Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative
	For the Year Ended December 31,
		2025		2024		2023
Interest rate derivatives		$	14	$	(2)	$	(36)
Commodity derivatives – Revenue (1)		321		182		81
Commodity derivatives – Operating costs and expenses (1)		(36)		(67)		12
Total		$	299	$	113	$	57

(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.

Schedule of 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,
			2025		2024		2023
Interest rate derivatives	Interest expense		$	7	$	6	$	5
Commodity derivatives	Revenue		235		249		106
Commodity derivatives	Operating costs and expenses		(43)		(71)		4
Total			$	199	$	184	$	115

Schedule of 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,
			2025		2024		2023
Commodity derivatives	Revenue		$	45	$	26	$	213
Commodity derivatives	Operating costs and expenses		(5)		(4)		–
Total			$	40	$	22	$	213

Schedule of Unrealized Mark-to-Market Gains (Losses)


	For the Year Ended December 31,
	2025		2024		2023
Mark-to-market gains (losses) in gross operating margin:
NGL Pipelines & Services	$	(3)	$	(8)	$	(25)
Crude Oil Pipelines & Services	(4)		21		(5)
Natural Gas Pipelines & Services	(10)		5		(1)
Petrochemical & Refined Products Services	1		2		(2)
Total mark-to-market impact on gross operating margin	$	(16)	$	20	$	(33)

Schedule of Fair Value Measurements of Financial Assets and Liabilities Measured on a Recurring Basis


	At December 31, 2025 Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Financial assets:

Commodity derivatives:
Value before application of CME Rule 814	$	172	$	777	$	–	$	949
Impact of CME Rule 814	(170)		(319)		–		(489)
Total commodity derivatives	2		458		–		460
Total	$	2	$	458	$	–	$	460

Financial liabilities:
Commodity derivatives:
Value before application of CME Rule 814	$	32	$	710	$	–	$	742
Impact of CME Rule 814	(31)		(348)		–		(379)
Total commodity derivatives	1		362		–		363
Total	$	1	$	362	$	–	$	363


	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

Commitments and Contingent Liabilities (Tables)

12 Months Ended

Dec. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

Schedule of Contractual Obligations

The following table summarizes our various contractual obligations at December 31, 2025. A description of each type of contractual obligation follows:


	Payment or Settlement due by Period
Contractual Obligations	Total		2026		2027		2028		2029		2030		Thereafter
Scheduled maturities of debt obligations	$	34,707	$	1,625	$	1,575	$	1,800	$	1,250	$	1,250	$	27,207
Estimated cash interest payments	$	28,309	$	1,578	$	1,509	$	1,477	$	1,409	$	1,354	$	20,982
Operating lease obligations (1)	$	576	$	111	$	73	$	52	$	39	$	36	$	265
Finance lease obligations (2)	$	18	$	4	$	4	$	5	$	3	$	1	$	1
Purchase obligations:
Product purchase commitments:
Estimated payment obligations:
NGLs	$	2,836	$	1,186	$	1,186	$	170	$	131	$	131	$	32
Crude oil	$	4,296	$	1,226	$	1,226	$	965	$	622	$	257	$	–
Other	$	43	$	7	$	8	$	8	$	8	$	7	$	5
Service payment commitments	$	271	$	41	$	38	$	33	$	25	$	24	$	110

Capital expenditure commitments	$	51	$	36	$	15	$	–	$	–	$	–	$	–

Schedule of Operating and Finance Leases

The following table presents information regarding operating and finance leases where we are the lessee at December 31, 2025:


Asset Category	ROU Asset Carrying Value (1)		Lease Liability Carrying Value (2)		Weighted- Average Remaining Term	Weighted- Average Discount Rate (3)
Operating leases
Storage and pipeline facilities	$	247	$	246	10 years	4.8	%
Transportation equipment	32		33		3 years	4.8	%
Office and warehouse space	158		192		11 years	3.3	%
Total operating leases	437		471
Finance leases
Transportation equipment	16		16		4 years	4.8	%
Total finance leases	16		16
Total leases	$	453	$	487

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

Schedule of Consolidated Lease Expense

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


	For the Year Ended December 31,
		2025		2024			2023
Long-term leases:
Fixed operating lease expense:
Non-cash lease expense (amortization of ROU assets)		$	109	$	95		$	72
Related accretion expense on lease liability balances		17		17			14
Total fixed operating lease expense		126		112			86
Fixed finance lease expense:
Amortization of ROU assets (1)		2		–		*	–
Interest on finance lease liabilities (1)		1		–		*	–
Total fixed finance lease expense (1)		3		–		*	–
Variable lease expense		18		17			13
Total long-term lease expense		147		129			99
Short-term leases		163		121			111
Total lease expense		$	310	$	250		$	210

(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 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,
	2025		2024
Noncurrent portion of AROs (see Note 4)	$	285	$	259
Deferred revenues – non-current portion (see Note 9)	261		284
Operating lease liability – non-current portion	377		366
Derivative liabilities	16		24
Other	45		17
Total	$	984	$	950

