0001581990-26-000012 | 10-K | XBRL Viewer

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Derivatives and Risk Management Activities - Net Unrealized Gain/(Loss) Recognized in AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Derivatives, Fair Value [Line Items]
Proceeds from settlement of interest rate hedging instruments	$ (37)	$ (57)	$ (80)
Deferred (gain) loss on accumulated other comprehensive income (loss), net of tax	(29)
Other long-term assets, net
Derivatives, Fair Value [Line Items]
Interest rate cash flow hedge derivative at fair value, net		27
Interest Rate Swap Terminated In October 2025 \| Cash Flow Hedging
Derivatives, Fair Value [Line Items]
Notional amount terminated	200
Proceeds from settlement of interest rate hedging instruments	7
Interest Rate Swap Terminated In June 2026 \| Cash Flow Hedging
Derivatives, Fair Value [Line Items]
Notional amount terminated	200
Proceeds from settlement of interest rate hedging instruments	30
Interest rate derivatives
Derivatives, Fair Value [Line Items]
Interest rate derivatives, net	$ 10	$ 29	$ 15

Acquisitions, Divestitures and Other Transactions - Schedule of Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Millions	Nov. 02, 2025	Nov. 01, 2025	Oct. 31, 2025	Jan. 31, 2025	Sep. 30, 2023
EPIC Crude Oil Pipeline
Business Combination [Line Items]
Property, plant and equipment, useful life	47 years
Working capital and other assets and liabilities	$ 160
Property and equipment	2,737
Intangible assets	267
Other long-term debt, net	(1,114)
Long-term operating lease liability	(34)	$ (501)	$ (613)
Total	$ 2,016
EPIC Crude Oil Pipeline \| Minimum
Business Combination [Line Items]
Finite-lived intangible asset, useful life	5 years
EPIC Crude Oil Pipeline \| Maximum
Business Combination [Line Items]
Finite-lived intangible asset, useful life	10 years
Ironwood Midstream Energy Partners II, LLC
Business Combination [Line Items]
Finite-lived intangible asset, useful life				16 years
Working capital and other assets and liabilities				$ 19
Property and equipment				435
Intangible assets				27
Total				$ 481
Ironwood Midstream Energy Partners II, LLC \| Minimum
Business Combination [Line Items]
Property, plant and equipment, useful life				3 years
Ironwood Midstream Energy Partners II, LLC \| Maximum
Business Combination [Line Items]
Property, plant and equipment, useful life				30 years
OMOG JV LLC and Southern Delaware Gathering Assets
Business Combination [Line Items]
Finite-lived intangible asset, useful life					10 years
Working capital and other assets and liabilities					$ 14
Property and equipment					484
Intangible assets					34
Total					$ 532
OMOG JV LLC and Southern Delaware Gathering Assets \| Minimum
Business Combination [Line Items]
Property, plant and equipment, useful life					3 years
OMOG JV LLC and Southern Delaware Gathering Assets \| Maximum
Business Combination [Line Items]
Property, plant and equipment, useful life					30 years

Income Taxes - Schedule of Differences Between Tax Expense Based on the Statutory Federal Income Tax Rate and the Effective Income Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Amount
U.S. federal statutory tax rate	$ 293	$ 202	$ 286
State and local income taxes	8	8	15
Nontaxable income attributable to noncontrolling interests	(212)	(143)	(180)
Other permanent book tax differences	0	0	(2)
Total income tax expense	$ 92	$ 124	$ 129
Percent
U.S. federal statutory tax rate	21.00%	21.00%	21.00%
State and local income taxes	0.57%	0.87%	1.08%
Nontaxable income attributable to noncontrolling interests	(15.20%)	(14.97%)	(13.25%)
Other permanent book tax differences	0.00%	0.00%	(0.14%)
Effective tax rate	6.59%	12.84%	9.48%
Canada
Amount
Foreign rate differential	$ (3)	$ (8)	$ (14)
Provincial taxes	5	13	20
Foreign withholding taxes	3	52	0
Other	$ (2)	$ 0	$ 4
Percent
Foreign rate differential	(0.22%)	(0.81%)	(1.02%)
Provincial taxes	0.36%	1.22%	1.50%
Foreign withholding taxes	0.22%	5.43%	0.00%
Other	(0.14%)		0.32%

Derivatives and Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2025

Derivatives and Risk Management Activities

Schedule of Impact of Derivative Activities Recognized in Earnings

The following table summarizes the impact of our commodity derivatives recognized in earnings (in millions):


	Year Ended December 31,
	2025		2024		2023
Product sales revenues	$	(20)	$	(24)	$	(10)
Field operating costs	2		(8)		19
Net gain/(loss) from commodity derivative activity	$	(18)	$	(32)	$	9

Schedule of Net Broker Receivable (Payable)

The following table provides the components of our net broker receivable (in millions):


	December 31,
	2025		2024
Initial margin	$	16	$	16
Variation margin posted	4		15
Letters of credit	(1)		(9)
Net broker receivable	$	19	$	22

Schedule of Derivative Assets and Liabilities on Consolidated Balance Sheets on a Gross Basis

The following table reflects the Consolidated Balance Sheet line items that include the fair values of our commodity derivative assets and liabilities and the effect of the collateral netting. Such amounts are presented on a gross basis, before the effects of counterparty netting. However, we have elected to present our commodity derivative assets and liabilities with the same counterparty on a net basis on our Consolidated Balance Sheet when the legal right of offset exists. Amounts in the table below are presented in millions.


	December 31, 2025								December 31, 2024
					Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet						Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet
	Commodity Derivatives								Commodity Derivatives
	Assets		Liabilities						Assets		Liabilities
Derivative Assets
Other current assets	$	18	$	(24)	$	19	$	13	$	25	$	(24)	$	22	$	23
Other long-term assets, net	1		—		—		1		—		—		—		—
Derivative Liabilities
Other current liabilities	(1)		—		—		(1)		(5)		5		—		—
Other long-term liabilities and deferred credits	10		(8)		—		2		2		(6)		—		(4)
Total	$	28	$	(32)	$	19	$	15	$	22	$	(25)	$	22	$	19

Summary of Net Deferred Gain/(Loss) Recognized in AOCI for Derivatives

The following table summarizes the net unrealized gain recognized in AOCI for derivatives (in millions):


	Year Ended December 31,
	2025		2024		2023
Interest rate derivatives, net	$	10	$	29	$	15

Schedule of Derivative Financial Assets and Liabilities Accounted for at Fair Value on a Recurring Basis, by Level Within the Fair Value Hierarchy

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions):


	Fair Value as of December 31, 2025						Fair Value as of December 31, 2024
Recurring Fair Value Measures (1)	Level 1		Level 2		Total			Level 1		Level 2		Total
Commodity derivatives	$	(2)	$	(2)	$	(4)		$	11	$	(14)	$	(3)
Interest rate derivatives	—		—		—			—		27		27

Foreign currency derivatives	—		8		8			—		—		—
Total net derivative asset/(liability)	$	(2)	$	6	$	4		$	11	$	13	$	24

(1)Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.

Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Recurring Fair Value Measurements
Total net derivative asset/(liability)	$ 4	$ 24
Commodity derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(4)	(3)
Interest rate derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)		27
Foreign currency derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	8
Level 1
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(2)	11
Level 1 \| Commodity derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(2)	11
Level 1 \| Foreign currency derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	0	0
Level 2
Recurring Fair Value Measurements
Total net derivative asset/(liability)	6	13
Level 2 \| Commodity derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(2)	(14)
Level 2 \| Interest rate derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)		$ 27
Level 2 \| Foreign currency derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	$ 8

Partners' Capital and Distributions - Distributions to Noncontrolling Interests (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Partners Capital and Distribution [Line Items]
Distributions paid	$ 1,733	$ 1,569	$ 1,330
Noncontrolling Interests
Partners Capital and Distribution [Line Items]
Distributions paid	1,433	1,318	1,121
Cash Distribution \| Noncontrolling Interests \| Consolidated Joint Venture Entities
Partners Capital and Distribution [Line Items]
Distributions paid	447	425	333
Cash Distribution \| Noncontrolling Interests \| Permian JV
Partners Capital and Distribution [Line Items]
Distributions paid	360	322	249
Cash Distribution \| Noncontrolling Interests \| Cactus II
Partners Capital and Distribution [Line Items]
Distributions paid	72	77	63
Cash Distribution \| Noncontrolling Interests \| Red River
Partners Capital and Distribution [Line Items]
Distributions paid	$ 15	$ 26	$ 21

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 1,686	$ 1,070	$ 1,425
Reconciliation of net income to net cash provided by operating activities:
Income from discontinued operations, net of tax	(383)	(231)	(192)
Depreciation and amortization	953	901	912
(Gains)/losses on asset sales, asset impairments and other, net (Note 7, Note 8)	(54)	159	(152)
Equity-indexed compensation expense	50	52	51
Deferred income tax expense	91	42	59
(Gain)/loss on foreign currency revaluation	13	(12)	3
Settlement of terminated interest rate hedging instruments (Note 13)	37	57	80
Change in fair value of Preferred Distribution Rate Reset Option (Note 13)	0	0	(58)
Equity earnings in unconsolidated entities	(382)	(452)	(369)
Distributions on earnings from unconsolidated entities	486	505	458
Gain on investments in unconsolidated entities, net (Note 8, Note 9)	(31)	(15)	(28)
Other	15	17	18
Changes in assets and liabilities, net of acquisitions:
Trade accounts receivable and other	207	94	79
Inventory	96	120	102
Trade accounts payable and other	(337)	(77)	(141)
Cash provided by operating activities - continuing operations	2,447	2,230	2,247
Cash provided by operating activities - discontinued operations	484	254	475
Net cash provided by operating activities	2,931	2,484	2,722
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired (Note 8)	(2,651)	(248)	(425)
Investments in unconsolidated entities (Note 9)	(2)	(4)	(33)
Additions to property, equipment and other	(643)	(448)	(408)
Cash paid for purchases of linefill	(27)	(21)	(10)
Proceeds from sales of assets (Note 8)	81	11	328
Other investing activities		5	8
Cash used in investing activities - continuing operations	(3,242)	(705)	(540)
Cash used in investing activities - discontinued operations	(197)	(170)	(162)
Net cash used in investing activities	(3,439)	(875)	(702)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) under PAA commercial paper program (Note 11)	577	(40)	433
Repayment under PAA EPIC credit agreement (Note 11)	(1,114)	0	0
Borrowing under PAA term loan (Note 11)	1,100	0	0
Proceeds from the issuance of PAA senior notes (Note 11)	2,998	650	0
Repayments of PAA senior notes (Note 11)	(1,000)	(750)	(1,100)
Repurchase of common units by a subsidiary (Note 12)	(8)	0
Repurchase of Series A preferred units by a subsidiary (Note 12)	(333)	0	0
Distributions paid to Class A shareholders (Note 12)	(301)	(251)	(209)
Distributions paid to noncontrolling interests (Note 12)	(1,441)	(1,319)	(1,113)
Contributions from noncontrolling interests	75	57	106
Other financing activities	(79)	(49)	(88)
Net cash provided by/(used in) financing activities	474	(1,702)	(1,971)
Effect of translation adjustment - continuing operations	14	(13)	3
Effect of translation adjustment - discontinued operations	0	2	(3)
Net increase/(decrease) in cash and cash equivalents and restricted cash	(20)	(104)	49
Cash and cash equivalents and restricted cash, beginning of period	349	453	404
Cash and cash equivalents and restricted cash, end of period	329	349	453
Cash paid for:
Interest, net of amounts capitalized	431	351	377
Income taxes, net of amounts refunded (Note 15)	$ 98	$ 269	$ 69

CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	$ 14,316	$ 14,972	$ 14,638
Total period activity	187	(247)	118
Balance, end of period	14,216	14,316	14,972
Total
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(1,083)	(836)	(954)
Reclassification adjustments	5	8	11
Unrealized gain on hedges	10	29	15
Currency translation adjustments	167	(284)	91
Other	5		1
Total period activity	187	(247)	118
Balance, end of period	(896)	(1,083)	(836)
Derivative Instruments
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(44)	(81)	(107)
Reclassification adjustments	5	8	11
Unrealized gain on hedges	10	29	15
Total period activity	15	37	26
Balance, end of period	(29)	(44)	(81)
Translation Adjustments
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(1,039)	(755)	(846)
Currency translation adjustments	167	(284)	91
Total period activity	167	(284)	91
Balance, end of period	(872)	$ (1,039)	(755)
Other
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period			(1)
Other	5		1
Total period activity	5		$ 1
Balance, end of period	$ 5

Intangible Assets, Net - Schedule of Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Finite-Lived Intangible Assets
Finite-lived intangible assets, cost	$ 3,063	$ 2,705
Finite-lived intangible assets, accumulated amortization	(1,309)	(1,028)
Finite-lived intangible assets, net	1,754	1,677
Customer contracts and relationships
Finite-Lived Intangible Assets
Finite-lived intangible assets, cost	3,034	2,677
Finite-lived intangible assets, accumulated amortization	(1,295)	(1,015)
Finite-lived intangible assets, net	$ 1,739	1,662
Customer contracts and relationships \| Minimum
Finite-Lived Intangible Assets
Estimated useful lives (in years)	1 year
Customer contracts and relationships \| Maximum
Finite-Lived Intangible Assets
Estimated useful lives (in years)	20 years
Other agreements
Finite-Lived Intangible Assets
Finite-lived intangible assets, cost	$ 29	28
Finite-lived intangible assets, accumulated amortization	(14)	(13)
Finite-lived intangible assets, net	$ 15	$ 15
Other agreements \| Minimum
Finite-Lived Intangible Assets
Estimated useful lives (in years)	15 years
Other agreements \| Maximum
Finite-Lived Intangible Assets
Estimated useful lives (in years)	70 years

- 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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Reference 33: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482665/350-30-50-3

Reference 34: http://www.xbrl.org/2003/role/disclosureRef
-Topic 985
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481283/985-20-50-2

Reference 35: http://www.xbrl.org/2003/role/disclosureRef
-Topic 926
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483154/926-20-50-5

+ Details

Leases - Maturity of Lease Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Operating
2026	$ 31
2027	29
2028	26
2029	22
2030	19
Thereafter	303
Total	430
Less: Present value discount	(201)
Lease liabilities	229	$ 222
Finance
2026	15
2027	15
2028	17
2029	12
2030	9
Thereafter	43
Total	111
Less: Present value discount	(39)
Lease liabilities	72	84
Equity Method Investees \| Agreement to Store at Facilities Owned by Equity Method Investee \| Equity Method Investee That Owns Leased Storage Tanks
Finance
2026	6
2027	6
2028	6
2029	6
2030	6
Thereafter	33
Lease liabilities	$ 32	$ 33
Ownership interest in unconsolidated entity prior to acquisition (as a percent)	50.00%

Property and Equipment - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment [Line Items]
Depreciation expense		$ 673	$ 639	$ 618
Construction in progress expenditures incurred but not yet paid		$ 43	$ 44	$ 40
NGL storage, terminal, fractionation and processing facilities \| NGL
Property, Plant and Equipment [Line Items]
Non-cash impairment losses, long-lived assets	$ 140
Impairment, Long-Lived Asset, Held-For-Use, Statement Of Income [Extensible Enumeration]	Gains/(losses) on asset sales, asset impairments and other, net

Debt - Term Loan Agreement (Details) - USD ($) $ in Millions	Nov. 26, 2025	Dec. 31, 2025
Debt Instrument [Line Items]
Long-term debt		$ 1,099
Term Loan Agreement
Debt Instrument [Line Items]
Long-term debt	$ 1,100
Long-term debt, mandatory prepayment, duration	7 days
Term Loan Agreement \| Secured Overnight Financing Rate (SOFR) \| First Anniversary Of The Closing Date
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	1.125%
Term Loan Agreement \| Secured Overnight Financing Rate (SOFR) \| After The First Anniversary Of The Closing Date
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	1.25%
Term Loan Agreement \| Base Rate \| First Anniversary Of The Closing Date
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	0.125%
Term Loan Agreement \| Base Rate \| After The First Anniversary Of The Closing Date
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	0.25%

- 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 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
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Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
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-SubTopic 10
-Name Accounting Standards Codification
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-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 4: http://www.xbrl.org/2009/role/commonPracticeRef
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Reference 5: http://www.xbrl.org/2009/role/commonPracticeRef
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-Paragraph 3
-Subparagraph (SX 210.12-04(a))
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Reference 6: http://www.xbrl.org/2009/role/commonPracticeRef
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Reference 7: http://www.xbrl.org/2003/role/exampleRef
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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/exampleRef
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Reference 10: http://www.xbrl.org/2003/role/exampleRef
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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 15: http://www.xbrl.org/2003/role/exampleRef
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Reference 16: http://www.xbrl.org/2003/role/disclosureRef
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Reference 26: http://www.xbrl.org/2003/role/disclosureRef
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Reference 27: http://www.xbrl.org/2003/role/disclosureRef
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Reference 28: http://www.xbrl.org/2003/role/disclosureRef
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Reference 29: http://www.xbrl.org/2003/role/disclosureRef
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Reference 30: http://www.xbrl.org/2009/role/commonPracticeRef
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Reference 31: http://www.xbrl.org/2009/role/commonPracticeRef
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-Name Accounting Standards Codification
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+ Details

- Definition

Amount, after deduction of unamortized premium (discount) and debt issuance cost, of long-term debt. Excludes lease obligation.

+ References

+ Details

Acquisitions, Divestitures and Other Transactions - Ironwood Midstream Narrative (Details) - Ironwood Midstream Energy Partners II, LLC $ in Millions	Jan. 31, 2025 USD ($)
Business Combination [Line Items]
Estimated useful lives (in years)	16 years
Intangible assets \| Level 3 \| Measurement Input, Discount Rate \| Valuation Technique, Discounted Cash Flow
Business Combination [Line Items]
Business combination, measurement input	0.18
Customer contracts and relationships
Business Combination [Line Items]
Estimated useful lives (in years)	16 years
EnCap Flatrock Midstream
Business Combination [Line Items]
Cash consideration	$ 481

Derivatives and Risk Management Activities - Currency Exchange Rate Risk Hedging (Details) $ in Millions, $ in Billions	3 Months Ended
	Dec. 31, 2025 USD ($) $ / $	Dec. 31, 2025 CAD ($) $ / $	Dec. 31, 2024 USD ($)
Derivatives and Risk Management Activities
Fair value, asset	$ 4		$ 24
Foreign currency derivatives
Derivatives and Risk Management Activities
Notional amount of derivatives		$ 4.5
Fair value, asset	8
Gains recognized	$ 8
Average fixed exchange rate (cad per usd) \| $ / $	1.37	1.37
Average exchange rate (cad per usd) \| $ / $	1.37	1.37

Commitments and Contingencies - Environmental Loss Contingencies (Details) - Excluding Line 901 Incident - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Loss Contingencies [Line Items]
Other current liabilities	$ 13	$ 11
Other long-term liabilities and deferred credits	70	69
Total	$ 83	$ 80
Environmental Loss Contingency, Current, Statement of Financial Position [Extensible Enumeration]	Other current liabilities	Other current liabilities
Environmental Loss Contingency, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other long-term liabilities and deferred credits	Other long-term liabilities and deferred credits

- 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 275
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 9
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482861/275-10-50-9

Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
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Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147483359/720-20-50-1

Reference 5: http://www.xbrl.org/2003/role/exampleRef
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-URI https://asc.fasb.org/1943274/2147482395/460-10-55-27

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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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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-Name Accounting Standards Codification
-Section 50
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483076/450-20-50-1

+ Details

Leases (Tables)

12 Months Ended

Dec. 31, 2025

Leases [Abstract]

Schedule of Lease Costs and Other Lessee Information

The following table presents components of lease cost, including both amounts recognized in income and amounts capitalized (in millions):


	Year Ended December 31,
Lease Cost	2025		2024		2023
Operating lease cost	$	37	$	44	$	48
Short-term lease cost	13		13		13
Other (1)	19		16		8
Total lease cost	$	69	$	73	$	69

(1)Includes finance lease costs, variable lease costs and sublease income.

The following table presents information related to cash flows arising from lease transactions (in millions):


	Year Ended December 31,
	2025		2024		2023
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	40	$	41	$	44
Operating cash flows for finance leases	$	9	$	7	$	6
Financing cash flows for finance leases	$	23	$	15	$	10

Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications:
Operating leases	$	30	$	50	$	12
Finance leases	$	7	$	23	$	27

Information related to the weighted-average remaining lease term and discount rate is presented in the table below:


	December 31,
	2025		2024
Weighted-average remaining lease term (in years):
Operating leases	21		20
Finance leases	8		7

Weighted-average discount rate:
Operating leases	5.5	%	5.5	%
Finance leases	11.1	%	10.7	%

Schedule of Assets and Liabilities, Lessee

The following table presents the amount and location of our operating and finance lease right-of-use assets and liabilities on our Consolidated Balance Sheets (in millions):


		December 31,
Leases	Balance Sheet Location	2025		2024
Assets
Operating lease right-of-use assets	Long-term operating lease right-of-use assets, net	$	198	$	189

Finance lease right-of-use assets (1)	Property and equipment	$	90	$	103
	Accumulated depreciation	(27)		(28)
	Property and equipment, net	$	63	$	75

Total lease right-of-use assets		$	261	$	264

Liabilities
Operating lease liabilities
Current	Other current liabilities	$	27	$	30
Noncurrent	Long-term operating lease liabilities	202		192
Total operating lease liabilities		$	229	$	222

Finance lease liabilities (1)
Current	Short-term debt	$	9	$	14
Noncurrent	Other long-term debt, net	63		70
Total finance lease liabilities		$	72	$	84

Total lease liabilities		$	301	$	306

(1)Includes right-of-use assets of $23 million and $26 million and lease liabilities of $32 million and $33 million as of December 31, 2025 and 2024, respectively, associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest.

Schedule of Finance Lease Maturity

The following table presents the maturity of undiscounted cash flows for future minimum lease payments under noncancelable leases as of December 31, 2025 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions):


	Operating		Finance (2)
Future minimum lease payments (1):
2026	$	31	$	15
2027	29		15
2028	26		17
2029	22		12
2030	19		9
Thereafter	303		43
Total	430		111
Less: Present value discount	(201)		(39)
Lease liabilities	$	229	$	72

(1)Excludes future minimum payments for short-term and other immaterial leases not included on our Consolidated Balance Sheet.

(2)Includes payments of approximately $6 million for each of the years ending 2026 through 2030 and approximately $33 million thereafter associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest.

Schedule of Operating Lease Maturity


	Operating		Finance (2)
Future minimum lease payments (1):
2026	$	31	$	15
2027	29		15
2028	26		17
2029	22		12
2030	19		9
Thereafter	303		43
Total	430		111
Less: Present value discount	(201)		(39)
Lease liabilities	$	229	$	72

(1)Excludes future minimum payments for short-term and other immaterial leases not included on our Consolidated Balance Sheet.

Schedule of Lessor Operating Lease Revenue

The following table presents our lease revenue for the periods indicated (in millions):


	Year Ended December 31,
	2025		2024		2023
Operating lease revenue (1)	$	8	$	10	$	16

(1)These amounts are included in “Services revenues” on our Consolidated Statements of Operations.

Schedule of Lessor Future Revenues Maturity

The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions):


	2026		2027		2028		2029		2030		Thereafter
Future minimum lease revenue	$	6	$	2	$	2	$	2	$	2	$	1

Revenues and Accounts Receivable

12 Months Ended

Dec. 31, 2025

Revenue from Contract with Customer [Abstract]

Revenues and Accounts Receivable

Revenue Recognition

We disaggregate our revenues by segment and type of activity. These categories depict how the nature, amount, timing and uncertainty of revenues and cash flows are affected by economic factors.

Revenues from Contracts with Customers. The following tables present our revenues from contracts with customers disaggregated by segment and type of activity (in millions):


	Year Ended December 31,
	2025		2024		2023
Crude Oil segment revenues from contracts with customers
Sales	$	42,408	$	47,036	$	45,621
Transportation	1,330		1,231		1,144
Terminalling, Storage and Other	349		384		381
Total Crude Oil segment revenues from contracts with customers	$	44,087	$	48,651	$	47,146


	Year Ended December 31,
	2025		2024		2023
NGL segment revenues from contracts with customers
Sales	$	144	$	180	$	179

Terminalling, Storage and Other	6		7		7

Total NGL segment revenues from contracts with customers	$	150	$	187	$	186

Sales Revenues. Revenues from sales of crude oil and NGL are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. The consideration received under these contracts is variable based on commodity prices. Inventory exchanges under buy/sell transactions are excluded from sales revenues in our Consolidated Statements of Operations.

Transportation Revenues. Transportation revenues include revenues from transporting crude oil on pipelines and trucks. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil at a published tariff. We primarily recognize pipeline tariff and fee revenues over time as services are rendered, based on the volumes transported. As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor. We recognize the allowance volumes collected as part of the transaction price and record this non-cash consideration at fair value, measured as of the contract inception date.

Terminalling, Storage and Other Revenues. Revenues in this category include (i) fees that are generated when we receive liquids from one connecting source and deliver the applicable product to another connecting carrier, (ii) fees from storage capacity agreements, (iii) fees from loading and unloading services at our terminals and (iv) fees from natural gas and condensate processing services. We generate revenue through a combination of month-to-month and multi-year agreements and processing arrangements. Storage fees are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized as our performance obligation is to make available storage capacity for a period of time. Terminal fees (including throughput and loading/unloading fees) are recognized as the liquids enter or exit the terminal and are received from or delivered to the connecting carrier or third-party terminal, as applicable. We recognize loading and unloading fees when the volumes are delivered or received.

Reconciliation to Total Revenues of Reportable Segments. The following disclosures only include information regarding revenues associated with consolidated entities; revenues from entities accounted for by the equity method are not included. The following tables present the reconciliation of our revenues from contracts with customers (as described above for each segment) to total revenues of reportable segments and total revenues as disclosed in our Consolidated Statements of Operations (in millions):


Year Ended December 31, 2025	Crude Oil		NGL		Total
Revenues from contracts with customers	$	44,087	$	150	$	44,237
Other revenues	44		1		45
Total revenues of reportable segments	$	44,131	$	151	$	44,282
Intersegment revenues elimination					(20)
Total revenues					$	44,262


Year Ended December 31, 2024	Crude Oil		NGL		Total
Revenues from contracts with customers	$	48,651	$	187	$	48,838
Other revenues	69		—		69
Total revenues of reportable segments	$	48,720	$	187	$	48,907
Intersegment revenues elimination					(18)
Total revenues					$	48,889


Year Ended December 31, 2023	Crude Oil		NGL		Total
Revenues from contracts with customers	$	47,146	$	186	$	47,332
Other revenues	28		—		28
Total revenues of reportable segments	$	47,174	$	186	$	47,360
Intersegment revenues elimination					(24)
Total revenues					$	47,336

Minimum Volume Commitments. We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right as a contract liability and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote.

The following table presents counterparty deficiencies associated with contracts with customers and buy/sell arrangements that include minimum volume commitments for which we had remaining performance obligations and the customers still had the ability to meet their obligations (in millions):


		December 31,
Counterparty Deficiencies	Financial Statement Classification	2025		2024
Billed and collected	Other current liabilities	$	47	$	83

Contract Balances. Our contract balances consist of amounts received associated with services or sales for which we have not yet completed the related performance obligation. The following table presents the changes in the liability balance associated with contracts with customers (in millions):


	Contract Liabilities
Balance at December 31, 2023	$	101
Amounts recognized as revenue	(36)

Additions	23
Other	(1)
Balance at December 31, 2024	$	87
Amounts recognized as revenue	(42)
Additions	42

Balance at December 31, 2025	$	87

Remaining Performance Obligations. The information below includes the amount of consideration allocated to partially and wholly unsatisfied remaining performance obligations under contracts that existed as of the end of the periods and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These contracts include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of December 31, 2025 (in millions):


	2026		2027		2028		2029		2030		2031 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	398	$	330	$	296	$	210	$	152	$	835
Terminalling, storage and other agreement revenues	241		211		153		109		72		423
Total	$	639	$	541	$	449	$	319	$	224	$	1,258

(1)Calculated as volumes committed under contracts multiplied by the current applicable tariff rate.

The presentation above does not include (i) expected revenues from legacy shippers not underpinned by minimum volume commitments, (ii) intersegment revenues and (iii) the amount of consideration associated with certain income generating contracts, which include a fixed minimum level of service, that are either not within the scope of ASC 606 or do not meet the requirements for presentation as remaining performance obligations. The following are examples of contracts that are not included in the table above because they are not within the scope of ASC 606 or do not meet the requirements for presentation:

•Minimum volume commitments on certain of our joint venture pipeline systems;

•Acreage dedications;

•Buy/sell arrangements with future committed volumes;

•Short-term contracts and those with variable consideration due to the election of practical expedients, as discussed below;

•Contracts within the scope of ASC Topic 842, Leases; and

•Contracts within the scope of ASC Topic 815, Derivatives and Hedging.

We have elected practical expedients to exclude the presentation of remaining performance obligations for variable consideration which relates to wholly unsatisfied performance obligations. Certain contracts do not meet the requirements for presentation of remaining performance obligations due to variability in amount of performance obligation remaining, variability in the timing of recognition or variability in consideration. Acreage dedications require us to perform future services but do not contain a minimum level of services and are therefore excluded from this presentation. Long-term merchant arrangements contain variable timing, volumes and/or consideration and are excluded from this presentation. The duration of these contracts varies across the periods presented above.

Additionally, we have elected practical expedients to exclude contracts with terms of one year or less, and therefore exclude the presentation of remaining performance obligations for short-term transportation, storage and processing services, merchant arrangements, including the non-cancelable period of evergreen arrangements, and any other types of arrangements with terms of one year or less.

Trade Accounts Receivable and Other Receivables, Net

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL. These purchasers include, but are not limited to, refiners, producers, marketing and trading companies and financial institutions. The majority of our accounts receivable relate to our crude oil merchant activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes.

To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions and perform credit reviews of each customer to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit, credit insurance or parental guarantees. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. For a majority of these net-cash arrangements, we also enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet).

Accounts receivable from the sale of crude oil are generally settled with counterparties on the industry settlement date, which is typically in the month following the month in which the title transfers. Otherwise, we generally invoice customers within 30 days of when the products or services were provided and generally require payment within 30 days of the invoice date. We review all outstanding accounts receivable balances on a monthly basis and record our receivables net of expected credit losses. We do not write-off accounts receivable balances until we have exhausted substantially all collection efforts. At December 31, 2025 and 2024, substantially all of our trade accounts receivable were less than 30 days past their invoice date. Our expected credit losses are immaterial. Although we consider our credit procedures to be adequate to mitigate any significant credit losses, the actual amount of current and future credit losses could vary significantly from estimated amounts.

The following is a reconciliation of trade accounts receivable from revenues from contracts with customers to total Trade accounts receivable and other receivables, net as presented on our Consolidated Balance Sheets (in millions):


	December 31,
	2025		2024
Trade accounts receivable arising from revenues from contracts with customers	$	3,639	$	3,922
Other trade accounts receivables and other receivables (1)	7,357		7,339
Impact due to contractual rights of offset with counterparties	(7,398)		(7,582)
Trade accounts receivable and other receivables, net	$	3,598	$	3,679

(1) The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of ASC 606.

- 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
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
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-Publisher FASB
-URI https://asc.fasb.org/606/tableOfContent

+ Details

Income Taxes

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Income Taxes

Income tax expense is estimated using the tax rate in effect or to be in effect during the relevant periods in the jurisdictions in which we operate. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes and are stated at enacted tax rates expected to be in effect when taxes are actually paid or recovered. To the extent we do not consider it more likely than not that a deferred tax asset will be recovered, a valuation allowance is established. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. We review contingent tax liabilities for estimated exposures on a more likely than not standard related to our current tax positions.

Pursuant to FASB guidance related to accounting for uncertainty in income taxes, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and precedents of the taxing authority. As of December 31, 2025 and 2024, we had not recognized any material amounts in connection with uncertainty in income taxes.

U.S. Federal and State Taxes

Although we are organized as a limited partnership, we have elected to be treated as a corporation for U.S. federal income tax purposes and are therefore subject to both U.S. federal and state income taxes.

Canadian Federal and Provincial Taxes

All of our Canadian operations are conducted by entities that are treated as corporations for Canadian tax purposes (flow through for U.S. income tax purposes) and thus are subject to Canadian federal and provincial taxes. Additionally, payments of interest and dividends from our Canadian entities to other Plains entities are subject to Canadian withholding tax that is treated as income tax expense.

Tax Components

Pre-tax book income by geography is as follows (in millions):


	Year Ended December 31,
	2025		2024		2023
United States	$	1,350	$	832	$	1,130
Canada	45		131		232
Total pre-tax book income	$	1,395	$	963	$	1,362

Components of income tax expense are as follows (in millions):


	Year Ended December 31,
	2025		2024		2023
Current income tax expense/(benefit):
State income tax	$	2	$	2	$	2
Canadian federal and provincial income and withholding taxes	(1)		80		68
Total current income tax expense	$	1	$	82	$	70

Deferred income tax expense/(benefit):
U.S. federal income tax	$	71	$	31	$	55
State income tax	6		6		13
Canadian federal and provincial income and withholding taxes	14		5		(9)
Total deferred income tax expense	$	91	$	42	$	59
Total income tax expense	$	92	$	124	$	129

The difference between income tax expense based on the statutory federal income tax rate and our effective income tax expense is summarized as follows (in millions, except percentages):


	Year Ended December 31,
	2025				2024				2023
	Amount		Percent		Amount		Percent		Amount		Percent
U.S. federal statutory tax rate	$	293	21.00	%	$	202	21.00	%	$	286	21.00	%

State and local income taxes (1)	8		0.57	%	8		0.87	%	15		1.08	%

Foreign tax effects:
Canada
Foreign rate differential	(3)		(0.22)	%	(8)		(0.81)	%	(14)		(1.02)	%
Provincial taxes	5		0.36	%	13		1.22	%	20		1.50	%
Foreign withholding taxes	3		0.22	%	52		5.43	%	—		—	%
Other	(2)		(0.14)	%	—		—	%	4		0.32	%

Nontaxable or nondeductible items:
Nontaxable income attributable to noncontrolling interests	(212)		(15.20)	%	(143)		(14.97)	%	(180)		(13.25)	%
Other permanent book tax differences	—		—	%	—		—	%	(2)		(0.14)	%

Effective tax rate (2)	$	92	6.59	%	$	124	12.84	%	$	129	9.48	%

(1)The state and local income tax category of the rate reconciliation is primarily comprised of income taxes in Texas, Oklahoma and New Mexico, which represents more than 50 percent of the state and local tax effect.

(2)Consolidated pretax income includes amounts attributable to non-controlling interests. Income attributable to non-controlling interests does not result in income tax expense of the reporting entity because the related taxes are incurred by the noncontrolling owners. Accordingly, the effective tax rate reconciliation includes a reconciling item for income attributable to non-controlling interests.

Supplemental Disclosures

Cash taxes paid were as follows (in millions):


	Year Ended December 31,
	2025		2024		2023


State income tax:
Texas	$	1	$	2	2

Total state income tax paid	1		2		2

Canadian federal and provincial income and withholding taxes	97		267		67

Total cash tax paid	$	98	$	269	$	69

Deferred tax assets and liabilities are aggregated by the applicable tax paying entity and jurisdiction and result from the following (in millions):


	December 31,
	2025		2024
Deferred tax assets:
Investment in partnerships	$	151	$	436
Net operating losses	985		784
Derivative instruments	—		6
Lease liabilities	10		8
Other	7		8
Total deferred tax assets	1,153		1,242

Deferred tax liabilities:
Property and equipment in excess of tax values	(204)		(188)

Lease assets	(9)		(10)
Other	(1)		—
Total deferred tax liabilities	(214)		(198)
Net deferred tax assets	$	939	$	1,044

Balance sheet classification of deferred tax assets/(liabilities):
Deferred tax asset	$	1,136	$	1,220
Other long-term liabilities and deferred credits	(197)		(176)
	$	939	$	1,044

As a result of the exchange of the ownership interest in AAP in connection with our IPO and all subsequent exchanges, a deferred tax asset was created. These transfers of ownership were accounted for at the historical carrying basis for GAAP accounting purposes, but were recorded at the fair market value of the Class A shares at the time of exchange for U.S. federal income tax purposes. These transfers were transactions among shareholders, with the basis differences resulting in a deferred tax asset that was recorded as a component of partners’ capital. Also, other equity transactions, including the repurchase of common units by PAA, and the associated adjustment to partners’ capital attributable to PAGP resulted in a corresponding change to the deferred tax asset balance that was recorded as a component of partners’ capital. See Note 12 for additional information regarding exchanges and the repurchase of common units by PAA. The deferred tax asset is amortized to deferred income tax expense as the associated basis step-up is realized on our tax returns.

As of December 31, 2025, our federal and state net operating loss carryforwards for income tax purposes were approximately $4,482 million and $1,134 million, respectively. If not utilized, the state net operating losses will begin to expire in 2026 and a portion of our federal net operating losses will begin to expire in 2033. Under the Tax Cuts and Jobs Act, U.S. federal NOLs generated after 2017 will have an indefinite carryforward period but may only reduce up to 80% of taxable income in any given year. Our U.S. federal NOLs generated prior to 2018 will not be subject to the taxable income limitation and will remain subject to a 20 year carryforward period.

Generally, tax returns for our Canadian entities are open to audit from 2018 through 2025. Our U.S. and state tax years are generally open to examination from 2022 to 2025.

As of December 31, 2025, in reference to tax years 2012 to 2019, we had received notices of reassessment (“notices”) from the Canada Revenue Agency and the Alberta Tax and Revenue Administration (the “Canadian Tax Authorities”) related primarily to transfer pricing associated with cross-border intercompany financing transactions. The notices include assessments, including penalties and interest, associated with these transfer pricing matters totaling approximately $189 million (based on the exchange rate as of December 31, 2025). Payment of a portion of the assessment is required in order to file a notice of objection to dispute the reassessment. Accordingly, we have remitted approximately $86 million (based on the exchange rate as of December 31, 2025) related to the assessments, which is included in “Other long-term assets, net,” on our Consolidated Balance Sheets. We disagree with these notices and have contested the reassessments. We intend to vigorously defend our position, and we plan to pursue all remedies available to us to successfully resolve these matters, including administrative remedies with the Canadian Tax Authorities, and judicial remedies, if necessary. As of December 31, 2025, we believe that our tax position associated with these matters is “more likely than not” to be sustained and have not recognized any amounts for uncertainty in income taxes related to these notices.

- Definition

The entire disclosure for income tax.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 740
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Segment Information

12 Months Ended

Dec. 31, 2025

Segment Reporting [Abstract]

Segment Information

Our operating segments, Crude Oil and NGL, which are also our reportable segments, are organized by product as our Crude Oil and NGL businesses are generally impacted by different market fundamentals and require the use of different assets and business strategies. The Crude Oil segment includes our crude oil pipelines, crude oil storage and marine terminals and related crude oil marketing activities. Our crude oil marketing activities are included in our Crude Oil reporting segment as its primary purpose is to support the utilization of our assets by entering into transactions that facilitate increased volumes handled by our assets, resulting in additional earnings for the segment. The NGL segment includes our NGL assets primarily located in the Southwestern United States.

Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below). The measure of Segment Adjusted EBITDA forms the basis of our internal financial reporting and is the primary performance measure of segment profit/(loss) used by our CODM in assessing performance and allocating resources among our operating segments. We define Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) significant segment expenses including: (i) purchases and related costs, (ii) field operating costs and (iii) segment general and administrative expenses, plus (b) our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities, further adjusted (c) for certain selected items including (i) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance and (d) to exclude the portion of all preceding items that is attributable to noncontrolling interests in consolidated joint venture entities (“Segment amounts attributable to noncontrolling interests in consolidated joint ventures”).

Our CODM uses Segment Adjusted EBITDA to evaluate the performance of each segment, including analyzing actual results compared to budget and guidance, to assess investment opportunities and to optimize and align assets to maximize returns to stakeholders.

Segment Adjusted EBITDA excludes depreciation and amortization. We look at each period’s earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of Segment Adjusted EBITDA as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as pipelines and facilities, caused by age-related decline and wear and tear. We compensate for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance investments, which act to partially offset the aging and wear and tear in the value of our principal fixed assets. These maintenance investments are a component of field operating costs included in Segment Adjusted EBITDA or in maintenance capital, depending on the nature of the cost. Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as investment capital. Capital expenditures made to replace and/or refurbish partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as maintenance capital. Maintenance capital is reviewed by our CODM on a segment basis. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are charged to expense as incurred. Assets are not reviewed by our CODM on a segmented basis; therefore, such information is not presented.

The following tables reflect certain financial data from continuing operations for each segment (in millions):


	Crude Oil		NGL		Intersegment Elimination		Total
Year Ended December 31, 2025
Revenues (1):
Product sales	$	42,373	$	145	$	(17)	$	42,501
Services	1,758		6		(3)		1,761
Total revenues	$	44,131	$	151	$	(20)	$	44,262

Significant segment expenses:
Purchases and related costs (1)	$	(40,323)	$	(130)	$	20	$	(40,433)
Field operating costs	(1,127)		(27)		—		(1,154)
Segment general and administrative expenses	(314)		(28)		—		(342)
Total significant segment expenses	$	(41,764)	$	(185)	$	20	$	(41,929)

Equity earnings in unconsolidated entities	$	382	$	—

Other segment items (2):
Depreciation and amortization of unconsolidated entities (3)	84		—
Derivative activities and inventory valuation adjustments (4)	(23)		—
Long-term inventory costing adjustments (5)	45		—
Deficiencies under minimum volume commitments, net (6)	(38)		—
Equity-indexed compensation expense (7)	37		—
Foreign currency revaluation (8)	12		—

Transaction-related expenses (9)	17		—
Segment amounts attributable to noncontrolling interests in consolidated joint ventures (10)	(539)		—
Total other segment items	$	(405)	$	—

Segment Adjusted EBITDA	$	2,344	$	(34)

Investment and acquisition capital expenditures (11) (12)	$	3,321	$	—			$	3,321
Maintenance capital expenditures (12)	$	153	$	3			$	156

As of December 31, 2025

Investments in unconsolidated entities	$	2,846	$	—			$	2,846


	Crude Oil		NGL		Intersegment Elimination		Total
Year Ended December 31, 2024
Revenues (1):
Product sales	$	47,034	$	181	$	(16)	$	47,199
Services	1,686		6		(2)		1,690
Total revenues	$	48,720	$	187	$	(18)	$	48,889

Significant segment expenses:
Purchases and related costs (1)	$	(45,033)	$	(147)	$	18	$	(45,162)
Field operating costs	(1,440)		(31)		—		(1,471)
Segment general and administrative expenses	(298)		(30)		—		(328)
Total significant segment expenses	$	(46,771)	$	(208)	$	18	$	(46,961)

Equity earnings in unconsolidated entities	$	452	$	—

Other segment items (2):
Depreciation and amortization of unconsolidated entities (3)	84		—
Derivative activities and inventory valuation adjustments (4)	5		—
Long-term inventory costing adjustments (5)	1		—
Deficiencies under minimum volume commitments, net (6)	(31)		—
Equity-indexed compensation expense (7)	36		—
Foreign currency revaluation (8)	(22)		—
Line 901 incident (13)	345		—

Segment amounts attributable to noncontrolling interests in consolidated joint ventures (10)	(543)		—
Total other segment items	$	(125)	$	—

Segment Adjusted EBITDA	$	2,276	$	(21)

Investment and acquisition capital expenditures (11) (12)	$	554	$	—			$	554
Maintenance capital expenditures (12)	$	183	$	4			$	187

As of December 31, 2024

Investments in unconsolidated entities	$	2,811	$	—			$	2,811


	Crude Oil		NGL		Intersegment Elimination		Total
Year Ended December 31, 2023
Revenues (1):
Product sales	$	45,587	$	180	$	(22)	$	45,745
Services	1,587		6		(2)		1,591
Total revenues	$	47,174	$	186	$	(24)	$	47,336

Significant segment expenses:
Purchases and related costs (1)	$	(43,805)	$	(156)	$	24	$	(43,937)
Field operating costs	(1,053)		(32)		—		(1,085)
Segment general and administrative expenses	(271)		(28)		—		(299)
Total significant segment expenses	$	(45,129)	$	(216)	$	24	$	(45,321)

Equity earnings in unconsolidated entities	$	369	$	—

Other segment items (2):
Depreciation and amortization of unconsolidated entities (3)	87		—
Derivative activities and inventory valuation adjustments (4)	17		—
Long-term inventory costing adjustments (5)	22		—
Deficiencies under minimum volume commitments, net (6)	12		—
Equity-indexed compensation expense (7)	35		—
Foreign currency revaluation (8)	19		—
Line 901 incident (13)	10		—
Transaction-related expenses (9)	1		—
Segment amounts attributable to noncontrolling interests in consolidated joint ventures (10)	(454)		—
Total other segment items	$	(251)	$	—

Segment Adjusted EBITDA	$	2,163	$	(30)

Investment and acquisition capital expenditures (11) (12)	$	765	$	—			$	765
Maintenance capital expenditures (12)	$	145	$	6			$	151

As of December 31, 2023

Investments in unconsolidated entities	$	2,820	$	—			$	2,820

(1)Segment revenues include intersegment amounts that are eliminated in Purchases and related costs. Intersegment activities are conducted at posted tariff rates where applicable, or otherwise at rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated.

(2)Represents adjustments utilized by our CODM in the evaluation of segment results.

(3)Includes our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities.

(4)We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify differences in the timing of earnings from the derivative instruments and the underlying transactions and exclude the related gains and losses in determining Segment Adjusted EBITDA such that the earnings from the derivative instruments and the underlying transactions impact Segment Adjusted EBITDA in the same period. In addition, we exclude gains and losses on derivatives that are related to (i) investing activities, such as the purchase of linefill, and (ii) purchases of long-term inventory. We also exclude the impact of corresponding inventory valuation adjustments, as applicable.

(5)We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We exclude the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and write-downs of such inventory that result from price declines from Segment Adjusted EBITDA.

(6)We, and certain of our equity method investees, have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue or equity earnings, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to Segment Adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.

(7)Our total equity-indexed compensation expense includes expense associated with awards that will be settled in PAA common units and awards that will be settled in cash. The awards that will be settled in PAA common units are included in PAA’s diluted net income per unit calculation when the applicable performance criteria have been met. We exclude compensation expense associated with these awards in determining Segment Adjusted EBITDA as the dilutive impact of the outstanding awards is included in PAA’s diluted net income per unit calculation, as applicable. The portion of compensation expense associated with awards that will be settled in cash is not excluded in determining Segment Adjusted EBITDA. See Note 18 for information regarding our equity-indexed compensation plans.

(8)During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. These gains and losses are not integral to our core operating performance and were therefore excluded in determining Segment Adjusted EBITDA.

(9)Primarily related to deal-specific costs incurred during the years presented. See Note 8 for additional discussion. An adjustment for these non-recurring expenses is included in the calculation of Segment Adjusted EBITDA for the years ended December 31, 2025 and 2023 as our CODM does not view such expenses as integral to understanding our core segment operating performance.

(10)Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River.

(11)Investment capital and acquisition capital expenditures, including investments in unconsolidated entities.

(12)These amounts combined represent total capital expenditures.

(13)Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance (as applicable). The year ended December 31, 2024 includes the write-off of a receivable for Line 901 insurance proceeds in the fourth quarter of 2024 and the impact of settlements in the third quarter of 2024. See Note 19 for additional information regarding the Line 901 incident.

Segment Adjusted EBITDA Reconciliation

The following table reconciles Segment Adjusted EBITDA to Income from continuing operations, net of tax (in millions):


	Year Ended December 31,
	2025		2024		2023
Segment Adjusted EBITDA	$	2,310	$	2,255	$	2,133
Total other segment items (1)	405		125		251
Unallocated general and administrative expenses (2)	(6)		(6)		(6)
Depreciation and amortization	(953)		(901)		(912)
Gains/(losses) on asset sales, asset impairments and other, net	54		(159)		152

Gain on investments in unconsolidated entities, net	31		15		28
Interest expense, net	(467)		(382)		(386)
Other income, net	21		16		102
Income from continuing operations before tax	1,395		963		1,362
Income tax expense from continuing operations	(92)		(124)		(129)
Income from continuing operations, net of tax	$	1,303	$	839	$	1,233

(1)See footnotes to the segment financial data tables above for a more detailed discussion of Other segment items.

(2)Represents general and administrative expenses incremental to those of PAA, which are not allocated to our reporting segments in determining Segment Adjusted EBITDA.

Geographic Data

We have operations in the United States and Canada. Set forth below are revenues and long-lived assets attributable to these geographic areas (in millions):


	Year Ended December 31,
Revenues (1)	2025		2024		2023
United States	$	39,761	$	43,535	$	41,738
Canada	4,501		5,354		5,598
	$	44,262	$	48,889	$	47,336

(1)Revenues are primarily attributed to each region based on where the services are provided or the product is shipped.


	December 31,
Long-Lived Assets (1)	2025		2024
United States	$	21,398	$	17,955
Canada	1,480		1,429
	$	22,878	$	19,384

(1)Excludes long-term derivative assets and long-term deferred tax assets.

- 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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+ Details

Investments in Unconsolidated Entities (Tables)

12 Months Ended

Dec. 31, 2025

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Investments in and Summarized Financial Information for Entities Accounted for under the Equity Method of Accounting

Our investments in unconsolidated entities consisted of the following (in millions, except percentage data):


		Ownership Interest at December 31, 2025	Investment Balance December 31,

Entity (1)	Type of Operation		2025		2024
BridgeTex Pipeline Company, LLC (“BridgeTex”)	Crude Oil Pipeline	40%	$	574	$	403
Capline Pipeline Company LLC (“Capline”) (2)	Crude Oil Pipeline	54%	473		501
Diamond Pipeline LLC	Crude Oil Pipeline	50%	432		440
Eagle Ford Pipeline LLC	Crude Oil Pipeline	50%	347		364
Eagle Ford Terminals Corpus Christi LLC	Crude Oil Terminal and Dock	50%	110		113

Saddlehorn Pipeline Company, LLC (“Saddlehorn”)	Crude Oil Pipeline	40%	262		275
White Cliffs Pipeline, L.L.C.	Crude Oil Pipeline	36%	109		123
Wink to Webster Pipeline LLC (“W2W Pipeline”) (3)	Crude Oil Pipeline	17%	383		393
Other investments			156		199
Total Investments in Unconsolidated Entities			$	2,846	$	2,811

(1)The financial results from these entities are reported in our Crude Oil segment.

(2)Although we own more than 50% of Capline, we use the equity method to account for the investment because the other joint venture members still retain substantive participating rights.

(3)Although we own less than 20% of W2W Pipeline, we use the equity method to account for the investment because we believe we have significant influence over the financial and operating decisions of the company.

Combined summarized financial information for all of our unconsolidated entities is shown in the tables below (in millions). None of our unconsolidated entities have noncontrolling interests.


	December 31,
	2025		2024
Current assets	$	441	$	475
Noncurrent assets	$	6,755	$	6,996
Current liabilities	$	317	$	261
Noncurrent liabilities	$	13	$	12


	Year Ended December 31,
	2025		2024		2023
Revenues	$	1,926	$	2,193	$	1,667
Operating income	$	1,075	$	1,373	$	921
Net income	$	1,094	$	1,407	$	947

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2025
Accounting Policies [Abstract]
Basis of Consolidation and Presentation	Basis of Consolidation and Presentation The accompanying financial statements and related notes present and discuss our consolidated financial position as of December 31, 2025 and 2024, and the consolidated results of our operations, cash flows, changes in partners’ capital, comprehensive income and changes in accumulated other comprehensive income/(loss) for the years ended December 31, 2025, 2024 and 2023. All significant intercompany balances and transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications had no impact on net income or total partners’ capital. The accompanying consolidated financial statements include the accounts of PAGP and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise.
Variable Interest Entities	Management judgment is required to evaluate whether PAGP controls an entity. Key areas of that evaluation include (i) determining whether an entity is a variable interest entity (“VIE”); (ii) determining whether PAGP is the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that PAGP and its related parties have over those activities through variable interests; and (iii) identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether PAGP is a VIE’s primary beneficiary. We have determined that our subsidiaries, PAA and AAP, are VIEs and should be consolidated by PAGP because: •The limited partners of PAA and AAP lack (i) substantive “kick-out rights” (i.e., the right to remove the general partner) based on a simple majority or lower vote and (ii) substantive participation rights and thus lack the ability to block actions of the general partner that most significantly impact the economic performance of PAA and AAP, respectively. •AAP is the primary beneficiary of PAA because it has the power to direct the activities that most significantly impact PAA’s performance and the right to receive benefits, and obligation to absorb losses, that could be significant to PAA. •PAGP is the primary beneficiary of AAP because it has the power to direct the activities that most significantly impact AAP’s performance and the right to receive benefits, and obligation to absorb losses, that could be significant to AAP. With the exception of a deferred tax asset of $1.136 billion and $1.220 billion as of December 31, 2025 and 2024, respectively, substantially all assets and liabilities presented on PAGP’s Consolidated Balance Sheets are those of PAA. Only the assets of each respective VIE can be used to settle the obligations of that individual VIE, and the creditors of each/either of those VIEs do not have recourse against the general credit of PAGP. PAGP did not provide any financial support to PAA or AAP during the years ended December 31, 2025, 2024 or 2023. See Note 17 for information regarding the Omnibus Agreement entered into by the Plains Entities on November 15, 2016. Pending Sale of Canadian NGL Business On June 17, 2025, a subsidiary of PAA entered into a definitive Share Purchase Agreement (“SPA”) with Keyera Corp. (“Keyera”), an Alberta corporation, pursuant to which Keyera agreed to acquire all of the issued and outstanding shares of Plains Midstream Canada ULC, PAA’s wholly-owned subsidiary that owns substantially all of the NGL business in Canada (the “Canadian NGL Business”), for cash consideration of approximately CAD$5.15 billion (approximately $3.75 billion), subject to certain post-closing adjustments, as defined in the SPA. This transaction is expected to close around the end of the first quarter of 2026, subject to the satisfaction or waiver of customary closing conditions, including receipt of regulatory approvals. We determined that in conjunction with entering into the SPA, the operations of the Canadian NGL Business meet the criteria for classification as held for sale and for discontinued operations reporting, as the sale will represent a strategic shift that will have a major effect on our operations and financial results. Accordingly, the assets and liabilities of the Canadian NGL Business have been classified as held for sale, and the balance sheet, results of operations and cash flows of the Canadian NGL Business have been presented as discontinued operations in our consolidated financial statements. Unless otherwise indicated, the disclosures included within the accompanying notes to the consolidated financial statements relate to our continuing operations and exclude amounts related to discontinued operations. These changes have been applied retrospectively to all periods presented. Discontinued operations are not presented separately within our Consolidated Statements of Comprehensive Income, Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss) or the Consolidated Statements of Changes in Partners’ Capital. See Note 3 for additional information regarding discontinued operations. All significant intercompany balances and transactions between the Canadian NGL Business and our continuing operations have been eliminated. We will divest the Canadian NGL Business as part of the sale, which includes substantially all of our NGL assets; the assets that we will retain are located in the United States. Prior to its classification as held for sale and presentation as discontinued operations, the Canadian NGL Business was part of our NGL reportable segment. In June 2025, we entered into a forward currency instrument to hedge currency exchange risk associated with anticipated proceeds from the pending sale of our Canadian NGL Business. See Note 13 for additional information. In connection with and contingent upon closing of the pending sale, we and Keyera entered into an agreement for certain hedging arrangements and payments relating to the differential between the price of natural gas and the extracted NGL commodities (“Frac Spread”) for a twelve-month period commencing the first month after the closing date. As a result of this arrangement, we will guarantee a minimum Frac Spread margin on certain volumes. The recognition of an asset or liability will be dependent upon the terms of the specific contracts transferred as part of the sale of the Canadian NGL Business and the market conditions at that time the sale closes. We do not expect any liability we might recognize as a result of this agreement to have a material adverse effect on our consolidated financial condition, results of operations or cash flows; for example, if the sale closed at the end of the first quarter of 2026, based on existing contracts to be transferred and current market conditions as of December 31, 2025, we would recognize a liability of approximately $65 million. Subsequent Events Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, as well as the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. We make significant estimates with respect to (i) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (ii) fair value of derivatives, (iii) accruals and contingent liabilities, (iv) property and equipment, depreciation and amortization expense and asset retirement obligations, (v) impairment assessments of property and equipment, investments in unconsolidated entities and intangible assets and (vi) inventory valuations. Although we believe these estimates are reasonable, actual results could differ from these estimates.
Purchases and Related Costs	Purchases and Related Costs Purchases and related costs include (i) the weighted average cost of crude oil and NGL sold to customers, (ii) fees incurred for storage and transportation, whether by pipeline, truck or rail and (iii) performance-related bonus costs. These costs are recognized when incurred except in the case of products sold, which are recognized at the time title transfers to our customers. Inventory exchanges under buy/sell transactions are presented net in “Purchases and related costs” in our Consolidated Statements of Operations.
Field Operating Costs and General and Administrative Expenses	Field Operating Costs and General and Administrative Expenses Field operating costs consist of various field operating expenses, including payroll, compensation and benefits costs for operations personnel; fuel and power costs (including the impact of gains and losses from derivative related activities); third-party trucking transportation costs for our U.S. crude oil operations; maintenance and integrity management costs; regulatory compliance; environmental remediation; insurance; costs for usage of third-party owned pipeline, rail and storage assets; vehicle leases; and property taxes. General and administrative expenses consist primarily of payroll, compensation and benefits costs; certain information systems and legal costs; office rent; contract and consultant costs; and audit and tax fees.
Foreign Currency Transactions/Translation	Foreign Currency Transactions/Translation Certain of our subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of subsidiaries with a Canadian dollar functional currency are translated at period-end rates of exchange, and revenues and expenses are translated at average exchange rates prevailing for each month. The resulting translation adjustments are made directly to a separate component of other comprehensive income, which is reflected in Partners’ Capital on our Consolidated Balance Sheets. Certain of our subsidiaries also enter into transactions and have monetary assets and liabilities that are denominated in a currency other than the entities’ respective functional currencies. Gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities are generally included in the Consolidated Statements of Operations. However, gains and losses arising from intercompany foreign currency transactions that are of a long-term investment nature are reported in the same manner as translation adjustments.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. In accordance with our policy, unless they may be covered by funds on deposit, outstanding checks are classified as trade accounts payable rather than negative cash. As of December 31, 2025 and 2024, trade accounts payable included $31 million and $27 million, respectively, of outstanding checks that were reclassified from cash and cash equivalents.
Noncontrolling Interests	Noncontrolling Interests Noncontrolling interest represents the portion of assets and liabilities in a consolidated subsidiary that is owned by a third party. FASB guidance requires all entities to report noncontrolling interests in subsidiaries as a component of equity in the consolidated financial statements. See Note 12 for additional discussion regarding our noncontrolling interests.
Asset Retirement Obligations	Asset Retirement Obligations FASB guidance establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including estimates related to (i) the time of the liability recognition, (ii) initial measurement of the liability, (iii) allocation of asset retirement cost to expense, (iv) subsequent measurement of the liability and (v) financial statement disclosures. FASB guidance also requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Some of our assets, primarily our pipelines and terminals assets, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. These assets have been in existence for many years and with regular maintenance will continue to be in service for many years to come. It is not possible to predict when demand for these transportation, storage or other services will cease, and we do not believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations. We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonably estimate the settlement dates. A small portion of our contractual or regulatory obligations is related to assets that are inactive or that we plan to take out of service and, although the ultimate timing and costs to settle these obligations are not known with certainty, we have recorded a reasonable estimate of these obligations.
Fair Value Measurements	Fair Value Measurements Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which affects the placement of assets and liabilities within the fair value hierarchy levels. The determination of the fair values includes not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit) but also the impact of our nonperformance risk on our liabilities. The fair value of our commodity, interest rate and foreign currency derivatives includes adjustments for credit risk. Our credit adjustment methodology uses market observable inputs and requires judgment. There were no changes to any of our valuation techniques during the period.
Recent Accounting Pronouncements, Disclosure Rules and Other Legislation	Recent Accounting Pronouncements, Disclosure Rules and Other Legislation Recent Accounting Pronouncements In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which requires, among other things, disclosure of specified information about certain costs and expenses in the notes to the financial statements. The guidance is effective prospectively for annual periods beginning after December 15, 2026 and interim periods beginning after December 15, 2027 with retrospective application and early adoption permitted. We intend to provide the required disclosures beginning with our annual report for the year ended December 31, 2027. In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires, among other things, disaggregated information about effective tax rate reconciliation and income taxes paid (net of refunds received) on an annual basis. The guidance is effective prospectively for annual periods beginning after December 15, 2024 with retrospective or early adoption permitted. We adopted this guidance beginning with our annual report for the year ended December 31, 2025. See Note 15 for updated income tax disclosures. Other than such disclosure updates, our adoption did not have a material impact on our financial position, results of operations or cash flows. In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which requires disaggregated disclosure of significant segment expenses and other amounts included within the reported measure of segment profit or loss for each reportable segment on an annual and interim basis. The guidance is effective retrospectively for annual periods beginning after December 15, 2023, and interim periods in fiscal years beginning after December 15, 2024 with early adoption permitted. We adopted this guidance beginning with our annual report for the year ended December 31, 2024. See Note 20 for our segment disclosures. Other than disclosures, our adoption did not have a material impact on our financial position, results of operations or cash flows. In August 2023, the FASB issued ASU 2023-05, Business Combinations—Joint Venture Formations (Subtopic 805-60): Recognition and Initial Measurement, which requires a newly-formed joint venture to apply a new basis of accounting to its contributed net assets, resulting in the joint venture initially measuring its contributed net assets at fair value on the formation date. This guidance is effective prospectively for all joint ventures with a formation date on or after January 1, 2025, with early adoption permitted. We adopted this guidance for joint venture formations on or after January 1, 2025. SEC Climate Disclosure Rules In March 2024, the SEC adopted final rules (“climate disclosure rules”) requiring registrants to disclose, among other things, information about material climate-related risks and their impact on a registrant’s strategy, business model and outlook; information about material direct and indirect greenhouse gas emissions (Scope 1 and Scope 2), which are subject to assurance requirements; and the financial statement effects of severe weather events and other natural conditions. In April 2024, the SEC stayed the climate disclosure rules pending resolution of legal challenges. In March 2025, the SEC voted to withdraw its defense of the climate disclosure rules. International Tax Reform Recently, several countries, including Canada, have enacted legislation to implement key aspects of the global minimum top-up tax in accordance with the Pillar Two model rules of the OECD tax framework. We continue to evaluate the new legislation, but do not currently expect a material impact on our financial position, results of operations or cash flows.
Revenue Recognition	Revenue Recognition We disaggregate our revenues by segment and type of activity. These categories depict how the nature, amount, timing and uncertainty of revenues and cash flows are affected by economic factors. Sales Revenues. Revenues from sales of crude oil and NGL are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. The consideration received under these contracts is variable based on commodity prices. Inventory exchanges under buy/sell transactions are excluded from sales revenues in our Consolidated Statements of Operations. Transportation Revenues. Transportation revenues include revenues from transporting crude oil on pipelines and trucks. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil at a published tariff. We primarily recognize pipeline tariff and fee revenues over time as services are rendered, based on the volumes transported. As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor. We recognize the allowance volumes collected as part of the transaction price and record this non-cash consideration at fair value, measured as of the contract inception date Terminalling, Storage and Other Revenues. Revenues in this category include (i) fees that are generated when we receive liquids from one connecting source and deliver the applicable product to another connecting carrier, (ii) fees from storage capacity agreements, (iii) fees from loading and unloading services at our terminals and (iv) fees from natural gas and condensate processing services. We generate revenue through a combination of month-to-month and multi-year agreements and processing arrangements. Storage fees are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized as our performance obligation is to make available storage capacity for a period of time. Terminal fees (including throughput and loading/unloading fees) are recognized as the liquids enter or exit the terminal and are received from or delivered to the connecting carrier or third-party terminal, as applicable. We recognize loading and unloading fees when the volumes are delivered or received. Reconciliation to Total Revenues of Reportable Segments. The following disclosures only include information regarding revenues associated with consolidated entities; revenues from entities accounted for by the equity method are not included. Minimum Volume Commitments. We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right as a contract liability and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. Contract Balances. Our contract balances consist of amounts received associated with services or sales for which we have not yet completed the related performance obligation.Remaining Performance Obligations. The information below includes the amount of consideration allocated to partially and wholly unsatisfied remaining performance obligations under contracts that existed as of the end of the periods and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These contracts include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. We have elected practical expedients to exclude the presentation of remaining performance obligations for variable consideration which relates to wholly unsatisfied performance obligations. Certain contracts do not meet the requirements for presentation of remaining performance obligations due to variability in amount of performance obligation remaining, variability in the timing of recognition or variability in consideration. Acreage dedications require us to perform future services but do not contain a minimum level of services and are therefore excluded from this presentation. Long-term merchant arrangements contain variable timing, volumes and/or consideration and are excluded from this presentation. The duration of these contracts varies across the periods presented above. Additionally, we have elected practical expedients to exclude contracts with terms of one year or less, and therefore exclude the presentation of remaining performance obligations for short-term transportation, storage and processing services, merchant arrangements, including the non-cancelable period of evergreen arrangements, and any other types of arrangements with terms of one year or less.
Trade Accounts Receivable and Other Receivables, Net	Trade Accounts Receivable and Other Receivables, Net Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL. These purchasers include, but are not limited to, refiners, producers, marketing and trading companies and financial institutions. The majority of our accounts receivable relate to our crude oil merchant activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions and perform credit reviews of each customer to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit, credit insurance or parental guarantees. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. For a majority of these net-cash arrangements, we also enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet). Accounts receivable from the sale of crude oil are generally settled with counterparties on the industry settlement date, which is typically in the month following the month in which the title transfers. Otherwise, we generally invoice customers within 30 days of when the products or services were provided and generally require payment within 30 days of the invoice date. We review all outstanding accounts receivable balances on a monthly basis and record our receivables net of expected credit losses. We do not write-off accounts receivable balances until we have exhausted substantially all collection efforts.
Net Income Per Class A Share	Basic net income per Class A share is determined by dividing net income attributable to PAGP from continuing operations and net income attributable to PAGP from discontinued operations by the weighted average number of Class A shares outstanding during the period. Our Class B and Class C shares do not share in the earnings of the Partnership; accordingly, basic and diluted net income per Class B and Class C share has not been presented. Diluted net income per Class A share is determined by dividing net income attributable to PAGP from continuing operations and net income attributable to PAGP from discontinued operations by the diluted weighted average number of Class A shares outstanding during the period. For purposes of calculating diluted net income per Class A share, both the net income attributable to PAGP and the diluted weighted average number of Class A shares outstanding consider the impact of possible future exchanges of AAP units and the associated Class B shares into our Class A shares. In addition, the calculation of the diluted weighted average number of Class A shares outstanding considers the effect of potentially dilutive awards under the Plains GP Holdings, L.P. Long-Term Incentive Plan (the “PAGP LTIP”). Exchanges of potentially dilutive AAP units are assumed to have occurred at the beginning of the period and the incremental income attributable to PAGP resulting from the assumed exchanges is representative of the incremental income that would have been attributable to PAGP if the assumed exchanges occurred on that date. See Note 12 for information regarding exchanges of AAP units. PAGP LTIP awards that are deemed to be dilutive are reduced by a hypothetical share repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 18 for information regarding PAGP LTIP awards.
Inventory, Linefill and Long-term Inventory	Inventory, including long-term inventory, primarily consists of crude oil and NGL in pipelines, storage facilities and railcars that are valued at the lower of cost or net realizable value, with cost determined using an average cost method within specific inventory pools. At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Consolidated Statements of Operations. No adjustments were recorded during the years ended December 31, 2025, 2024 or 2023. Linefill in assets we own is recorded at historical cost. We classify as linefill (i) our proportionate share of barrels used to fill a pipeline that we own such that when an incremental barrel is pumped into or enters a pipeline it forces product out at another location and (ii) barrels that represent the minimum working requirements in tanks and caverns that we own. Linefill carrying amounts are reviewed for impairment in accordance with FASB guidance with respect to accounting for the impairment or disposal of long-lived assets. Carrying amounts that are not expected to be recoverable through future cash flows are written down to estimated fair value. See Note 7 for further discussion regarding impairment of long-lived assets. During 2025, 2024 and 2023, we did not recognize any material impairments of linefill. Minimum working inventory requirements in third-party assets and other working inventory in our assets that are needed for our commercial operations are included within specific inventory pools in inventory (a current asset) in determining the average cost of operating inventory. At the end of each period, we reclassify the inventory not expected to be liquidated within the succeeding twelve months out of “Inventory,” at the average cost of the applicable inventory pools, and into “Long-term inventory,” which is reflected as a separate line item under “Other assets” on our Consolidated Balance Sheets.
Property and Equipment	In accordance with our capitalization policy, expenditures made to expand the existing operating and/or earnings capacity of our assets are capitalized, as are certain costs directly related to the construction of such assets, including related internal labor costs, engineering costs and interest costs. We also capitalize expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are expensed as incurred. We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets. In addition, when we evaluate property and equipment and other long-lived assets for recoverability, it may also be necessary to review related depreciation estimates and methods.
Impairment of Long-Lived Assets (Held and Used)	Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value in accordance with FASB guidance with respect to the accounting for the impairment or disposal of long-lived assets. Under this guidance, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. We periodically evaluate property and equipment and other long-lived assets for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. The subjective assumptions used to determine the existence of an impairment in carrying value include: •whether there is an indication of impairment; •the grouping of assets; •the intention of “holding,” “abandoning” or “selling” an asset; •the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and •if an impairment exists, the fair value of the asset or asset group. In addition, when we evaluate property and equipment and other long-lived assets for recoverability, it may also be necessary to review related depreciation estimates and methods.
Investments in Unconsolidated Entities	Investments in entities over which we have significant influence but not control are accounted for under the equity method. We do not consolidate any part of the assets or liabilities of our equity investees. Our share of net income or loss is reflected as one line item on our Consolidated Statements of Operations entitled “Equity earnings in unconsolidated entities” and will increase or decrease, as applicable, the carrying value of our investments in unconsolidated entities on our Consolidated Balance Sheets. We evaluate our equity investments for impairment in accordance with FASB guidance with respect to the equity method of accounting for investments in common stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature. Distributions Distributions received from unconsolidated entities are classified based on the nature of the distribution approach, which looks to the activity that generated the distribution. We consider distributions received from unconsolidated entities as a return on investment in those entities to the extent that the distribution was generated through operating results, and therefore classify these distributions as cash flows from operating activities in our Consolidated Statement of Cash Flows. Other distributions received from unconsolidated entities are considered a return of investment and classified as cash flows from investing activities on the Consolidated Statement of Cash Flows. Contributions We generally fund our portion of development, construction or capital investment projects of our equity method investees through capital contributions. During the years ended December 31, 2025, 2024 and 2023, we made cash contributions of $2 million, $4 million and $29 million, respectively, to certain of our equity method investees. We capitalize interest costs associated with contributions to unconsolidated entities for projects under development and construction. Our contributions to these entities (including capitalized interest costs) increase the carrying value of our investments and are reflected in our Consolidated Statements of Cash Flows as cash used in investing activities. Basis Differences Our investments in unconsolidated entities exceeded our share of the underlying equity in the net assets of such entities by $237 million and $213 million at December 31, 2025 and 2024, respectively. Such basis differences are included in the carrying values of our investments on our Consolidated Balance Sheets. The portion of the basis differences attributable to depreciable or amortizable assets is amortized on a straight-line basis over the estimated useful life of the related assets, which reduces “Equity earnings in unconsolidated entities” on our Consolidated Statements of Operations. The portion of the basis differences attributable to goodwill is not amortized. The majority of the basis difference at both December 31, 2025 and 2024 was attributable to goodwill related to our ownership interest in BridgeTex with the remaining basis difference primarily related to capitalized interest incurred during construction of the assets of our unconsolidated entities.
Intangible Assets	Intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable.
Debt	In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil and NGL. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil or NGL is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. Costs incurred in connection with the issuance of senior notes are recorded as a direct deduction from the related debt liability and are amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization.
Lessee	Lessee We evaluate all agreements entered into or modified that convey to us the use of property or equipment for a term to determine whether the agreement is or contains a lease. Significant judgment is required when determining whether we obtain the right to direct the use of identified property or equipment. We lease certain property and equipment under noncancelable and cancelable operating and finance leases. Our operating leases primarily relate to office space, land, vehicles and storage tanks, and our finance leases primarily relate to tractor trailers, storage tanks and vehicles. One of our finance leases is for storage tanks owned by an equity method investee, in which we own a 50% interest. For leases with an initial term of greater than 12 months, we recognize a right-of-use asset and lease liability on the balance sheet. Leases with an initial term of 12 months or less are not recorded on the balance sheet. We have elected the non-lease component separation practical expedient for certain classes of assets where we are the lessee. Our lease agreements have remaining lease terms ranging from one year to approximately 55 years. When applicable, this range includes additional terms associated with leases for which we are reasonably certain to exercise the option to renew and such renewal options are recognized as part of our right-of-use assets and lease liabilities. We have renewal options for leases with terms ranging from one year to 25 years that are not recognized as part of our right-of-use assets or lease liabilities as we have determined we are not reasonably certain to exercise the option to renew. Certain of our leases have variable lease payments, many of which are based on changes in market indices such as the Consumer Price Index. Our lease agreements for our tractor trailers contain residual value guarantees equal to the fair market value of the tractor trailers at the end of the lease term in the event that we elect not to purchase the asset for an amount equal to the fair value. Our lease agreements do not contain any material restrictive covenants. For determining the present value of lease payments, we use the discount rate implicit in the lease when readily determinable; however, such rate is not readily determinable for most of our leases. For those leases for which the discount rate is not readily determinable, we utilize incremental borrowing rates that reflect collateralized borrowing with payments and terms that mirror our lease portfolio to discount the lease payments based on information available at the lease commencement date.
Lessor	Lessor We evaluate all agreements entered into or modified that convey to others the use of property or equipment for a term to determine whether the agreement is or contains a lease. Significant judgment is required when determining whether a customer obtains the right to direct the use of identified property or equipment. The underlying assets associated with these agreements are evaluated for future use beyond the lease term. We have elected the non-lease component separation practical expedient for all classes of assets where we are the lessor. We enter into agreements to conduct activities associated with (i) providing storage services primarily for crude oil and (ii) transporting crude oil. Certain of these agreements convey counterparties the right to direct the operation of physically distinct assets. Such agreements include (i) fixed consideration, which is measured based on an available capacity during the period multiplied by the rate in the agreement, or (ii) a fixed monthly fee and variable consideration based on usage. These agreements often include options to extend or terminate the lease, with advance notice. These agreements are operating leases.
Income Taxes	Income tax expense is estimated using the tax rate in effect or to be in effect during the relevant periods in the jurisdictions in which we operate. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes and are stated at enacted tax rates expected to be in effect when taxes are actually paid or recovered. To the extent we do not consider it more likely than not that a deferred tax asset will be recovered, a valuation allowance is established. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. We review contingent tax liabilities for estimated exposures on a more likely than not standard related to our current tax positions. Pursuant to FASB guidance related to accounting for uncertainty in income taxes, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and precedents of the taxing authority. As a result of the exchange of the ownership interest in AAP in connection with our IPO and all subsequent exchanges, a deferred tax asset was created. These transfers of ownership were accounted for at the historical carrying basis for GAAP accounting purposes, but were recorded at the fair market value of the Class A shares at the time of exchange for U.S. federal income tax purposes. These transfers were transactions among shareholders, with the basis differences resulting in a deferred tax asset that was recorded as a component of partners’ capital. Also, other equity transactions, including the repurchase of common units by PAA, and the associated adjustment to partners’ capital attributable to PAGP resulted in a corresponding change to the deferred tax asset balance that was recorded as a component of partners’ capital. See Note 12 for additional information regarding exchanges and the repurchase of common units by PAA. The deferred tax asset is amortized to deferred income tax expense as the associated basis step-up is realized on our tax returns.
Concentration of Credit Risk	Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL. This industry concentration has the potential to impact our overall exposure to credit risk in that the customers may be similarly affected by changes in economic, industry or other conditions. We review credit exposure and financial information of our counterparties and generally require letters of credit for receivables from customers that are not considered creditworthy, unless the credit risk can otherwise be reduced.
Equity-indexed Compensation	Our LTIP awards include both liability-classified and equity-classified awards. In accordance with FASB guidance regarding share-based payments, the fair value of liability-classified LTIP awards is calculated based on the closing market price of the underlying PAGP share or PAA unit at each balance sheet date and adjusted for the present value of any distributions that are estimated to occur on the underlying shares or units over the vesting period that will not be received by the award recipients. The fair value for equity-classified awards is calculated in a similar manner on the respective grant dates. These fair values are recognized as compensation expense over the service period. We have elected to recognize forfeitures of awards when they occur. Our LTIP awards contain (i) time-based vesting criteria, (ii) performance conditions, (iii) market conditions or (iv) a combination of time-based vesting criteria and performance conditions. For awards with performance conditions, expense is accrued over the service period only if the performance condition is considered probable of occurring. When awards with performance conditions that were previously considered improbable become probable, we incur additional expense in the period that the probability assessment changes. This is necessary to bring the accrued obligation associated with these awards up to the level it would have been if we had been accruing for these awards since the grant date. For awards with market conditions, the probable outcomes are determined on the respective dates that the fair values are calculated, and the resulting expense is accrued over the service period.
Segment Information	Our operating segments, Crude Oil and NGL, which are also our reportable segments, are organized by product as our Crude Oil and NGL businesses are generally impacted by different market fundamentals and require the use of different assets and business strategies. The Crude Oil segment includes our crude oil pipelines, crude oil storage and marine terminals and related crude oil marketing activities. Our crude oil marketing activities are included in our Crude Oil reporting segment as its primary purpose is to support the utilization of our assets by entering into transactions that facilitate increased volumes handled by our assets, resulting in additional earnings for the segment. The NGL segment includes our NGL assets primarily located in the Southwestern United States. Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below). The measure of Segment Adjusted EBITDA forms the basis of our internal financial reporting and is the primary performance measure of segment profit/(loss) used by our CODM in assessing performance and allocating resources among our operating segments. We define Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) significant segment expenses including: (i) purchases and related costs, (ii) field operating costs and (iii) segment general and administrative expenses, plus (b) our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities, further adjusted (c) for certain selected items including (i) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance and (d) to exclude the portion of all preceding items that is attributable to noncontrolling interests in consolidated joint venture entities (“Segment amounts attributable to noncontrolling interests in consolidated joint ventures”). Our CODM uses Segment Adjusted EBITDA to evaluate the performance of each segment, including analyzing actual results compared to budget and guidance, to assess investment opportunities and to optimize and align assets to maximize returns to stakeholders. Segment Adjusted EBITDA excludes depreciation and amortization. We look at each period’s earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of Segment Adjusted EBITDA as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as pipelines and facilities, caused by age-related decline and wear and tear. We compensate for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance investments, which act to partially offset the aging and wear and tear in the value of our principal fixed assets. These maintenance investments are a component of field operating costs included in Segment Adjusted EBITDA or in maintenance capital, depending on the nature of the cost. Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as investment capital. Capital expenditures made to replace and/or refurbish partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as maintenance capital. Maintenance capital is reviewed by our CODM on a segment basis. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are charged to expense as incurred. Assets are not reviewed by our CODM on a segmented basis; therefore, such information is not presented.