Debt Obligations - Schedule of Consolidated Debt Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Debt Instrument [Line Items]
Principal outstanding	$ 34,707	$ 32,207
Other, non-principal amounts	(312)	(311)
Less current maturities of debt	(1,625)	(1,150)
Long-term debt (see Note 7)	32,770	30,746
Senior Debt Obligations
Debt Instrument [Line Items]
Principal outstanding	32,425	29,925
Commercial Paper Notes, variable-rates \| Senior Debt Obligations
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	3,000
Principal outstanding	$ 0	0
Senior Notes MM, 3.75% fixed-rate, due February 2025 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	3.75%
Principal outstanding	$ 0	1,150
Senior Notes FFF, 5.05% fixed-rate, due January 2026 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	5.05%
Principal outstanding	$ 750	750
Senior Notes PP, 3.70% fixed-rate, due February 2026 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	3.70%
Principal outstanding	$ 875	875
March 2025 $1.5 Billion 364-Day Revolving Credit Agreement, variable-rate, due March 2026 \| Senior Debt Obligations
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 1,500
Debt instrument, term	364 days
Principal outstanding	$ 0	0
Maximum bank commitments increase	200
Total maximum borrowing capacity	$ 1,700
Senior Notes HHH, 4.60% fixed-rate, due January 2027 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	4.60%
Principal outstanding	$ 1,000	1,000
Senior Notes SS, 3.95% fixed-rate, due February 2027 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	3.95%
Principal outstanding	$ 575	575
Senior Notes LLL, 4.30% fixed-rate, due June 2028 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	4.30%
Principal outstanding	$ 800	0
Senior Notes WW, 4.15% fixed-rate, due October 2028 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	4.15%
Principal outstanding	$ 1,000	1,000
Senior Notes YY, 3.125% fixed-rate, due July 2029 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	3.125%
Principal outstanding	$ 1,250	1,250
Senior Notes AAA, 2.80% fixed-rate, due January 2030 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	2.80%
Principal outstanding	$ 1,250	1,250
March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement, variable-rate, due March 2030 \| Senior Debt Obligations
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	2,700
Principal outstanding	0	0
Maximum bank commitments increase	500
Total maximum borrowing capacity	$ 3,200
Senior Notes MMM, 4.60% fixed-rate, due January 2031 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	4.60%
Principal outstanding	$ 1,350	0
Senior Notes GGG, 5.35% fixed-rate, due January 2033 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	5.35%
Principal outstanding	$ 1,000	1,000
Senior Notes D, 6.875% fixed-rate, due March 2033 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	6.875%
Principal outstanding	$ 500	500
Senior Notes III, 4.85% fixed-rate, due January 2034 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	4.85%
Principal outstanding	$ 1,000	1,000
Senior Notes H, 6.65% fixed-rate, due October 2034 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	6.65%
Principal outstanding	$ 350	350
Senior Notes JJJ 4.95% fixed-rate, due February 2035 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	4.95%
Principal outstanding	$ 1,100	1,100
Senior Notes J, 5.75% fixed-rate, due March 2035 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	5.75%
Principal outstanding	$ 250	250
Senior Notes NNN, 5.20% fixed-rate, due January 2036 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	5.20%
Principal outstanding	$ 1,500	0
Senior Notes W, 7.55% fixed-rate, due April 2038 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	7.55%
Principal outstanding	$ 400	400
Senior Notes R, 6.125% fixed-rate, due October 2039 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	6.125%
Principal outstanding	$ 600	600
Senior Notes Z, 6.45% fixed-rate, due September 2040 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	6.45%
Principal outstanding	$ 600	600
Senior Notes BB, 5.95% fixed-rate, due February 2041 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	5.95%
Principal outstanding	$ 750	750
Senior Notes DD, 5.70% fixed-rate, due February 2042 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	5.70%
Principal outstanding	$ 600	600
Senior Notes EE, 4.85% fixed-rate, due August 2042 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	4.85%
Principal outstanding	$ 750	750
Senior Notes GG, 4.45% fixed-rate, due February 2043 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	4.45%
Principal outstanding	$ 1,100	1,100
Senior Notes II, 4.85% fixed-rate, due March 2044 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	4.85%
Principal outstanding	$ 1,400	1,400
Senior Notes KK, 5.10% fixed-rate, due February 2045 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	5.10%
Principal outstanding	$ 1,150	1,150
Senior Notes QQ, 4.90% fixed-rate, due May 2046 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	4.90%
Principal outstanding	$ 975	975
Senior Notes UU, 4.25% fixed-rate, due February 2048 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	4.25%
Principal outstanding	$ 1,250	1,250
Senior Notes XX, 4.80% fixed-rate, due February 2049 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	4.80%
Principal outstanding	$ 1,250	1,250
Senior Notes ZZ, 4.20% fixed-rate, due January 2050 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	4.20%
Principal outstanding	$ 1,250	1,250
Senior Notes BBB, 3.70% fixed-rate, due January 2051 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	3.70%
Principal outstanding	$ 1,000	1,000
Senior Notes DDD, 3.20% fixed-rate, due February 2052 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	3.20%
Principal outstanding	$ 1,000	1,000
Senior Notes EEE, 3.30% fixed-rate, due February 2053 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	3.30%
Principal outstanding	$ 1,000	1,000
Senior Notes NN, 4.95% fixed-rate, due October 2054 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	4.95%
Principal outstanding	$ 400	400
Senior Notes KKK, 5.55% fixed-rate, due February 2055 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	5.55%
Principal outstanding	$ 1,400	1,400
Senior Notes CCC, 3.95% fixed-rate, due January 2060 \| Senior Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	3.95%
Principal outstanding	$ 1,000	1,000
EPO Junior Subordinated Notes C \| Subordinated Debt Obligations
Debt Instrument [Line Items]
Principal outstanding	$ 232	232
EPO Junior Subordinated Notes C \| Subordinated Debt Obligations \| Tenor Spread Adjustment
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	0.26161%
EPO Junior Subordinated Notes C \| Subordinated Debt Obligations \| Additional Spread Adjustment
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	2.778%
EPO Junior Subordinated Notes D \| Subordinated Debt Obligations
Debt Instrument [Line Items]
Principal outstanding	$ 350	350
EPO Junior Subordinated Notes D \| Subordinated Debt Obligations \| Tenor Spread Adjustment
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	0.26161%
EPO Junior Subordinated Notes D \| Subordinated Debt Obligations \| Additional Spread Adjustment
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	2.986%
EPO Junior Subordinated Notes E \| Subordinated Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	5.25%
Principal outstanding	$ 1,000	1,000
EPO Junior Subordinated Notes E \| Subordinated Debt Obligations \| Tenor Spread Adjustment
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	0.26161%
EPO Junior Subordinated Notes E \| Subordinated Debt Obligations \| Additional Spread Adjustment
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	3.033%
EPO Junior Subordinated Notes F \| Subordinated Debt Obligations
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	5.375%
Principal outstanding	$ 700	$ 700
EPO Junior Subordinated Notes F \| Subordinated Debt Obligations \| Tenor Spread Adjustment
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	0.26161%
EPO Junior Subordinated Notes F \| Subordinated Debt Obligations \| Additional Spread Adjustment
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	2.57%

Acquisitions - Schedule of Allocation of Total Cost to Assets Acquired and Liabilities Assumed (Details) - Oxy Natural Gas Gathering Affiliate $ in Millions	Aug. 22, 2025 USD ($)
Asset Acquisition [Line Items]
Property, plant and equipment	$ 223
Contract-based intangible asset	360
Total net assets acquired	$ 583

STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Operating activities:
Net income	$ 5,876	$ 5,970	$ 5,657
Reconciliation of net income to net cash flow provided by operating activities:
Depreciation and accretion	2,107	1,987	1,871
Amortization of intangible assets	216	207	201
Amortization of major maintenance costs for reaction-based plants	72	59	64
Other amortization expense	228	220	207
Impairment of assets other than goodwill (see Notes 2 and 4)	50	57	32
Equity in income of unconsolidated affiliates	(361)	(408)	(462)
Distributions received from unconsolidated affiliates attributable to earnings	364	406	446
Net losses (gains) attributable to asset sales and related matters	(14)	2	(10)
Deferred income tax expense	46	45	12
Change in fair market value of derivative instruments	16	(20)	33
Non-cash expense related to long-term operating leases (see Note 17)	109	95	72
Net effect of changes in operating accounts (see Note 19)	(124)	(506)	(555)
Other operating activities	0	1	1
Net cash flow provided by operating activities	8,585	8,115	7,569
Investing activities:
Capital expenditures	(5,620)	(4,544)	(3,266)
Cash used for business combinations, net of cash received (see Note 12)	0	(949)	0
Investments in unconsolidated affiliates	(2)	0	(2)
Distributions received from unconsolidated affiliates attributable to the return of capital	74	77	42
Proceeds from asset sales and other matters	82	14	42
Other investing activities	(25)	(31)	(13)
Net cash flow used in investing activities	(5,491)	(5,433)	(3,197)
Financing activities:
Borrowings under debt agreements	88,281	53,715	89,899
Repayments of debt	(85,771)	(50,546)	(89,447)
Debt issuance costs	(42)	(44)	(17)
Monetization of interest rate derivative instruments (see Note 14)	14	(33)	21
Cash distributions paid to common unitholders (see Note 8)	(4,678)	(4,512)	(4,301)
Cash payments made in connection with distribution equivalent rights	(44)	(43)	(38)
Cash distributions paid to noncontrolling interests (see Note 8)	(93)	(106)	(160)
Cash contributions from noncontrolling interests (see Note 8)	5	90	44
Repurchase of common units under 2019 Buyback Program (see Note 8)	(300)	(219)	(188)
Acquisition of noncontrolling interests	0	(400)	(10)
Other financing activities	(59)	(66)	(61)
Net cash flow used in financing activities	(2,687)	(2,164)	(4,258)
Net change in cash and cash equivalents, including restricted cash	407	518	114
Cash and cash equivalents, including restricted cash, January 1	838	320	206
Cash and cash equivalents, including restricted cash, December 31	$ 1,245	$ 838	$ 320