Inventory, Linefill and Long-term Inventory (Tables)

12 Months Ended

Dec. 31, 2025

Inventory Disclosure [Abstract]

Schedule of Inventory

Inventory, linefill and long-term inventory consisted of the following (barrels in thousands and carrying value in millions):


	December 31, 2025						December 31, 2024
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	2,948	barrels	$	166	$	56.31	3,321	barrels	$	221	$	66.55
NGL	562	barrels	27		$	48.04	603	barrels	26		$	43.12

Other	N/A		18		N/A		N/A		14		N/A
Inventory subtotal			211						261

Linefill
Crude oil	15,112	barrels	898		$	59.42	15,463	barrels	903		$	58.40
NGL	33	barrels	2		$	60.61	32	barrels	1		$	31.25

Linefill subtotal			900						904

Long-term inventory
Crude oil	3,724	barrels	213		$	57.20	3,413	barrels	238		$	69.73
NGL	26	barrels	1		$	38.46	90	barrels	4		$	44.44
Long-term inventory subtotal			214						242

Total			$	1,325					$	1,407

(1)Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products.

Schedule of Linefill and Long-term Inventory

Inventory, linefill and long-term inventory consisted of the following (barrels in thousands and carrying value in millions):


	December 31, 2025						December 31, 2024
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	2,948	barrels	$	166	$	56.31	3,321	barrels	$	221	$	66.55
NGL	562	barrels	27		$	48.04	603	barrels	26		$	43.12

Other	N/A		18		N/A		N/A		14		N/A
Inventory subtotal			211						261

Linefill
Crude oil	15,112	barrels	898		$	59.42	15,463	barrels	903		$	58.40
NGL	33	barrels	2		$	60.61	32	barrels	1		$	31.25

Linefill subtotal			900						904

Long-term inventory
Crude oil	3,724	barrels	213		$	57.20	3,413	barrels	238		$	69.73
NGL	26	barrels	1		$	38.46	90	barrels	4		$	44.44
Long-term inventory subtotal			214						242

Total			$	1,325					$	1,407

Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2025

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Disposal Groups, Including Discontinued Operations

The following table summarizes the carrying amounts of major classes of assets and liabilities of discontinued operations (in millions):


	December 31, 2025		December 31, 2024
Assets:
Current assets:

Trade accounts receivable and other receivables, net	$	285	$	222
Inventory	176		178
Other current assets	18		15
Total current assets of discontinued operations	$	479	$	415

Long-term assets:
Property and equipment, net (1)	$	2,191	$	1,978

Linefill	70		64
Long-term operating lease right-of-use assets, net	138		143
Long-term inventory	38		38
Other long-term assets, net	120		126
Total long-term assets of discontinued operations	$	2,557	$	2,349

Liabilities:
Current liabilities:
Trade accounts payable	$	295	$	234

Other current liabilities	87		116
Total current liabilities of discontinued operations	$	382	$	350

Long-term liabilities:

Long-term operating lease liabilities	$	96	$	121
Other long-term liabilities and deferred credits	510		455
Total long-term liabilities of discontinued operations	$	606	$	576

(1)Amounts are net of accumulated depreciation of $876 million and $794 million as of December 31, 2025 and 2024, respectively.

The following table provides a reconciliation of the line items comprising income from discontinued operations before tax to income from discontinued operations, net of tax (in millions):


	Year Ended December 31,
	2025		2024		2023
Revenues:
Product sales	$	1,186	$	1,055	$	1,229
Services	131		129		147
Total revenues	1,317		1,184		1,376
Cost and Expenses:
Purchases and related costs	411		398		594
Field operating costs	259		297		340
General and administrative expenses	47		53		51
Depreciation and amortization	57		125		139
Losses on asset sales, net	21		1		—
Total costs and expenses	795		874		1,124
Other income, net	—		1		—
Income from discontinued operations before tax	522		311		252
Current income tax expense	(99)		(113)		(75)
Deferred income tax (expense)/benefit	(40)		33		15
Income from discontinued operations, net of tax	$	383	$	231	$	192

- 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
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-Publisher FASB
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Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 360
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 3A
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482099/360-10-50-3A

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 360
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-Name Accounting Standards Codification
-Section 50
-Paragraph 3A
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482099/360-10-50-3A

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
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-Name Accounting Standards Codification
-Section 45
-Paragraph 11
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483475/205-20-45-11

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
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-Name Accounting Standards Codification
-Section 50
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-URI https://asc.fasb.org/1943274/2147483499/205-20-50-3A

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
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-Name Accounting Standards Codification
-Section 50
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483499/205-20-50-4A

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
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-Name Accounting Standards Codification
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Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 11: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 13: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 15: http://fasb.org/us-gaap/role/ref/legacyRef
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+ Details

Leases - Narrative (Details)	12 Months Ended
Leases - Narrative (Details)	Dec. 31, 2025
Minimum
Lessee, Lease, Description [Line Items]
Lessee, leases, term of contract (in years)	1 year
Lessee, leases, renewal term (in years)	1 year
Lessor, Lease, Description [Line Items]
Lessor, operating lease, term of contract	1 year
Maximum
Lessee, Lease, Description [Line Items]
Lessee, leases, term of contract (in years)	55 years
Lessee, leases, renewal term (in years)	25 years
Lessor, Lease, Description [Line Items]
Lessor, operating lease, term of contract	6 years
Equity Method Investees \| Agreement to Store at Facilities Owned by Equity Method Investee \| Equity Method Investee That Owns Leased Storage Tanks
Lessee, Lease, Description [Line Items]
Ownership interest in unconsolidated entity prior to acquisition (as a percent)	50.00%

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

Schedule of Change in Asset Retirement Obligation

The following table presents the change in the liability for asset retirement obligations, substantially all of which is reflected in “Other long-term liabilities and deferred credits” on our Consolidated Balance Sheets as of December 31, 2025, 2024 and 2023 (in millions):


	December 31,
	2025		2024		2023
Beginning balance	$	109	$	106	$	103
Liabilities incurred	—		—		1
Liabilities settled	(1)		(2)		(1)
Accretion expense	4		4		4
Revisions in estimated cash flows	—		1		(1)
Ending balance	$	112	$	109	$	106

Acquisitions, Divestitures and Other Transactions - Other Acquisitions Narrative (Details) - USD ($) $ in Millions	1 Months Ended							3 Months Ended		6 Months Ended	12 Months Ended
	Jul. 31, 2025	Feb. 28, 2025	Jan. 31, 2025	Dec. 31, 2024	Aug. 31, 2024	Mar. 31, 2024	Nov. 30, 2023	Jun. 30, 2025	Sep. 30, 2023	Sep. 30, 2024	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Nov. 30, 2024	Jul. 31, 2024	Feb. 29, 2024
Business Combination [Line Items]
Gains (losses) on investments in unconsolidated entities, net											$ 31	$ 15	$ 28
Payments to acquire businesses											$ 2,651	$ 248	$ 425
Pipeline and Termination Terminal Assets
Business Combination [Line Items]
Payments to acquire productive assets										$ 32
Northern Delaware Basin Gathering System
Business Combination [Line Items]
Asset acquisition amount, net to our interest in the Permian JV							$ 88
Subsidiary of LM Energy Partners \| Plains Oryx Permian Basin LLC \| Northern Delaware Basin Gathering System
Business Combination [Line Items]
Asset acquisition, consideration transferred							$ 135
Plains Oryx Permian Basin LLC
Business Combination [Line Items]
Consolidated subsidiary, ownership interest (as a percent)			65.00%				65.00%	65.00%	65.00%
Black Knight Midstream, LLC
Business Combination [Line Items]
Cash consideration								$ 59
Business acquisition amount, net to our interest in the Permian JV								$ 38
Cheyenne Pipeline LLC
Business Combination [Line Items]
Additional interest acquired (as a percent)		50.00%
Business combination, step acquisition, equity interest in acquiree, including subsequent acquisition (as a percent)		100.00%
Gains (losses) on investments in unconsolidated entities, net		$ 31
EMG Medallion 2 Holdings, LLC
Business Combination [Line Items]
Business acquisition amount, net to our interest in the Permian JV			$ 106
Other payments to acquire businesses				$ 16
EMG Medallion 2 Holdings, LLC \| The Energy & Minerals Group \| Plains Oryx Permian Basin LLC
Business Combination [Line Items]
Cash consideration			$ 163
Midway Pipeline LLC
Business Combination [Line Items]
Additional interest acquired (as a percent)				50.00%								50.00%
Cash consideration				$ 90
Business combination, step acquisition, equity interest in acquire (as a percent)														50.00%
Business combination, step acquisition, equity interest in acquiree, including subsequent acquisition (as a percent)				100.00%								100.00%
Business Combination, Achieved in Stages, Preacquisition Equity Interest in Acquiree, Remeasurement, Gain, Statement of Income or Comprehensive Income [Extensible Enumeration]				Gains (losses) on investments in unconsolidated entities, net
Equity interest in acquiree, remeasurement gain				$ 15
Wink to Webster Pipeline LLC (“W2W Pipeline”)
Business Combination [Line Items]
Additional interest acquired (as a percent)					0.67%
Business combination, step acquisition, equity interest in acquire (as a percent)															16.00%
Business combination, step acquisition, equity interest in acquiree, including subsequent acquisition (as a percent)					17.00%
Payments to acquire businesses					$ 20
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)
Business Combination [Line Items]
Additional interest acquired (as a percent)						10.00%
Business combination, step acquisition, equity interest in acquire (as a percent)																30.00%
Business combination, step acquisition, equity interest in acquiree, including subsequent acquisition (as a percent)						40.00%
Payments to acquire businesses						$ 91
BridgeTex Pipeline Company, LLC (“BridgeTex”) \| BridgeTex Pipeline Company, LLC (“BridgeTex”)
Business Combination [Line Items]
Additional interest acquired (as a percent)	20.00%
Cash consideration	$ 180
Business combination, step acquisition, equity interest in acquire (as a percent)								20.00%
Business combination, step acquisition, equity interest in acquiree, including subsequent acquisition (as a percent)	40.00%

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions	Total	Common Units	Series A Preferred Stock	Noncontrolling Interests	Noncontrolling Interests Common Units	Noncontrolling Interests Series A Preferred Stock	Limited Partners Class A Shares Partners’ Capital	Limited Partners Class A Shares Partners’ Capital Common Units	Limited Partners Class A Shares Partners’ Capital Series A Preferred Stock
Balance, beginning of period at Dec. 31, 2022	$ 14,638			$ 13,114			$ 1,524
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	1,425			1,227			198
Distributions	(1,330)			(1,121)			(209)
Deferred tax asset	(2)						(2)
Other comprehensive income (loss)	118			85			33
Equity-indexed compensation expense	37			26			11
Contributions from noncontrolling interests	106			106
Other	(20)			(13)			(7)
Balance, end of period at Dec. 31, 2023	14,972			13,424			1,548
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	1,070			967			103
Distributions	(1,569)			(1,318)			(251)
Deferred tax asset	18						18
Other comprehensive income (loss)	(247)			(178)			(69)
Equity-indexed compensation expense	38			26			12
Contributions from noncontrolling interests	57			57
Other	(23)			(13)			(10)
Balance, end of period at Dec. 31, 2024	14,316			12,965			1,351
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	1,686			1,426			260
Distributions	(1,733)			(1,433)			(300)
Deferred tax asset	(4)						(4)
Other comprehensive income (loss)	187			134			53
Equity-indexed compensation expense	38			26			12
Repurchase of units		$ (8)	$ (313)		$ (9)	$ (301)		$ 1	$ (12)
Contributions from noncontrolling interests	75			75
Other	(28)			(12)			(16)
Balance, end of period at Dec. 31, 2025	$ 14,216			$ 12,871			$ 1,345

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

Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2025

Property, Plant and Equipment [Abstract]

Schedule of Components of Property and Equipment, Net

Property and equipment, net is stated at cost and consisted of the following (in millions):


	Estimated Useful Lives (Years)	December 31,
		2025		2024
Crude oil pipeline systems	10 - 50	$	18,428	$	14,612
Crude oil storage and terminal facilities	10 - 50	2,808		2,679
NGL storage, terminal, fractionation and processing facilities	10 - 50	365		364

Office property and equipment and rolling stock	2 - 50	373		430
Construction in progress	N/A	238		148
Land and other	N/A	324		295
Property and equipment, gross (1)		22,536		18,528
Accumulated depreciation		(5,676)		(5,082)
Property and equipment, net		$	16,860	$	13,446

(1)We include rights-of-way, which are intangible assets, within property and equipment.

Partners' Capital and Distributions (Tables)

12 Months Ended

Dec. 31, 2025

Partners Capital and Distribution [Line Items]

Schedule of Changes in Shares Outstanding

The following table presents the activity for our Class A shares, Class B shares and Class C shares:


	Class A Shares	Class B Shares	Class C Shares







Outstanding at December 31, 2022	194,407,642	46,205,947	528,442,538

Conversion of AAP Management Units	—	388,839	—
Exchange Right exercises	1,869,768	(1,869,768)	—
Redemption Right exercises	—	(8,487,850)	8,487,850

Other	139,350	—	2,514,901
Outstanding at December 31, 2023	196,416,760	36,237,168	539,445,289


Exchange Right exercises	846,937	(846,937)	—


Other	202,002	—	2,559,549
Outstanding at December 31, 2024	197,465,699	35,390,231	542,004,838
Exchange Right exercises	293,925	(293,925)	—
Repurchase and cancellation of common units by a subsidiary under the Common Equity Repurchase Program	—	—	(476,695)
Repurchase of Series A preferred units by a subsidiary	—	—	(12,678,560)
Other	144,500		2,082,592
Outstanding at December 31, 2025	197,904,124	35,096,306	530,932,175

Schedule of Distributions paid to Noncontrolling Interests

The following table details distributions paid to noncontrolling interests in consolidated joint venture entities during the years presented (in millions):


	2025		2024		2023
Permian JV	$	360	$	322	$	249
Cactus II	72		77		63
Red River	15		26		21
	$	447	$	425	$	333

Class A Shares

Partners Capital and Distribution [Line Items]

Schedule of Distributions

The following table details distributions paid to our Class A shareholders during the years presented (in millions, except per share data):


Year	Distributions to Class A Shareholders		Distributions per Class A Share
2025	$	301	$	1.5200
2024	$	251	$	1.2700
2023	$	209	$	1.0700

PAA | Series A Preferred Units

Partners Capital and Distribution [Line Items]

Schedule of Distributions

The following table details distributions paid to PAA’s Series A preferred unitholders during the years presented (in millions, except unit data):


	Series A Preferred Unitholders


Year	Cash Distribution		Distribution per Unit
2025 (1)	$	154		$	2.46
2024	$	175		$	2.46
2023	$	166		$	2.34

(1)Includes distribution of approximately $10 million associated with PAA’s repurchase of Series A preferred units in January 2025.

PAA | Series B Preferred Units

Partners Capital and Distribution [Line Items]

Schedule of Distributions

The following table details distributions paid to PAA’s Series B preferred unitholders during the years presented (in millions, except unit data):


	Series B Preferred Unitholders


Year	Cash Distribution		Distribution per Unit
2025	$	71	$	88.38
2024	$	79	$	98.14
2023	$	75	$	93.43

PAA | Common Units

Partners Capital and Distribution [Line Items]

Schedule of Distributions

The following table details distributions paid by PAA to its common unitholders during the years presented (in millions, except per unit data):


	Distributions Paid						Distributions per Common Unit
Year	Public		AAP		Total
2025	$	716	$	354	$	1,070	$	1.5200
2024	$	595	$	296	$	891	$	1.2700
2023	$	492	$	256	$	748	$	1.0700

AAP

Partners Capital and Distribution [Line Items]

Schedule of Distributions

The following table details the distributions to AAP’s partners paid during the years presented from distributions received from PAA (in millions):


	Distributions to AAP’s Partners
Year	Noncontrolling Interests		PAGP		Total Cash Distributions

2025	$	53	$	301	$	354
2024	$	45	$	251	$	296
2023	$	47	$	209	$	256

Commitments and Contingencies

12 Months Ended

Dec. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments

We have commitments (some of which are leases) related to real property, equipment and operating facilities. Future noncancelable commitments related to these items at December 31, 2025 are summarized below (in millions):


	2026		2027		2028		2029		2030		Thereafter		Total
Leases (1)	$	46	$	44	$	43	$	34	$	28	$	346	$	541
Other commitments (2)	245		215		116		114		117		141		948
Total	$	291	$	259	$	159	$	148	$	145	$	487	$	1,489

(1)Includes both operating and finance leases as defined by FASB guidance. Leases are primarily for (i) office space, (ii) land, (iii) vehicles, (iv) storage tanks and (v) tractor trailers. See Note 14 for additional information.

(2)Primarily includes storage, transportation and pipeline throughput agreements. Expense associated with such agreements was approximately $363 million, $341 million and $348 million for 2025, 2024 and 2023, respectively. A majority of the storage, transportation and pipeline throughput commitments are associated with agreements to store crude oil at facilities and transport crude oil on pipelines owned by equity method investees at posted tariff rates or prices that we believe approximate market. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities.

Loss Contingencies — General

To the extent we are able to assess the likelihood of a negative outcome for a contingency, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount. 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 we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred.

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.

Legal Proceedings — General

In the ordinary course of business, we are involved in various legal proceedings, including those arising from regulatory and environmental matters. In connection with determining the probability of loss associated with such legal proceedings and whether any potential losses associated therewith are estimable, we take into account what we believe to be all relevant known facts and circumstances, and what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing agreements, laws and regulations. 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 protect us from losses arising from current or future legal proceedings.

Accordingly, we can provide no assurance that the outcome of the various legal proceedings that we are currently involved in, or will become involved with in the future, will not, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

Environmental — General

We currently own or lease, and in the past have owned and leased, properties where hazardous liquids, including hydrocarbons, are or have been handled. These properties and the hazardous liquids or associated wastes disposed thereon may be subject to the U.S. federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, and the U.S. federal Resource Conservation and Recovery Act, as amended, as well as state and Canadian federal and provincial laws and regulations. Under such laws and regulations, we could be required to remove or remediate hazardous liquids or associated wastes (including wastes disposed of or released by prior owners or operators) and to clean up contaminated property (including contaminated groundwater). Assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified or insured.

Although we have made significant investments in our maintenance and integrity programs, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail, storage and other facility operations. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. We also may discover environmental impacts from past releases that were previously unidentified. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated. Generally, our recording of these liabilities coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. We record receivables for amounts we believe are recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery.

Environmental expenditures that pertain to current operations or to future revenues are expensed or capitalized consistent with our capitalization policy for property and equipment. Expenditures that result from the remediation of an existing condition caused by past operations and that do not contribute to current or future profitability are expensed.

Our estimated undiscounted reserves for environmental liabilities (excluding liabilities related to the Line 901 incident, as discussed further below) were reflected on our Consolidated Balance Sheets as follows (in millions):


	December 31, 2025		December 31, 2024
Other current liabilities	$	13	$	11
Other long-term liabilities and deferred credits	70		69
Total	$	83	$	80

In some cases, the actual cash expenditures associated with these liabilities may not occur for several years. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing or future legal claims giving rise to additional liabilities. Therefore, although we believe that our reserves are adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of such reserves and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

Specific Legal, Environmental or Regulatory Matters

Line 901 Incident. In May 2015, we experienced a release of crude oil from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. Effective as of December 31, 2025, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $870 million, which includes actual emergency response and clean-up costs, natural resource damage assessments, fines and penalties incurred, certain third-party claims settlements, and estimated costs associated with our remaining Line 901 lawsuits and claims as described below, as well as estimates for certain legal fees and statutory interest where applicable. We accrue such estimates of aggregate total costs to “Field operating costs” in our Consolidated Statements of Operations. This estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the resolution of certain third-party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and (ii) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. Our estimate does not include any lost revenue associated with the shutdown of Line 901 or 903 and does not include any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, with respect to potential losses that we regard as only reasonably possible or remote, we have made assumptions regarding the strength of our legal position based on our assessment of the relevant facts and applicable law and precedent; if our assumptions regarding such matters turn out to be inaccurate (i.e., we are found to be liable under circumstances where we regard the likelihood of loss as being only reasonably possible or remote), we could be responsible for significant costs and expenses that are not currently included in our estimates and accruals. In addition, for any potential losses that we regard as probable and for which we have accrued an estimate of the potential losses, our estimates regarding damages, legal fees, court costs and interest could turn out to be inaccurate and the actual losses we incur could be significantly higher than the amounts included in our estimates and accruals. Also, the amount of time it takes for us to resolve all of the current and future lawsuits and claims that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated.

During the year ended December 31, 2025, we did not recognize any costs related to the Line 901 incident. During the years ended December 31, 2024 and 2023, we recognized costs, net of amounts probable of recovery from insurance (as applicable) of $345 million and $10 million, respectively. As of December 31, 2025 and 2024, we had a remaining undiscounted gross liability of approximately $22 million and $5 million, respectively, related to the Line 901 incident, which aggregate amounts are reflected in “Current liabilities” on our Consolidated Balance Sheet.

We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such liabilities. To date, we have collected approximately $295 million of the $500 million available under our 2015 insurance program. With respect to the Line 901 incident, we do not have any amounts recorded as receivables that are recognized on our Consolidated Balance Sheets as of December 31, 2025 and 2024.

We have completed the required clean-up and remediation work with respect to the Line 901 incident; however, we expect to make payments for additional legal and professional costs during future periods. During the second quarter of 2025, we agreed to confidential settlement terms for various lawsuits filed in California Superior Court in Santa Barbara County by companies and individuals who provided labor, goods, or services associated with oil production activities they claim were disrupted following the Line 901 incident, the agreed aggregate settlement amount has been factored into our Line 901 total cost estimate. The only other remaining Line 901 lawsuit is pending in California Superior Court in Santa Barbara County, in which a landowner on an adjacent pipeline is alleging property damage from the “stigma” of the Line 901 incident. We are vigorously defending this remaining lawsuit, which has not yet been set for trial, and believe we have strong defenses. Taking into account the costs that we have included in our total estimate of costs for the Line 901 incident and considering what we regard as very strong defenses to the claims made in our remaining Line 901 lawsuits, we do not believe the ultimate resolution of such remaining lawsuit will have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

L48 Pipeline Release. In March of 2025, our subsidiary, Pacific Pipeline System LLC, experienced a crude oil release of approximately 125 barrels on a segment of the Line 48 pipeline in Carson, California. Clean-up and remediation activities were conducted in cooperation with applicable state and federal regulatory agencies. An investigation by the California Office of the State Fire Marshall is not complete. To date no charges, fines or penalties have been assessed against us with respect to this release; however, it is possible that charges, fines or penalties may be assessed against us in the future. We provided notification to our applicable insurance carriers and intend to pursue reimbursement of any costs incurred in excess of our $10 million self-insured retention. We estimate that the aggregate cost to clean-up and remediate the site will be approximately $20 million. Through December 31, 2025, we incurred $12 million in connection with clean-up and remediation activities.

Hartree. On July 19, 2022, Hartree Natural Gas Storage, LLC (“Hartree”) filed a lawsuit under seal in the Superior Court for the State of Delaware asserting claims against PAA Natural Gas Storage, L.P. and PAA arising out of a Membership Interest Purchase Agreement relating to the 2021 sale of the Pine Prairie Energy Center natural gas storage facility to Hartree. In early 2025, we entered into a settlement agreement with Hartree; the terms of the settlement are confidential and the amount paid is not material to our operations. All of Hartree’s claims were dismissed with prejudice and without any admission of wrongdoing by Plains.

Louisiana Coastal Erosion Lawsuit. Various coastal parishes, the State of Louisiana and some of its departments have filed lawsuits in Louisiana against a number of energy companies seeking damages for coastal erosion in connection with oil and gas operations in Louisiana. One of our subsidiaries has been named in such a lawsuit filed by The Louisiana Department of Wildlife and Fisheries (“LADWF”). LADWF filed a lawsuit in the 24th Judicial District Court of Jefferson Parish, Louisiana on October 30, 2023 against our subsidiary, Plains Pipeline, L.P., Chevron Pipe Line Company, BP Oil Pipeline Company and Arrowhead Gulf Coast Pipeline, LLC (collectively, “Defendants”), as the former and current parties to certain pipeline right of way agreements (“ROWs”) in the vicinity of the Elmer Island Wildlife Refuge. LADWF alleges that the Defendants breached the terms of the ROWs by failing to prevent erosion and seeks restoration of the Wildlife Refuge or alternatively monetary compensatory damages including restoration costs, legal fees and disgorgement of profits derived from the alleged trespass. Our subsidiary owned and operated a pipeline in the vicinity of the refuge from 2006 through 2016. We settled this lawsuit in January 2026 for a payment from Plains of $1.5 million.

Debt - Senior Notes (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
Debt - Senior Notes (Details) - USD ($) $ in Millions	Nov. 30, 2024	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Sep. 08, 2025
Debt Instrument [Line Items]
Repayments of PAA senior notes		$ 1,000	$ 750	$ 1,100
PAA Senior Notes
Debt Instrument [Line Items]
Debt instrument face value		$ 9,200	$ 7,200
PAA Senior Notes \| 4.70% senior notes issued at 99.872% of face value
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)		4.70%			4.70%
Debt instrument, issued face value, percentage		99.872%
Debt instrument face value		$ 300
PAA Senior Notes \| 5.60% senior notes issued at 100.518% of face value
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)		5.60%
Debt instrument, issued face value, percentage		100.518%
Debt instrument face value		$ 450
PAA Senior Notes \| 4.70% senior notes issued at 99.865% of face value
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)		4.70%
Debt instrument, issued face value, percentage		99.865%
Debt instrument face value		$ 700
PAA Senior Notes \| 5.60% senior notes issued at 99.798% of face value
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)		5.60%			5.60%
Debt instrument, issued face value, percentage		99.798%
Debt instrument face value		$ 550
PAA Senior Notes \| 5.95% senior notes issued at 99.761% of face value
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)		5.95%
Debt instrument, issued face value, percentage		99.761%
Debt instrument face value		$ 1,000
PAA Senior Notes \| 5.70% senior notes issued at 99.953% of face value
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)		5.70%
Debt instrument, issued face value, percentage		99.953%
Debt instrument face value		$ 650
PAA Senior Notes \| $1,000 million 4.65% senior notes
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)		4.65%	4.65%
Repayments of PAA senior notes	$ 1,000
PAA Senior Notes \| $750 million 3.60% senior notes
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)	3.60%
Repayments of PAA senior notes	$ 750
Consolidated Finance Subsidiary Issuer
Debt Instrument [Line Items]
Consolidated subsidiary, ownership interest held by the parent (as a percent)		100.00%

Revenues and Accounts Receivable - Contract Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Change in Contract Liabilities [Roll Forward]
Beginning balance	$ 87	$ 101
Amounts recognized as revenue	(42)	(36)
Additions	42	23
Other		(1)
Ending balance	$ 87	$ 87

Net Income Per Class A Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 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, 2025	Dec. 31, 2024	Dec. 31, 2023
Basic Net Income per Class A Share
Net income attributable to PAGP from continuing operations									$ 152	$ 39	$ 144
Net income attributable to PAGP from discontinued operations									108	64	54
Diluted Net Income per Class A Share
Net income attributable to PAGP from continuing operations									152	39	144
Incremental net income attributable to PAGP resulting from assumed exchange of AAP Management Units									15	9	9
Net income attributable to PAGP from continuing operations including incremental net income from assumed exchange of AAP Management Units									$ 123	$ 73	$ 63
AAP Units \| Weighted Average \| Discontinued Operations, Held-for-Sale \| NGL Business
Basic and diluted earnings per share
Antidilutive securities excluded from computation of earnings per share (in shares)									35	35	44
Class A Shares
Basic Net Income per Class A Share
Basic weighted average Class A shares outstanding (in shares)									198	197	195
Basic Net Income per Class A Share:
Continuing operations (in usd per share)	$ 0.17	$ 0.31	$ 0.05	$ 0.23	$ (0.16)	$ 0.01	$ 0.15	$ 0.20	$ 0.77	$ 0.19	$ 0.74
Discontinued operations (in usd per share)	0.14	0.11	0.10	0.19	0.11	0.16	0.05	0.01	0.54	0.33	0.27
Basic net income per Class A share (in usd per share)	0.31	0.42	0.15	0.42	(0.05)	0.17	0.20	0.21	$ 1.31	$ 0.52	$ 1.01
Diluted Net Income per Class A Share
Dilutive shares resulting from assumed exchange of AAP Management Units (in shares)									35	35	44
Diluted weighted average Class A shares outstanding (in shares)									233	232	239
Diluted Net Income per Class A Share:
Continuing operations (in usd per share)	0.17	0.31	0.05	0.23	(0.16)	0.01	0.15	0.20	$ 0.77	$ 0.19	$ 0.74
Discontinued operations (in usd per share)	0.14	0.10	0.10	0.19	0.11	0.16	0.04	0.01	0.53	0.32	0.26
Diluted net income per Class A share (in usd per share)	$ 0.31	$ 0.41	$ 0.15	$ 0.42	$ (0.05)	$ 0.17	$ 0.19	$ 0.21	$ 1.30	$ 0.51	$ 1.00

Leases

12 Months Ended

Dec. 31, 2025

Leases [Abstract]

Leases

Lessee

We evaluate all agreements entered into or modified that convey to us the use of property or equipment for a term to determine whether the agreement is or contains a lease. Significant judgment is required when determining whether we obtain the right to direct the use of identified property or equipment. We lease certain property and equipment under noncancelable and cancelable operating and finance leases. Our operating leases primarily relate to office space, land, vehicles and storage tanks, and our finance leases primarily relate to tractor trailers, storage tanks and vehicles. One of our finance leases is for storage tanks owned by an equity method investee, in which we own a 50% interest. For leases with an initial term of greater than 12 months, we recognize a right-of-use asset and lease liability on the balance sheet. Leases with an initial term of 12 months or less are not recorded on the balance sheet. We have elected the non-lease component separation practical expedient for certain classes of assets where we are the lessee. Our lease agreements have remaining lease terms ranging from one year to approximately 55 years. When applicable, this range includes additional terms associated with leases for which we are reasonably certain to exercise the option to renew and such renewal options are recognized as part of our right-of-use assets and lease liabilities. We have renewal options for leases with terms ranging from one year to 25 years that are not recognized as part of our right-of-use assets or lease liabilities as we have determined we are not reasonably certain to exercise the option to renew.

Certain of our leases have variable lease payments, many of which are based on changes in market indices such as the Consumer Price Index. Our lease agreements for our tractor trailers contain residual value guarantees equal to the fair market value of the tractor trailers at the end of the lease term in the event that we elect not to purchase the asset for an amount equal to the fair value. Our lease agreements do not contain any material restrictive covenants.

For determining the present value of lease payments, we use the discount rate implicit in the lease when readily determinable; however, such rate is not readily determinable for most of our leases. For those leases for which the discount rate is not readily determinable, we utilize incremental borrowing rates that reflect collateralized borrowing with payments and terms that mirror our lease portfolio to discount the lease payments based on information available at the lease commencement date.

The following table presents components of lease cost, including both amounts recognized in income and amounts capitalized (in millions):


	Year Ended December 31,
Lease Cost	2025		2024		2023
Operating lease cost	$	37	$	44	$	48
Short-term lease cost	13		13		13
Other (1)	19		16		8
Total lease cost	$	69	$	73	$	69

(1)Includes finance lease costs, variable lease costs and sublease income.

The following table presents information related to cash flows arising from lease transactions (in millions):


	Year Ended December 31,
	2025		2024		2023
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	40	$	41	$	44
Operating cash flows for finance leases	$	9	$	7	$	6
Financing cash flows for finance leases	$	23	$	15	$	10

Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications:
Operating leases	$	30	$	50	$	12
Finance leases	$	7	$	23	$	27

Information related to the weighted-average remaining lease term and discount rate is presented in the table below:


	December 31,
	2025		2024
Weighted-average remaining lease term (in years):
Operating leases	21		20
Finance leases	8		7

Weighted-average discount rate:
Operating leases	5.5	%	5.5	%
Finance leases	11.1	%	10.7	%

The following table presents the amount and location of our operating and finance lease right-of-use assets and liabilities on our Consolidated Balance Sheets (in millions):


		December 31,
Leases	Balance Sheet Location	2025		2024
Assets
Operating lease right-of-use assets	Long-term operating lease right-of-use assets, net	$	198	$	189

Finance lease right-of-use assets (1)	Property and equipment	$	90	$	103
	Accumulated depreciation	(27)		(28)
	Property and equipment, net	$	63	$	75

Total lease right-of-use assets		$	261	$	264

Liabilities
Operating lease liabilities
Current	Other current liabilities	$	27	$	30
Noncurrent	Long-term operating lease liabilities	202		192
Total operating lease liabilities		$	229	$	222

Finance lease liabilities (1)
Current	Short-term debt	$	9	$	14
Noncurrent	Other long-term debt, net	63		70
Total finance lease liabilities		$	72	$	84

Total lease liabilities		$	301	$	306


	Operating		Finance (2)
Future minimum lease payments (1):
2026	$	31	$	15
2027	29		15
2028	26		17
2029	22		12
2030	19		9
Thereafter	303		43
Total	430		111
Less: Present value discount	(201)		(39)
Lease liabilities	$	229	$	72

(1)Excludes future minimum payments for short-term and other immaterial leases not included on our Consolidated Balance Sheet.

Lessor

We evaluate all agreements entered into or modified that convey to others the use of property or equipment for a term to determine whether the agreement is or contains a lease. Significant judgment is required when determining whether a customer obtains the right to direct the use of identified property or equipment. The underlying assets associated with these agreements are evaluated for future use beyond the lease term. We have elected the non-lease component separation practical expedient for all classes of assets where we are the lessor.

We enter into agreements to conduct activities associated with (i) providing storage services primarily for crude oil and (ii) transporting crude oil. Certain of these agreements convey counterparties the right to direct the operation of physically distinct assets. Such agreements include (i) fixed consideration, which is measured based on an available capacity during the period multiplied by the rate in the agreement, or (ii) a fixed monthly fee and variable consideration based on usage. These agreements often include options to extend or terminate the lease, with advance notice. These agreements are operating leases.

The following table presents our lease revenue for the periods indicated (in millions):


	Year Ended December 31,
	2025		2024		2023
Operating lease revenue (1)	$	8	$	10	$	16

(1)These amounts are included in “Services revenues” on our Consolidated Statements of Operations.

The table below presents the maturity of lease payments for operating lease agreements in effect as of December 31, 2025. This presentation includes minimum fixed lease payments and does not include an estimate of variable lease consideration. These agreements have remaining lease terms ranging from one year to 6 years. The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions):


	2026		2027		2028		2029		2030		Thereafter
Future minimum lease revenue	$	6	$	2	$	2	$	2	$	2	$	1

Leases

Lessee

The following table presents components of lease cost, including both amounts recognized in income and amounts capitalized (in millions):


	Year Ended December 31,
Lease Cost	2025		2024		2023
Operating lease cost	$	37	$	44	$	48
Short-term lease cost	13		13		13
Other (1)	19		16		8
Total lease cost	$	69	$	73	$	69

(1)Includes finance lease costs, variable lease costs and sublease income.

The following table presents information related to cash flows arising from lease transactions (in millions):


	Year Ended December 31,
	2025		2024		2023
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	40	$	41	$	44
Operating cash flows for finance leases	$	9	$	7	$	6
Financing cash flows for finance leases	$	23	$	15	$	10

Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications:
Operating leases	$	30	$	50	$	12
Finance leases	$	7	$	23	$	27

Information related to the weighted-average remaining lease term and discount rate is presented in the table below:


	December 31,
	2025		2024
Weighted-average remaining lease term (in years):
Operating leases	21		20
Finance leases	8		7

Weighted-average discount rate:
Operating leases	5.5	%	5.5	%
Finance leases	11.1	%	10.7	%

The following table presents the amount and location of our operating and finance lease right-of-use assets and liabilities on our Consolidated Balance Sheets (in millions):


		December 31,
Leases	Balance Sheet Location	2025		2024
Assets
Operating lease right-of-use assets	Long-term operating lease right-of-use assets, net	$	198	$	189

Finance lease right-of-use assets (1)	Property and equipment	$	90	$	103
	Accumulated depreciation	(27)		(28)
	Property and equipment, net	$	63	$	75

Total lease right-of-use assets		$	261	$	264

Liabilities
Operating lease liabilities
Current	Other current liabilities	$	27	$	30
Noncurrent	Long-term operating lease liabilities	202		192
Total operating lease liabilities		$	229	$	222

Finance lease liabilities (1)
Current	Short-term debt	$	9	$	14
Noncurrent	Other long-term debt, net	63		70
Total finance lease liabilities		$	72	$	84

Total lease liabilities		$	301	$	306


	Operating		Finance (2)
Future minimum lease payments (1):
2026	$	31	$	15
2027	29		15
2028	26		17
2029	22		12
2030	19		9
Thereafter	303		43
Total	430		111
Less: Present value discount	(201)		(39)
Lease liabilities	$	229	$	72

(1)Excludes future minimum payments for short-term and other immaterial leases not included on our Consolidated Balance Sheet.

Lessor

The following table presents our lease revenue for the periods indicated (in millions):


	Year Ended December 31,
	2025		2024		2023
Operating lease revenue (1)	$	8	$	10	$	16

(1)These amounts are included in “Services revenues” on our Consolidated Statements of Operations.