Hedging Activities and Fair Value Measurements - Narrative (Details) $ in Millions	1 Months Ended	12 Months Ended
	May 31, 2025 USD ($) derivativeInstrument	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Derivative [Line Items]
Payments for (proceeds from) hedge, financing activities		$ (14)	$ 33	$ (21)
Carrying amount of hedged asset		6	11
Unrealized gain (loss) on commodity contracts		(16)	20	(33)
Carrying Value
Derivative [Line Items]
Fixed rate debt principal amount fair value		34,100	31,600
Significant Other Observable Inputs (Level 2) \| Fair Value
Derivative [Line Items]
Fixed rate debt principal amount fair value		32,200	28,900
Derivatives not designated as hedging instruments:
Derivative [Line Items]
Gain (loss) recognized in income on derivative		$ 40
Treasury lock \| Cash flow hedge \| Derivatives designated as hedging instruments:
Derivative [Line Items]
Number of transactions \| derivativeInstrument	4
Derivative, fixed interest rate	3.98%
Derivative, notional amount	$ 750		3,750	1,500
Payments for (proceeds from) hedge, financing activities	$ (14)		$ 33	$ (21)
Derivative, gains, amortization period		7 years
Interest Rate Derivative Instruments \| Cash flow hedge
Derivative [Line Items]
Accumulated other comprehensive income related to interest rate derivative instruments expected to be reclassified to earnings in interest expense over the next twelve months		$ 7
Commodity Derivative Instruments \| Cash flow hedge
Derivative [Line Items]
Net accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to earnings over the next twelve months		163
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to revenue over the next twelve months		169
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to operating costs and expenses over the next twelve months		(6)
Commodity Derivative Instruments \| Derivatives not designated as hedging instruments:
Derivative [Line Items]
Realized gain (loss) on commodity contracts		52
Unrealized gain (loss) on commodity contracts		(12)
Value before application of CME Rule 814 \| Fair Value, Recurring
Derivative [Line Items]
Price risk derivatives, at fair value, net		$ 207

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2025

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,
	2025		2024		2023
Balance at beginning of period	$	38	$	35	$	54
Charged to costs and expenses	–		3		1

Deductions	(3)		–		(20)
Balance at end of period	$	35	$	38	$	35

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.



	December 31,
	2025		2024
Cash and cash equivalents	$	969	$	583
Restricted cash	276		255
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows	$	1,245	$	838

Consolidation Policy

Contingencies

Current Assets and Current Liabilities

Derivative Instruments

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.

Environmental Costs

For the year ended December 31, 2025 and 2024, our environmental reserves totaled $36 million and $9 million, respectively.

Estimates

Fair Value Measurements

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,
	2025		2024		2023
Impairment charges reflected in operating costs and expenses:
Property, plant and equipment	$	45	$	50	$	18
Other (1)	5		7		12
Total asset impairment charges in operating costs and expenses (2)	50		57		30
Other property, plant and equipment impairment charges (3)	–		–		2
Total asset impairment charges	$	50	$	57	$	32

(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:

We did not record any non-cash goodwill impairment charges during the years ended December 31, 2025, 2024 or 2023. See Note 6 for additional information regarding our goodwill.

Inventories

Leases

We account for our leases under Accounting Standards Codification (“ASC”) 842, Leases, which requires substantially all leases be recorded on the balance sheet.

See Note 17 for our disclosures regarding our lease obligations.

Property, Plant and Equipment

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.

See Note 4 for additional information regarding our property, plant and equipment and AROs.

Revenues

See Note 9 regarding our revenue disclosures.

Related Party Transactions - Schedule of Costs and Expenses Attributable (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Related Party Transaction [Line Items]
Operating costs and expenses	$ 45,440	$ 49,045	$ 43,017
General and administrative costs	251	244	231
Total costs and expenses	45,691	49,289	43,248
Related Party
Related Party Transaction [Line Items]
Operating costs and expenses	1,615	1,491	1,385
General and administrative costs	148	166	156
Total costs and expenses	1,763	1,657	1,541
EPCO and its privately held affiliates
Related Party Transaction [Line Items]
Total costs and expenses	1,604	1,472	1,353
Administrative Services Agreement \| EPCO and its privately held affiliates
Related Party Transaction [Line Items]
Operating costs and expenses	1,443	1,294	1,189
General and administrative costs	134	152	141
Total costs and expenses	$ 1,577	$ 1,446	$ 1,330

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483326/850-10-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483326/850-10-50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483326/850-10-50-3

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(k)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(k)(1))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 310
-SubTopic 10
-Name Accounting Standards Codification
-Section 45
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481990/310-10-45-13

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.6-07(2)(c)(2)(i))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.6-07(2)(c)(2)(ii))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.6-07(2)(g)(3))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-1

+ Details

Property, Plant and Equipment - Schedule of Impairments of Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment [Line Items]
Total impairment charges for property, plant and equipment	$ 45	$ 50	$ 20
NGL Pipelines & Services
Property, Plant and Equipment [Line Items]
Total impairment charges for property, plant and equipment	14	28	12
Crude Oil Pipelines & Services
Property, Plant and Equipment [Line Items]
Total impairment charges for property, plant and equipment	4	0	1
Natural Gas Pipelines & Services
Property, Plant and Equipment [Line Items]
Total impairment charges for property, plant and equipment	11	7	5
Petrochemical & Refined Products Services
Property, Plant and Equipment [Line Items]
Total impairment charges for property, plant and equipment	$ 16	$ 15	$ 2

Hedging Activities and Fair Value Measurements - Schedule of Derivative Fair Value Amounts (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Commodity derivatives
Derivatives, Fair Value [Line Items]
Asset Derivatives	$ 460	$ 575
Liability Derivatives	363	495
Derivatives designated as hedging instruments:
Derivatives, Fair Value [Line Items]
Asset Derivatives	429	232
Liability Derivatives	325	182
Derivatives designated as hedging instruments: \| Commodity derivatives
Derivatives, Fair Value [Line Items]
Asset Derivatives	429	232
Liability Derivatives	325	182
Derivatives designated as hedging instruments: \| Commodity derivatives \| Current assets
Derivatives, Fair Value [Line Items]
Asset Derivatives	403	210
Derivatives designated as hedging instruments: \| Commodity derivatives \| Current liabilities
Derivatives, Fair Value [Line Items]
Liability Derivatives	312	178
Derivatives designated as hedging instruments: \| Commodity derivatives \| Other assets
Derivatives, Fair Value [Line Items]
Asset Derivatives	26	22
Derivatives designated as hedging instruments: \| Commodity derivatives \| Other liabilities
Derivatives, Fair Value [Line Items]
Liability Derivatives	13	4
Derivatives not designated as hedging instruments:
Derivatives, Fair Value [Line Items]
Asset Derivatives	31	343
Liability Derivatives	38	313
Derivatives not designated as hedging instruments: \| Commodity derivatives
Derivatives, Fair Value [Line Items]
Asset Derivatives	31	343
Liability Derivatives	38	313
Derivatives not designated as hedging instruments: \| Commodity derivatives \| Current assets
Derivatives, Fair Value [Line Items]
Asset Derivatives	31	324
Derivatives not designated as hedging instruments: \| Commodity derivatives \| Current liabilities
Derivatives, Fair Value [Line Items]
Liability Derivatives	35	293
Derivatives not designated as hedging instruments: \| Commodity derivatives \| Other assets
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	19
Derivatives not designated as hedging instruments: \| Commodity derivatives \| Other liabilities
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ 3	$ 20

Property, Plant and Equipment - Narrative (Details) - USD ($) $ in Millions	1 Months Ended		2 Months Ended	12 Months Ended
	Jan. 31, 2026	Dec. 31, 2025	Jan. 31, 2026	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Proceeds from sale of productive assets				$ 82	$ 14	$ 42
Asset retirement costs capitalized		$ 141		141	134
Total asset retirement obligation liability		290		290	265	$ 225	$ 234
Asset retirement obligation, current		5		5
Asset retirement obligations, noncurrent		285		$ 285	$ 259
Bahia NGL Pipeline
Property, Plant and Equipment [Line Items]
Proceeds from sale of productive assets		$ 60
Undivided joint interest, ownership percentage		60.00%		60.00%
ExxonMobil \| Bahia NGL Pipeline
Property, Plant and Equipment [Line Items]
Undivided joint interest, ownership interest sold, percent		40.00%
Subsequent Event \| Bahia NGL Pipeline
Property, Plant and Equipment [Line Items]
Proceeds from sale of productive assets	$ 595		$ 655

Acquisitions

12 Months Ended

Dec. 31, 2025

Business Combination, Asset Acquisition, Transaction between Entities under Common Control, and Joint Venture Formation [Abstract]

Acquisitions

Note 12. Acquisitions

Acquisition of Oxy Natural Gas Gathering Affiliate

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

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

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

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


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

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

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

Acquisition of Pinon Midstream

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

Pinon Midstream’s assets include 43 miles of natural gas gathering and redelivery pipelines, five 3-stage compressor stations, 270 million cubic feet per day (“MMcf/d”) of hydrogen sulfide and carbon dioxide treating facilities and two high capacity acid gas injection wells. The acquisition of Pinon Midstream was accounted for under the acquisition method in accordance with ASC 805, Business Combinations.

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


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

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

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.

Acquisitions

Note 12. Acquisitions

Acquisition of Oxy Natural Gas Gathering Affiliate

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


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

Acquisition of Pinon Midstream

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

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


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

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

- Definition

The entire disclosure for business combination.

+ References

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+ Details

Property, Plant and Equipment - Schedule of Depreciation Expense and Capitalized Interest Amounts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Depreciation expense	$ 2,087	$ 1,974	$ 1,860
Capitalized interest	$ 182	$ 121	$ 106

Capital Accounts (Tables)

12 Months Ended

Dec. 31, 2025

Partners' Capital, Including Portion Attributable to Noncontrolling Interest [Abstract]

Schedule of Changes in Outstanding Common Units

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


Common units outstanding at December 31, 2022			2,170,806,347
Common unit repurchases under 2019 Buyback Program			(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
Common unit repurchases under 2019 Buyback Program			(9,496,536)
Common units issued in connection with the vesting of phantom unit awards, net			5,346,387
Conversion of preferred units to common units			194,472
Other			16,398
Common units outstanding at December 31, 2025			2,161,760,683

Schedule of Changes in Outstanding Preferred Units

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


Preferred units outstanding at December 31, 2022			50,412
Preferred units outstanding at December 31, 2023			50,412
Paid in-kind distribution to third party			275
Preferred units outstanding at December 31, 2024			50,687
Paid in-kind distribution to third party			291
Conversion of preferred units to common units			(5,566)
Preferred units outstanding at December 31, 2025			45,412

Schedule of 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				Other		Total
	Commodity Derivative Instruments		Interest Rate Derivative Instruments
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
Other comprehensive income (loss) for period, before reclassifications	285		14		–		299
Reclassification of losses (gains) to net income during period	(192)		(7)		–		(199)
Total other comprehensive income (loss) for period	93		7		–		100
Accumulated Other Comprehensive Income (Loss), December 31, 2025	$	184	$	150	$	2	$	336

Schedule of Reclassification out of Accumulated Other Comprehensive Income (Loss)

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		2025		2024
Interest rate derivatives	Interest expense		$	(7)	$	(6)
Commodity derivatives	Revenue		(235)		(249)
Commodity derivatives	Operating costs and expenses		43		71
Total			$	(199)	$	(184)

Schedule of Noncontrolling Interests

The following table presents the components of noncontrolling interests as reported on our Consolidated Balance Sheets at the dates indicated:


	December 31,
Consolidated Subsidiary	2025		2024
Breviloba LLC (“Breviloba”)(1)	$	411	$	423

Enterprise Navigator Ethylene Terminal LLC (“ENET”)(2)	240		245
Other (3)	180		189
Total noncontrolling interests in consolidated subsidiaries	$	831	$	857

(1)An affiliate of Kinetik Holdings Inc. owns a noncontrolling 33% equity interest in Breviloba, which owns the Shin Oak NGL Pipeline.