	2026		2027		2028		2029		2030		Thereafter
Future minimum lease revenue	$	6	$	2	$	2	$	2	$	2	$	1

Leases

Lessee

The following table presents components of lease cost, including both amounts recognized in income and amounts capitalized (in millions):


	Year Ended December 31,
Lease Cost	2025		2024		2023
Operating lease cost	$	37	$	44	$	48
Short-term lease cost	13		13		13
Other (1)	19		16		8
Total lease cost	$	69	$	73	$	69

(1)Includes finance lease costs, variable lease costs and sublease income.

The following table presents information related to cash flows arising from lease transactions (in millions):


	Year Ended December 31,
	2025		2024		2023
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	40	$	41	$	44
Operating cash flows for finance leases	$	9	$	7	$	6
Financing cash flows for finance leases	$	23	$	15	$	10

Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications:
Operating leases	$	30	$	50	$	12
Finance leases	$	7	$	23	$	27

Information related to the weighted-average remaining lease term and discount rate is presented in the table below:


	December 31,
	2025		2024
Weighted-average remaining lease term (in years):
Operating leases	21		20
Finance leases	8		7

Weighted-average discount rate:
Operating leases	5.5	%	5.5	%
Finance leases	11.1	%	10.7	%

The following table presents the amount and location of our operating and finance lease right-of-use assets and liabilities on our Consolidated Balance Sheets (in millions):


		December 31,
Leases	Balance Sheet Location	2025		2024
Assets
Operating lease right-of-use assets	Long-term operating lease right-of-use assets, net	$	198	$	189

Finance lease right-of-use assets (1)	Property and equipment	$	90	$	103
	Accumulated depreciation	(27)		(28)
	Property and equipment, net	$	63	$	75

Total lease right-of-use assets		$	261	$	264

Liabilities
Operating lease liabilities
Current	Other current liabilities	$	27	$	30
Noncurrent	Long-term operating lease liabilities	202		192
Total operating lease liabilities		$	229	$	222

Finance lease liabilities (1)
Current	Short-term debt	$	9	$	14
Noncurrent	Other long-term debt, net	63		70
Total finance lease liabilities		$	72	$	84

Total lease liabilities		$	301	$	306


	Operating		Finance (2)
Future minimum lease payments (1):
2026	$	31	$	15
2027	29		15
2028	26		17
2029	22		12
2030	19		9
Thereafter	303		43
Total	430		111
Less: Present value discount	(201)		(39)
Lease liabilities	$	229	$	72

(1)Excludes future minimum payments for short-term and other immaterial leases not included on our Consolidated Balance Sheet.

Lessor

The following table presents our lease revenue for the periods indicated (in millions):


	Year Ended December 31,
	2025		2024		2023
Operating lease revenue (1)	$	8	$	10	$	16

(1)These amounts are included in “Services revenues” on our Consolidated Statements of Operations.


	2026		2027		2028		2029		2030		Thereafter
Future minimum lease revenue	$	6	$	2	$	2	$	2	$	2	$	1

Partners' Capital and Distributions - Distributions, Class A (Details) - USD ($) $ / shares in Units, $ in Millions			12 Months Ended
	Feb. 13, 2026	Jan. 05, 2026	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Class A Shares
Partners Capital and Distribution [Line Items]
Percentage of available cash distributed (as a percent)			100.00%
Number of days after end of quarter within which distributions must be paid to shareholders (in days)			55 days
Class A Shares \| Cash Distribution
Partners Capital and Distribution [Line Items]
Distributions to Class A Shareholders			$ 301	$ 251	$ 209
Cash distributions per Class A share (in dollars per share)			$ 1.5200	$ 1.2700	$ 1.0700
Class A Shares \| Cash Distribution \| Subsequent Event
Partners Capital and Distribution [Line Items]
Distributions to Class A Shareholders	$ 83
Common Units \| Cash Distribution \| Subsequent Event
Partners Capital and Distribution [Line Items]
Distributions per Class A share declared (in dollars per share)		$ 0.4175
Common Units \| Cash Distribution \| PAA
Partners Capital and Distribution [Line Items]
Cash distributions per Class A share (in dollars per share)			$ 1.5200	$ 1.2700	$ 1.0700
Common Units \| Cash Distribution \| PAA \| Subsequent Event
Partners Capital and Distribution [Line Items]
Distributions to Class A Shareholders	$ 295

Net Income Per Class A Share (Tables)

12 Months Ended

Dec. 31, 2025

Earnings Per Share [Abstract]

Schedule of Calculation of Basic and Diluted Net Income per Class A Share

The following table sets forth the computation of basic and diluted net income per Class A share (in millions, except per share data):


	Year Ended December 31,
	2025		2024		2023
Basic Net Income per Class A Share
Net income attributable to PAGP from continuing operations	$	152	$	39	$	144

Net income attributable to PAGP from discontinued operations	$	108	$	64	$	54

Basic weighted average Class A shares outstanding	198		197		195

Basic Net Income per Class A Share:
Continuing operations	$	0.77	$	0.19	$	0.74
Discontinued operations	0.54		0.33		0.27
Basic net income per Class A share	$	1.31	$	0.52	$	1.01

Diluted Net Income per Class A Share
Net income attributable to PAGP from continuing operations	$	152	$	39	$	144



Net income attributable to PAGP from discontinued operations	$	108	$	64	$	54
Incremental net income attributable to PAGP resulting from assumed exchange of AAP Management Units	15		9		9
Net income attributable to PAGP from discontinued operations including incremental net income from assumed exchange of AAP Management Units	$	123	$	73	$	63

Basic weighted average Class A shares outstanding	198		197		195
Dilutive shares resulting from assumed exchange of AAP Management Units	35		35		44
Diluted weighted average Class A shares outstanding	233		232		239

Diluted Net Income per Class A Share:
Continuing operations	$	0.77	$	0.19	$	0.74
Discontinued operations	0.53		0.32		0.26
Diluted net income per Class A share	$	1.30	$	0.51	$	1.00

Revenues and Accounts Receivable - Narrative (Details)	12 Months Ended
Revenues and Accounts Receivable - Narrative (Details)	Dec. 31, 2025	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
Substantially all trade accounts receivable, net, maximum age of balances past their invoice date	30 days	30 days

Commitments and Contingencies - Narrative (Details) $ in Millions	1 Months Ended		12 Months Ended		128 Months Ended
	Jan. 31, 2026 USD ($)	Mar. 31, 2025 USD ($) bbl	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2025 USD ($)
Line 901 Incident
Loss Contingencies [Line Items]
Aggregate total estimated costs					$ 870.0
Costs related to the Line 901 incident			$ 345.0	$ 10.0
Line 901 Incident \| Current Liabilities
Loss Contingencies [Line Items]
Remaining undiscounted liability			$ 5.0		22.0
Line 901 2015 Insurance Program
Loss Contingencies [Line Items]
Recoveries from insurance carriers					295.0
Coverage limit under insurance program					500.0
Line 48 Incident
Loss Contingencies [Line Items]
Estimated size of release (in bbl) \| bbl		125
Loss contingency, self-insured retention		$ 10.0
Loss contingency, clean-up and remediate aggregate cost		$ 20.0
Loss contingency, clean-up and remediation activities					$ 12.0
Louisiana Coastal Erosion Lawsuit \| Subsequent Event
Loss Contingencies [Line Items]
Litigation settlement, amount awarded to other party	$ 1.5

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2025

Schedule of Related Party Transactions

The impact to our Consolidated Statements of Operations from these transactions is included below (in millions):


	Year Ended December 31,
	2025		2024		2023



Revenues from related parties	$	49	$	46	$	48




Purchases and related costs from related parties	$	358	$	400	$	404

Our receivable and payable amounts with these related parties as reflected on our Consolidated Balance Sheets were as follows (in millions):


	December 31,
	2025		2024



Trade accounts receivable and other receivables, net from related parties (1)	$	49	$	40




Trade accounts payable to related parties (1) (2)	$	64	$	66

(1)Primarily includes amounts related to transportation and storage services.

(2)We have agreements to store crude oil at facilities and transport crude oil or utilize capacity on pipelines that are owned by equity method investees. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities.

Property and Equipment

12 Months Ended

Dec. 31, 2025

Property, Plant and Equipment [Abstract]

Property and Equipment

In accordance with our capitalization policy, expenditures made to expand the existing operating and/or earnings capacity of our assets are capitalized, as are certain costs directly related to the construction of such assets, including related internal labor costs, engineering costs and interest costs. We also capitalize expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are expensed as incurred.

Property and equipment, net is stated at cost and consisted of the following (in millions):


	Estimated Useful Lives (Years)	December 31,
		2025		2024
Crude oil pipeline systems	10 - 50	$	18,428	$	14,612
Crude oil storage and terminal facilities	10 - 50	2,808		2,679
NGL storage, terminal, fractionation and processing facilities	10 - 50	365		364

Office property and equipment and rolling stock	2 - 50	373		430
Construction in progress	N/A	238		148
Land and other	N/A	324		295
Property and equipment, gross (1)		22,536		18,528
Accumulated depreciation		(5,676)		(5,082)
Property and equipment, net		$	16,860	$	13,446

(1)We include rights-of-way, which are intangible assets, within property and equipment.

We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets. Depreciation expense for the years ended December 31, 2025, 2024 and 2023 was $673 million, $639 million and $618 million, respectively.

As of December 31, 2025, 2024 and 2023, we incurred liabilities of $43 million, $44 million and $40 million, respectively, for construction in progress that had not been paid.

Impairment of Long-Lived Assets (Held and Used)

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value in accordance with FASB guidance with respect to the accounting for the impairment or disposal of long-lived assets. Under this guidance, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized.

We periodically evaluate property and equipment and other long-lived assets for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. The subjective assumptions used to determine the existence of an impairment in carrying value include:

•whether there is an indication of impairment;

•the grouping of assets;

•the intention of “holding,” “abandoning” or “selling” an asset;

•the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and

•if an impairment exists, the fair value of the asset or asset group.

In addition, when we evaluate property and equipment and other long-lived assets for recoverability, it may also be necessary to review related depreciation estimates and methods.

During the fourth quarter of 2024, we recognized approximately $140 million of non-cash charges related to the write-down of certain of our long-lived U.S. based NGL terminal assets included in our NGL segment due to asset impairments and accelerated depreciation. Such charges are reflected in “(Gains)/losses on asset sales, asset impairments and other, net” on our Consolidated Statement of Operations. We have experienced a decrease in demand for our services at certain of our terminals within two asset groups related to changing market conditions specific to their locations, which was a triggering event that required us to assess the recoverability of carrying value of such long-lived assets. As a result of our impairment review, we wrote-off the portion of the carrying amount of these long-lived assets that exceeded their fair value. Our estimated fair value was based on the determination that a portion of the long-lived assets had no residual value. We consider such inputs to be a Level 3 input in the fair value hierarchy. Further, we determined that an acceleration of depreciation was appropriate for another portion of the long-lived assets.

We did not recognize any material asset impairments during the years ended December 31, 2025 and 2023.

Intangible Assets, Net (Tables)

12 Months Ended

Dec. 31, 2025

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Components of Intangible Assets, Net of Accumulated Amortization

Intangible assets, net of accumulated amortization, consisted of the following (in millions):


		December 31, 2025						December 31, 2024
	Estimated Useful Lives (Years)	Cost		Accumulated Amortization		Net		Cost		Accumulated Amortization		Net
Customer contracts and relationships	1 – 20	$	3,034	$	(1,295)	$	1,739	$	2,677	$	(1,015)	$	1,662

Other agreements	15 – 70	29		(14)		15		28		(13)		15
Intangible assets (1) (2)		$	3,063	$	(1,309)	$	1,754	$	2,705	$	(1,028)	$	1,677

(1)We include rights-of-way, which are intangible assets, within property and equipment. See Note 7 for a discussion of property and equipment.

(2)The increase in intangible assets in 2025 is associated with the assets acquired during the period. See Note 8 for additional information.

Schedule of Estimated Amortization Expense Related to Finite-lived Intangible Assets for the next Five Years

We estimate that our amortization expense related to finite-lived intangible assets for the next five years will be as follows (in millions):


2026	$	301
2027	$	261
2028	$	215
2029	$	192
2030	$	165

Segment Information - Geographical Data (Details) - USD ($) $ in Millions	3 Months Ended								12 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, 2025	Dec. 31, 2024	Dec. 31, 2023
Geographic Data
Total revenues	$ 10,565	$ 11,578	$ 10,642	$ 11,477	$ 12,035	$ 12,456	$ 12,757	$ 11,639	$ 44,262	$ 48,889	$ 47,336
Long-lived assets	22,878				19,384				22,878	19,384
United States
Geographic Data
Total revenues									39,761	43,535	41,738
Long-lived assets	21,398				17,955				21,398	17,955
Canada
Geographic Data
Total revenues									4,501	5,354	$ 5,598
Long-lived assets	$ 1,480				$ 1,429				$ 1,480	$ 1,429

- 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).

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+ Details

Revenues and Accounts Receivable - Disaggregation of Revenue (Details) - Operating Segments - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 44,237	$ 48,838	$ 47,332
Crude Oil
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	44,087	48,651	47,146
Crude Oil \| Sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	42,408	47,036	45,621
Crude Oil \| Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,330	1,231	1,144
Crude Oil \| Terminalling, Storage and Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	349	384	381
NGL
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	150	187	186
NGL \| Sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	144	180	179
NGL \| Terminalling, Storage and Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 6	$ 7	$ 7

- 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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Amount, excluding tax collected from customer, of revenue from satisfaction of performance obligation by transferring promised good or service to customer. Tax collected from customer is tax assessed by governmental authority that is both imposed on and concurrent with specific revenue-producing transaction, including, but not limited to, sales, use, value added and excise.

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+ Details

Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2025

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Data

The following table sets forth selected quarterly financial data (in millions, except per share data):


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total (1)
Year Ended December 31, 2025
Total revenues	$	11,477	$	10,642	$	11,578	$	10,565	$	44,262
Gross margin (2)	$	440	$	321	$	567	$	447	$	1,776
Operating income	$	353	$	237	$	483	$	354	$	1,428
Income from continuing operations, net of tax	$	356	$	213	$	428	$	306	$	1,303
Income from discontinued operations, net of tax	$	136	$	70	$	76	$	102	$	383
Net income	$	492	$	283	$	504	$	408	$	1,686
Net income attributable to PAGP	$	84	$	30	$	83	$	62	$	260
Basic net income per Class A share:
Continuing operations	$	0.23	$	0.05	$	0.31	$	0.17	$	0.77
Discontinued operations	0.19		0.10		0.11		0.14		0.54
Basic net income per Class A share	$	0.42	$	0.15	$	0.42	$	0.31	$	1.31
Diluted net income per Class A share:
Continuing operations	$	0.23	$	0.05	$	0.31	$	0.17	$	0.77
Discontinued operations	0.19		0.10		0.10		0.14		0.53
Diluted net income per Class A share	$	0.42	$	0.15	$	0.41	$	0.31	$	1.30

Year Ended December 31, 2024
Total revenues	$	11,639	$	12,757	$	12,456	$	12,035	$	48,889
Gross margin (2)	$	437	$	411	$	282	$	67	$	1,196
Operating income/(loss)	$	355	$	330	$	195	$	(17)	$	862
Income from continuing operations, net of tax	$	326	$	284	$	187	$	42	$	839
Income from discontinued operations, net of tax	$	10	$	32	$	114	$	74	$	231
Net income	$	336	$	316	$	301	$	116	$	1,070
Net income/(loss) attributable to PAGP	$	42	$	39	$	33	$	(11)	$	103
Basic net income/(loss) per Class A share:
Continuing operations	$	0.20	$	0.15	$	0.01	$	(0.16)	$	0.19
Discontinued operations	0.01		0.05		0.16		0.11		0.33
Basic net income/(loss) per Class A share	$	0.21	$	0.20	$	0.17	$	(0.05)	$	0.52
Diluted net income/(loss) per Class A share:
Continuing operations	$	0.20	$	0.15	$	0.01	$	(0.16)	$	0.19
Discontinued operations	0.01		0.04		0.16		0.11		0.32
Diluted net income/(loss) per Class A share	$	0.21	$	0.19	$	0.17	$	(0.05)	$	0.51

(1)The sum of the four quarters may not equal the year due to rounding.

(2)Gross margin is calculated as Total revenues less (i) Purchases and related costs, (ii) Field operating costs, (iii) Depreciation and amortization and (iv) (Gains)/losses on asset sales, asset impairments and other, net.

Segment Information - Narrative (Details)	12 Months Ended
Segment Information - Narrative (Details)	Dec. 31, 2025 segment
Segment Reporting [Abstract]
Number of reportable segments	2

Derivatives and Risk Management Activities - Offsetting Asset and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Derivative Assets
Effect of Collateral Netting (Liability)	$ 19	$ 22
Commodity derivatives
Derivative Assets
Effect of Collateral Netting (Liability)	19	22
Derivative Liabilities
Gross Position - Asset	28	22
Gross Position - Liability	(32)	(25)
Net Carrying Value Presented on the Balance Sheet		(4)
Net Carrying Value Presented on the Balance Sheet	15	19
Commodity derivatives \| Other current assets
Derivative Assets
Gross Position - Asset	18	25
Gross Position - Liability	(24)	(24)
Effect of Collateral Netting (Liability)	19	22
Net Carrying Value Presented on the Balance Sheet	13	23
Commodity derivatives \| Other long-term assets, net
Derivative Assets
Gross Position - Asset	1
Gross Position - Liability	0
Effect of Collateral Netting (Liability)	0
Net Carrying Value Presented on the Balance Sheet	1	0
Commodity derivatives \| Other current liabilities
Derivative Assets
Effect of Collateral Netting (Liability)	0
Derivative Liabilities
Gross Position - Asset	(1)	(5)
Gross Position - Liability		5
Net Carrying Value Presented on the Balance Sheet	(1)
Commodity derivatives \| Other long-term liabilities and deferred credits
Derivative Assets
Effect of Collateral Netting (Liability)	0	0
Derivative Liabilities
Gross Position - Asset	10	2
Gross Position - Liability	(8)	$ (6)
Net Carrying Value Presented on the Balance Sheet	$ 2

Discontinued Operations - Assets and Liabilities of Discontinued Operations (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Current assets:
Total current assets of discontinued operations	$ 479	$ 415
Long-term assets:
Total long-term assets of discontinued operations	2,557	2,349
Current liabilities:
Total current liabilities of discontinued operations	382	350
Long-term liabilities:
Total long-term liabilities of discontinued operations	606	576
NGL Business \| Discontinued Operations, Held-for-Sale
Current assets:
Trade accounts receivable and other receivables, net	285	222
Inventory	176	178
Other current assets	18	15
Total current assets of discontinued operations	479	415
Long-term assets:
Property and equipment, net	2,191	1,978
Linefill	70	64
Long-term operating lease right-of-use assets, net	138	143
Long-term inventory	38	38
Other long-term assets, net	120	126
Total long-term assets of discontinued operations	2,557	2,349
Current liabilities:
Trade accounts payable	295	234
Other current liabilities	87	116
Total current liabilities of discontinued operations	382	350
Long-term liabilities:
Long-term operating lease liabilities	96	121
Other long-term liabilities and deferred credits	510	455
Total long-term liabilities of discontinued operations	606	576
Accumulated depreciation	$ 876	$ 794

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2025

Loss Contingencies [Line Items]

Schedule of Future Non-Cancelable Commitments

Future noncancelable commitments related to these items at December 31, 2025 are summarized below (in millions):


	2026		2027		2028		2029		2030		Thereafter		Total
Leases (1)	$	46	$	44	$	43	$	34	$	28	$	346	$	541
Other commitments (2)	245		215		116		114		117		141		948
Total	$	291	$	259	$	159	$	148	$	145	$	487	$	1,489

Excluding Line 901 Incident

Loss Contingencies [Line Items]

Schedule of Consolidated Balance Sheets


	December 31, 2025		December 31, 2024
Other current liabilities	$	13	$	11
Other long-term liabilities and deferred credits	70		69
Total	$	83	$	80

- 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

Inventory, Linefill and Long-term Inventory

12 Months Ended

Dec. 31, 2025

Inventory Disclosure [Abstract]

Inventory, Linefill and Long-term Inventory

Inventory, including long-term inventory, primarily consists of crude oil and NGL in pipelines, storage facilities and railcars that are valued at the lower of cost or net realizable value, with cost determined using an average cost method within specific inventory pools. At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Consolidated Statements of Operations. No adjustments were recorded during the years ended December 31, 2025, 2024 or 2023.

Linefill in assets we own is recorded at historical cost. We classify as linefill (i) our proportionate share of barrels used to fill a pipeline that we own such that when an incremental barrel is pumped into or enters a pipeline it forces product out at another location and (ii) barrels that represent the minimum working requirements in tanks and caverns that we own. Linefill carrying amounts are reviewed for impairment in accordance with FASB guidance with respect to accounting for the impairment or disposal of long-lived assets. Carrying amounts that are not expected to be recoverable through future cash flows are written down to estimated fair value. See Note 7 for further discussion regarding impairment of long-lived assets. During 2025, 2024 and 2023, we did not recognize any material impairments of linefill.

Minimum working inventory requirements in third-party assets and other working inventory in our assets that are needed for our commercial operations are included within specific inventory pools in inventory (a current asset) in determining the average cost of operating inventory. At the end of each period, we reclassify the inventory not expected to be liquidated within the succeeding twelve months out of “Inventory,” at the average cost of the applicable inventory pools, and into “Long-term inventory,” which is reflected as a separate line item under “Other assets” on our Consolidated Balance Sheets.

Inventory, linefill and long-term inventory consisted of the following (barrels in thousands and carrying value in millions):


	December 31, 2025						December 31, 2024
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	2,948	barrels	$	166	$	56.31	3,321	barrels	$	221	$	66.55
NGL	562	barrels	27		$	48.04	603	barrels	26		$	43.12

Other	N/A		18		N/A		N/A		14		N/A
Inventory subtotal			211						261

Linefill
Crude oil	15,112	barrels	898		$	59.42	15,463	barrels	903		$	58.40
NGL	33	barrels	2		$	60.61	32	barrels	1		$	31.25

Linefill subtotal			900						904

Long-term inventory
Crude oil	3,724	barrels	213		$	57.20	3,413	barrels	238		$	69.73
NGL	26	barrels	1		$	38.46	90	barrels	4		$	44.44
Long-term inventory subtotal			214						242

Total			$	1,325					$	1,407

Debt - Maturities (Details) $ in Millions	12 Months Ended
Debt - Maturities (Details) $ in Millions	Dec. 31, 2025 USD ($)
Debt Disclosure [Abstract]
Weighted-average maturity of long-term debt	10 years
Maturities
2026	$ 750
2027	0
2028	0
2029	1,000
2030	750
Thereafter	$ 6,683

Segment Information - Reconciliation of Segment Adjusted EBITDA (Details) - USD ($) $ in Millions	3 Months Ended								12 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, 2025	Dec. 31, 2024	Dec. 31, 2023
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA									$ 2,310	$ 2,255	$ 2,133
Total other segment items									405	125	251
Unallocated general and administrative expenses									(348)	(334)	(305)
Depreciation and amortization									(953)	(901)	(912)
Gains/(losses) on asset sales, asset impairments and other, net									54	(159)	152
Gain on investments in unconsolidated entities, net (Note 8, Note 9)									31	15	28
Interest expense, net									(467)	(382)	(386)
Other income, net									21	16	102
INCOME FROM CONTINUING OPERATIONS BEFORE TAX									1,395	963	1,362
Income tax expense from continuing operations									(92)	(124)	(129)
Income from continuing operations, net of tax	$ 306	$ 428	$ 213	$ 356	$ 42	$ 187	$ 284	$ 326	1,303	839	1,233
Segment Reporting, Reconciling Item, Corporate Nonsegment
Segment Reporting Information [Line Items]
Unallocated general and administrative expenses									$ (6)	$ (6)	$ (6)

Cover - USD ($) $ in Billions	12 Months Ended
Cover - USD ($) $ in Billions	Dec. 31, 2025	Feb. 20, 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	1-36132
Entity Registrant Name	PLAINS GP HOLDINGS LP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	90-1005472
Entity Address, Address Line One	333 Clay Street
Entity Address, Address Line Two	Suite 1600
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	646-4100
Title of 12(b) Security	Class A Shares, Representing Limited Partner Interests
Trading Symbol	PAGP
Security Exchange Name	NASDAQ
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			$ 3.7
Entity Common Stock Outstanding (in shares)		197,904,124
Documents Incorporated by Reference	Portions of the registrant’s definitive Proxy Statement to be filed pursuant to Regulation 14A pertaining to the 2026 Annual Meeting of Shareholders are incorporated by reference into Part III hereof. The registrant intends to file such Proxy Statement no later than 120 days after the end of the fiscal year covered by this Form 10-K.
Entity Central Index Key	0001581990
Amendment Flag	false
Document Fiscal Year Focus	2025
Document Fiscal Period Focus	FY

Derivatives and Risk Management Activities - Financial Impact (Details) - Derivatives Not Designated as a Hedge - Commodity derivatives - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Impact of derivative activities recognized in earnings
Net gain/(loss) from commodity derivative activity	$ (18)	$ (32)	$ 9
Product sales revenues
Impact of derivative activities recognized in earnings
Net gain/(loss) from commodity derivative activity	(20)	(24)	(10)
Field operating costs
Impact of derivative activities recognized in earnings
Net gain/(loss) from commodity derivative activity	$ 2	$ (8)	$ 19

- 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 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
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Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 815
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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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+ Details

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense

Pre-tax book income by geography is as follows (in millions):


	Year Ended December 31,
	2025		2024		2023
United States	$	1,350	$	832	$	1,130
Canada	45		131		232
Total pre-tax book income	$	1,395	$	963	$	1,362

Components of income tax expense are as follows (in millions):


	Year Ended December 31,
	2025		2024		2023
Current income tax expense/(benefit):
State income tax	$	2	$	2	$	2
Canadian federal and provincial income and withholding taxes	(1)		80		68
Total current income tax expense	$	1	$	82	$	70

Deferred income tax expense/(benefit):
U.S. federal income tax	$	71	$	31	$	55
State income tax	6		6		13
Canadian federal and provincial income and withholding taxes	14		5		(9)
Total deferred income tax expense	$	91	$	42	$	59
Total income tax expense	$	92	$	124	$	129

Schedule of Differences Between Tax Expense Based on the Statutory Federal Income Tax Rate and the Effective Income Tax Expense

The difference between income tax expense based on the statutory federal income tax rate and our effective income tax expense is summarized as follows (in millions, except percentages):


	Year Ended December 31,
	2025				2024				2023
	Amount		Percent		Amount		Percent		Amount		Percent
U.S. federal statutory tax rate	$	293	21.00	%	$	202	21.00	%	$	286	21.00	%

State and local income taxes (1)	8		0.57	%	8		0.87	%	15		1.08	%

Foreign tax effects:
Canada
Foreign rate differential	(3)		(0.22)	%	(8)		(0.81)	%	(14)		(1.02)	%
Provincial taxes	5		0.36	%	13		1.22	%	20		1.50	%
Foreign withholding taxes	3		0.22	%	52		5.43	%	—		—	%
Other	(2)		(0.14)	%	—		—	%	4		0.32	%

Nontaxable or nondeductible items:
Nontaxable income attributable to noncontrolling interests	(212)		(15.20)	%	(143)		(14.97)	%	(180)		(13.25)	%
Other permanent book tax differences	—		—	%	—		—	%	(2)		(0.14)	%

Effective tax rate (2)	$	92	6.59	%	$	124	12.84	%	$	129	9.48	%

Schedule of Cash Flow, Supplemental Disclosures

Cash taxes paid were as follows (in millions):


	Year Ended December 31,
	2025		2024		2023


State income tax:
Texas	$	1	$	2	2

Total state income tax paid	1		2		2

Canadian federal and provincial income and withholding taxes	97		267		67

Total cash tax paid	$	98	$	269	$	69

Schedule of Deferred Tax Assets and Liabilities

Deferred tax assets and liabilities are aggregated by the applicable tax paying entity and jurisdiction and result from the following (in millions):


	December 31,
	2025		2024
Deferred tax assets:
Investment in partnerships	$	151	$	436
Net operating losses	985		784
Derivative instruments	—		6
Lease liabilities	10		8
Other	7		8
Total deferred tax assets	1,153		1,242

Deferred tax liabilities:
Property and equipment in excess of tax values	(204)		(188)

Lease assets	(9)		(10)
Other	(1)		—
Total deferred tax liabilities	(214)		(198)
Net deferred tax assets	$	939	$	1,044

Balance sheet classification of deferred tax assets/(liabilities):
Deferred tax asset	$	1,136	$	1,220
Other long-term liabilities and deferred credits	(197)		(176)
	$	939	$	1,044

Investments in Unconsolidated Entities

12 Months Ended

Dec. 31, 2025

Equity Method Investments and Joint Ventures [Abstract]

Investments in Unconsolidated Entities

Investments in entities over which we have significant influence but not control are accounted for under the equity method. We do not consolidate any part of the assets or liabilities of our equity investees. Our share of net income or loss is reflected as one line item on our Consolidated Statements of Operations entitled “Equity earnings in unconsolidated entities” and will increase or decrease, as applicable, the carrying value of our investments in unconsolidated entities on our Consolidated Balance Sheets. We evaluate our equity investments for impairment in accordance with FASB guidance with respect to the equity method of accounting for investments in common stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature.

Our investments in unconsolidated entities consisted of the following (in millions, except percentage data):


		Ownership Interest at December 31, 2025	Investment Balance December 31,

Entity (1)	Type of Operation		2025		2024
BridgeTex Pipeline Company, LLC (“BridgeTex”)	Crude Oil Pipeline	40%	$	574	$	403
Capline Pipeline Company LLC (“Capline”) (2)	Crude Oil Pipeline	54%	473		501
Diamond Pipeline LLC	Crude Oil Pipeline	50%	432		440
Eagle Ford Pipeline LLC	Crude Oil Pipeline	50%	347		364
Eagle Ford Terminals Corpus Christi LLC	Crude Oil Terminal and Dock	50%	110		113

Saddlehorn Pipeline Company, LLC (“Saddlehorn”)	Crude Oil Pipeline	40%	262		275
White Cliffs Pipeline, L.L.C.	Crude Oil Pipeline	36%	109		123
Wink to Webster Pipeline LLC (“W2W Pipeline”) (3)	Crude Oil Pipeline	17%	383		393
Other investments			156		199
Total Investments in Unconsolidated Entities			$	2,846	$	2,811

(1)The financial results from these entities are reported in our Crude Oil segment.

(2)Although we own more than 50% of Capline, we use the equity method to account for the investment because the other joint venture members still retain substantive participating rights.

Acquisitions

During 2025, we acquired the remaining 50% interest in Cheyenne (which was previously presented in “Other investments” in the table above). Prior to our acquisition, our 50% interest in Cheyenne was accounted for as an equity method investment. In addition, during 2025, we acquired an additional interest in BridgeTex, which we continue to account for as an equity method investment. See Note 8 for additional information regarding these transactions.

During 2024, we acquired the remaining 50% interest in Midway (which was previously presented in “Other investments” in the table above). Prior to our acquisition, our 50% interest in Midway was accounted for as an equity method investment. In addition, during 2024, we acquired additional interests in W2W Pipeline and Saddlehorn, which we continue to account for as equity method investments. See Note 8 for additional information regarding these transactions.

In the third quarter of 2023, we acquired the remaining 43% interest in OMOG. We now reflect OMOG and its subsidiaries as consolidated subsidiaries in our Consolidated Financial Statements. See “Rattler Permian Transaction” in Note 8 for additional information.

Distributions

Distributions received from unconsolidated entities are classified based on the nature of the distribution approach, which looks to the activity that generated the distribution. We consider distributions received from unconsolidated entities as a return on investment in those entities to the extent that the distribution was generated through operating results, and therefore classify these distributions as cash flows from operating activities in our Consolidated Statement of Cash Flows. Other distributions received from unconsolidated entities are considered a return of investment and classified as cash flows from investing activities on the Consolidated Statement of Cash Flows.

Contributions

We generally fund our portion of development, construction or capital investment projects of our equity method investees through capital contributions. During the years ended December 31, 2025, 2024 and 2023, we made cash contributions of $2 million, $4 million and $29 million, respectively, to certain of our equity method investees. We capitalize interest costs associated with contributions to unconsolidated entities for projects under development and construction. Our contributions to these entities (including capitalized interest costs) increase the carrying value of our investments and are reflected in our Consolidated Statements of Cash Flows as cash used in investing activities.

Basis Differences

Our investments in unconsolidated entities exceeded our share of the underlying equity in the net assets of such entities by $237 million and $213 million at December 31, 2025 and 2024, respectively. Such basis differences are included in the carrying values of our investments on our Consolidated Balance Sheets. The portion of the basis differences attributable to depreciable or amortizable assets is amortized on a straight-line basis over the estimated useful life of the related assets, which reduces “Equity earnings in unconsolidated entities” on our Consolidated Statements of Operations. The portion of the basis differences attributable to goodwill is not amortized. The majority of the basis difference at both December 31, 2025 and 2024 was attributable to goodwill related to our ownership interest in BridgeTex with the remaining basis difference primarily related to capitalized interest incurred during construction of the assets of our unconsolidated entities.

Summarized Financial Information of Unconsolidated Entities

Combined summarized financial information for all of our unconsolidated entities is shown in the tables below (in millions). None of our unconsolidated entities have noncontrolling interests.


	December 31,
	2025		2024
Current assets	$	441	$	475
Noncurrent assets	$	6,755	$	6,996
Current liabilities	$	317	$	261
Noncurrent liabilities	$	13	$	12


	Year Ended December 31,
	2025		2024		2023
Revenues	$	1,926	$	2,193	$	1,667
Operating income	$	1,075	$	1,373	$	921
Net income	$	1,094	$	1,407	$	947

Investments in Unconsolidated Entities - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Nov. 30, 2025	Nov. 30, 2024	Sep. 30, 2023
Investments in Unconsolidated Entities
Capital contributions to equity method investees excluding capitalized interest	$ 2	$ 4	$ 29
Amount by which investments in unconsolidated entities exceeded our share of the underlying equity in the net assets	$ 237	$ 213
Cheyenne
Investments in Unconsolidated Entities
Business combination, step acquisition, equity interest in acquire (as a percent)				50.00%
Additional interest acquired (as a percent)	50.00%
Midway Pipeline LLC
Investments in Unconsolidated Entities
Business combination, step acquisition, equity interest in acquire (as a percent)					50.00%
Additional interest acquired (as a percent)		50.00%
OMOG JV LLC (“OMOG”)
Investments in Unconsolidated Entities
Additional interest acquired (as a percent)						43.00%

- 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

Equity-Indexed Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2025

Share-Based Payment Arrangement [Abstract]

Schedule of LTIP Awards Authorized

The following is a summary of the awards authorized under our LTIPs (including those associated with discontinued operations) as of December 31, 2025 (in millions):


LTIP						LTIP Awards Authorized
Plains GP Holdings, L.P. Long-Term Incentive Plan						3.8
Plains All American 2021 Long-Term Incentive Plan						28.8
Plains All American PNG Successor Long-Term Incentive Plan						1.3
Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan						13.4
Total (1)						47.3

(1)Of the 47.3 million total awards authorized, 16.4 million awards are currently available for future grant. The remaining balance has already vested or is currently outstanding.

Derivatives and Risk Management Activities

12 Months Ended

Dec. 31, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives and Risk Management Activities

We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. We use various derivative instruments to manage our exposure to commodity price risk, interest rate risk, and currency exchange rate risk. Our commodity price risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate risk and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on changes in commodity prices or interest rates. When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. At the inception of the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions. Throughout the hedging relationship, retrospective and prospective hedge effectiveness is assessed on a qualitative basis.

We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives designated as cash flow hedges, changes in fair value are deferred in AOCI and recognized in earnings in the periods during which the underlying hedged transactions are recognized in earnings. Derivatives that are not designated in a hedging relationship for accounting purposes are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Consolidated Statements of Cash Flows.

Our financial derivatives, used for hedging risk, are governed through ISDA master agreements and clearing brokerage agreements. These agreements include stipulations regarding the right of set off in the event that we or our counterparty default on performance obligations. If a default were to occur, both parties have the right to net amounts payable and receivable into a single net settlement between parties.

At December 31, 2025 and 2024, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our exchange-traded derivatives transacted through a clearing brokerage account, as described below, we do not require our non-cleared derivative counterparties to post collateral with us.

Commodity Price Risk Hedging

Our core business activities involve certain commodity price-related risks that we manage in various ways, including through the use of derivative instruments. Our policy is to (i) only purchase inventory for which we have a sales market, (ii) structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold material physical inventory or derivatives for the purpose of speculating on commodity price changes. The material commodity-related risks inherent in our business activities are described below.

In the normal course of our operations, we purchase and sell commodities. We use derivatives to manage the associated risks and, in certain circumstances, to optimize profits. As of December 31, 2025, net derivative positions related to these activities included:

•A net long position of 5.8 million barrels associated with our crude oil purchases, which will be unwound ratably through March 2026 to match monthly average pricing.

•A net short time spread position of 1.9 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through April 2026.

•A net crude oil basis spread position of 1.5 million barrels at multiple locations through December 2026. These derivatives allow us to lock in grade and location basis differentials.

•A net short position of 6.9 million barrels through December 2029 related to anticipated net sales of crude oil inventory.

•A net long position of 0.5 TWh through December 2030 related to anticipated power supply requirements.

Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchases and normal sales scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings. We have determined that substantially all of our physical commodity contracts qualify for the normal purchases and normal sales scope exception.

Our commodity derivatives are not designated in a hedging relationship for accounting purposes; as such, changes in the fair value are reported in earnings. The following table summarizes the impact of our commodity derivatives recognized in earnings (in millions):


	Year Ended December 31,
	2025		2024		2023
Product sales revenues	$	(20)	$	(24)	$	(10)
Field operating costs	2		(8)		19
Net gain/(loss) from commodity derivative activity	$	(18)	$	(32)	$	9

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through clearing brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. The following table provides the components of our net broker receivable (in millions):


	December 31,
	2025		2024
Initial margin	$	16	$	16
Variation margin posted	4		15
Letters of credit	(1)		(9)
Net broker receivable	$	19	$	22


	December 31, 2025								December 31, 2024
					Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet						Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet
	Commodity Derivatives								Commodity Derivatives
	Assets		Liabilities						Assets		Liabilities
Derivative Assets
Other current assets	$	18	$	(24)	$	19	$	13	$	25	$	(24)	$	22	$	23
Other long-term assets, net	1		—		—		1		—		—		—		—
Derivative Liabilities
Other current liabilities	(1)		—		—		(1)		(5)		5		—		—
Other long-term liabilities and deferred credits	10		(8)		—		2		2		(6)		—		(4)
Total	$	28	$	(32)	$	19	$	15	$	22	$	(25)	$	22	$	19

Interest Rate Risk Hedging

We use interest rate derivatives to hedge the benchmark interest rate associated with interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist of forward starting interest rate swaps and treasury locks. These derivatives are designated as cash flow hedges. As such, changes in fair value are deferred in AOCI and are reclassified to interest expense as we incur the interest expense associated with the underlying debt.