(2)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.

(3)Primarily represents noncontrolling equity interests in NGL fractionation and pipeline businesses.

Schedule of Declared Quarterly Cash Distribution Rates


	Quarterly Distribution Per Common Unit		Record Date	Payment Date
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
2025:
1st Quarter	$	0.5350	4/30/2025	5/14/2025
2nd Quarter	$	0.5450	7/31/2025	8/14/2025
3rd Quarter	$	0.5450	10/31/2025	11/14/2025
4th Quarter	$	0.5500	1/30/2026	2/13/2026

Investments in Unconsolidated Affiliates - Schedule of Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	1 Months Ended
	Jun. 30, 2025	Dec. 31, 2025	Dec. 31, 2024
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates		$ 2,185	$ 2,259
Transport 4, LLC (“Transport 4”)
Schedule of Equity Method Investments [Line Items]
Ownership interest	25.00%
Proceeds from sale of equity method investments	$ 8
Equity method investment, realized gain (loss) on disposal	$ 6
NGL Pipelines & Services
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates		$ 572	598
NGL Pipelines & Services \| Venice Energy Service Company, L.L.C. (“VESCO”)
Schedule of Equity Method Investments [Line Items]
Ownership interest		13.10%
Investments in unconsolidated affiliates		$ 24	24
NGL Pipelines & Services \| K/D/S Promix, L.L.C. (“Promix”)
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 21	22
NGL Pipelines & Services \| Baton Rouge Fractionators LLC (“BRF”)
Schedule of Equity Method Investments [Line Items]
Ownership interest		32.20%
Investments in unconsolidated affiliates		$ 12	12
NGL Pipelines & Services \| Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”)
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 21	25
NGL Pipelines & Services \| Texas Express Pipeline LLC (“Texas Express”)
Schedule of Equity Method Investments [Line Items]
Ownership interest		35.00%
Investments in unconsolidated affiliates		$ 287	299
NGL Pipelines & Services \| Texas Express Gathering LLC (“TEG”)
Schedule of Equity Method Investments [Line Items]
Ownership interest		45.00%
Investments in unconsolidated affiliates		$ 32	33
NGL Pipelines & Services \| Front Range Pipeline LLC (“Front Range”)
Schedule of Equity Method Investments [Line Items]
Ownership interest		33.30%
Investments in unconsolidated affiliates		$ 175	183
Crude Oil Pipelines & Services
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates		$ 1,581	1,628
Crude Oil Pipelines & Services \| Seaway Crude Holdings LLC (“Seaway”)
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 1,120	1,147
Crude Oil Pipelines & Services \| Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”)
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 351	368
Crude Oil Pipelines & Services \| Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”)
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 110	113
Natural Gas Pipelines & Services
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates		$ 31	30
Natural Gas Pipelines & Services \| White River Hub, LLC (“White River Hub”)
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 16	16
Natural Gas Pipelines & Services \| Old Ocean Pipeline, LLC (“Old Ocean”)
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Investments in unconsolidated affiliates		$ 15	14
Petrochemical & Refined Products Services
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates		$ 1	3
Petrochemical & Refined Products Services \| Baton Rouge Propylene Concentrator LLC (“BRPC”)
Schedule of Equity Method Investments [Line Items]
Ownership interest		30.00%
Investments in unconsolidated affiliates		$ 1	1
Petrochemical & Refined Products Services \| Transport 4, LLC (“Transport 4”)
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates		$ 0	$ 2

Intangible Assets and Goodwill - Schedule of Forecasted Amortization Expense Associated with Existing Intangible Assets (Details) $ in Millions	Dec. 31, 2025 USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2026	$ 224
2027	225
2028	221
2029	217
2030	$ 217

Intangible Assets and Goodwill (Tables)

12 Months Ended

Dec. 31, 2025

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Intangible Assets by Business Segment

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


	December 31, 2025						December 31, 2024
	Gross Value		Accumulated Amortization		Carrying Value		Gross Value		Accumulated Amortization		Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	449	$	(289)	$	160	$	449	$	(276)	$	173
Contract-based intangibles	1,050		(177)		873		754		(141)		613
Segment total	1,499		(466)		1,033		1,203		(417)		786
Crude Oil Pipelines & Services:
Customer relationship intangibles	2,195		(710)		1,485		2,195		(627)		1,568
Contract-based intangibles	283		(280)		3		283		(278)		5
Segment total	2,478		(990)		1,488		2,478		(905)		1,573
Natural Gas Pipelines & Services:
Customer relationship intangibles	1,351		(700)		651		1,351		(663)		688
Contract-based intangibles	1,150		(265)		885		1,081		(227)		854
Segment total	2,501		(965)		1,536		2,432		(890)		1,542
Petrochemical & Refined Products Services:
Customer relationship intangibles	181		(99)		82		181		(92)		89
Contract-based intangibles	50		(30)		20		45		(30)		15
Segment total	231		(129)		102		226		(122)		104
Total intangible assets	$	6,709	$	(2,550)	$	4,159	$	6,339	$	(2,334)	$	4,005