During the year ended December 31, 2025, we terminated $200 million of notional interest hedging instruments previously expected to terminate in October 2025 for proceeds of $7 million and $200 million of notional interest hedging instruments previously expected to terminate in June 2026 for proceeds of $30 million which were recorded in AOCI. As of December 31, 2025, there was a net loss of $29 million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with interest expense accruals associated with underlying debt instruments. The early termination did not result in an impact to the relationship between the hedging instrument and hedged item. We estimate that substantially all of the remaining deferred loss will be reclassified to earnings through 2056 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of December 31, 2025; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

The following table summarizes the net unrealized gain recognized in AOCI for derivatives (in millions):


	Year Ended December 31,
	2025		2024		2023
Interest rate derivatives, net	$	10	$	29	$	15

At December 31, 2025, we did not have any interest rate hedges recorded on our Consolidated Balance Sheet. At December 31, 2024, the net fair value of these hedges totaled $27 million, which was included in “Other long-term assets, net” on our Consolidated Balance Sheet.

Currency Exchange Rate Risk Hedging

In connection with the pending sale of the Canadian NGL Business, we entered into a forward currency instrument (CAD$4.5 billion notional amount) to hedge currency exchange risk. The instrument is contingent upon the sale occurring and will settle at closing. The cost of the deal-contingent structure is embedded in the hedge rate. As of December 31, 2025, the sale of the Canadian NGL Business is probable and the fair value of the instrument is an $8 million asset, presented in “Other current assets” on our Consolidated Balance Sheet. For the year ended December 31, 2025, we recognized the gains of $8 million, which was included in “(Gains)/losses on asset sales, asset impairments and other, net” on our Consolidated Statements of Operations. As of December 31, 2025, for the periods covered by the instrument, the average fixed USD to CAD rate of the instrument is $1.37 and the average forward USD to CAD rate is $1.37. See Note 1 for additional information regarding the pending sale of the Canadian NGL Business.

Preferred Distribution Rate Reset Option

In January 2023, PAA received notice that the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option. Prior to this election, the Preferred Distribution Rate Reset Option was accounted for as an embedded derivative. A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. The Preferred Distribution Rate Reset Option embedded derivative was required to be bifurcated from the related host contract, the PAA partnership agreement, and recorded at fair value on our Consolidated Balance Sheet. The Preferred Distribution Rate Reset Option embedded derivative was not designated in a hedging relationship for accounting purposes and corresponding changes in fair value were recognized in “Other income, net” in our Consolidated Statements of Operations. The Preferred Distribution Rate Reset Option was settled at a fair value of $131 million when we received notice that the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option, which resulted in a gain of $58 million, for the year ended December 31, 2023. See Note 12 for additional information regarding the Preferred Distribution Rate Reset Option.

Recurring Fair Value Measurements

Derivative Financial Assets and Liabilities

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions):


	Fair Value as of December 31, 2025						Fair Value as of December 31, 2024
Recurring Fair Value Measures (1)	Level 1		Level 2		Total			Level 1		Level 2		Total
Commodity derivatives	$	(2)	$	(2)	$	(4)		$	11	$	(14)	$	(3)
Interest rate derivatives	—		—		—			—		27		27

Foreign currency derivatives	—		8		8			—		—		—
Total net derivative asset/(liability)	$	(2)	$	6	$	4		$	11	$	13	$	24

(1)Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.

Level 1

Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives and over-the-counter commodity contracts such as futures and swaps. The fair value of exchange-traded commodity derivatives and over-the-counter commodity contracts is based on unadjusted quoted prices in active markets.

Level 2

Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives, over-the-counter commodity, foreign exchange and interest rate derivatives that are traded in observable markets with less volume and transaction frequency than active markets. In addition, it includes certain physical commodity contracts. The fair values of these derivatives are corroborated with market observable inputs.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

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-Name Accounting Standards Codification
-Section 50
-Paragraph 1A
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-1A

Reference 26: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1A
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-1A

Reference 27: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1A
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-1A

Reference 28: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1A
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-1A

Reference 29: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/815/tableOfContent

Reference 30: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480237/815-40-50-5

Reference 31: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 5C
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-5C

+ Details

Acquisitions, Divestitures and Other Transactions (Tables)

12 Months Ended

Dec. 31, 2025

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

Schedule of Business Combination, Consideration Transferred, Equity Interest

The EPIC acquisition was accounted for as a business combination using the acquisition method of accounting. The following table presents the fair value of the consideration in the EPIC acquisition (in millions):


Consideration:	Recognized Amount
Cash consideration	$	1,901
Contingent consideration	115

Total consideration	$	2,016

Schedule of Assets Acquired and Liabilities Assumed

The following table reflects

our preliminary determination of the fair value of the assets acquired and liabilities assumed in connection with the EPIC acquisition (in millions):


Identifiable Assets Acquired and Liabilities Assumed:	Estimated Useful Lives (in years)	Recognized Amount
Working capital and other assets, net	N/A	$	160
Property and equipment, net	47	2,737
Intangible assets	5 - 10	267
Other long-term debt, net	N/A	(1,114)
Long-term operating lease liability	N/A	(34)
Total		$	2,016

The following table reflects our preliminary determination of the fair value of the Ironwood Midstream acquisition assets and liabilities (in millions):


Identifiable Assets Acquired and Liabilities Assumed:	Estimated Useful Lives (in years)	Recognized Amount
Property and equipment	3 - 30	$	435
Intangible assets	16	27
Working capital and other assets and liabilities	N/A	19
		$	481

The following table reflects our determination of the fair value of the assets acquired and liabilities assumed in connection with the transaction (in millions):


Identifiable Assets Acquired and Liabilities Assumed:	Estimated Useful Lives (in years)	Recognized Amount
Property and equipment	3 - 30	$	484
Intangible assets	10	34
Working capital and other assets and liabilities	N/A	14
		$	532

Schedule of Amortization Expense

Amortization expense was approximately $15 million for the year ended December 31, 2025, and the future amortization expense through 2030 is estimated as follows (in millions):


2026	$	67
2027	$	53
2028	$	34
2029	$	29
2030	$	21

Amortization expense was approximately $4 million for the year ended December 31, 2025, and the future amortization expense through 2030 is estimated as follows (in millions):


2026	$	5
2027	$	4
2028	$	3
2029	$	3
2030	$	2

Amortization expense was approximately $10 million, $8 million and $4 million during the years ended December 31, 2025, 2024 and 2023, respectively, and the future amortization expense through 2028 is estimated as follows (in millions):





2026	$	4
2027	$	3
2028	$	2

Schedule of Business Combination, Pro Forma Information

These results are not necessarily indicative of the results that might have actually occurred had the acquisition taken place on January 1, 2024; furthermore, this financial information is not intended to be a projection of future results (in millions, except per unit amounts):


	Year Ended December 31,
	2025		2024
Total revenues	$	44,464	$	49,124
Net income/(loss) attributable to PAGP from continuing operations	$	136	$	(4)

Basic and diluted net income/(loss) per Class A share from continuing operations	$	0.69	$	(0.02)

Leases - Lessor Operating Lease Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
Operating lease revenue	$ 8	$ 10	$ 16

Leases - Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Lessee, Lease, Assets and Liabilities [Line Items]
Long-term operating lease right-of-use assets, net	$ 198	$ 189
Finance lease right-of-use assets, gross	90	103
Finance lease right-of-use assets, accumulated depreciation	(27)	(28)
Finance lease right-of-use assets, net	$ 63	$ 75
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Property, Plant, and Equipment and Finance Lease Right-of-Use Asset, after Accumulated Depreciation and Amortization	Property, Plant, and Equipment and Finance Lease Right-of-Use Asset, after Accumulated Depreciation and Amortization
Total lease right-of-use assets	$ 261	$ 264
Operating lease liabilities
Operating lease liabilities, current	$ 27	$ 30
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other current liabilities	Other current liabilities
Long-term operating lease liabilities	$ 202	$ 192
Total operating lease liabilities	229	222
Finance lease liabilities
Finance lease liabilities, current	$ 9	$ 14
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Short-term debt	Short-term debt
Finance lease liabilities, noncurrent	$ 63	$ 70
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Noncurrent portion of other long-term debt	Noncurrent portion of other long-term debt
Total finance lease liabilities	$ 72	$ 84
Total lease liabilities	301	306
Equity Method Investees \| Agreement to Store at Facilities Owned by Equity Method Investee \| Equity Method Investee That Owns Leased Storage Tanks
Lessee, Lease, Assets and Liabilities [Line Items]
Finance lease right-of-use assets, net	23	26
Finance lease liabilities
Total finance lease liabilities	$ 32	$ 33
Ownership interest in unconsolidated entity prior to acquisition (as a percent)	50.00%

Debt (Tables)

12 Months Ended

Dec. 31, 2025

Debt Disclosure [Abstract]

Schedule of Debt

Debt consisted of the following (in millions):


	December 31, 2025		December 31, 2024
SHORT-TERM DEBT
PAA commercial paper notes, bearing a weighted-average interest rate of 3.9% and 4.6%, respectively (1)	$	554	$	393



Other	9		14
Total short-term debt	563		407

LONG-TERM DEBT
PAA senior notes:



4.65% senior notes due October 2025 (2)	—		1,000
4.50% senior notes due December 2026 (3)	750		750
3.55% senior notes due December 2029	1,000		1,000
3.80% senior notes due September 2030	750		750
4.70% senior notes due January 2031	1,000		—
5.70% senior notes due September 2034	650		650
5.95% senior notes due June 2035	1,000		—
5.60% senior notes due January 2036	1,000		—
6.70% senior notes due May 2036	250		250
6.65% senior notes due January 2037	600		600
5.15% senior notes due June 2042	499		499
4.30% senior notes due January 2043	348		348
4.70% senior notes due June 2044	687		687
4.90% senior notes due February 2045	649		649
Unamortized discounts and debt issuance costs	(65)		(42)
PAA senior notes, net of unamortized discounts and debt issuance costs	9,118		7,141
Other long-term debt:
PAA commercial paper notes, bearing a weighted-average interest rate of 3.9% (3)	416		—
PAA term loan, net of debt issuance costs of $1, bearing a weighted-average interest rate of 5.0%	1,099		—

Other	63		70
Total long-term debt	10,696		7,211
Total debt (4)	$	11,259	$	7,618

(1)PAA classified these commercial paper notes as short-term as of December 31, 2025 and 2024, as these notes were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.

(2)As of December 31, 2024, PAA classified its $1.0 billion, 4.65% senior notes due October 2025 as long-term based on its ability and intent to refinance these notes on a long-term basis at that time. PAA redeemed these senior notes on October 3, 2025.

(3)As of December 31, 2025, PAA classified its $750 million, 4.50% senior notes due December 2026 as long-term based on its ability and intent to refinance the notes on a long-term basis.

(4)As of December 31, 2025, we classified a portion of our commercial paper notes as long-term based on our ability and intent to refinance such amounts on a long-term basis.

(5)PAA’s fixed-rate senior notes had a face value of approximately $9.2 billion and $7.2 billion as of December 31, 2025 and 2024, respectively. We estimated the aggregate fair value of these notes as of December 31, 2025 and 2024 to be approximately $9.0 billion and $6.7 billion, respectively. PAA’s fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under PAA’s commercial paper program and term loan approximate fair value as interest rates reflect current market rates. The fair value estimates for the PAA senior notes, commercial paper program and term loan are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

Schedule of PAA's Senior Unsecured Notes

PAA Senior Notes Issuances. The table below summarizes PAA’s issuances of senior unsecured notes during the three years ended December 31, 2025 (face value in millions):

Issuance Date

Description

Maturity

Face Value

Interest Payment Dates

November 14, 2025

4.70% senior notes issued at 99.872% of face value

January 2031

300

January 15 and July 15

(1)

November 14, 2025

5.60% senior notes issued at 100.518% of face value

January 2036

450

January 15 and July 15

(2)

September 8, 2025

4.70% senior notes issued at 99.865% of face value

January 2031

700

January 15 and July 15

September 8, 2025

5.60% senior notes issued at 99.798% of face value

January 2036

550

January 15 and July 15

January 15, 2025

5.95% senior notes issued at 99.761% of face value

June 2035

1,000

June 15 and December 15

June 27, 2024

5.70% senior notes issued at 99.953% of face value

September 2034

650

March 15 and September 15

(1) Additional issuance of PAA 4.70% senior notes due 2031 that were issued on September 8, 2025, and trade interchangeably with such notes.

(2) Additional issuance of PAA 5.60% senior notes due 2036 that were issued on September 8, 2025 and trade interchangeably with such notes.

During the three years ended December 31, 2025, PAA repaid the following senior unsecured notes in full:

Repayment Date

Description

Maturity

October 3, 2025

$1,000 million 4.65% senior notes

October 2025

(1)

November 1, 2024

$750 million 3.60% senior notes

November 2024

(2)

(1)PAA repaid these senior notes with a combination of proceeds from PAA senior notes issued in September 2025, cash on hand and borrowings under its commercial paper program.

(2)PAA repaid these senior notes with a combination of proceeds from PAA senior notes issued in June 2024, cash on hand and borrowings under its commercial paper program.

Schedule of Aggregate Maturities of Long-term Debt

The following table presents the aggregate contractually scheduled maturities of such senior notes for the next five years and thereafter. The amounts presented exclude unamortized discounts and debt issuance costs.


Calendar Year	Payment (in millions)
2026	$	750
2027	$	—
2028	$	—
2029	$	1,000
2030	$	750
Thereafter	$	6,683

- 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

+ Details

Income Taxes - Narrative (Details) $ in Millions	Dec. 31, 2025 USD ($)
U.S. federal
Income Tax Examination [Line Items]
Net operating loss carryforwards	$ 4,482
State
Income Tax Examination [Line Items]
Net operating loss carryforwards	1,134
Canadian Tax Authorities \| Foreign tax effects:
Income Tax Examination [Line Items]
Amount of assessments received, including penalty and interest	189
Canadian Tax Authorities \| Foreign tax effects: \| Other long-term assets, net
Income Tax Examination [Line Items]
Amount of disputed assessments paid	$ 86

Debt - Debt Covenants (Details) $ in Millions	12 Months Ended
Debt - Debt Covenants (Details) $ in Millions	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Debt Instrument [Line Items]
Coverage ratio of debt-to-EBITDA, maximum	5.00
Ratio of debt-to-EBITDA during acquisition period, maximum	5.50
Threshold for acquisition period qualification	$ 150
Outstanding letters of credit	95	$ 90
Credit Agreements and PAA Commercial Paper Program
Debt Instrument [Line Items]
Total borrowings	56,400	28,100	$ 18,100
Total repayments	$ 55,800	$ 28,100	$ 17,700
Letters of Credit \| Maximum
Debt Instrument [Line Items]
Periods for which letters of credit are issued (in days)	70 days

Intangible Assets, Net

12 Months Ended

Dec. 31, 2025

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets, Net

Intangible assets, net of accumulated amortization, consisted of the following (in millions):


		December 31, 2025						December 31, 2024
	Estimated Useful Lives (Years)	Cost		Accumulated Amortization		Net		Cost		Accumulated Amortization		Net
Customer contracts and relationships	1 – 20	$	3,034	$	(1,295)	$	1,739	$	2,677	$	(1,015)	$	1,662

Other agreements	15 – 70	29		(14)		15		28		(13)		15
Intangible assets (1) (2)		$	3,063	$	(1,309)	$	1,754	$	2,705	$	(1,028)	$	1,677

(1)We include rights-of-way, which are intangible assets, within property and equipment. See Note 7 for a discussion of property and equipment.

(2)The increase in intangible assets in 2025 is associated with the assets acquired during the period. See Note 8 for additional information.

Intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. We did not recognize any impairments of finite-lived intangible assets during the three years ended December 31, 2025.

The majority of our finite-lived intangible assets are amortized under the declining balance method. Amortization expense for finite-lived intangible assets for the years ended December 31, 2025, 2024 and 2023 was $280 million, $262 million and $291 million, respectively. We estimate that our amortization expense related to finite-lived intangible assets for the next five years will be as follows (in millions):


2026	$	301
2027	$	261
2028	$	215
2029	$	192
2030	$	165

Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2025

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Data (Unaudited)

On June 17, 2025, we entered into a SPA with Keyera, pursuant to which Keyera agreed to acquire all of the issued and outstanding shares of Plains Midstream Canada ULC, our wholly-owned subsidiary that owns substantially all of our Canadian NGL Business. See Note 1 for additional information. We determined that in conjunction with entering into the SPA, the operations of the Canadian NGL Business meet the criteria for classification as held for sale and for discontinued operations reporting, as the sale will represent a strategic shift that will have a major effect on our operations and financial results.

The following table sets forth selected quarterly financial data (in millions, except per share data):


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total (1)
Year Ended December 31, 2025
Total revenues	$	11,477	$	10,642	$	11,578	$	10,565	$	44,262
Gross margin (2)	$	440	$	321	$	567	$	447	$	1,776
Operating income	$	353	$	237	$	483	$	354	$	1,428
Income from continuing operations, net of tax	$	356	$	213	$	428	$	306	$	1,303
Income from discontinued operations, net of tax	$	136	$	70	$	76	$	102	$	383
Net income	$	492	$	283	$	504	$	408	$	1,686
Net income attributable to PAGP	$	84	$	30	$	83	$	62	$	260
Basic net income per Class A share:
Continuing operations	$	0.23	$	0.05	$	0.31	$	0.17	$	0.77
Discontinued operations	0.19		0.10		0.11		0.14		0.54
Basic net income per Class A share	$	0.42	$	0.15	$	0.42	$	0.31	$	1.31
Diluted net income per Class A share:
Continuing operations	$	0.23	$	0.05	$	0.31	$	0.17	$	0.77
Discontinued operations	0.19		0.10		0.10		0.14		0.53
Diluted net income per Class A share	$	0.42	$	0.15	$	0.41	$	0.31	$	1.30

Year Ended December 31, 2024
Total revenues	$	11,639	$	12,757	$	12,456	$	12,035	$	48,889
Gross margin (2)	$	437	$	411	$	282	$	67	$	1,196
Operating income/(loss)	$	355	$	330	$	195	$	(17)	$	862
Income from continuing operations, net of tax	$	326	$	284	$	187	$	42	$	839
Income from discontinued operations, net of tax	$	10	$	32	$	114	$	74	$	231
Net income	$	336	$	316	$	301	$	116	$	1,070
Net income/(loss) attributable to PAGP	$	42	$	39	$	33	$	(11)	$	103
Basic net income/(loss) per Class A share:
Continuing operations	$	0.20	$	0.15	$	0.01	$	(0.16)	$	0.19
Discontinued operations	0.01		0.05		0.16		0.11		0.33
Basic net income/(loss) per Class A share	$	0.21	$	0.20	$	0.17	$	(0.05)	$	0.52
Diluted net income/(loss) per Class A share:
Continuing operations	$	0.20	$	0.15	$	0.01	$	(0.16)	$	0.19
Discontinued operations	0.01		0.04		0.16		0.11		0.32
Diluted net income/(loss) per Class A share	$	0.21	$	0.19	$	0.17	$	(0.05)	$	0.51

(1)The sum of the four quarters may not equal the year due to rounding.

Partners' Capital and Distributions - PAA Distributions (Details) $ / shares in Units, shares in Millions, $ in Millions							1 Months Ended	12 Months Ended
	Feb. 17, 2026 USD ($) $ / shares	Feb. 13, 2026 USD ($)	Jan. 05, 2026 $ / shares	Jan. 31, 2025 USD ($) $ / shares shares	Jan. 31, 2023 $ / shares	Nov. 15, 2022 $ / shares	May 31, 2023 $ / shares	Dec. 31, 2025 USD ($) $ / shares	Dec. 31, 2024 USD ($) $ / shares	Dec. 31, 2023 USD ($) $ / shares	Jan. 30, 2025 USD ($)	Aug. 15, 2023
Partners' Capital and Distributions [Line Items]
Distributions paid								$ 1,733	$ 1,569	$ 1,330
PAA
Partners' Capital and Distributions [Line Items]
Number of days after end of quarter within which distributions must be paid to unitholders (in days)								45 days
Series A Preferred Units \| PAA
Partners' Capital and Distributions [Line Items]
Distribution rate reset, basis spread on variable rate (as a percent)					5.85%
Preferred units, distribution rate					9.375%
Preferred units, annualized distributions per unit \| $ / shares					$ 2.46
Preferred Units repurchased and retired during period, shares (in shares) \| shares				12.7
Preferred units, outstanding repurchased rate				0.18
Shares acquired, average cost per share (in dollars per unit) \| $ / shares				$ 26.25
Total purchase price of PAA common units repurchased				$ 333
Series A Preferred Units \| PAA \| Other current liabilities
Partners' Capital and Distributions [Line Items]
Cash distribution paid								$ 36			$ 10
Series A Preferred Units \| PAA \| Cash Distribution
Partners' Capital and Distributions [Line Items]
Preferred unit distribution amount (in dollars per unit) \| $ / shares							$ 0.585	$ 2.46	$ 2.46	$ 2.34
Preferred unit distribution amount				$ 10				$ 154	$ 175	$ 166
Series A Preferred Units \| PAA \| Cash Distribution \| Subsequent Event
Partners' Capital and Distributions [Line Items]
Preferred unit distribution amount		$ 36
Series B Preferred Units \| PAA
Partners' Capital and Distributions [Line Items]
Distribution rate percentage						6.125%
Distribution rate per unit (in dollars per unit) \| $ / shares						$ 61.25
Preferred unit, distribution percentage spread (as a percent)						4.11%						4.11%
Preferred unit, credit percentage spread (as a percent)												0.26161%
Series B Preferred Units \| PAA \| Other current liabilities
Partners' Capital and Distributions [Line Items]
Cash distribution paid								$ 9
Series B Preferred Units \| PAA \| Cash Distribution
Partners' Capital and Distributions [Line Items]
Preferred unit distribution amount (in dollars per unit) \| $ / shares								$ 88.38	$ 98.14	$ 93.43
Preferred unit distribution amount								$ 71	$ 79	$ 75
Series B Preferred Units \| PAA \| Cash Distribution \| Subsequent Event
Partners' Capital and Distributions [Line Items]
Preferred unit distribution amount (in dollars per unit) \| $ / shares	$ 21.02
Preferred unit distribution amount	$ 17
Class A Shares \| Cash Distribution
Partners' Capital and Distributions [Line Items]
Distributions per common unit (in dollars per share) \| $ / shares								$ 1.5200	$ 1.2700	$ 1.0700
Distributions to Class A Shareholders								$ 301	$ 251	$ 209
Class A Shares \| Cash Distribution \| Subsequent Event
Partners' Capital and Distributions [Line Items]
Distributions to Class A Shareholders		83
Common Units \| Cash Distribution \| Subsequent Event
Partners' Capital and Distributions [Line Items]
Distributions per Class A share declared (in dollars per share) \| $ / shares			$ 0.4175
Common Units \| PAA \| Cash Distribution
Partners' Capital and Distributions [Line Items]
Distributions paid								$ 1,070	$ 891	$ 748
Distributions per common unit (in dollars per share) \| $ / shares								$ 1.5200	$ 1.2700	$ 1.0700
Common Units \| PAA \| Cash Distribution \| AAP
Partners' Capital and Distributions [Line Items]
Distributions paid								$ 354	$ 296	$ 256
Common Units \| PAA \| Cash Distribution \| Public
Partners' Capital and Distributions [Line Items]
Distributions paid								$ 716	$ 595	$ 492
Common Units \| PAA \| Cash Distribution \| Subsequent Event
Partners' Capital and Distributions [Line Items]
Distributions to Class A Shareholders		295
Common Units \| PAA \| Cash Distribution \| Subsequent Event \| AAP
Partners' Capital and Distributions [Line Items]
Distributions paid		$ 97

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, as well as the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. We make significant estimates with respect to (i) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (ii) fair value of derivatives, (iii) accruals and contingent liabilities, (iv) property and equipment, depreciation and amortization expense and asset retirement obligations, (v) impairment assessments of property and equipment, investments in unconsolidated entities and intangible assets and (vi) inventory valuations. Although we believe these estimates are reasonable, actual results could differ from these estimates.

Purchases and Related Costs

Purchases and related costs include (i) the weighted average cost of crude oil and NGL sold to customers, (ii) fees incurred for storage and transportation, whether by pipeline, truck or rail and (iii) performance-related bonus costs. These costs are recognized when incurred except in the case of products sold, which are recognized at the time title transfers to our customers. Inventory exchanges under buy/sell transactions are presented net in “Purchases and related costs” in our Consolidated Statements of Operations.

Field Operating Costs and General and Administrative Expenses

Field operating costs consist of various field operating expenses, including payroll, compensation and benefits costs for operations personnel; fuel and power costs (including the impact of gains and losses from derivative related activities); third-party trucking transportation costs for our U.S. crude oil operations; maintenance and integrity management costs; regulatory compliance; environmental remediation; insurance; costs for usage of third-party owned pipeline, rail and storage assets; vehicle leases; and property taxes. General and administrative expenses consist primarily of payroll, compensation and benefits costs; certain information systems and legal costs; office rent; contract and consultant costs; and audit and tax fees.

Foreign Currency Transactions/Translation

Certain of our subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of subsidiaries with a Canadian dollar functional currency are translated at period-end rates of exchange, and revenues and expenses are translated at average exchange rates prevailing for each month. The resulting translation adjustments are made directly to a separate component of other comprehensive income, which is reflected in Partners’ Capital on our Consolidated Balance Sheets.

Certain of our subsidiaries also enter into transactions and have monetary assets and liabilities that are denominated in a currency other than the entities’ respective functional currencies. Gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities are generally included in the Consolidated Statements of Operations. However, gains and losses arising from intercompany foreign currency transactions that are of a long-term investment nature are reported in the same manner as translation adjustments. For the years ended December 31, 2025, 2024 and 2023, the revaluation of foreign currency transactions and monetary assets and liabilities resulted in the recognition of a net loss of $13 million, a net gain of $12 million and a net loss of $3 million, respectively, in our Consolidated Statements of Operations.

Cash and Cash Equivalents

Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal.

In accordance with our policy, unless they may be covered by funds on deposit, outstanding checks are classified as trade accounts payable rather than negative cash. As of December 31, 2025 and 2024, trade accounts payable included $31 million and $27 million, respectively, of outstanding checks that were reclassified from cash and cash equivalents.

Noncontrolling Interests

Noncontrolling interest represents the portion of assets and liabilities in a consolidated subsidiary that is owned by a third party. FASB guidance requires all entities to report noncontrolling interests in subsidiaries as a component of equity in the consolidated financial statements. See Note 12 for additional discussion regarding our noncontrolling interests.

Asset Retirement Obligations

FASB guidance establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including estimates related to (i) the time of the liability recognition, (ii) initial measurement of the liability, (iii) allocation of asset retirement cost to expense, (iv) subsequent measurement of the liability and (v) financial statement disclosures. FASB guidance also requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method.

Some of our assets, primarily our pipelines and terminals assets, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. These assets have been in existence for many years and with regular maintenance will continue to be in service for many years to come. It is not possible to predict when demand for these transportation, storage or other services will cease, and we do not believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations. We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonably estimate the settlement dates.

A small portion of our contractual or regulatory obligations is related to assets that are inactive or that we plan to take out of service and, although the ultimate timing and costs to settle these obligations are not known with certainty, we have recorded a reasonable estimate of these obligations. The following table presents the change in the liability for asset retirement obligations, substantially all of which is reflected in “Other long-term liabilities and deferred credits” on our Consolidated Balance Sheets as of December 31, 2025, 2024 and 2023 (in millions):


	December 31,
	2025		2024		2023
Beginning balance	$	109	$	106	$	103
Liabilities incurred	—		—		1
Liabilities settled	(1)		(2)		(1)
Accretion expense	4		4		4
Revisions in estimated cash flows	—		1		(1)
Ending balance	$	112	$	109	$	106

Fair Value Measurements

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which affects the placement of assets and liabilities within the fair value hierarchy levels. The determination of the fair values includes not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit) but also the impact of our nonperformance risk on our liabilities. The fair value of our commodity, interest rate and foreign currency derivatives includes adjustments for credit risk. Our credit adjustment methodology uses market observable inputs and requires judgment. There were no changes to any of our valuation techniques during the period. See Note 13 for further discussion.

Other Significant Accounting Policies

See the respective footnotes for our accounting policies regarding (i) revenues and accounts receivable, (ii) net income per Class A share, (iii) inventory, linefill and long-term inventory, (iv) property and equipment, (v) acquisitions, (vi) investments in unconsolidated entities, (vii) intangible assets, (viii) derivatives and risk management activities, (ix) leases, (x) income taxes, (xi) equity-indexed compensation and (xii) legal and environmental matters.

Recent Accounting Pronouncements, Disclosure Rules and Other Legislation

Recent Accounting Pronouncements

In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which requires, among other things, disclosure of specified information about certain costs and expenses in the notes to the financial statements. The guidance is effective prospectively for annual periods beginning after December 15, 2026 and interim periods beginning after December 15, 2027 with retrospective application and early adoption permitted. We intend to provide the required disclosures beginning with our annual report for the year ended December 31, 2027.

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires, among other things, disaggregated information about effective tax rate reconciliation and income taxes paid (net of refunds received) on an annual basis. The guidance is effective prospectively for annual periods beginning after December 15, 2024 with retrospective or early adoption permitted. We adopted this guidance beginning with our annual report for the year ended December 31, 2025. See Note 15 for updated income tax disclosures. Other than such disclosure updates, our adoption did not have a material impact on our financial position, results of operations or cash flows.

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which requires disaggregated disclosure of significant segment expenses and other amounts included within the reported measure of segment profit or loss for each reportable segment on an annual and interim basis. The guidance is effective retrospectively for annual periods beginning after December 15, 2023, and interim periods in fiscal years beginning after December 15, 2024 with early adoption permitted. We adopted this guidance beginning with our annual report for the year ended December 31, 2024. See Note 20 for our segment disclosures. Other than disclosures, our adoption did not have a material impact on our financial position, results of operations or cash flows.

In August 2023, the FASB issued ASU 2023-05, Business Combinations—Joint Venture Formations (Subtopic 805-60): Recognition and Initial Measurement, which requires a newly-formed joint venture to apply a new basis of accounting to its contributed net assets, resulting in the joint venture initially measuring its contributed net assets at fair value on the formation date. This guidance is effective prospectively for all joint ventures with a formation date on or after January 1, 2025, with early adoption permitted. We adopted this guidance for joint venture formations on or after January 1, 2025.

SEC Climate Disclosure Rules

In March 2024, the SEC adopted final rules (“climate disclosure rules”) requiring registrants to disclose, among other things, information about material climate-related risks and their impact on a registrant’s strategy, business model and outlook; information about material direct and indirect greenhouse gas emissions (Scope 1 and Scope 2), which are subject to assurance requirements; and the financial statement effects of severe weather events and other natural conditions. In April 2024, the SEC stayed the climate disclosure rules pending resolution of legal challenges. In March 2025, the SEC voted to withdraw its defense of the climate disclosure rules.

International Tax Reform

Recently, several countries, including Canada, have enacted legislation to implement key aspects of the global minimum top-up tax in accordance with the Pillar Two model rules of the OECD tax framework. We continue to evaluate the new legislation, but do not currently expect a material impact on our financial position, results of operations or cash flows.

Revenues and Accounts Receivable - Trade Accounts Receivable and Other Receivables (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
Trade accounts receivable arising from revenues from contracts with customers	$ 3,639	$ 3,922
Other trade accounts receivables and other receivables	7,357	7,339
Impact due to contractual rights of offset with counterparties	(7,398)	(7,582)
Trade accounts receivable and other receivables, net	$ 3,598	$ 3,679

Investments in Unconsolidated Entities - Summarized Financial Information (Details) - USD ($) $ in Millions	3 Months Ended								12 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, 2025	Dec. 31, 2024	Dec. 31, 2023
Investments in Unconsolidated Entities
Current assets	$ 4,704				$ 4,776				$ 4,704	$ 4,776
Current liabilities	4,902				4,924				4,902	4,924
Noncurrent liabilities	12,158				8,516				12,158	8,516
Revenues	10,565	$ 11,578	$ 10,642	$ 11,477	12,035	$ 12,456	$ 12,757	$ 11,639	44,262	48,889	$ 47,336
Operating income	354	$ 483	$ 237	$ 353	(17)	$ 195	$ 330	$ 355	1,428	862	1,249
Equity Method Investment, Nonconsolidated Investee
Investments in Unconsolidated Entities
Current assets	441				475				441	475
Noncurrent assets	6,755				6,996				6,755	6,996
Current liabilities	317				261				317	261
Noncurrent liabilities	$ 13				$ 12				13	12
Revenues									1,926	2,193	1,667
Operating income									1,075	1,373	921
Net income									$ 1,094	$ 1,407	$ 947

- Definition

Amount of asset recognized for present right to economic benefit, classified as current.

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+ Details

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Amount of obligation due after one year or beyond the normal operating cycle, if longer.

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+ Details

- Definition

The net result for the period of deducting operating expenses from operating revenues.

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 - Schedule of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Short-term debt:
Short-term debt	$ 563	$ 407
Long-term debt:
PAA senior notes, net of unamortized discounts and debt issuance costs	9,118	7,141
PAA term loan, net of debt issuance costs of $1, bearing a weighted-average interest rate of 5.0%	1,099
Noncurrent portion of other long-term debt	1,578	70
Total long-term debt	10,696	7,211
Total debt	11,259	7,618
PAA Senior Notes
Long-term debt:
Unamortized discounts and debt issuance costs	(65)	(42)
PAA senior notes, net of unamortized discounts and debt issuance costs	9,118	7,141
Debt instrument face value	9,200	7,200
PAA Senior Notes \| Level 2
Long-term debt:
Debt instrument fair value	$ 9,000	$ 6,700
PAA Senior Notes \| $1,000 million 4.65% senior notes
Short-term debt:
Debt instrument, interest rate (as a percent)	4.65%	4.65%
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 0	$ 1,000
PAA Senior Notes \| 4.50% senior notes due December 2026
Short-term debt:
Debt instrument, interest rate (as a percent)	4.50%
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 750	750
PAA Senior Notes \| 3.55% senior notes due December 2029
Short-term debt:
Debt instrument, interest rate (as a percent)	3.55%
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 1,000	1,000
PAA Senior Notes \| 3.80% senior notes due September 2030
Short-term debt:
Debt instrument, interest rate (as a percent)	3.80%
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 750	750
PAA Senior Notes \| 4.70% senior notes due January 2031
Short-term debt:
Debt instrument, interest rate (as a percent)	4.70%
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 1,000	0
PAA Senior Notes \| 5.70% senior notes due September 2034
Short-term debt:
Debt instrument, interest rate (as a percent)	5.70%
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 650	650
PAA Senior Notes \| 5.95% senior notes due June 2035
Short-term debt:
Debt instrument, interest rate (as a percent)	5.95%
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 1,000	0
PAA Senior Notes \| 5.60% senior notes due January 2036
Short-term debt:
Debt instrument, interest rate (as a percent)	5.60%
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 1,000	0
PAA Senior Notes \| 6.70% senior notes due May 2036
Short-term debt:
Debt instrument, interest rate (as a percent)	6.70%
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 250	250
PAA Senior Notes \| 6.65% senior notes due January 2037
Short-term debt:
Debt instrument, interest rate (as a percent)	6.65%
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 600	600
PAA Senior Notes \| 5.15% senior notes due June 2042
Short-term debt:
Debt instrument, interest rate (as a percent)	5.15%
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 499	499
PAA Senior Notes \| 4.30% senior notes due January 2043
Short-term debt:
Debt instrument, interest rate (as a percent)	4.30%
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 348	348
PAA Senior Notes \| 4.70% senior notes due June 2044
Short-term debt:
Debt instrument, interest rate (as a percent)	4.70%
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 687	687
PAA Senior Notes \| 4.90% senior notes due February 2045
Short-term debt:
Debt instrument, interest rate (as a percent)	4.90%
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 649	649
Term loan
Short-term debt:
Weighted average interest rate, short-term (as a percent)	5.00%
Debt issuance costs	$ 1
Other
Long-term debt:
Noncurrent portion of other long-term debt	63	70
Line of Credit \| PAA Commercial Paper Notes
Short-term debt:
Short-term notes and borrowings	$ 554	$ 393
Weighted average interest rate, short-term (as a percent)	3.90%	4.60%
Long-term debt:
PAA term loan, net of debt issuance costs of $1, bearing a weighted-average interest rate of 5.0%	$ 416
Other
Short-term debt:
Short-term debt	$ 9	$ 14

Major Customers and Concentration of Credit Risk (Details) - Revenues - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
ExxonMobil Corporation
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue (as a percent)	31.00%	31.00%	27.00%
BP p.l.c. and Subsidiaries
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue (as a percent)			10.00%

- 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/2009/role/commonPracticeRef
-Topic 275
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 18
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482861/275-10-50-18

Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 275
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 18
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482861/275-10-50-18

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 275
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 20
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482861/275-10-50-20

Reference 4: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 275
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 18
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482861/275-10-50-18

Reference 5: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 275
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 18
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482861/275-10-50-18

Reference 6: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 275
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 18
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482861/275-10-50-18

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 275
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 18
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482836/275-10-55-18

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 275
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 20
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482861/275-10-50-20

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 954
-SubTopic 310
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478785/954-310-50-2

+ Details

- 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

Segment Information (Tables)

12 Months Ended

Dec. 31, 2025

Segment Reporting [Abstract]

Schedule of Segment Financial Data

The following tables reflect certain financial data from continuing operations for each segment (in millions):


	Crude Oil		NGL		Intersegment Elimination		Total
Year Ended December 31, 2025
Revenues (1):
Product sales	$	42,373	$	145	$	(17)	$	42,501
Services	1,758		6		(3)		1,761
Total revenues	$	44,131	$	151	$	(20)	$	44,262

Significant segment expenses:
Purchases and related costs (1)	$	(40,323)	$	(130)	$	20	$	(40,433)
Field operating costs	(1,127)		(27)		—		(1,154)
Segment general and administrative expenses	(314)		(28)		—		(342)
Total significant segment expenses	$	(41,764)	$	(185)	$	20	$	(41,929)

Equity earnings in unconsolidated entities	$	382	$	—

Other segment items (2):
Depreciation and amortization of unconsolidated entities (3)	84		—
Derivative activities and inventory valuation adjustments (4)	(23)		—
Long-term inventory costing adjustments (5)	45		—
Deficiencies under minimum volume commitments, net (6)	(38)		—
Equity-indexed compensation expense (7)	37		—
Foreign currency revaluation (8)	12		—

Transaction-related expenses (9)	17		—
Segment amounts attributable to noncontrolling interests in consolidated joint ventures (10)	(539)		—
Total other segment items	$	(405)	$	—

Segment Adjusted EBITDA	$	2,344	$	(34)

Investment and acquisition capital expenditures (11) (12)	$	3,321	$	—			$	3,321
Maintenance capital expenditures (12)	$	153	$	3			$	156

As of December 31, 2025

Investments in unconsolidated entities	$	2,846	$	—			$	2,846


	Crude Oil		NGL		Intersegment Elimination		Total
Year Ended December 31, 2024
Revenues (1):
Product sales	$	47,034	$	181	$	(16)	$	47,199
Services	1,686		6		(2)		1,690
Total revenues	$	48,720	$	187	$	(18)	$	48,889

Significant segment expenses:
Purchases and related costs (1)	$	(45,033)	$	(147)	$	18	$	(45,162)
Field operating costs	(1,440)		(31)		—		(1,471)
Segment general and administrative expenses	(298)		(30)		—		(328)
Total significant segment expenses	$	(46,771)	$	(208)	$	18	$	(46,961)

Equity earnings in unconsolidated entities	$	452	$	—

Other segment items (2):
Depreciation and amortization of unconsolidated entities (3)	84		—
Derivative activities and inventory valuation adjustments (4)	5		—
Long-term inventory costing adjustments (5)	1		—
Deficiencies under minimum volume commitments, net (6)	(31)		—
Equity-indexed compensation expense (7)	36		—
Foreign currency revaluation (8)	(22)		—
Line 901 incident (13)	345		—

Segment amounts attributable to noncontrolling interests in consolidated joint ventures (10)	(543)		—
Total other segment items	$	(125)	$	—

Segment Adjusted EBITDA	$	2,276	$	(21)

Investment and acquisition capital expenditures (11) (12)	$	554	$	—			$	554
Maintenance capital expenditures (12)	$	183	$	4			$	187

As of December 31, 2024

Investments in unconsolidated entities	$	2,811	$	—			$	2,811


	Crude Oil		NGL		Intersegment Elimination		Total
Year Ended December 31, 2023
Revenues (1):
Product sales	$	45,587	$	180	$	(22)	$	45,745
Services	1,587		6		(2)		1,591
Total revenues	$	47,174	$	186	$	(24)	$	47,336

Significant segment expenses:
Purchases and related costs (1)	$	(43,805)	$	(156)	$	24	$	(43,937)
Field operating costs	(1,053)		(32)		—		(1,085)
Segment general and administrative expenses	(271)		(28)		—		(299)
Total significant segment expenses	$	(45,129)	$	(216)	$	24	$	(45,321)

Equity earnings in unconsolidated entities	$	369	$	—

Other segment items (2):
Depreciation and amortization of unconsolidated entities (3)	87		—
Derivative activities and inventory valuation adjustments (4)	17		—
Long-term inventory costing adjustments (5)	22		—
Deficiencies under minimum volume commitments, net (6)	12		—
Equity-indexed compensation expense (7)	35		—
Foreign currency revaluation (8)	19		—
Line 901 incident (13)	10		—
Transaction-related expenses (9)	1		—
Segment amounts attributable to noncontrolling interests in consolidated joint ventures (10)	(454)		—
Total other segment items	$	(251)	$	—

Segment Adjusted EBITDA	$	2,163	$	(30)

Investment and acquisition capital expenditures (11) (12)	$	765	$	—			$	765
Maintenance capital expenditures (12)	$	145	$	6			$	151

As of December 31, 2023

Investments in unconsolidated entities	$	2,820	$	—			$	2,820

(2)Represents adjustments utilized by our CODM in the evaluation of segment results.