Schedule of Amortization Expense of our Intangible Assets by Business 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,
		2025		2024		2023
NGL Pipelines & Services		$	49	$	44	$	40
Crude Oil Pipelines & Services		85		100		103
Natural Gas Pipelines & Services		75		56		51
Petrochemical & Refined Products Services		7		7		7
Total		$	216	$	207	$	201

Schedule of Forecasted Amortization Expense Associated with Existing Intangible Assets

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


2026		2027		2028		2029		2030
$	224	$	225	$	221	$	217	$	217

Schedule of Significant Acquired Intangible Assets

At December 31, 2025, the carrying value of our portfolio of customer relationship intangible assets was $2.4 billion, the principal components of which were as follows:


	Weighted Average Remaining Amortization Period	December 31, 2025
		Gross Value		Accumulated Amortization		Carrying Value
Basin-specific customer relationships:
EFS Midstream (acquired 2015)	16.4 years	$	1,410	$	(461)	$	949
State Line and Fairplay (acquired 2010)	21.2 years	895		(356)		539
San Juan Gathering (acquired 2004)	13.8 years	331		(280)		51
General customer relationships:
Oiltanking (acquired 2014)	18.0 years	1,193		(386)		807

At December 31, 2025, the carrying value of our portfolio of contract-based intangible assets was $1.8 billion, the principal components of which were as follows:


	Weighted Average Remaining Amortization Period	December 31, 2025
		Gross Value		Accumulated Amortization		Carrying Value
Midland Basin customer contracts (acquired 2022)	26.0 years	$	989	$	(113)	$	876
Pinon Midstream customer contracts (acquired 2024)	23.0 years	435		(19)		416
Midland Basin Oxy customer contract (acquired 2025)	23.0 years	360		(5)		355
Jonah natural gas gathering agreements (acquired 2001)	16.0 years	224		(189)		35
Delaware Basin natural gas processing contracts (acquired 2018)	2.1 years	82		(66)		16

Schedule of Goodwill

The following table presents changes in the carrying amount of goodwill by business segment during the years indicated:


	NGL Pipelines & Services		Crude Oil Pipelines & Services		Natural Gas Pipelines & Services		Petrochemical & Refined Products Services		Consolidated Total
Balance at December 31, 2023 (1)	$	2,811	$	1,841	$	–	$	956	$	5,608
Goodwill related to acquisition (2)	29		–		75		–		104
Balance at December 31, 2024 (1)	2,840		1,841		75		956		5,712

Balance at December 31, 2025 (1)	$	2,840	$	1,841	$	75	$	956	$	5,712

- Definition

Tabular disclosure of goodwill by reportable segment and in total which includes a rollforward schedule.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 24
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482548/350-20-55-24

Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 4: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 5: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 6: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 7: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 8: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
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-Section 50
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 9: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
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-Name Accounting Standards Codification
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-Paragraph 1
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 10: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 11: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1A
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1A

Reference 12: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-2

+ Details

Equity-Based Awards - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Mar. 31, 2024
Equity-Based Compensation Arrangement by Equity-Based Payment Award [Line Items]
Common units issued in connection with the vesting of phantom unit awards, net (in units)	5,346,387	4,990,360	4,662,539
Phantom unit awards
Equity-Based Compensation Arrangement by Equity-Based Payment Award [Line Items]
Common units issued in connection with the vesting of phantom unit awards, net (in units)	5,346,387	4,990,360	4,662,539
Vesting rate of phantom unit awards	25.00%
Unrecognized compensation cost	$ 181
Equity-based payment arrangement, cost not yet recognized, period for recognition	2 years 2 months 12 days
Phantom unit awards \| EPCO Companies
Equity-Based Compensation Arrangement by Equity-Based Payment Award [Line Items]
Unrecognized compensation cost	$ 229
Profits interest awards \| EPCO Unit II [Member]
Equity-Based Compensation Arrangement by Equity-Based Payment Award [Line Items]
Employee partnership liquidation threshold (in dollars per unit)				$ 29.02
Vesting period		30 days
Profits interest awards \| EPD 2018 Unit IV [Member]
Equity-Based Compensation Arrangement by Equity-Based Payment Award [Line Items]
Employee partnership liquidation threshold (in dollars per unit)				$ 29.02
Vesting period		30 days
Long-Term Incentive Plan (2008)
Equity-Based Compensation Arrangement by Equity-Based Payment Award [Line Items]
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)	97,704,053

Intangible Assets and Goodwill - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2018
Finite-Lived Intangible Assets [Line Items]
Carrying Value	$ 4,159	$ 4,005
Delaware Basin natural gas processing contracts (acquired 2018)
Finite-Lived Intangible Assets [Line Items]
Voting interest acquired			50.00%
Customer relationship intangibles
Finite-Lived Intangible Assets [Line Items]
Carrying Value	2,400
Contract-based intangibles
Finite-Lived Intangible Assets [Line Items]
Carrying Value	1,800
Contract-based intangibles \| Delaware Basin natural gas processing contracts (acquired 2018)
Finite-Lived Intangible Assets [Line Items]
Carrying Value	$ 16

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

+ Details

Debt Obligations - Schedule of Maturities of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Debt Instrument [Line Items]
Total	$ 34,707	$ 32,207
2026	1,625
2027	1,575
2028	1,800
2029	1,250
2030	1,250
Thereafter	27,207
Senior Notes
Debt Instrument [Line Items]
Total	32,425
2026	1,625
2027	1,575
2028	1,800
2029	1,250
2030	1,250
Thereafter	24,925
Junior Subordinated Notes
Debt Instrument [Line Items]
Total	2,282
2026	0
2027	0
2028	0
2029	0
2030	0
Thereafter	$ 2,282

Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Related Party Transaction [Line Items]
Revenues	$ 52,596	$ 56,219	$ 49,715
Costs and expenses	45,691	49,289	43,248
Related Party
Related Party Transaction [Line Items]
Revenues	52	58	61
Costs and expenses	1,763	1,657	1,541
Unconsolidated affiliates
Related Party Transaction [Line Items]
Revenues	52	58	61
Costs and expenses	159	185	188
EPCO and its privately held affiliates
Related Party Transaction [Line Items]
Costs and expenses	$ 1,604	$ 1,472	$ 1,353

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483326/850-10-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483326/850-10-50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 850
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483326/850-10-50-3

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(k)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(k)(1))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 310
-SubTopic 10
-Name Accounting Standards Codification
-Section 45
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481990/310-10-45-13

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.6-07(2)(c)(2)(ii))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.6-07(2)(g)(3))
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-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-1

Summary of Significant Accounting Policies - Schedule of Asset Impairment Charges (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Impaired Long-Lived Assets Held and Used [Line Items]
Total impairment charges for property, plant and equipment	$ 45	$ 50	$ 20
Total asset impairment charges in operating costs and expenses	50	57	30
Total asset impairment charges	50	57	32
Operating costs and expenses
Impaired Long-Lived Assets Held and Used [Line Items]
Total impairment charges for property, plant and equipment	45	50	18
Other	5	7	12
Total asset impairment charges in operating costs and expenses	50	57	30
General and administrative costs
Impaired Long-Lived Assets Held and Used [Line Items]
Total impairment charges for property, plant and equipment	$ 0	$ 0	$ 2

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2025

Property, Plant and Equipment [Abstract]

Schedule of Historical Costs of our Property, Plant and Equipment and Related Balances

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


	Estimated Useful Life in Years	December 31,
		2025		2024

Plants, pipelines and facilities (1)(5)	3-45	$	66,498	$	60,716
Underground and other storage facilities (2)(6)	5-40	4,871		4,704
Transportation equipment (3)	3-10	294		272
Marine vessels (4)	15-30	970		949
Land		439		424
Construction in progress		2,400		4,138
Subtotal		75,472		71,203
Less accumulated depreciation		24,338		22,330
Subtotal property, plant and equipment, net		51,134		48,873
Capitalized major maintenance costs for reaction-based plants, net of accumulated amortization (7)		225		189
Property, plant and equipment, net		$	51,359	$	49,062

(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.

(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.

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


	For the Year Ended December 31,
		2025		2024		2023
Depreciation expense (1)		$	2,087	$	1,974	$	1,860
Capitalized interest (2)		182		121		106

(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.

Schedule of Information Regarding our Asset Retirement Obligations, or AROs

The following table presents information regarding our AROs for the years indicated:


	For the Year Ended December 31,
	2025		2024		2023
ARO liability beginning balance	$	265	$	225	$	234
Liabilities incurred (1)	10		1		5
Revisions in estimated cash flows (2)	1		30		(12)
Liabilities settled (3)	(6)		(4)		(13)
Accretion expense (4)	20		13		11
ARO liability ending balance	$	290	$	265	$	225

(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:


2026		2027		2028		2029		2030
$	17	$	18	$	19	$	20	$	21

Schedule of 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,
	2025		2024		2023
NGL Pipelines & Services	$	14	$	28	$	12
Crude Oil Pipelines & Services	4		–		1
Natural Gas Pipelines & Services	11		7		5
Petrochemical & Refined Products Services	16		15		2
Total impairment charges for property, plant and equipment	$	45	$	50	$	20

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2025

Schedule of Related Party Transactions

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


	For the Year Ended December 31,
		2025		2024		2023
Revenues – related parties:
Unconsolidated affiliates		$	52	$	58	$	61
Costs and expenses – related parties:
EPCO and its privately held affiliates		$	1,604	$	1,472	$	1,353
Unconsolidated affiliates		159		185		188
Total		$	1,763	$	1,657	$	1,541

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


	December 31,
	2025		2024

Accounts receivable - related parties:
Unconsolidated affiliates	$	1	$	4

Accounts payable - related parties:
EPCO and its privately held affiliates	$	195	$	180
Unconsolidated affiliates	22		18
Total	$	217	$	198

At December 31, 2025, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us:


Total Number of Limited Partner Interests Held			Percentage of Common Units Outstanding
702,259,470 common units			32.5%

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,
		2025		2024		2023
Operating costs and expenses		$	1,443	$	1,294	$	1,189
General and administrative expenses		134		152		141
Total costs and expenses		$	1,577	$	1,446	$	1,330