(3)Includes our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities.

(10)Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River.

(11)Investment capital and acquisition capital expenditures, including investments in unconsolidated entities.

(12)These amounts combined represent total capital expenditures.

Schedule of Reconciliation of Segment Adjusted EBITDA to Net Income Attributable to PAGP

The following table reconciles Segment Adjusted EBITDA to Income from continuing operations, net of tax (in millions):


	Year Ended December 31,
	2025		2024		2023
Segment Adjusted EBITDA	$	2,310	$	2,255	$	2,133
Total other segment items (1)	405		125		251
Unallocated general and administrative expenses (2)	(6)		(6)		(6)
Depreciation and amortization	(953)		(901)		(912)
Gains/(losses) on asset sales, asset impairments and other, net	54		(159)		152

Gain on investments in unconsolidated entities, net	31		15		28
Interest expense, net	(467)		(382)		(386)
Other income, net	21		16		102
Income from continuing operations before tax	1,395		963		1,362
Income tax expense from continuing operations	(92)		(124)		(129)
Income from continuing operations, net of tax	$	1,303	$	839	$	1,233

(1)See footnotes to the segment financial data tables above for a more detailed discussion of Other segment items.

(2)Represents general and administrative expenses incremental to those of PAA, which are not allocated to our reporting segments in determining Segment Adjusted EBITDA.

Schedule of Revenues Attributable to Geographic Areas

We have operations in the United States and Canada. Set forth below are revenues and long-lived assets attributable to these geographic areas (in millions):


	Year Ended December 31,
Revenues (1)	2025		2024		2023
United States	$	39,761	$	43,535	$	41,738
Canada	4,501		5,354		5,598
	$	44,262	$	48,889	$	47,336

(1)Revenues are primarily attributed to each region based on where the services are provided or the product is shipped.

Schedule of Long-lived Assets Attributable to Geographic Areas


	December 31,
Long-Lived Assets (1)	2025		2024
United States	$	21,398	$	17,955
Canada	1,480		1,429
	$	22,878	$	19,384

(1)Excludes long-term derivative assets and long-term deferred tax assets.

Inventory, Linefill and Long-term Inventory - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Inventory Disclosure [Abstract]
Charge related to the write-down of inventory	$ 0	$ 0	$ 0

Organization and Basis of Consolidation and Presentation (Details) shares in Millions, $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025 USD ($) segment shares	Mar. 31, 2026 USD ($)	Mar. 31, 2026 CAD ($)	Dec. 31, 2024 USD ($)
Organization and basis of presentation
Operating segments number \| segment	2
Deferred tax asset	$ 1,136			$ 1,220
Forecast \| Discontinued Operations, Held-for-Sale \| NGL Business
Organization and basis of presentation
Cash consideration		$ 3,750	$ 5,150
Derivative Liability, Statement of Financial Position [Extensible Enumeration]		Current liabilities	Current liabilities
Derivative liability		$ 65
Consolidated Entity Excluding VIE
Organization and basis of presentation
Deferred tax asset	$ 1,136			$ 1,220
AAP
Organization and basis of presentation
Consolidated subsidiary, ownership interest (as a percent)	85.00%
Consolidated subsidiary, ownership interest (in units) \| shares	197.9
GP LLC
Organization and basis of presentation
Consolidated subsidiary, ownership interest (as a percent)	100.00%
PAA \| AAP
Organization and basis of presentation
Consolidated subsidiary, ownership interest (as a percent)	31.00%
Consolidated subsidiary, ownership interest (in units) \| shares	233.0

Income Taxes - Components (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes - Components (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest [Abstract]
United States	$ 1,350	$ 832	$ 1,130
Canada	45	131	232
INCOME FROM CONTINUING OPERATIONS BEFORE TAX	1,395	963	1,362
Current income tax expense/(benefit):
State income tax	2	2	2
Canadian federal and provincial income and withholding taxes	(1)	80	68
Total current income tax expense	1	82	70
Deferred income tax expense/(benefit):
U.S. federal income tax	71	31	55
State income tax	6	6	13
Canadian federal and provincial income and withholding taxes	14	5	(9)
Total deferred income tax expense	91	42	59
Total income tax expense	$ 92	$ 124	$ 129

Summary of Significant Accounting Policies - Various Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Accounting Policies [Abstract]
Gain (loss) on revaluation of foreign currency transactions and monetary assets and liabilities	$ (13)	$ 12	$ (3)
Outstanding checks included in accounts payable that were reclassified from cash and cash equivalents	$ 31	$ 27

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2025
Audit Information [Abstract]
Auditor Firm ID	238
Auditor Name	PricewaterhouseCoopers LLP
Auditor Location	Houston, Texas

Segment Information - Segment Financial Data (Details) - USD ($) $ in Millions	3 Months Ended								12 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, 2025	Dec. 31, 2024	Dec. 31, 2023
Revenues:
Total revenues	$ 10,565	$ 11,578	$ 10,642	$ 11,477	$ 12,035	$ 12,456	$ 12,757	$ 11,639	$ 44,262	$ 48,889	$ 47,336
Significant segment expenses:
Purchases and related costs									(40,433)	(45,162)	(43,937)
Field operating costs									(1,154)	(1,471)	(1,085)
Segment general and administrative expenses									(342)	(328)	(299)
Total significant segment expenses									(41,929)	(46,961)	(45,321)
Equity earnings in unconsolidated entities									382	452	369
Other segment items:
Total other segment items									(405)	(125)	(251)
Segment Adjusted EBITDA									2,310	2,255	2,133
Investment and acquisition capital expenditures									3,321	554	765
Maintenance capital expenditures									156	187	151
Investments in unconsolidated entities	2,846				2,811				2,846	2,811	2,820
Product sales revenues
Revenues:
Total revenues									42,501	47,199	45,745
Services
Revenues:
Total revenues									1,761	1,690	1,591
NGL
Significant segment expenses:
Equity earnings in unconsolidated entities											0
Operating Segments
Revenues:
Total revenues									44,282	48,907	47,360
Operating Segments \| Crude Oil
Revenues:
Total revenues									44,131	48,720	47,174
Significant segment expenses:
Purchases and related costs									(40,323)	(45,033)	(43,805)
Field operating costs									(1,127)	(1,440)	(1,053)
Segment general and administrative expenses									(314)	(298)	(271)
Total significant segment expenses									(41,764)	(46,771)	(45,129)
Equity earnings in unconsolidated entities									382	452	369
Other segment items:
Depreciation and amortization of unconsolidated entities									84	84	87
Derivative activities and inventory valuation adjustments									(23)	5	17
Long-term inventory costing adjustments									45	1	22
Deficiencies under minimum volume commitments, net									(38)	(31)	12
Equity-indexed compensation expense									37	36	35
Foreign currency revaluation									12	(22)	19
Transaction-related expenses									17		1
Segment amounts attributable to noncontrolling interests in consolidated joint ventures									(539)	(543)	(454)
Total other segment items									(405)	(125)	(251)
Segment Adjusted EBITDA									2,344	2,276	2,163
Investment and acquisition capital expenditures									3,321	554	765
Maintenance capital expenditures									153	183	145
Investments in unconsolidated entities	$ 2,846				2,811				2,846	2,811	2,820
Operating Segments \| Crude Oil \| Line 901 Incident
Other segment items:
Line 901 incident										345	10
Operating Segments \| Crude Oil \| Product sales revenues
Revenues:
Total revenues									42,373	47,034	45,587
Operating Segments \| Crude Oil \| Services
Revenues:
Total revenues									1,758	1,686	1,587
Operating Segments \| NGL
Revenues:
Total revenues									151	187	186
Significant segment expenses:
Purchases and related costs									(130)	(147)	(156)
Field operating costs									(27)	(31)	(32)
Segment general and administrative expenses									(28)	(30)	(28)
Total significant segment expenses									(185)	(208)	(216)
Equity earnings in unconsolidated entities									0	0
Other segment items:
Depreciation and amortization of unconsolidated entities									0	0	0
Derivative activities and inventory valuation adjustments									0	0	0
Long-term inventory costing adjustments									0	0	0
Deficiencies under minimum volume commitments, net									0	0	0
Equity-indexed compensation expense									0	0	0
Foreign currency revaluation									0	0	0
Transaction-related expenses									0		0
Segment amounts attributable to noncontrolling interests in consolidated joint ventures									0	0	0
Total other segment items									0	0	0
Segment Adjusted EBITDA									(34)	(21)	(30)
Investment and acquisition capital expenditures									0	0	0
Maintenance capital expenditures									3	4	6
Investments in unconsolidated entities					$ 0					0	0
Operating Segments \| NGL \| Line 901 Incident
Other segment items:
Line 901 incident										0	0
Operating Segments \| NGL \| Product sales revenues
Revenues:
Total revenues									145	181	180
Operating Segments \| NGL \| Services
Revenues:
Total revenues									6	6	6
Intersegment Elimination
Revenues:
Total revenues									(20)	(18)	(24)
Significant segment expenses:
Purchases and related costs									20	18	24
Field operating costs									0	0	0
Segment general and administrative expenses									0	0	0
Total significant segment expenses									20	18	24
Intersegment Elimination \| Product sales revenues
Revenues:
Total revenues									(17)	(16)	(22)
Intersegment Elimination \| Services
Revenues:
Total revenues									$ (3)	$ (2)	$ (2)

Discontinued Operations - Income (Loss) from Discontinued Operations (Details) - USD ($) $ in Millions	3 Months Ended								12 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, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income from discontinued operations, net of tax	$ 102	$ 76	$ 70	$ 136	$ 74	$ 114	$ 32	$ 10	$ 383	$ 231	$ 192
Discontinued Operations, Held-for-Sale \| NGL Business
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues									1,317	1,184	1,376
Purchases and related costs									411	398	594
Field operating costs									259	297	340
General and administrative expenses									47	53	51
Depreciation and amortization									57	125	139
Losses on asset sales, net									21	1	0
Total costs and expenses									795	874	1,124
Other income, net									0	1	0
Income from discontinued operations before tax									522	311	252
Current income tax expense									(99)	(113)	(75)
Deferred income tax (expense)/benefit									(40)	33	15
Income from discontinued operations, net of tax									383	231	192
Discontinued Operations, Held-for-Sale \| NGL Business \| Product sales
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues									1,186	1,055	1,229
Discontinued Operations, Held-for-Sale \| NGL Business \| Services
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues									$ 131	$ 129	$ 147

Property and Equipment - Components of Property and Equipment, Net (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Property, Plant and Equipment [Line Items]
Property and equipment, gross	$ 22,536	$ 18,528
Accumulated depreciation	(5,676)	(5,082)
Property and equipment, net	16,860	13,446
Pipeline systems \| Crude Oil
Property, Plant and Equipment [Line Items]
Property and equipment, gross	$ 18,428	14,612
Pipeline systems \| Minimum \| Crude Oil
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	10 years
Pipeline systems \| Maximum \| Crude Oil
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	50 years
Crude oil storage and terminal facilities \| Crude Oil
Property, Plant and Equipment [Line Items]
Property and equipment, gross	$ 2,808	2,679
Crude oil storage and terminal facilities \| Minimum \| Crude Oil
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	10 years
Crude oil storage and terminal facilities \| Maximum \| Crude Oil
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	50 years
NGL storage, terminal, fractionation and processing facilities \| NGL
Property, Plant and Equipment [Line Items]
Property and equipment, gross	$ 365	364
NGL storage, terminal, fractionation and processing facilities \| Minimum \| NGL
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	10 years
NGL storage, terminal, fractionation and processing facilities \| Maximum \| NGL
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	50 years
Office property and equipment and rolling stock
Property, Plant and Equipment [Line Items]
Property and equipment, gross	$ 373	430
Office property and equipment and rolling stock \| Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	2 years
Office property and equipment and rolling stock \| Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	50 years
Construction in progress
Property, Plant and Equipment [Line Items]
Property and equipment, gross	$ 238	148
Land and other
Property, Plant and Equipment [Line Items]
Property and equipment, gross	$ 324	$ 295

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Class A Shares
Shares outstanding (in shares)	197,904,124	197,465,699	196,416,760	194,407,642

Net Income Per Class A Share

12 Months Ended

Dec. 31, 2025

Earnings Per Share [Abstract]

Net Income Per Class A Share

Basic net income per Class A share is determined by dividing net income attributable to PAGP from continuing operations and net income attributable to PAGP from discontinued operations by the weighted average number of Class A shares outstanding during the period. Our Class B and Class C shares do not share in the earnings of the Partnership; accordingly, basic and diluted net income per Class B and Class C share has not been presented.

Diluted net income per Class A share is determined by dividing net income attributable to PAGP from continuing operations and net income attributable to PAGP from discontinued operations by the diluted weighted average number of Class A shares outstanding during the period. For purposes of calculating diluted net income per Class A share, both the net income attributable to PAGP and the diluted weighted average number of Class A shares outstanding consider the impact of possible future exchanges of AAP units and the associated Class B shares into our Class A shares. In addition, the calculation of the diluted weighted average number of Class A shares outstanding considers the effect of potentially dilutive awards under the Plains GP Holdings, L.P. Long-Term Incentive Plan (the “PAGP LTIP”).

Exchanges of potentially dilutive AAP units are assumed to have occurred at the beginning of the period and the incremental income attributable to PAGP resulting from the assumed exchanges is representative of the incremental income that would have been attributable to PAGP if the assumed exchanges occurred on that date. See Note 12 for information regarding exchanges of AAP units. PAGP LTIP awards that are deemed to be dilutive are reduced by a hypothetical share repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 18 for information regarding PAGP LTIP awards.

On a weighted-average basis, for the years ended December 31, 2025, 2024 and 2023, the possible exchange of 35 million, 35 million and 44 million AAP units, respectively, was dilutive to net income per Class A share from discontinued operations. The possible exchange did not result in dilution for net income per Class A share from continuing operations for any of the years presented. Accordingly, the effect of the possible exchange of AAP units is included in the computation of diluted net income per Class A share for discontinued operations for these years and excluded from the calculation for all others. For each of the years ended December 31, 2025, 2024 and 2023, our PAGP LTIP awards were also dilutive and are included in the calculation of diluted weighted average Class A shares outstanding, as applicable.

The following table sets forth the computation of basic and diluted net income per Class A share (in millions, except per share data):


	Year Ended December 31,
	2025		2024		2023
Basic Net Income per Class A Share
Net income attributable to PAGP from continuing operations	$	152	$	39	$	144

Net income attributable to PAGP from discontinued operations	$	108	$	64	$	54

Basic weighted average Class A shares outstanding	198		197		195

Basic Net Income per Class A Share:
Continuing operations	$	0.77	$	0.19	$	0.74
Discontinued operations	0.54		0.33		0.27
Basic net income per Class A share	$	1.31	$	0.52	$	1.01

Diluted Net Income per Class A Share
Net income attributable to PAGP from continuing operations	$	152	$	39	$	144



Net income attributable to PAGP from discontinued operations	$	108	$	64	$	54
Incremental net income attributable to PAGP resulting from assumed exchange of AAP Management Units	15		9		9
Net income attributable to PAGP from discontinued operations including incremental net income from assumed exchange of AAP Management Units	$	123	$	73	$	63

Basic weighted average Class A shares outstanding	198		197		195
Dilutive shares resulting from assumed exchange of AAP Management Units	35		35		44
Diluted weighted average Class A shares outstanding	233		232		239

Diluted Net Income per Class A Share:
Continuing operations	$	0.77	$	0.19	$	0.74
Discontinued operations	0.53		0.32		0.26
Diluted net income per Class A share	$	1.30	$	0.51	$	1.00

Derivatives and Risk Management Activities - Preferred Distribution Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Derivatives and Risk Management Activities
Gain/(loss) recognized	$ 0	$ 0	$ 58
Preferred Distribution Rate Reset Option
Derivatives and Risk Management Activities
Derivative liability			131
Preferred Distribution Rate Reset Option \| Not Designated as Hedging Instrument \| Other Income/(Expense), Net
Derivatives and Risk Management Activities
Gain/(loss) recognized			$ 58

- 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

Reference 1: http://www.xbrl.org/2009/role/commonPracticeRef
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Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
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+ Details

Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 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, 2025	Dec. 31, 2024	Dec. 31, 2023
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Revenues	$ 10,565	$ 11,578	$ 10,642	$ 11,477	$ 12,035	$ 12,456	$ 12,757	$ 11,639	$ 44,262	$ 48,889	$ 47,336
Gross margin	447	567	321	440	67	282	411	437	1,776	1,196
Operating income	354	483	237	353	(17)	195	330	355	1,428	862	1,249
Income from continuing operations, net of tax	306	428	213	356	42	187	284	326	1,303	839	1,233
Income from discontinued operations, net of tax	102	76	70	136	74	114	32	10	383	231	192
Net income	408	504	283	492	116	301	316	336	1,686	1,070	1,425
Net income attributable to PAGP	$ 62	$ 83	$ 30	$ 84	$ (11)	$ 33	$ 39	$ 42	$ 260	$ 103	$ 198
Class A Shares
Earnings Per Unit [Abstract]
Continuing operations (in usd per share)	$ 0.17	$ 0.31	$ 0.05	$ 0.23	$ (0.16)	$ 0.01	$ 0.15	$ 0.20	$ 0.77	$ 0.19	$ 0.74
Discontinued operations (in usd per share)	0.14	0.11	0.10	0.19	0.11	0.16	0.05	0.01	0.54	0.33	0.27
Basic net income per Class A share (in usd per share)	0.31	0.42	0.15	0.42	(0.05)	0.17	0.20	0.21	1.31	0.52	1.01
Continuing operations (in usd per share)	0.17	0.31	0.05	0.23	(0.16)	0.01	0.15	0.20	0.77	0.19	0.74
Discontinued operations (in usd per share)	0.14	0.10	0.10	0.19	0.11	0.16	0.04	0.01	0.53	0.32	0.26
Diluted net income per Class A share (in usd per share)	$ 0.31	$ 0.41	$ 0.15	$ 0.42	$ (0.05)	$ 0.17	$ 0.19	$ 0.21	$ 1.30	$ 0.51	$ 1.00

Acquisitions, Divestitures and Other Transactions - Schedule of Amortization Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Business Combination [Line Items]
2026	$ 301
2027	261
2028	215
2029	192
2030	165
EPIC Crude Oil Pipeline \| Customer relationships
Business Combination [Line Items]
Amortization	15
2026	67
2027	53
2028	34
2029	29
2030	21
Ironwood Midstream Energy Partners II, LLC \| Customer relationships
Business Combination [Line Items]
Amortization	4
2026	5
2027	4
2028	3
2029	3
2030	2
OMOG JV LLC and Southern Delaware Gathering Assets \| Customer relationships
Business Combination [Line Items]
Amortization	10	$ 8	$ 4
2026	4
2027	3
2028	$ 2

Acquisitions, Divestitures and Other Transactions - Divestitures Narrative (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Feb. 28, 2023	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Divestitures
Gains/(losses) on asset sales, asset impairments and other, net		$ 54	$ (159)	$ 152
Crude Oil
Divestitures
Proceeds from sale of productive assets and agreements		81
Gain from sale of assets		$ 44
Keyera Fort Saskatchewan Facility
Divestitures
Non-operated/undivided joint interest rate	21.00%
Proceeds from divestiture of interest in joint venture	$ 270
Gains/(losses) on asset sales, asset impairments and other, net	$ 140
Keyera Fort Saskatchewan Facility \| Other current assets
Divestitures
Assets held-for-sale					$ 130

Discontinued Operations

12 Months Ended

Dec. 31, 2025

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

The operations of the Canadian NGL Business meet the criteria for classification as held for sale and for discontinued operations reporting. The Canadian NGL Business disposal group is recorded at its historical carrying value, as the fair value of the disposal group, less estimated costs to sell, is greater than the carrying value of the Canadian NGL Business disposal group. Depreciation and amortization on the long-lived assets of the Canadian NGL Business disposal group ceased upon meeting the criteria to be classified as assets held for sale. See Note 1 for information regarding the pending sale of the Canadian NGL Business.

The following table summarizes the carrying amounts of major classes of assets and liabilities of discontinued operations (in millions):


	December 31, 2025		December 31, 2024
Assets:
Current assets:

Trade accounts receivable and other receivables, net	$	285	$	222
Inventory	176		178
Other current assets	18		15
Total current assets of discontinued operations	$	479	$	415

Long-term assets:
Property and equipment, net (1)	$	2,191	$	1,978

Linefill	70		64
Long-term operating lease right-of-use assets, net	138		143
Long-term inventory	38		38
Other long-term assets, net	120		126
Total long-term assets of discontinued operations	$	2,557	$	2,349

Liabilities:
Current liabilities:
Trade accounts payable	$	295	$	234

Other current liabilities	87		116
Total current liabilities of discontinued operations	$	382	$	350

Long-term liabilities:

Long-term operating lease liabilities	$	96	$	121
Other long-term liabilities and deferred credits	510		455
Total long-term liabilities of discontinued operations	$	606	$	576

(1)Amounts are net of accumulated depreciation of $876 million and $794 million as of December 31, 2025 and 2024, respectively.

The following table provides a reconciliation of the line items comprising income from discontinued operations before tax to income from discontinued operations, net of tax (in millions):


	Year Ended December 31,
	2025		2024		2023
Revenues:
Product sales	$	1,186	$	1,055	$	1,229
Services	131		129		147
Total revenues	1,317		1,184		1,376
Cost and Expenses:
Purchases and related costs	411		398		594
Field operating costs	259		297		340
General and administrative expenses	47		53		51
Depreciation and amortization	57		125		139
Losses on asset sales, net	21		1		—
Total costs and expenses	795		874		1,124
Other income, net	—		1		—
Income from discontinued operations before tax	522		311		252
Current income tax expense	(99)		(113)		(75)
Deferred income tax (expense)/benefit	(40)		33		15
Income from discontinued operations, net of tax	$	383	$	231	$	192

Equity-Indexed Compensation Plans - Awards Authorized Under our LTIPs (Details) shares in Millions	Dec. 31, 2025 shares
Equity-Indexed Compensation Plans
LTIP awards authorized (in shares)	47.3
LTIP awards available (in shares)	16.4
Plains GP Holdings, L.P. Long-Term Incentive Plan
Equity-Indexed Compensation Plans
LTIP awards authorized (in shares)	3.8
Plains All American 2021 Long-Term Incentive Plan
Equity-Indexed Compensation Plans
LTIP awards authorized (in shares)	28.8
Plains All American PNG Successor Long-Term Incentive Plan
Equity-Indexed Compensation Plans
LTIP awards authorized (in shares)	1.3
Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan
Equity-Indexed Compensation Plans
LTIP awards authorized (in shares)	13.4

- 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 718
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-Name Accounting Standards Codification
-Section 50
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-URI https://asc.fasb.org/1943274/2147480429/718-10-50-2

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+ Details

Partners' Capital and Distributions - Consolidated Subsidiaries (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Nov. 30, 2020
Common Equity Repurchase Program
Subsidiary, Sale of Stock [Line Items]
Common equity repurchase program, authorized amount				$ 500
Common Equity Repurchase Program \| PAA
Subsidiary, Sale of Stock [Line Items]
Total purchase price of PAA common units repurchased	$ 8	$ 0	$ 0
Common equity repurchase program, remaining amount	$ 190
PAA \| Common Units and Series A Preferred Units
Subsidiary, Sale of Stock [Line Items]
Noncontrolling interest, ownership (as a percent)	70.00%
PAA \| Series B Preferred Units
Subsidiary, Sale of Stock [Line Items]
Noncontrolling interest, ownership (as a percent)	100.00%
AAP
Subsidiary, Sale of Stock [Line Items]
Noncontrolling interest, ownership (as a percent)	15.00%
Plains Oryx Permian Basin LLC
Subsidiary, Sale of Stock [Line Items]
Noncontrolling interest, ownership (as a percent)	35.00%
Cactus II Pipeline LLC
Subsidiary, Sale of Stock [Line Items]
Noncontrolling interest, ownership (as a percent)	30.00%
Red River
Subsidiary, Sale of Stock [Line Items]
Noncontrolling interest, ownership (as a percent)	33.00%

Partners' Capital and Distributions

12 Months Ended

Dec. 31, 2025

Partners' Capital Notes [Abstract]

Partners' Capital and Distributions

Partners’ Capital and Distributions

Our Shares

Our Class A shares, Class B shares and Class C shares represent limited partner interests in us. The holders of our Class A and Class B shares are entitled to exercise the rights or privileges available to limited partners under our partnership agreement, but only holders of Class A shares are entitled to participate in our distributions.

Our Class C shares are non-economic and provide PAA, as the sole holder of such Class C shares, the right to vote, pro rata with the holders of our Class A and Class B shares, in the election of eligible PAGP GP directors. Pursuant to the Omnibus Agreement entered into on November 15, 2016, the number of Class C shares that PAA owns will at all times equal the number of outstanding PAA common units, excluding common units held by AAP, and Series A preferred units. Thus, the Class C shares function as a “pass-through” voting mechanism through which PAA votes at the direction of and as proxy for the PAA common unitholders (other than AAP) and Series A preferred unitholders in such director elections.

Exchange and Redemption Rights

Holders of AAP units and their permitted transferees each have the right to exchange all or a portion of their AAP units for Class A shares at an exchange ratio of one Class A share for each AAP unit exchanged (referred to herein as the “Exchange Right”). This Exchange Right may be exercised only if, simultaneously therewith, an equal number of our Class B shares and general partner units (if any) are transferred by the exercising party to us. See Note 15 for information regarding the recognition of deferred tax assets associated the transfer of ownership resulting from Exchange Right exercises.

Additionally, subject to certain limitations, a holder of AAP units (other than us) has the right (a “Redemption Right”) to cause AAP to redeem any or all of such holder’s AAP units in exchange for the distribution of an equivalent number of PAA common units held by AAP (“AAP Unit Redemption”). In connection with any AAP Unit Redemption, the redeeming holder will transfer the AAP units to AAP and a corresponding number of our Class B shares and general partner units (if any), in each case, to us. The AAP units transferred to AAP will be canceled, the Class B shares transferred to us will be canceled and any general partner units transferred to us will remain outstanding and increase our ownership percentage in our general partner. Additionally, we will issue a corresponding number of Class C shares to PAA.

Shares Outstanding

The following table presents the activity for our Class A shares, Class B shares and Class C shares:


	Class A Shares	Class B Shares	Class C Shares







Outstanding at December 31, 2022	194,407,642	46,205,947	528,442,538

Conversion of AAP Management Units	—	388,839	—
Exchange Right exercises	1,869,768	(1,869,768)	—
Redemption Right exercises	—	(8,487,850)	8,487,850

Other	139,350	—	2,514,901
Outstanding at December 31, 2023	196,416,760	36,237,168	539,445,289


Exchange Right exercises	846,937	(846,937)	—


Other	202,002	—	2,559,549
Outstanding at December 31, 2024	197,465,699	35,390,231	542,004,838
Exchange Right exercises	293,925	(293,925)	—
Repurchase and cancellation of common units by a subsidiary under the Common Equity Repurchase Program	—	—	(476,695)
Repurchase of Series A preferred units by a subsidiary	—	—	(12,678,560)
Other	144,500		2,082,592
Outstanding at December 31, 2025	197,904,124	35,096,306	530,932,175

Distributions to Our Shareholders

We distribute 100% of our available cash within 55 days following the end of each quarter to Class A shareholders of record. Available cash is generally defined as all cash on hand at the date of determination of available cash for the distribution in respect to such quarter (including expected distributions from AAP in respect of such quarter), less reserves established by our general partner for future requirements.

The following table details distributions paid to our Class A shareholders during the years presented (in millions, except per share data):


Year	Distributions to Class A Shareholders		Distributions per Class A Share
2025	$	301	$	1.5200
2024	$	251	$	1.2700
2023	$	209	$	1.0700

On January 5, 2026, we declared a cash distribution of $0.4175 per outstanding Class A share. This distribution of $83 million was paid on February 13, 2026 to shareholders of record at the close of business on January 30, 2026, for the period October 1, 2025 through December 31, 2025.

Other Comprehensive Income/(Loss)

Other comprehensive income/(loss) attributable to our Class A shareholders is comprised solely of their proportionate share of PAA’s other comprehensive income/(loss) based on our indirect ownership interest in PAA during the period.

Consolidated Subsidiaries

Noncontrolling Interests in Subsidiaries

As of December 31, 2025, noncontrolling interests in our subsidiaries consisted of (i) limited partner interests in PAA including a 70% interest in PAA’s common units and PAA’s Series A preferred units combined and 100% of PAA’s Series B preferred units, (ii) an approximate 15% limited partner interest in AAP, (iii) a 35% interest in the Permian JV, (iv) a 30% interest in Cactus II and (v) a 33% interest in Red River Pipeline Company LLC (“Red River”). The transactions resulting in the recognition of noncontrolling interests in the Permian JV and Cactus II are described below.

Common Equity Repurchase Program

In November 2020, the board of directors of our general partner approved a $500 million common equity repurchase program (the “Program”) to be utilized as an additional method of returning capital to investors. The Program authorizes the repurchase from time to time of up to $500 million of PAA common units and/or our Class A shares via open market purchases or negotiated transactions conducted in accordance with applicable regulatory requirements. No time limit has been set for completion of the Program, and the Program may be suspended or discontinued at any time. The Program does not obligate PAA or us to acquire a particular number of PAA common units or Class A shares. Any PAA common units or Class A shares that are repurchased will be canceled. Class C shares held by PAA associated with any publicly held common units that are repurchased will also be canceled.

During the year ended December 31, 2025, PAA repurchased common units under the Program through open market purchases for a total purchase price of $8 million, including commissions and fees. The repurchased common units were canceled immediately upon acquisition, as were the Class C shares held by PAA associated with the repurchased common units. There were no repurchases under the Program during the years ended December 31, 2024 or 2023. At December 31, 2025, the remaining available capacity under the Program was $190 million.

PAA’s capital attributable to AAP was adjusted, in accordance with ASC 810, to reflect the accretion of its interest in PAA as a result of the repurchase of common units from public unitholders. Such adjustment is recognized by PAGP in proportion to its ownership interest in AAP, which results in a net increase in partners’ capital attributable to PAGP. See Note 15 for additional information regarding the associated impact to the deferred tax asset.

Subsidiary Distributions

PAA Series A Preferred Unit Distributions. After the fifth anniversary of the January 28, 2016 issuance date of PAA’s Series A preferred units, the holders of PAA’s Series A preferred units, acting by majority vote, had the option to make a one-time election to reset the Series A preferred unit distribution rate to equal the then applicable rate of ten-year U.S. Treasury Securities plus 5.85% (the “Preferred Distribution Rate Reset Option”). The Preferred Distribution Rate Reset Option was accounted for as an embedded derivative. See Note 13 for additional information. In January 2023, the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option. Effective January 31, 2023, the new Series A preferred unit distribution rate is equal to 9.375% per annum of the original Issue Price (approximately $2.46 per unit annualized). The quarterly distribution paid in May 2023 reflected a pro-rated amount of approximately $0.585 per unit.

On January 31, 2025, PAA repurchased approximately 12.7 million units, or 18%, of its outstanding Series A preferred units from EnCap Flatrock Midstream at the issue price of $26.25 per unit for a purchase price of approximately $333 million, plus accrued and unpaid distributions through January 30, 2025 of approximately $10 million. EnCap Flatrock Midstream is affiliated with EnCap Investments, L.P., an entity that is associated with a member of our board of directors. The repurchase also resulted in a reduction to the related Preferred Distribution Rate Reset Option liability.

The following table details distributions paid to PAA’s Series A preferred unitholders during the years presented (in millions, except unit data):


	Series A Preferred Unitholders


Year	Cash Distribution		Distribution per Unit
2025 (1)	$	154		$	2.46
2024	$	175		$	2.46
2023	$	166		$	2.34

(1)Includes distribution of approximately $10 million associated with PAA’s repurchase of Series A preferred units in January 2025.

On February 13, 2026, PAA paid a cash distribution of $36 million to its Series A preferred unitholders outstanding as of January 30, 2026. At December 31, 2025, such amount was accrued as distributions payable in “Other current liabilities” on our Consolidated Balance Sheet.

PAA Series B Preferred Unit Distributions. The initial distribution rate for the Series B preferred units from and including October 10, 2017 to, but not including, November 15, 2022 was 6.125% per year of the liquidation preference per unit (equal to $61.25 per unit per year). From November 15, 2022 through August 14, 2023, distributions on the Series B preferred units accumulated for each distribution period at a percentage of the liquidation preference equal to the applicable three-month LIBOR plus a spread of 4.11% per annum. Beginning August 15, 2023, distributions on the Series B preferred units accumulate based on the applicable three-month SOFR, plus a credit spread adjustment of 0.26161%, plus 4.11% per annum.

The following table details distributions paid to PAA’s Series B preferred unitholders during the years presented (in millions, except unit data):


	Series B Preferred Unitholders


Year	Cash Distribution		Distribution per Unit
2025	$	71	$	88.38
2024	$	79	$	98.14
2023	$	75	$	93.43

On February 17, 2026, PAA paid a cash distribution of $17 million ($21.02 per unit) to its Series B preferred unitholders. At December 31, 2025, approximately $9 million of accrued distributions payable to PAA’s Series B preferred unitholders was included in “Other current liabilities” on our Consolidated Balance Sheet.

PAA Common Unit Distributions. After making distributions to its outstanding preferred units, PAA distributes the remainder of its available cash within 45 days following the end of each quarter to common unitholders of record, including AAP. Available cash is generally defined as all of PAA’s cash and cash equivalents on hand at the end of each quarter, less reserves established in the discretion of its general partner for future requirements. PAA’s available cash also includes cash on hand resulting from borrowings made after the end of the quarter.

The following table details distributions paid by PAA to its common unitholders during the years presented (in millions, except per unit data):


	Distributions Paid						Distributions per Common Unit
Year	Public		AAP		Total
2025	$	716	$	354	$	1,070	$	1.5200
2024	$	595	$	296	$	891	$	1.2700
2023	$	492	$	256	$	748	$	1.0700

On January 5, 2026, PAA declared a cash distribution of $0.4175 per unit on its outstanding common units. The total distribution of $295 million was paid on February 13, 2026 to unitholders of record at the close of business on January 30, 2026, for the period from October 1, 2025 through December 31, 2025. Of this amount, approximately $97 million was paid to AAP.

AAP Distributions. AAP distributes all of the cash received from PAA distributions on a quarterly basis, less reserves established in the discretion of its general partner for future requirements. Generally, distributions are paid to its partners in proportion to their percentage interest in AAP. The following table details the distributions to AAP’s partners paid during the years presented from distributions received from PAA (in millions):


	Distributions to AAP’s Partners
Year	Noncontrolling Interests		PAGP		Total Cash Distributions

2025	$	53	$	301	$	354
2024	$	45	$	251	$	296
2023	$	47	$	209	$	256

On February 13, 2026, AAP distributed $97 million to its partners from distributions received from PAA. Of this amount, $14 million was distributed to noncontrolling interests and $83 million was distributed to us.

Consolidated Joint Venture Distributions. Distributions from Cactus II and Red River are paid in proportion to each owner’s interest in the entity. Cash available for distribution is cash on hand less the amount of cash required to fund normal operations and capital projects. The following table details distributions paid to noncontrolling interests in consolidated joint venture entities during the years presented (in millions):


	2025		2024		2023
Permian JV	$	360	$	322	$	249
Cactus II	72		77		63
Red River	15		26		21
	$	447	$	425	$	333

Revenues and Accounts Receivable - Counterparty Deficiencies (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Contract With Customer, Asset And Liability [Line Items]
Counterparty deficiencies, billed and collected	$ 87	$ 87	$ 101
Minimum Volume Commitments
Contract With Customer, Asset And Liability [Line Items]
Counterparty deficiencies, billed and collected	$ 47	$ 83

Income Taxes - Schedule of Cash Flow, Supplemental Disclosures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Tax Paid, by Individual Jurisdiction [Line Items]
Total state income tax paid	$ 1	$ 2	$ 2
Total cash tax paid	98	269	69
Texas
Income Tax Paid, by Individual Jurisdiction [Line Items]
Total state income tax paid	1	2	2
Canada
Income Tax Paid, by Individual Jurisdiction [Line Items]
Canadian federal and provincial income and withholding taxes	$ 97	$ 267	$ 67

Revenues and Accounts Receivable (Tables)

12 Months Ended

Dec. 31, 2025

Revenue from Contract with Customer [Abstract]

Schedule of Disaggregation of Revenue

The following tables present our revenues from contracts with customers disaggregated by segment and type of activity (in millions):


	Year Ended December 31,
	2025		2024		2023
Crude Oil segment revenues from contracts with customers
Sales	$	42,408	$	47,036	$	45,621
Transportation	1,330		1,231		1,144
Terminalling, Storage and Other	349		384		381
Total Crude Oil segment revenues from contracts with customers	$	44,087	$	48,651	$	47,146


	Year Ended December 31,
	2025		2024		2023
NGL segment revenues from contracts with customers
Sales	$	144	$	180	$	179

Terminalling, Storage and Other	6		7		7

Total NGL segment revenues from contracts with customers	$	150	$	187	$	186

The following tables present the reconciliation of our revenues from contracts with customers (as described above for each segment) to total revenues of reportable segments and total revenues as disclosed in our Consolidated Statements of Operations (in millions):


Year Ended December 31, 2025	Crude Oil		NGL		Total
Revenues from contracts with customers	$	44,087	$	150	$	44,237
Other revenues	44		1		45
Total revenues of reportable segments	$	44,131	$	151	$	44,282
Intersegment revenues elimination					(20)
Total revenues					$	44,262


Year Ended December 31, 2024	Crude Oil		NGL		Total
Revenues from contracts with customers	$	48,651	$	187	$	48,838
Other revenues	69		—		69
Total revenues of reportable segments	$	48,720	$	187	$	48,907
Intersegment revenues elimination					(18)
Total revenues					$	48,889


Year Ended December 31, 2023	Crude Oil		NGL		Total
Revenues from contracts with customers	$	47,146	$	186	$	47,332
Other revenues	28		—		28
Total revenues of reportable segments	$	47,174	$	186	$	47,360
Intersegment revenues elimination					(24)
Total revenues					$	47,336

Schedule of Contract with Customer, Counterparty Deficiencies


		December 31,
Counterparty Deficiencies	Financial Statement Classification	2025		2024
Billed and collected	Other current liabilities	$	47	$	83

Schedule of Contracts with Customers, Change in Contract Asset and Liability Balance

The following table presents the changes in the liability balance associated with contracts with customers (in millions):


	Contract Liabilities
Balance at December 31, 2023	$	101
Amounts recognized as revenue	(36)

Additions	23
Other	(1)
Balance at December 31, 2024	$	87
Amounts recognized as revenue	(42)
Additions	42

Balance at December 31, 2025	$	87


	December 31,
	2025		2024
Trade accounts receivable arising from revenues from contracts with customers	$	3,639	$	3,922
Other trade accounts receivables and other receivables (1)	7,357		7,339
Impact due to contractual rights of offset with counterparties	(7,398)		(7,582)
Trade accounts receivable and other receivables, net	$	3,598	$	3,679

(1) The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of ASC 606.

Schedule of Remaining Performance Obligations

The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of December 31, 2025 (in millions):


	2026		2027		2028		2029		2030		2031 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	398	$	330	$	296	$	210	$	152	$	835
Terminalling, storage and other agreement revenues	241		211		153		109		72		423
Total	$	639	$	541	$	449	$	319	$	224	$	1,258

(1)Calculated as volumes committed under contracts multiplied by the current applicable tariff rate.

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]	To assess, identify and manage material cybersecurity risks, we have endeavored to implement policies, standards and technical controls with the aim of protecting our information technology (“IT”) and operational technology (“OT”) systems (collectively, our “IT systems”). These standards are guided, in part, by the relevant National Institute of Standards and Technology and American Petroleum Institute frameworks. We use various internal and third-party tools, security measures and technologies to aid in seeking to protect our network perimeter and internal systems from unauthorized access, intrusion or disruption. Regular assessments are conducted across our systems, networks and data infrastructure to identify potential cybersecurity threats and vulnerabilities. In addition, a monitoring and detection system has been implemented to help identify cybersecurity threats and incidents. Our cybersecurity program also focuses on providing training and awareness to our employees and contractors on cybersecurity best practices. We engage assessors, consultants, auditors and other third parties in connection with the above processes. We recognize that third-party service providers may introduce cybersecurity risks. In an effort to mitigate these risks, we have established a process to assess and oversee the cybersecurity practices of our vendors. Before engaging with third-party service providers, we conduct due diligence to evaluate their cybersecurity capabilities and potential vulnerabilities. Additionally, we endeavor to include cybersecurity requirements in our contracts with these providers, including adherence to specific security practices and protocols. The above cybersecurity risk management processes are integrated into our overall risk management program. Cybersecurity threats are understood to be dynamic and to intersect with various other enterprise risks. As such, cybersecurity is considered an integral component of our enterprise-wide risk management approach. As of the date of this Report, we are not aware of any previous cybersecurity threats that have materially affected or are reasonably likely to materially affect the Partnership. Despite the implementation of our cybersecurity programs, our security measures cannot guarantee that a significant cyberattack will not occur. A successful attack on our IT systems or those of our vendors could have significant consequences to our business. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. See “Item 1A. Risk Factors” for additional information about the risks to our business associated with a breach or compromise to our IT systems.
Cybersecurity Risk Management Processes Integrated [Flag]	true
Cybersecurity Risk Management Processes Integrated [Text Block]	To assess, identify and manage material cybersecurity risks, we have endeavored to implement policies, standards and technical controls with the aim of protecting our information technology (“IT”) and operational technology (“OT”) systems (collectively, our “IT systems”). These standards are guided, in part, by the relevant National Institute of Standards and Technology and American Petroleum Institute frameworks. We use various internal and third-party tools, security measures and technologies to aid in seeking to protect our network perimeter and internal systems from unauthorized access, intrusion or disruption. Regular assessments are conducted across our systems, networks and data infrastructure to identify potential cybersecurity threats and vulnerabilities. In addition, a monitoring and detection system has been implemented to help identify cybersecurity threats and incidents. Our cybersecurity program also focuses on providing training and awareness to our employees and contractors on cybersecurity best practices.
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 Board of Directors Oversight [Text Block]	Our cybersecurity program is led by our Vice President of Information Services, North America, who reports directly to our CFO and oversees the dedicated team responsible for executing our cybersecurity strategy, including the primary assessment and management of cybersecurity risks. Our cybersecurity leadership team also includes our Senior Director, Enterprise Technology, our Director, Cybersecurity and Technology Risk, and other senior leaders from our Information Services team. The Board receives quarterly updates on material security incidents (if applicable), detection, monitoring, and other key initiatives and notable events from our Vice President of Information Services – North America.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]	Our cybersecurity program is led by our Vice President of Information Services, North America, who reports directly to our CFO and oversees the dedicated team responsible for executing our cybersecurity strategy, including the primary assessment and management of cybersecurity risks. Our cybersecurity leadership team also includes our Senior Director, Enterprise Technology, our Director, Cybersecurity and Technology Risk, and other senior leaders from our Information Services team. The Board receives quarterly updates on material security incidents (if applicable), detection, monitoring, and other key initiatives and notable events from our Vice President of Information Services – North America.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	Our cybersecurity program is led by our Vice President of Information Services, North America, who reports directly to our CFO and oversees the dedicated team responsible for executing our cybersecurity strategy, including the primary assessment and management of cybersecurity risks. Our cybersecurity leadership team also includes our Senior Director, Enterprise Technology, our Director, Cybersecurity and Technology Risk, and other senior leaders from our Information Services team. The Board receives quarterly updates on material security incidents (if applicable), detection, monitoring, and other key initiatives and notable events from our Vice President of Information Services – North America.
Cybersecurity Risk Role of Management [Text Block]	Our cybersecurity program is led by our Vice President of Information Services, North America, who reports directly to our CFO and oversees the dedicated team responsible for executing our cybersecurity strategy, including the primary assessment and management of cybersecurity risks. Our cybersecurity leadership team also includes our Senior Director, Enterprise Technology, our Director, Cybersecurity and Technology Risk, and other senior leaders from our Information Services team. The Board receives quarterly updates on material security incidents (if applicable), detection, monitoring, and other key initiatives and notable events from our Vice President of Information Services – North America. To facilitate effective management, our cybersecurity leadership team holds regular discussions with our dedicated cybersecurity team on cybersecurity risks, threat intelligence, incident trends, security audits, and the effectiveness of our training and testing. Our cybersecurity leadership team convenes regularly to review and monitor programs designed to prevent and detect cybersecurity threats and mitigate and remediate cybersecurity incidents. Our cybersecurity leadership team also receives comprehensive reports on security incidents, threat intelligence, and vulnerability assessments from our cybersecurity team. Our cybersecurity leadership team is made up of highly experienced professionals with extensive backgrounds in information security, risk management, and incident response, including our Vice President of Information Services – North America, our Senior Director, Enterprise Technology and our Director, Cybersecurity and Technology Risk. Our Vice President of Information Services – North America has been with Plains for over 15 years and has over 25 years’ experience in technology infrastructure and security including senior management level oversight of cybersecurity for organizations in both the health care and oil and gas industries. Our Senior Director, Enterprise Technology reports to the Vice President, Information Services – North America and has accountability for core enterprise technology platforms, including hosting, networks, data platforms, and cybersecurity programs. This individual has over 20 years of experience in the information services industry, including experience with cyber incident detection and response. The Director, Cybersecurity and Technology Risk has responsibility for oversight of cybersecurity strategy across IT and OT environments, implementation of programs aligned with recognized frameworks, and implementation of key security controls. This individual has more than 20 years of experience in enterprise cybersecurity, OT security, and critical infrastructure risk management at publicly traded companies and holds multiple industry-recognized certifications in information security, audit, privacy, and enterprise IT governance. In addition to having the requisite training, knowledge, skills and abilities required for their respective positions, the cybersecurity leadership team collectively holds various relevant U.S. and Canadian information security certifications. The cybersecurity leadership team is supported by a dedicated team of skilled cybersecurity professionals, each bringing diverse expertise in areas such as network security, data protection, and threat intelligence.
Cybersecurity Risk Management Positions or Committees Responsible [Flag]	true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	Our cybersecurity program is led by our Vice President of Information Services, North America, who reports directly to our CFO and oversees the dedicated team responsible for executing our cybersecurity strategy, including the primary assessment and management of cybersecurity risks. Our cybersecurity leadership team also includes our Senior Director, Enterprise Technology, our Director, Cybersecurity and Technology Risk, and other senior leaders from our Information Services team.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	Our cybersecurity leadership team is made up of highly experienced professionals with extensive backgrounds in information security, risk management, and incident response, including our Vice President of Information Services – North America, our Senior Director, Enterprise Technology and our Director, Cybersecurity and Technology Risk. Our Vice President of Information Services – North America has been with Plains for over 15 years and has over 25 years’ experience in technology infrastructure and security including senior management level oversight of cybersecurity for organizations in both the health care and oil and gas industries. Our Senior Director, Enterprise Technology reports to the Vice President, Information Services – North America and has accountability for core enterprise technology platforms, including hosting, networks, data platforms, and cybersecurity programs. This individual has over 20 years of experience in the information services industry, including experience with cyber incident detection and response. The Director, Cybersecurity and Technology Risk has responsibility for oversight of cybersecurity strategy across IT and OT environments, implementation of programs aligned with recognized frameworks, and implementation of key security controls. This individual has more than 20 years of experience in enterprise cybersecurity, OT security, and critical infrastructure risk management at publicly traded companies and holds multiple industry-recognized certifications in information security, audit, privacy, and enterprise IT governance. In addition to having the requisite training, knowledge, skills and abilities required for their respective positions, the cybersecurity leadership team collectively holds various relevant U.S. and Canadian information security certifications. The cybersecurity leadership team is supported by a dedicated team of skilled cybersecurity professionals, each bringing diverse expertise in areas such as network security, data protection, and threat intelligence.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	To facilitate effective management, our cybersecurity leadership team holds regular discussions with our dedicated cybersecurity team on cybersecurity risks, threat intelligence, incident trends, security audits, and the effectiveness of our training and testing. Our cybersecurity leadership team convenes regularly to review and monitor programs designed to prevent and detect cybersecurity threats and mitigate and remediate cybersecurity incidents. Our cybersecurity leadership team also receives comprehensive reports on security incidents, threat intelligence, and vulnerability assessments from our cybersecurity team.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

Acquisitions, Divestitures and Other Transactions - Schedule of Business Combination, Pro Forma Information Pro Forma (Details) - EPIC Crude Oil Pipeline - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Business Combination [Line Items]
Total revenues	$ 44,464	$ 49,124
Net income/(loss) attributable to PAGP from continuing operations	$ 136	$ (4)
Basic net income/(loss) per Class A share from continuing operations (in dollars per share)	$ 0.69	$ (0.02)
Diluted net income/(loss) per Class A share from continuing operations (in dollars per share)	$ 0.69	$ (0.02)

- 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

Equity-Indexed Compensation Plans - Narrative (Details) shares in Millions, $ in Millions	Dec. 31, 2025 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Probable vesting, unrecognized fair value \| $	$ 70
PAA LTIP \| PAA
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
LTIP awards outstanding (in shares)	10.5
LTIP awards outstanding including DERs (in shares)	8.9
Plains G P Holdings Long Term Incentive Plans
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
LTIP awards outstanding (in shares)	0.1
LTIP awards outstanding including DERs (in shares)	0.1

- Definition

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+ References

+ Details

Revenues and Accounts Receivable - Segment Revenue (Details) - USD ($) $ in Millions	3 Months Ended								12 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, 2025	Dec. 31, 2024	Dec. 31, 2023
Disaggregation of Revenue [Line Items]
Total revenues	$ 10,565	$ 11,578	$ 10,642	$ 11,477	$ 12,035	$ 12,456	$ 12,757	$ 11,639	$ 44,262	$ 48,889	$ 47,336
Operating Segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers									44,237	48,838	47,332
Other revenues									45	69	28
Total revenues									44,282	48,907	47,360
Operating Segments \| Crude Oil
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers									44,087	48,651	47,146
Other revenues									44	69	28
Total revenues									44,131	48,720	47,174
Operating Segments \| NGL
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers									150	187	186
Other revenues									1	0	0
Total revenues									151	187	186
Intersegment revenues elimination
Disaggregation of Revenue [Line Items]
Total revenues									$ (20)	$ (18)	$ (24)

- Definition

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Related Party Transactions - Narrative (Details) - shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
PAGP \| Class C Shares \| PAA
Related Party Transaction [Line Items]
Class C shares held by PAA (in shares)	530,932,175	542,004,838

- Definition

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+ Details

Investments in Unconsolidated Entities - Equity Method Investments (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Investments in Unconsolidated Entities
Investments in unconsolidated entities	$ 2,846	$ 2,811	$ 2,820
BridgeTex Pipeline Company, LLC (“BridgeTex”)
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)	40.00%
Investments in unconsolidated entities	$ 574	403
Capline Pipeline Company LLC (“Capline”)
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)	54.00%
Investments in unconsolidated entities	$ 473	501
Diamond Pipeline LLC
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)	50.00%
Investments in unconsolidated entities	$ 432	440
Eagle Ford Pipeline LLC
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)	50.00%
Investments in unconsolidated entities	$ 347	364
Eagle Ford Terminals Corpus Christi LLC
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)	50.00%
Investments in unconsolidated entities	$ 110	113
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)	40.00%
Investments in unconsolidated entities	$ 262	275
White Cliffs Pipeline, L.L.C.
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)	36.00%
Investments in unconsolidated entities	$ 109	123
Wink to Webster Pipeline LLC (“W2W Pipeline”)
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)	17.00%
Investments in unconsolidated entities	$ 383	393
Other investments
Investments in Unconsolidated Entities
Investments in unconsolidated entities	$ 156	$ 199

Organization and Basis of Consolidation and Presentation

12 Months Ended

Dec. 31, 2025

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Basis of Consolidation and Presentation

Organization

Plains GP Holdings, L.P. (“PAGP”) is a Delaware limited partnership formed in 2013 that has elected to be taxed as a corporation for United States federal income tax purposes. PAGP does not directly own any operating assets; as of December 31, 2025, its sole source of cash flow is derived from an indirect investment in Plains All American Pipeline, L.P. (“PAA”), a publicly traded Delaware limited partnership. As used in this Form 10-K and unless the context indicates otherwise (taking into account the fact that PAGP has no operating activities apart from those conducted by PAA and its subsidiaries), the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAGP and its subsidiaries.

As of December 31, 2025, we owned an approximate 85% limited partner interest in Plains AAP, L.P. (“AAP”) through our ownership of approximately 197.9 million Class A units of AAP (“AAP units”). We also own a 100% managing member interest in Plains All American GP LLC (“GP LLC”), a Delaware limited liability company that holds the non-economic general partner interest in AAP. AAP is a Delaware limited partnership that, as of December 31, 2025, directly owned a limited partner interest in PAA through its ownership of approximately 233.0 million PAA common units (approximately 31% of PAA’s total outstanding common units and Series A preferred units combined). AAP is the sole member of PAA GP LLC (“PAA GP”), a Delaware limited liability company that directly holds the non-economic general partner interest in PAA.

PAA’s business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals. As one of the largest crude oil midstream service providers in North America, PAA owns an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. PAA’s assets and the services it provides are primarily focused on and conducted through two operating segments: Crude Oil and NGL. See Note 20 for further discussion of our operating segments.

PAA GP Holdings LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities and is responsible for exercising on our behalf any rights we have as the sole and managing member of GP LLC, including responsibility for conducting the business and managing the operations of AAP and PAA. GP LLC employs our domestic officers and personnel involved in the operation and management of AAP and PAA. PAA’s Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC.

References to the “Plains Entities” include us, our general partner, GP LLC, AAP, PAA GP and PAA and its subsidiaries.

Definitions

Additional defined terms may be used in the following notes and shall have the meanings indicated below:


AOCI	=	Accumulated other comprehensive income/(loss)
ASC	=	Accounting Standards Codification
ASU	=	Accounting Standards Update


CAD	=	Canadian dollar
CODM	=	Chief Operating Decision Maker
DERs	=	Distribution equivalent rights
EBITDA	=	Earnings before interest, taxes, depreciation and amortization

FASB	=	Financial Accounting Standards Board
GAAP	=	Generally accepted accounting principles in the United States
ICE	=	Intercontinental Exchange
ISDA	=	International Swaps and Derivatives Association
LIBOR	=	London Interbank Offered Rate
LTIP	=	Long-term incentive plan


NGL	=	Natural gas liquids, including ethane, propane and butane
NYMEX	=	New York Mercantile Exchange
OECD	=	Organisation for Economic Co-operation and Development
SEC	=	United States Securities and Exchange Commission
SOFR	=	Secured Overnight Financing Rate
TWh	=	Terawatt hour
U.S.	=	United States
USD	=	United States dollar

Basis of Consolidation and Presentation

The accompanying financial statements and related notes present and discuss our consolidated financial position as of December 31, 2025 and 2024, and the consolidated results of our operations, cash flows, changes in partners’ capital, comprehensive income and changes in accumulated other comprehensive income/(loss) for the years ended December 31, 2025, 2024 and 2023. All significant intercompany balances and transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications had no impact on net income or total partners’ capital.

The accompanying consolidated financial statements include the accounts of PAGP and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise.

Management judgment is required to evaluate whether PAGP controls an entity. Key areas of that evaluation include (i) determining whether an entity is a variable interest entity (“VIE”); (ii) determining whether PAGP is the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that PAGP and its related parties have over those activities through variable interests; and (iii) identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether PAGP is a VIE’s primary beneficiary.

We have determined that our subsidiaries, PAA and AAP, are VIEs and should be consolidated by PAGP because:

•The limited partners of PAA and AAP lack (i) substantive “kick-out rights” (i.e., the right to remove the general partner) based on a simple majority or lower vote and (ii) substantive participation rights and thus lack the ability to block actions of the general partner that most significantly impact the economic performance of PAA and AAP, respectively.

•AAP is the primary beneficiary of PAA because it has the power to direct the activities that most significantly impact PAA’s performance and the right to receive benefits, and obligation to absorb losses, that could be significant to PAA.

•PAGP is the primary beneficiary of AAP because it has the power to direct the activities that most significantly impact AAP’s performance and the right to receive benefits, and obligation to absorb losses, that could be significant to AAP.

With the exception of a deferred tax asset of $1.136 billion and $1.220 billion as of December 31, 2025 and 2024, respectively, substantially all assets and liabilities presented on PAGP’s Consolidated Balance Sheets are those of PAA. Only the assets of each respective VIE can be used to settle the obligations of that individual VIE, and the creditors of each/either of those VIEs do not have recourse against the general credit of PAGP. PAGP did not provide any financial support to PAA or AAP during the years ended December 31, 2025, 2024 or 2023. See Note 17 for information regarding the Omnibus Agreement entered into by the Plains Entities on November 15, 2016.

Pending Sale of Canadian NGL Business

On June 17, 2025, a subsidiary of PAA entered into a definitive Share Purchase Agreement (“SPA”) with Keyera Corp. (“Keyera”), an Alberta corporation, pursuant to which Keyera agreed to acquire all of the issued and outstanding shares of Plains Midstream Canada ULC, PAA’s wholly-owned subsidiary that owns substantially all of the NGL business in Canada (the “Canadian NGL Business”), for cash consideration of approximately CAD$5.15 billion (approximately $3.75 billion), subject to certain post-closing adjustments, as defined in the SPA. This transaction is expected to close around the end of the first quarter of 2026, subject to the satisfaction or waiver of customary closing conditions, including receipt of regulatory approvals.

We determined that in conjunction with entering into the SPA, the operations of the Canadian NGL Business meet the criteria for classification as held for sale and for discontinued operations reporting, as the sale will represent a strategic shift that will have a major effect on our operations and financial results. Accordingly, the assets and liabilities of the Canadian NGL Business have been classified as held for sale, and the balance sheet, results of operations and cash flows of the Canadian NGL Business have been presented as discontinued operations in our consolidated financial statements. Unless otherwise indicated, the disclosures included within the accompanying notes to the consolidated financial statements relate to our continuing operations and exclude amounts related to discontinued operations. These changes have been applied retrospectively to all periods presented. Discontinued operations are not presented separately within our Consolidated Statements of Comprehensive Income, Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss) or the Consolidated Statements of Changes in Partners’ Capital. See Note 3 for additional information regarding discontinued operations. All significant intercompany balances and transactions between the Canadian NGL Business and our continuing operations have been eliminated.

We will divest the Canadian NGL Business as part of the sale, which includes substantially all of our NGL assets; the assets that we will retain are located in the United States. Prior to its classification as held for sale and presentation as discontinued operations, the Canadian NGL Business was part of our NGL reportable segment.

In June 2025, we entered into a forward currency instrument to hedge currency exchange risk associated with anticipated proceeds from the pending sale of our Canadian NGL Business. See Note 13 for additional information.

In connection with and contingent upon closing of the pending sale, we and Keyera entered into an agreement for certain hedging arrangements and payments relating to the differential between the price of natural gas and the extracted NGL commodities (“Frac Spread”) for a twelve-month period commencing the first month after the closing date. As a result of this arrangement, we will guarantee a minimum Frac Spread margin on certain volumes. The recognition of an asset or liability will be dependent upon the terms of the specific contracts transferred as part of the sale of the Canadian NGL Business and the market conditions at that time the sale closes. We do not expect any liability we might recognize as a result of this agreement to have a material adverse effect on our consolidated financial condition, results of operations or cash flows; for example, if the sale closed at the end of the first quarter of 2026, based on existing contracts to be transferred and current market conditions as of December 31, 2025, we would recognize a liability of approximately $65 million.

Subsequent Events

Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Statement of Comprehensive Income [Abstract]
Net income	$ 1,686	$ 1,070	$ 1,425
Other comprehensive income/(loss)	187	(247)	118
Comprehensive income	1,873	823	1,543
Comprehensive income attributable to noncontrolling interests	(1,561)	(789)	(1,312)
Comprehensive income attributable to PAGP	$ 312	$ 34	$ 231

- Definition

Amount after tax of increase (decrease) in equity from transactions and other events and circumstances from net income and other comprehensive income, attributable to parent entity. Excludes changes in equity resulting from investments by owners and distributions to owners.

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Amount after tax of increase (decrease) in equity from transactions and other events and circumstances from net income (loss) and other comprehensive income (loss), attributable to noncontrolling interests. Excludes changes in equity resulting from investments by owners and distributions to owners.

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+ Details

Related Party Transactions - Transactions with Other Related Parties (Details) - USD ($) $ in Millions	3 Months Ended								12 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, 2025	Dec. 31, 2024	Dec. 31, 2023
Related Party Transaction [Line Items]
Revenues from related parties	$ 10,565	$ 11,578	$ 10,642	$ 11,477	$ 12,035	$ 12,456	$ 12,757	$ 11,639	$ 44,262	$ 48,889	$ 47,336
Purchases and related costs from related parties									358	400	404
Trade accounts receivable and other receivables, net from related parties	3,598				3,679				3,598	3,679
Trade accounts payable to related parties	3,457				3,647				3,457	3,647
Affiliated Entity
Related Party Transaction [Line Items]
Revenues from related parties									49	46	$ 48
Trade accounts receivable and other receivables, net from related parties	49				40				49	40
Trade accounts payable to related parties	$ 64				$ 66				$ 64	$ 66

- 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.

Partners' Capital and Distributions - Shares and Exchange and Redemption Rights (Details)	12 Months Ended
	Dec. 31, 2025 shares	Dec. 31, 2024 shares	Dec. 31, 2023 shares
Class A Shares
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance, beginning of period (in shares)	197,465,699	196,416,760	194,407,642
Conversion of AAP Management Units (in shares)			0
Exchange Right exercises (in shares)	293,925	846,937	1,869,768
Redemption Right exercises (in shares)			0
Other (in shares)	144,500	202,002	139,350
Balance, end of period (in shares)	197,904,124	197,465,699	196,416,760
Class A Shares \| Common Equity Repurchase Program
Increase (Decrease) in Partners' Capital [Roll Forward]
Repurchase and cancellation (in shares)	0
Class A Shares \| Series A Preferred Stock
Increase (Decrease) in Partners' Capital [Roll Forward]
Repurchase and cancellation (in shares)	0
Class B Shares
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance, beginning of period (in shares)	35,390,231	36,237,168	46,205,947
Conversion of AAP Management Units (in shares)			388,839
Exchange Right exercises (in shares)	(293,925)	(846,937)	(1,869,768)
Redemption Right exercises (in shares)			(8,487,850)
Other (in shares)		0	0
Balance, end of period (in shares)	35,096,306	35,390,231	36,237,168
Class B Shares \| Common Equity Repurchase Program
Increase (Decrease) in Partners' Capital [Roll Forward]
Repurchase and cancellation (in shares)	0
Class B Shares \| Series A Preferred Stock
Increase (Decrease) in Partners' Capital [Roll Forward]
Repurchase and cancellation (in shares)	0
Class C Shares
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance, beginning of period (in shares)	542,004,838	539,445,289	528,442,538
Conversion of AAP Management Units (in shares)			0
Exchange Right exercises (in shares)	0	0	0
Redemption Right exercises (in shares)			8,487,850
Other (in shares)	2,082,592	2,559,549	2,514,901
Balance, end of period (in shares)	530,932,175	542,004,838	539,445,289
Class C Shares \| Common Equity Repurchase Program
Increase (Decrease) in Partners' Capital [Roll Forward]
Repurchase and cancellation (in shares)	(476,695)
Class C Shares \| Series A Preferred Stock
Increase (Decrease) in Partners' Capital [Roll Forward]
Repurchase and cancellation (in shares)	(12,678,560)
AAP \| Exchange of AAP Units and Class B Shares for Class A Shares
Partners Capital and Distribution [Line Items]
Ratio for conversion or exchange of units	1

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Statement [Abstract]
Interest expense, capitalized interest	$ 11	$ 9	$ 10

Acquisitions, Divestitures and Other Transactions - Schedule of Business Combination, Consideration Transferred, Equity Interest (Details) - EPIC Crude Oil Pipeline - USD ($) $ in Millions	Nov. 02, 2025	Nov. 01, 2025	Oct. 31, 2025
Business Combination [Line Items]
Cash consideration	$ 1,901
Contingent consideration	115
Total consideration	$ 2,016	$ 1,327	$ 1,568

- 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

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
CURRENT ASSETS
Cash and cash equivalents	$ 329	$ 349
Trade accounts receivable and other receivables, net	3,598	3,679
Inventory	211	261
Current assets of discontinued operations (Note 3)	479	415
Other current assets	87	72
Total current assets	4,704	4,776
PROPERTY AND EQUIPMENT	22,536	18,528
Accumulated depreciation	(5,676)	(5,082)
Property and equipment, net	16,860	13,446
OTHER ASSETS
Investments in unconsolidated entities	2,846	2,811
Intangible assets, net	1,754	1,677
Deferred tax asset	1,136	1,220
Linefill	900	904
Long-term operating lease right-of-use assets, net	198	189
Long-term inventory	214	242
Long-term assets of discontinued operations (Note 3)	2,557	2,349
Other long-term assets, net	107	142
Total assets	31,276	27,756
CURRENT LIABILITIES
Trade accounts payable	3,457	3,647
Short-term debt	563	407
Current liabilities of discontinued operations (Note 3)	382	350
Other current liabilities	500	520
Total current liabilities	4,902	4,924
LONG-TERM LIABILITIES
Senior notes, net	9,118	7,141
Other long-term debt, net	1,578	70
Long-term operating lease liabilities	202	192
Long-term liabilities of discontinued operations (Note 3)	606	576
Other long-term liabilities and deferred credits	654	537
Total long-term liabilities	12,158	8,516
COMMITMENTS AND CONTINGENCIES (NOTE 19)
PARTNERS’ CAPITAL
Noncontrolling interests	12,871	12,965
Total partners’ capital	14,216	14,316
Total liabilities and partners’ capital	31,276	27,756
Class A Shares
PARTNERS’ CAPITAL
Class A shareholders (197,904,124 and 197,465,699 shares outstanding, respectively)	$ 1,345	$ 1,351

Equity-Indexed Compensation Plans

12 Months Ended

Dec. 31, 2025

Share-Based Payment Arrangement [Abstract]

Equity-Indexed Compensation Plans

Our equity-indexed compensation plans primarily include LTIPs. Although other types of awards are contemplated under certain of the LTIPs, currently outstanding awards are limited to “phantom units,” which mature into the right to receive our Class A shares or common units of PAA (or cash equivalent) upon vesting, and “tracking units,” which, upon vesting, represent the right to receive a cash payment in an amount based upon the market value of a PAA common unit at the time of vesting. Some awards also include DERs, which, subject to applicable vesting criteria, entitle the grantee to a cash payment equal to the cash distribution paid on an outstanding Class A share or PAA common unit. The DERs terminate with the vesting or forfeiture of the underlying LTIP award.

Our LTIP awards include both liability-classified and equity-classified awards. In accordance with FASB guidance regarding share-based payments, the fair value of liability-classified LTIP awards is calculated based on the closing market price of the underlying PAGP share or PAA unit at each balance sheet date and adjusted for the present value of any distributions that are estimated to occur on the underlying shares or units over the vesting period that will not be received by the award recipients. The fair value for equity-classified awards is calculated in a similar manner on the respective grant dates. These fair values are recognized as compensation expense over the service period. We have elected to recognize forfeitures of awards when they occur.

Our LTIP awards contain (i) time-based vesting criteria, (ii) performance conditions, (iii) market conditions or (iv) a combination of time-based vesting criteria and performance conditions. For awards with performance conditions, expense is accrued over the service period only if the performance condition is considered probable of occurring. When awards with performance conditions that were previously considered improbable become probable, we incur additional expense in the period that the probability assessment changes. This is necessary to bring the accrued obligation associated with these awards up to the level it would have been if we had been accruing for these awards since the grant date. For awards with market conditions, the probable outcomes are determined on the respective dates that the fair values are calculated, and the resulting expense is accrued over the service period.

The following is a summary of the awards authorized under our LTIPs (including those associated with discontinued operations) as of December 31, 2025 (in millions):


LTIP						LTIP Awards Authorized
Plains GP Holdings, L.P. Long-Term Incentive Plan						3.8
Plains All American 2021 Long-Term Incentive Plan						28.8
Plains All American PNG Successor Long-Term Incentive Plan						1.3
Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan						13.4
Total (1)						47.3

(1)Of the 47.3 million total awards authorized, 16.4 million awards are currently available for future grant. The remaining balance has already vested or is currently outstanding.

As of December 31, 2025, 10.5 million PAA LTIP awards and 0.1 million PAGP LTIP awards were outstanding (including those associated with discontinued operations). Of the awards outstanding, 8.9 million PAA LTIP awards and 0.1 million PAGP LTIP awards include associated DERs. At December 31, 2025, certain of the outstanding LTIP awards were considered probable of vesting and such awards are expected to vest at various dates between August 2026 and August 2030. As of December 31, 2025, the outstanding awards that are considered probable of vesting have a remaining unrecognized fair value of approximately $70 million.

Major Customers and Concentration of Credit Risk	12 Months Ended
Major Customers and Concentration of Credit Risk	Dec. 31, 2025
Risks and Uncertainties [Abstract]
Major Customers and Concentration of Credit Risk	Major Customers and Concentration of Credit Risk ExxonMobil Corporation and its subsidiaries accounted for approximately 31%, 31% and 27% of our revenues for the years ended December 31, 2025, 2024 and 2023, respectively. BP p.l.c. and its subsidiaries accounted for approximately 10% of our revenues for the year ended December 31, 2023. No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2025. The majority of revenues from these customers pertain to our Crude Oil segment merchant activities, and sales to these customers occur at multiple locations. If we were to lose one or more of these customers, there is risk that we would not be able to identify and access a replacement market at a comparable margin. Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL. This industry concentration has the potential to impact our overall exposure to credit risk in that the customers may be similarly affected by changes in economic, industry or other conditions. We review credit exposure and financial information of our counterparties and generally require letters of credit for receivables from customers that are not considered creditworthy, unless the credit risk can otherwise be reduced. See Note 4 for additional discussion of our accounts receivable and our review of credit exposure.

- 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.

+ References

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-Section 50
-Paragraph 21
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+ Details

Acquisitions, Divestitures and Other Transactions

12 Months Ended

Dec. 31, 2025

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

Acquisitions, Divestitures and Other Transactions

Acquisitions

EPIC (Cactus III)

On October 31, 2025, we purchased an aggregate 55% equity interest in EPIC Crude Holdings, LP (“EPIC Crude Holdings”), which owns the EPIC Crude Oil Pipeline (which we now refer to as our “Cactus III Pipeline”), from subsidiaries of Diamondback Energy, Inc. and Kinetik Holdings Inc., for approximately $1.568 billion, subject to certain adjustments and inclusive of $613 million of debt assumed. We also agreed to a potential earnout payment of $193 million contingent upon the formal sanctioning before the end of 2027 of one or more expansions of Cactus III Pipeline that in the aggregate will increase the capacity of the pipeline to at least 900,000 barrels per day. In a separate transaction, effective November 1, 2025, we acquired the remaining 45% equity interest in EPIC Crude Holdings from a portfolio company of Ares Private Equity funds for approximately $1.327 billion, subject to certain adjustments and inclusive of $501 million of debt assumed. We also agreed to a potential earnout payment to the seller of up to $157 million depending on the timing and amount of incremental expansion capacity up to 300,000 barrels per day in excess of 650,000 barrels per day that is formally sanctioned before the end of 2028. The aggregate cash consideration also includes closing cash and working capital of approximately $121 million. The estimated fair value of the aggregate earnout consideration recorded in connection with these transactions was approximately $115 million. The fair value of the aggregate earnout consideration was determined based on weighted-average probabilities of certain capacity expansion scenarios and the related timing thereof.

Subsequent to these two transactions (collectively, the “EPIC acquisition”), we now own 100% of EPIC Crude Holdings and are the operator of record for the Cactus III Pipeline, which provides long-haul crude oil takeaway from the Permian and Eagle Ford basins to the Gulf Coast market at Corpus Christi. We believe this acquisition is highly synergistic and strategic to our existing footprint. The EPIC acquisition will be accounted for in our Crude Oil segment.


Consideration:	Recognized Amount
Cash consideration	$	1,901
Contingent consideration	115

Total consideration	$	2,016

In accordance with applicable accounting guidance, the fair value of the assets acquired and liabilities assumed following the acquisition was utilized as the consideration transferred for the purchase price allocation. The determination of the fair value of the assets and liabilities assumed was estimated in accordance with applicable accounting guidance. The analysis was performed based on estimates that are reflective of market participant assumptions. The following table reflects

our preliminary determination of the fair value of the assets acquired and liabilities assumed in connection with the EPIC acquisition (in millions):


Identifiable Assets Acquired and Liabilities Assumed:	Estimated Useful Lives (in years)	Recognized Amount
Working capital and other assets, net	N/A	$	160
Property and equipment, net	47	2,737
Intangible assets	5 - 10	267
Other long-term debt, net	N/A	(1,114)
Long-term operating lease liability	N/A	(34)
Total		$	2,016

The acquired Property and equipment, net is primarily comprised of pipelines, equipment and rights of way. The intangible assets recognized in this transaction relate to long-term contracts which contain rates that are favorable to current market conditions. We utilized widely accepted valuation techniques for these types of assets that represent Level 3 measurements in the fair value hierarchy. A Level 3 measurement is one for which there are no observable market inputs.

The fair value of acquired pipelines and equipment was determined using a cost approach with an assumption for replacement cost. The fair value of acquired rights of way was determined using a market approach for similar assets.

The fair value of the favorable contracts was determined using an income approach that considers the projected volumes to be transported over the life of the contracts, assumptions for current market rates, and a discount rate that a theoretical market participant would assign to the intangible asset of approximately 17%.

The useful lives of the favorable contracts range from 5 to 10 years, and amortization of these intangible assets is recognized using the declining balance method of amortization. Amortization expense was approximately $15 million for the year ended December 31, 2025, and the future amortization expense through 2030 is estimated as follows (in millions):


2026	$	67
2027	$	53
2028	$	34
2029	$	29
2030	$	21

In connection with the EPIC acquisition, we assumed the EPIC credit agreement, which provided for a $1.2 billion term loan (the “EPIC term loan”) and a $125 million revolving credit facility (the “EPIC revolver”). On December 1, 2025, we repaid the $1.1 billion of borrowings outstanding under the EPIC term loan and terminated the EPIC credit agreement. See Note 11 for additional information regarding the EPIC credit agreement. The EPIC term loan was valued at par based on the expectation of terminating the loan at such value.

During the year ended December 31, 2025, we incurred approximately $9 million of transaction-related costs associated with the EPIC acquisition. Such costs are reflected as a component of “General and administrative expenses” on our Consolidated Statements of Operations.

Pro Forma and Other Financial Results

Financial results from the EPIC acquisition have been included in our results of operations within the Crude Oil segment since the date of the acquisition. The EPIC revenues and earnings generated during the period since the acquisition date were not material for disclosure purposes.

The following selected unaudited pro forma results of operations were derived from the historical financial statements of EPIC Crude Holdings, and gives effect to the EPIC acquisition as if it had occurred on January 1, 2024. The pro forma results of operations do not include any cost savings or other synergies that may result from the EPIC acquisition or any

estimated costs that have been or will be incurred by us to integrate the assets acquired. These results are not necessarily indicative of the results that might have actually occurred had the acquisition taken place on January 1, 2024; furthermore, this financial information is not intended to be a projection of future results (in millions, except per unit amounts):


	Year Ended December 31,
	2025		2024
Total revenues	$	44,464	$	49,124
Net income/(loss) attributable to PAGP from continuing operations	$	136	$	(4)

Basic and diluted net income/(loss) per Class A share from continuing operations	$	0.69	$	(0.02)

Ironwood Midstream

On January 31, 2025, we acquired Ironwood Midstream Energy Partners II, LLC (“Ironwood Midstream”), which owns a gathering system in the Eagle Ford Basin, for approximately $481 million in cash from EnCap Flatrock Midstream. The Ironwood Midstream acquisition is accounted for in our Crude Oil segment. In January 2025, in a separate transaction, we also repurchased from EnCap Flatrock Midstream, a portion of our outstanding Series A preferred units. EnCap Flatrock Midstream is affiliated with EnCap Investments, L.P, an entity that is associated with a member of the board of directors of PAGP GP. See Note 12 for additional information.

The Ironwood Midstream acquisition was accounted for as a business combination using the acquisition method of accounting. In accordance with applicable accounting guidance, the fair value of the assets acquired and liabilities assumed following the acquisition was utilized as the consideration transferred for the purchase price allocation. The determination of the fair value of the assets and liabilities assumed was estimated in accordance with applicable accounting guidance. The analysis was performed based on estimates that are reflective of market participant assumptions. The following table reflects our preliminary determination of the fair value of the Ironwood Midstream acquisition assets and liabilities (in millions):


Identifiable Assets Acquired and Liabilities Assumed:	Estimated Useful Lives (in years)	Recognized Amount
Property and equipment	3 - 30	$	435
Intangible assets	16	27
Working capital and other assets and liabilities	N/A	19
		$	481

The fair value of the tangible asset is a Level 3 measurement in the fair value hierarchy and was determined using a cost approach for tangible assets, with an assumption for replacement cost, and a market approach for rights-of-way. A Level 3 measurement is one for which there are no observable market inputs. The fair value of the intangible assets is also a Level 3 measurement in the fair value hierarchy and was determined by applying a discounted cash flow approach. Such approach utilized a discount rate of 18%, based on our estimate of the risk that a theoretical market participant would assign to the intangible asset. The projection of future crude oil volumes transported and the estimated tariff rates for transportation were also key assumptions in the valuation of the intangible assets. Projected future volumes and estimated tariff rates were based on current contracts in place with assumptions for forecasted rate increases and contract renewals.

The fair value of intangible asset is comprised of customer relationships that will be amortized over their useful lives, which have a remaining weighted average life of approximately 16 years. The value assigned to such intangible asset will be

amortized to earnings under the declining balance method of amortization. Amortization expense was approximately $4 million for the year ended December 31, 2025, and the future amortization expense through 2030 is estimated as follows (in millions):


2026	$	5
2027	$	4
2028	$	3
2029	$	3
2030	$	2

Pro forma financial information assuming the acquisition had occurred as of the beginning of the calendar year prior to the year of the acquisition, as well as the revenues and earnings generated during the period since the acquisition date, were not material for disclosure purposes.

Rattler Permian Transaction

In the third quarter of 2023, we completed a transaction with Rattler Midstream Operating LLC (“Rattler”) pursuant to which the Permian JV acquired the remaining 43% interest in OMOG JV Holdings LLC (“OMOG”) and certain gathering assets in the Southern Delaware basin. The transaction had an aggregate purchase price of $294 million ($191 million net to our 65% interest in the Permian JV). As a result of the transaction, the Permian JV now owns 100% of OMOG and its subsidiaries and such entities are reflected as consolidated subsidiaries in our Consolidated Financial Statements. Prior to this transaction, the Permian JV’s 57% interest in OMOG was accounted for as an equity method investment.

The transaction was accounted for as a business combination using the acquisition method of accounting. In accordance with applicable accounting guidance, the fair value of the assets acquired and liabilities assumed following the transaction was utilized as the consideration transferred for the purchase price allocation.

As a result of us obtaining control over OMOG, the Permian JV’s previously-held 57% interest in OMOG was remeasured to its fair value of $239 million based upon a valuation of the acquired business, as of the date of acquisition. We considered multiple factors in determining the fair value of the previously-held equity method investment, including, (i) the price negotiated with Rattler for its 43% interest in OMOG and (ii) a discounted cash flow approach. The discounted cash flow approach utilized a discount rate of approximately 11%, based on the estimate of the risk that a theoretical market participant would assign to the business. The remeasurement of the Permian JV’s investment in OMOG to fair value resulted in a gain of $29 million. This gain has been recognized in the line item “Gain on investments in unconsolidated entities, net” on our Consolidated Statement of Operations.

The determination of the fair value of the assets and liabilities assumed was estimated in accordance with applicable accounting guidance. The analysis was performed based on estimates that are reflective of market participant assumptions. While the purchase price for the transaction was $294 million, all of the OMOG assets and liabilities were remeasured to fair value and therefore, the fair value of the assets and liabilities that are now consolidated on the balance sheet as a result of this transaction is $532 million. The following table reflects our determination of the fair value of the assets acquired and liabilities assumed in connection with the transaction (in millions):


Identifiable Assets Acquired and Liabilities Assumed:	Estimated Useful Lives (in years)	Recognized Amount
Property and equipment	3 - 30	$	484
Intangible assets	10	34
Working capital and other assets and liabilities	N/A	14
		$	532

The fair value of the tangible assets is a Level 3 measurement in the fair value hierarchy and was determined using the cost approach based on costs incurred on similar recent construction projects. The fair value of the intangible assets is also a Level 3 measurement in the fair value hierarchy and was determined by applying a discounted cash flow approach. Such approach utilized discount rates varying from approximately 21% to 23%, based on our estimate of the risk that a theoretical market participant would assign to the respective intangible assets. The projection of future crude oil volumes transported and the estimated tariff rates for transportation were also key assumptions in the valuation of the intangible assets. Projected future volumes and estimated tariff rates were based on current contracts in place with assumptions for forecasted rate increases and contract renewals.

The fair value of intangible assets is comprised of customer relationships that will be amortized over their useful lives, which have a remaining weighted average life of approximately 10 years. The value assigned to such intangible assets will be amortized to earnings under the declining balance method of amortization. Amortization expense was approximately $10 million, $8 million and $4 million during the years ended December 31, 2025, 2024 and 2023, respectively, and the future amortization expense through 2028 is estimated as follows (in millions):





2026	$	4
2027	$	3
2028	$	2

Other Acquisitions

2025

During the year ended December 31, 2025, we completed the following additional acquisitions:

•the acquisition in July 2025 of an additional 20% interest in BridgeTex Pipeline Company, LLC (“BridgeTex”) for approximately $180 million, increasing our ownership interest from 20% to 40%. See Note 9 for additional information about our investments in unconsolidated entities.

•the acquisition during the second quarter of 2025 of Black Knight Midstream, LLC (“Black Knight Midstream”), which owns a crude oil gathering business in the Permian Basin, for $59 million (approximately $38 million net to our 65% interest in the Permian JV), subject to certain adjustments. The Black Knight Midstream assets are accounted for in our Crude Oil segment.

•the acquisition in February 2025, through a non-monetary transaction, of the remaining 50% interest in Cheyenne Pipeline LLC (“Cheyenne”) in exchange for the termination of certain obligations. As a result of this transaction, we now own 100% of Cheyenne and reflect such entity as a consolidated subsidiary in our Consolidated Financial Statements within our Crude Oil segment. The transaction resulted in a net gain of approximately $31 million, which represents the difference between the fair value of the entity and the historical book value of our investment. This gain is reflected in “Gain on investments in unconsolidated entities, net” on our Consolidated Statement of Operations.

•the acquisition in January 2025 of EMG Medallion 2 Holdings, LLC and its subsidiaries, which own a crude oil gathering and transportation business in the Delaware Basin, for $163 million (approximately $106 million net to our 65% interest in the Permian JV), subject to certain adjustments. A cash deposit of approximately $16 million was paid upon signing in December 2024. EMG Medallion 2 Holdings was a portfolio company of The Energy & Minerals Group (“EMG”), which is associated with a member of the board of directors of our general partner.

2024

During the year ended December 31, 2024, we also completed the following acquisitions:

•the acquisition in December 2024 of the remaining 50% interest in Midway Pipeline LLC (“Midway”) for approximately $90 million. As a result of this transaction, we now own 100% of Midway and reflect such entity as a consolidated subsidiary in our Consolidated Financial Statements. The remeasurement of our previously-held investment in Midway to fair value resulted in a gain of approximately $15 million. This gain is reflected in “Gain on investments in unconsolidated entities, net” on our Consolidated Statement of Operations.

•the acquisition of additional interests in certain unconsolidated entities, including (i) the acquisition in August 2024 of an additional approximate 0.67% interest in Wink to Webster Pipeline LLC (increasing our ownership interest from 16% to 17%) for $20 million and (ii) the acquisition in March 2024 of an additional 10% interest in Saddlehorn Pipeline Company, LLC (increasing our ownership interest from 30% to 40%) for $91 million. See Note 9 for additional information about our investments in unconsolidated entities.

•the acquisition in the second and third quarters of 2024 of pipeline and terminal assets within our asset footprint for approximately $32 million.

2023

In November 2023, we acquired a crude oil gathering system in the Northern Delaware Basin from a subsidiary of LM Energy Partners for approximately $135 million (approximately $88 million net to our 65% interest in the Permian JV), subject to certain adjustments. This transaction was accounted for as an asset acquisition since substantially all of the value of the assets acquired was concentrated in a single asset.

Divestitures

During the year ended December 31, 2025, we received cash proceeds of $81 million, primarily from the sale of non-core assets, which were previously included in our Crude Oil segment. We recognized gains of approximately $44 million related to these asset sales, which is included in “(Gains)/losses on asset sales, asset impairments and other, net” on our Consolidated Statement of Operations.

In February 2023, we sold our 21% non-operated/undivided joint interest in the Keyera Fort Saskatchewan facility to Keyera Corporation for approximately $270 million. As of December 31, 2022, we classified the assets related to this transaction (primarily “Property and equipment” in our NGL segment), valued at the lower of the carrying amount or fair value less costs to sell, of approximately $130 million as assets held for sale on our Consolidated Balance Sheet (in “Other current assets”). At the time of this transaction, we concluded that this disposition did not meet the criteria for discontinued operations. Upon the sale of this facility, we recognized a gain of approximately $140 million which is included in “(Gains)/losses on asset sales, asset impairments and other, net” on our Consolidated Statement of Operations.

Related Party Transactions

12 Months Ended

Dec. 31, 2025

Related Party Transactions

PAA’s Ownership of our Class C Shares

As of December 31, 2025 and 2024, PAA owned 530,932,175 and 542,004,838, respectively, Class C shares. See Note 12 for additional information regarding our Class C shares.

Omnibus Agreement

The Plains Entities entered into an Omnibus Agreement on November 15, 2016, which provides for, among other things, the following:

•our ability to issue additional Class A shares and use the net proceeds therefrom to purchase a like number of AAP units from AAP, and the corresponding ability of AAP to use the net proceeds therefrom to purchase a like number of PAA common units; and

•our ability to lend proceeds of any future indebtedness incurred by us to AAP, and AAP’s corresponding ability to lend such proceeds to PAA, in each case on substantially the same terms as incurred by us.

Transactions with Other Related Parties

Our other related parties include entities in which we hold investments and account for under the equity method of accounting (see Note 9 for information regarding such entities). During the three years ended December 31, 2025, we recognized sales and transportation revenues, purchased petroleum products and utilized transportation and storage services from our related parties. These transactions were conducted at posted tariff rates or prices that we believe approximate market.

The impact to our Consolidated Statements of Operations from these transactions is included below (in millions):


	Year Ended December 31,
	2025		2024		2023



Revenues from related parties	$	49	$	46	$	48




Purchases and related costs from related parties	$	358	$	400	$	404

Our receivable and payable amounts with these related parties as reflected on our Consolidated Balance Sheets were as follows (in millions):


	December 31,
	2025		2024



Trade accounts receivable and other receivables, net from related parties (1)	$	49	$	40




Trade accounts payable to related parties (1) (2)	$	64	$	66

(1)Primarily includes amounts related to transportation and storage services.

- 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
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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 5: http://www.xbrl.org/2003/role/disclosureRef
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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/1943274/2147483326/850-10-50-1

+ Details

Partners' Capital and Distributions - AAP Distributions (Details) - USD ($) $ in Millions		12 Months Ended
	Feb. 13, 2026	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Partners' Capital and Distributions [Line Items]
Distributions paid		$ 1,733	$ 1,569	$ 1,330
Cash Distribution \| AAP
Partners' Capital and Distributions [Line Items]
Distributions to noncontrolling interests		53	45	47
Distributions to PAGP		301	251	209
Distributions to Class A Shareholders		$ 354	$ 296	$ 256
Cash Distribution \| Subsequent Event \| AAP
Partners' Capital and Distributions [Line Items]
Distributions paid	$ 97
Distributions to noncontrolling interests	14
Distributions to PAGP	$ 83

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
REVENUES
Total revenues	$ 44,262	$ 48,889	$ 47,336
COSTS AND EXPENSES
Purchases and related costs	40,433	45,162	43,937
Field operating costs	1,154	1,471	1,085
General and administrative expenses	348	334	305
Depreciation and amortization	953	901	912
(Gains)/losses on asset sales, asset impairments and other, net (Note 7, Note 8)	(54)	159	(152)
Total costs and expenses	42,834	48,027	46,087
OPERATING INCOME	1,428	862	1,249
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	382	452	369
Gain on investments in unconsolidated entities, net (Note 8, Note 9)	31	15	28
Interest expense (net of capitalized interest of $11, $9 and $10, respectively)	(467)	(382)	(386)
Other income, net	21	16	102
INCOME FROM CONTINUING OPERATIONS BEFORE TAX	1,395	963	1,362
Current income tax expense from continuing operations	(1)	(82)	(70)
Deferred income tax expense from continuing operations	(91)	(42)	(59)
INCOME FROM CONTINUING OPERATIONS, NET OF TAX	1,303	839	1,233
INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX (NOTE 3)	383	231	192
NET INCOME	1,686	1,070	1,425
Net income attributable to noncontrolling interests from continuing operations	(1,151)	(800)	(1,089)
Net income attributable to noncontrolling interests from discontinued operations	(275)	(167)	(138)
Net income attributable to noncontrolling interests	(1,426)	(967)	(1,227)
Net income attributable to PAGP from continuing operations	152	39	144
Net income attributable to PAGP from discontinued operations	108	64	54
Net income attributable to PAGP	$ 260	$ 103	$ 198
Class A Shares
OTHER INCOME/(EXPENSE)
Basic weighted average Class A shares outstanding (in shares)	198	197	195
Basic Net Income per Class A Share:
Continuing operations (in usd per share)	$ 0.77	$ 0.19	$ 0.74
Discontinued operations (in usd per share)	0.54	0.33	0.27
Basic net income per Class A share (in usd per share)	$ 1.31	$ 0.52	$ 1.01
Diluted weighted average Class A shares outstanding (in shares)	233	232	239
Diluted Net Income per Class A Share:
Continuing operations (in usd per share)	$ 0.77	$ 0.19	$ 0.74
Discontinued operations (in usd per share)	0.53	0.32	0.26
Diluted net income per Class A share (in usd per share)	$ 1.30	$ 0.51	$ 1.00
Product sales revenues
REVENUES
Total revenues	$ 42,501	$ 47,199	$ 45,745
Services revenues
REVENUES
Total revenues	$ 1,761	$ 1,690	$ 1,591

Acquisitions, Divestitures and Other Transactions - Rattler Permian Transaction Narrative (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended
	Jan. 31, 2025	Nov. 30, 2023	Jun. 30, 2025	Sep. 30, 2023	Dec. 31, 2025	Jun. 30, 2023
Minimum \| Customer contracts and relationships
Business Combination [Line Items]
Finite-lived intangible asset, useful life					1 year
Maximum \| Customer contracts and relationships
Business Combination [Line Items]
Finite-lived intangible asset, useful life					20 years
Plains Oryx Permian Basin LLC
Business Combination [Line Items]
Consolidated subsidiary, ownership interest (as a percent)	65.00%	65.00%	65.00%	65.00%
Plains Oryx Permian Basin LLC \| OMOG JV LLC (“OMOG”)
Business Combination [Line Items]
Ownership interest in unconsolidated entity (as a percent)						57.00%
OMOG JV LLC (“OMOG”)
Business Combination [Line Items]
Additional interest acquired (as a percent)				43.00%
Fair value amount				$ 239
Equity interest in acquiree, remeasurement gain				$ 29
Business Combination, Achieved in Stages, Preacquisition Equity Interest in Acquiree, Remeasurement, Gain, Statement of Income or Comprehensive Income [Extensible Enumeration]				Gains (losses) on investments in unconsolidated entities, net
OMOG JV LLC (“OMOG”) \| Level 3 \| Measurement Input, Discount Rate \| Valuation Technique, Discounted Cash Flow
Business Combination [Line Items]
Business combination, measurement input				0.11
OMOG JV LLC (“OMOG”) \| Plains Oryx Permian Basin LLC
Business Combination [Line Items]
Business combination, step acquisition, equity interest in acquiree, including subsequent acquisition (as a percent)				100.00%
Business combination, step acquisition, equity interest in acquire (as a percent)						57.00%
OMOG JV LLC and Southern Delaware Gathering Assets
Business Combination [Line Items]
Business acquisition amount, net to our interest in the Permian JV				$ 191
Total consideration				294
Business combination, consideration transferred, including equity interest in acquire held prior to combination				$ 532
Finite-lived intangible asset, useful life				10 years
OMOG JV LLC and Southern Delaware Gathering Assets \| Customer contracts and relationships
Business Combination [Line Items]
Finite-lived intangible asset, useful life				10 years
OMOG JV LLC and Southern Delaware Gathering Assets \| Level 3 \| Measurement Input, Discount Rate \| Valuation Technique, Discounted Cash Flow \| Minimum \| Intangible assets
Business Combination [Line Items]
Business combination, measurement input				0.21
OMOG JV LLC and Southern Delaware Gathering Assets \| Level 3 \| Measurement Input, Discount Rate \| Valuation Technique, Discounted Cash Flow \| Maximum \| Intangible assets
Business Combination [Line Items]
Business combination, measurement input				0.23
Rattler \| OMOG JV LLC (“OMOG”)
Business Combination [Line Items]
Additional interest acquired (as a percent)				43.00%
Rattler \| OMOG JV LLC (“OMOG”) \| Plains Oryx Permian Basin LLC
Business Combination [Line Items]
Additional interest acquired (as a percent)				43.00%
Rattler \| OMOG JV LLC and Southern Delaware Gathering Assets \| Plains Oryx Permian Basin LLC
Business Combination [Line Items]
Cash consideration				$ 294

Intangible Assets, Net - Amortization Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense for finite-lived intangible assets	$ 280	$ 262	$ 291
Estimated amortization expense related to finite-lived intangible assets for the next five years
2026	301
2027	261
2028	215
2029	192
2030	$ 165

- 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.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Section 45
-Paragraph 28
-Subparagraph (b)
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-Topic 230
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147476148/220-40-50-6

+ Details

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

Acquisitions, Divestitures and Other Transactions - EPIC Narrative (Details) $ in Millions					12 Months Ended
	Dec. 01, 2025 USD ($)	Nov. 02, 2025 USD ($)	Nov. 01, 2025 USD ($)	Oct. 31, 2025 USD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Business Combination [Line Items]
Repayments of PAA senior notes					$ 1,000	$ 750	$ 1,100
EPIC Credit Agreement
Business Combination [Line Items]
Repayments of PAA senior notes	$ 1,100
EPIC Credit Agreement \| Line of Credit
Business Combination [Line Items]
Debt instrument face value					1,200
Maximum aggregate borrowing capacity					$ 125
Minimum \| Customer contracts and relationships
Business Combination [Line Items]
Finite-lived intangible asset, useful life					1 year
Maximum \| Customer contracts and relationships
Business Combination [Line Items]
Finite-lived intangible asset, useful life					20 years
EPIC Crude Oil Pipeline
Business Combination [Line Items]
Additional interest acquired (as a percent)			45.00%	55.00%
Total consideration		$ 2,016	$ 1,327	$ 1,568
Long-term operating lease liability		$ 34	501	613
Contingent consideration			157	$ 193
Business combination, consideration transferred, cash and working capital			121
Business combination, step acquisition, equity interest in acquiree, including subsequent acquisition (as a percent)		100.00%
Transaction-related costs					$ 9
EPIC Crude Oil Pipeline \| Minimum
Business Combination [Line Items]
Finite-lived intangible asset, useful life		5 years
EPIC Crude Oil Pipeline \| Minimum \| Customer contracts and relationships
Business Combination [Line Items]
Finite-lived intangible asset, useful life				5 years
EPIC Crude Oil Pipeline \| Maximum
Business Combination [Line Items]
Finite-lived intangible asset, useful life		10 years
EPIC Crude Oil Pipeline \| Maximum \| Customer contracts and relationships
Business Combination [Line Items]
Finite-lived intangible asset, useful life				10 years
EPIC Crude Oil Pipeline \| Intangible assets \| Level 3 \| Measurement Input, Discount Rate \| Valuation Technique, Discounted Cash Flow
Business Combination [Line Items]
Business combination, measurement input				0.17
EPIC Crude Oil Pipeline \| Earnout Consideration
Business Combination [Line Items]
Contingent consideration			$ 115

Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 109	$ 106	$ 103
Liabilities incurred	0	0	1
Liabilities settled	(1)	(2)	(1)
Accretion expense	4	4	4
Revisions in estimated cash flows	0	1	(1)
Ending balance	$ 112	$ 109	$ 106

Leases - Lease Costs (Details) - USD ($) $ in Millions	12 Months Ended
Leases - Lease Costs (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
Operating lease cost	$ 37	$ 44	$ 48
Short-term lease cost	13	13	13
Other	19	16	8
Total lease cost	$ 69	$ 73	$ 69

Inventory, Linefill and Long-term Inventory - Components of Inventory, Linefill and Long-term Inventory (Details) bbl in Thousands, $ in Millions	Dec. 31, 2025 USD ($) $ / bbl bbl	Dec. 31, 2024 USD ($) $ / bbl bbl
Inventory disclosures
Inventory subtotal, Carrying Value	$ 211	$ 261
Linefill subtotal, Carrying Value	900	904
Long-term inventory subtotal, Carrying Value	214	242
Total	$ 1,325	$ 1,407
Crude oil
Inventory disclosures
Inventory, Volumes (in barrels) \| bbl	2,948	3,321
Linefill, Volumes (in barrels) \| bbl	15,112	15,463
Long-term inventory, Volumes (in barrels) \| bbl	3,724	3,413
Inventory subtotal, Carrying Value	$ 166	$ 221
Linefill subtotal, Carrying Value	898	903
Long-term inventory subtotal, Carrying Value	$ 213	$ 238
Inventory (Price/Unit of measure) (in dollars per unit) \| $ / bbl	56.31	66.55
Linefill (Price/Unit of measure) (in dollars per unit) \| $ / bbl	59.42	58.40
Long-term inventory (Price/Unit of measure) (in dollars per unit) \| $ / bbl	57.20	69.73
NGL
Inventory disclosures
Inventory, Volumes (in barrels) \| bbl	562	603
Linefill, Volumes (in barrels) \| bbl	33	32
Long-term inventory, Volumes (in barrels) \| bbl	26	90
Inventory subtotal, Carrying Value	$ 27	$ 26
Linefill subtotal, Carrying Value	2	1
Long-term inventory subtotal, Carrying Value	$ 1	$ 4
Inventory (Price/Unit of measure) (in dollars per unit) \| $ / bbl	48.04	43.12
Linefill (Price/Unit of measure) (in dollars per unit) \| $ / bbl	60.61	31.25
Long-term inventory (Price/Unit of measure) (in dollars per unit) \| $ / bbl	38.46	44.44
Other
Inventory disclosures
Inventory subtotal, Carrying Value	$ 18	$ 14

Leases - Lessor Future Minimum Lease Revenue (Details) $ in Millions	Dec. 31, 2025 USD ($)
Future minimum lease revenue
2026	$ 6
2027	2
2028	2
2029	2
2030	2
Thereafter	$ 1

Debt - Commercial Paper and Credit Facilities (Details) $ in Millions		12 Months Ended
	Dec. 01, 2025 USD ($)	Dec. 31, 2025 USD ($) extension	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Aug. 31, 2024 USD ($)
Debt Instrument [Line Items]
Repayments of PAA senior notes		$ 1,000	$ 750	$ 1,100
PAA Commercial Paper Notes
Debt Instrument [Line Items]
Maximum aggregate borrowing capacity		2,700
PAA Senior Secured Hedged Inventory Facility
Debt Instrument [Line Items]
Maximum aggregate borrowing capacity		1,900
Committed borrowing capacity		$ 1,350			$ 1,350
Number of years by which maturity date of credit facility may be extended (in years)		1 year
PAA Senior Secured Hedged Inventory Facility \| Minimum
Debt Instrument [Line Items]
Credit facility extensions available \| extension		1
PAA Senior Secured Hedged Inventory Facility \| Letters of Credit
Debt Instrument [Line Items]
Committed borrowing capacity		$ 400
Senior Unsecured Revolving Credit Facility, Maturiting in August 2027
Debt Instrument [Line Items]
Committed borrowing capacity					64
PAA Senior Unsecured Revolving Credit Facility
Debt Instrument [Line Items]
Maximum aggregate borrowing capacity		2,100
Committed borrowing capacity		$ 1,350			$ 1,350
Number of years by which maturity date of credit facility may be extended (in years)		1 year
PAA Senior Unsecured Revolving Credit Facility \| Minimum
Debt Instrument [Line Items]
Credit facility extensions available \| extension		1
PAA Senior Unsecured Revolving Credit Facility \| Letters of Credit
Debt Instrument [Line Items]
Committed borrowing capacity		$ 400
EPIC Credit Agreement
Debt Instrument [Line Items]
Repayments of PAA senior notes	$ 1,100
EPIC Credit Agreement \| Line of Credit
Debt Instrument [Line Items]
Maximum aggregate borrowing capacity		125
Debt instrument face value		$ 1,200

Commitments and Contingencies - Commitments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Leases
2026	$ 46
2027	44
2028	43
2029	34
2030	28
Thereafter	346
Total	541
Other commitments
2026	245
2027	215
2028	116
2029	114
2030	117
Thereafter	141
Total	948
Total
2026	291
2027	259
2028	159
2029	148
2030	145
Thereafter	487
Total	1,489
Expense associated with agreements	$ 363	$ 341	$ 348

Derivatives and Risk Management Activities - Broker Receivable/Payable (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Derivative assets and liabilities
Initial margin	$ 16	$ 16
Variation margin posted	4	15
Letters of credit	(95)	(90)
Net broker receivable	19	22
Exchange Traded
Derivative assets and liabilities
Letters of credit	$ (1)	$ (9)

Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions	12 Months Ended
	Dec. 31, 2025 TWh bbl
Crude Oil Purchases \| Long
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	5.8
Time Spread On Hedge Anticipated Crude Oil Lease Gathering Purchase Contracts \| Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	1.9
Crude Oil Grade Basis Position
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	1.5
Anticipated Net Sales Of Inventory \| Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	6.9
Power Supply Requirements Contracts \| Long
Commodity Price Risk Hedging:
Derivative position notional amount (in Terawatt hours) \| TWh	0.5

Leases - Other Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
Operating cash flows for operating leases	$ 40	$ 41	$ 44
Operating cash flows for finance leases	9	7	6
Financing cash flows for finance leases	23	15	10
Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications - operating leases	30	50	12
Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications - finance leases	$ 7	$ 23	$ 27
Weighted-average remaining lease term (in years):
Weighted-average remaining lease term (in years) - operating lease	21 years	20 years
Weighted-average remaining lease term (in years) - finance lease	8 years	7 years
Weighted-average discount rate:
Weighted-average discount rate - operating lease	5.50%	5.50%
Weighted-average discount rate - finance lease	11.10%	10.70%

Debt

12 Months Ended

Dec. 31, 2025

Debt Disclosure [Abstract]

Debt

Debt consisted of the following (in millions):


	December 31, 2025		December 31, 2024
SHORT-TERM DEBT
PAA commercial paper notes, bearing a weighted-average interest rate of 3.9% and 4.6%, respectively (1)	$	554	$	393



Other	9		14
Total short-term debt	563		407

LONG-TERM DEBT
PAA senior notes:



4.65% senior notes due October 2025 (2)	—		1,000
4.50% senior notes due December 2026 (3)	750		750
3.55% senior notes due December 2029	1,000		1,000
3.80% senior notes due September 2030	750		750
4.70% senior notes due January 2031	1,000		—
5.70% senior notes due September 2034	650		650
5.95% senior notes due June 2035	1,000		—
5.60% senior notes due January 2036	1,000		—
6.70% senior notes due May 2036	250		250
6.65% senior notes due January 2037	600		600
5.15% senior notes due June 2042	499		499
4.30% senior notes due January 2043	348		348
4.70% senior notes due June 2044	687		687
4.90% senior notes due February 2045	649		649
Unamortized discounts and debt issuance costs	(65)		(42)
PAA senior notes, net of unamortized discounts and debt issuance costs	9,118		7,141
Other long-term debt:
PAA commercial paper notes, bearing a weighted-average interest rate of 3.9% (3)	416		—
PAA term loan, net of debt issuance costs of $1, bearing a weighted-average interest rate of 5.0%	1,099		—

Other	63		70
Total long-term debt	10,696		7,211
Total debt (4)	$	11,259	$	7,618

(3)As of December 31, 2025, PAA classified its $750 million, 4.50% senior notes due December 2026 as long-term based on its ability and intent to refinance the notes on a long-term basis.

(4)As of December 31, 2025, we classified a portion of our commercial paper notes as long-term based on our ability and intent to refinance such amounts on a long-term basis.

PAA Commercial Paper Program

PAA has a commercial paper program under which it may issue (and have outstanding at any time) up to $2.7 billion in the aggregate of privately placed, unsecured commercial paper notes. Such notes are backstopped by the PAA senior unsecured revolving credit facility and the PAA senior secured hedged inventory facility; as such, any borrowings under the PAA commercial paper program reduce the available capacity under these facilities.

Credit Agreements

PAA senior secured hedged inventory facility. PAA has a credit agreement that provides for a senior secured hedged inventory facility with a committed borrowing capacity of $1.35 billion. Subject to obtaining additional or increased lender commitments and other terms and conditions, the committed capacity of the facility may be increased to $1.9 billion. The credit agreement provides for the issuance of letters of credit of up to $400 million. Proceeds from the facility are primarily used to finance purchased or stored hedged inventory, including NYMEX and ICE margin deposits. Such obligations under the committed facility are secured by the financed inventory and the associated accounts receivable and are repaid from the proceeds of the sale of the financed inventory. Borrowings accrue interest based, at our election, on certain floating rate indices as defined in the credit agreement, in each case plus a margin based on our credit rating at the applicable time. The amended credit agreement also provides for one or more one-year extensions, subject to applicable approval and other terms and conditions. The maturity date of the facility is August 2027 with respect to all extending lenders under the facility, except for a non-extending lender (which represents a commitment of approximately $64 million out of total commitments of $1.35 billion from all lenders), which has a maturity date of August 2026.

PAA senior unsecured revolving credit facility. PAA has a credit agreement that provides for a senior unsecured revolving credit facility with a committed borrowing capacity of $1.35 billion, of which $400 million is available for the issuance of letters of credit. Subject to obtaining additional or increased lender commitments and other terms and conditions, the committed capacity may be increased to $2.1 billion. Borrowings accrue interest based, at our election, on certain floating rate indices as defined in the credit agreement, in each case plus a margin based on our credit rating at the applicable time. The credit agreement provides for one or more one-year extensions, subject to applicable approval and other terms and conditions. The maturity date of the facility is August 2029 with respect to all extending lenders under the facility, except for a non-extending lender (which represents a commitment of approximately $64 million out of total commitments of $1.35 billion from all lenders), which has a maturity date of August 2027.

EPIC credit agreement. In connection with the EPIC Acquisition, completed on November 1, 2025, PAA assumed the EPIC credit agreement, which provided for a $1.2 billion term loan and a $125 million revolving credit facility. Borrowings under the EPIC credit agreement accrued interest based, at our election, on certain floating rate indices as defined in the EPIC credit agreement, in each case, plus an applicable margin. On December 1, 2025, PAA terminated the EPIC credit agreement and repaid the $1.1 billion of borrowings outstanding under the EPIC term loan.

Term Loan Agreement

On November 26, 2025, PAA entered into a term loan agreement that provides for a $1.1 billion senior unsecured term loan, which was funded on December 1, 2025. The term loan will mature in November 2027. PAA may at any time prepay amounts outstanding under the term loan agreement, in whole or in part, without premium or penalty. The closing of the Canadian NGL Business divestiture will trigger mandatory prepayment of all amounts outstanding under the term loan agreement within seven business days of the closing of such divestiture. Borrowings accrue interest based, at its election, on either Term SOFR or the Base Rate, in each case, plus an applicable rate. From the closing date to (but excluding) the first anniversary of the closing date, the applicable rate is 1.125% for Term SOFR Loans and 0.125% for Base Rate Loans; on and after the first anniversary, the applicable rate increases to 1.250% for Term SOFR Loans and 0.250% for Base Rate Loans.

PAA Senior Notes

PAA’s senior notes are co-issued, jointly and severally, by Plains All American Pipeline, L.P. and a 100%-owned consolidated finance subsidiary (neither of which have independent assets or operations) and are unsecured senior obligations of such entities and rank equally in right of payment with existing and future senior indebtedness of the issuers. PAA may, at its option, redeem any series of senior notes at any time in whole or from time to time in part, prior to maturity, at the redemption prices described in the indentures governing the senior notes. PAA’s senior notes are not guaranteed by any of its subsidiaries.

PAA Senior Notes Issuances. The table below summarizes PAA’s issuances of senior unsecured notes during the three years ended December 31, 2025 (face value in millions):

Issuance Date

Description

Maturity

Face Value

Interest Payment Dates

November 14, 2025

4.70% senior notes issued at 99.872% of face value

January 2031

300

January 15 and July 15

(1)

November 14, 2025

5.60% senior notes issued at 100.518% of face value

January 2036

450

January 15 and July 15

(2)

September 8, 2025

4.70% senior notes issued at 99.865% of face value

January 2031

700

January 15 and July 15

September 8, 2025

5.60% senior notes issued at 99.798% of face value

January 2036

550

January 15 and July 15

January 15, 2025

5.95% senior notes issued at 99.761% of face value

June 2035

1,000

June 15 and December 15

June 27, 2024

5.70% senior notes issued at 99.953% of face value

September 2034

650

March 15 and September 15

(1) Additional issuance of PAA 4.70% senior notes due 2031 that were issued on September 8, 2025, and trade interchangeably with such notes.

(2) Additional issuance of PAA 5.60% senior notes due 2036 that were issued on September 8, 2025 and trade interchangeably with such notes.

PAA Senior Notes Repayments. During the three years ended December 31, 2025, PAA repaid the following senior unsecured notes in full:

Repayment Date

Description

Maturity

October 3, 2025

$1,000 million 4.65% senior notes

October 2025

(1)

November 1, 2024

$750 million 3.60% senior notes

November 2024

(2)

(1)PAA repaid these senior notes with a combination of proceeds from PAA senior notes issued in September 2025, cash on hand and borrowings under its commercial paper program.

(2)PAA repaid these senior notes with a combination of proceeds from PAA senior notes issued in June 2024, cash on hand and borrowings under its commercial paper program.

Maturities

The weighted average maturity of PAA’s senior notes outstanding at December 31, 2025 was approximately 10 years. The following table presents the aggregate contractually scheduled maturities of such senior notes for the next five years and thereafter. The amounts presented exclude unamortized discounts and debt issuance costs.


Calendar Year	Payment (in millions)
2026	$	750
2027	$	—
2028	$	—
2029	$	1,000
2030	$	750
Thereafter	$	6,683

Covenants and Compliance

The credit agreements for PAA’s revolving credit facilities (which impact the ability to access the PAA commercial paper program because they provide the financial backstop that supports PAA’s short-term credit ratings), the term loan agreement and the indentures governing PAA’s senior notes contain cross-default provisions. PAA’s credit agreements prohibit declaration or payments of distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, PAA’s agreements contain various covenants limiting PAA’s ability to, among other things:

•grant liens on certain property;

•incur indebtedness, including finance leases;

•sell substantially all of its assets or enter into a merger or consolidation;

•engage in certain transactions with affiliates; and

•enter into certain burdensome agreements.

The credit agreements for the PAA senior unsecured revolving credit facility and senior secured hedged inventory facility and the term loan agreement treat a change of control as an event of default and also require PAA to maintain a debt-to-EBITDA coverage ratio that, on a trailing four-quarter basis, will not be greater than 5.00 to 1.00 (or 5.50 to 1.00 on all outstanding debt during an acquisition period (generally, the period consisting of three fiscal quarters following an acquisition greater than $150 million)). For covenant compliance purposes, Consolidated EBITDA may include certain adjustments, including those for material projects and certain non-recurring expenses. Additionally, letters of credit and borrowings to fund hedged inventory and margin requirements are excluded when calculating the debt coverage ratio.

A default under PAA’s credit agreements, term loan agreement or indentures would permit the lenders to accelerate the maturity of the outstanding debt. As long as PAA is in compliance with the provisions contained in its credit agreements and term loan agreement, PAA’s ability to make distributions of available cash is not restricted. As of December 31, 2025, PAA was in compliance with the covenants contained in its credit agreements, term loan agreement and indentures.

Borrowings and Repayments

Total borrowings under PAA’s credit facilities and commercial paper program for the years ended December 31, 2025, 2024 and 2023 were approximately $56.4 billion, $28.1 billion and $18.1 billion, respectively. Total repayments under PAA’s credit facilities and commercial paper program were approximately $55.8 billion, $28.1 billion and $17.7 billion for the years ended December 31, 2025, 2024 and 2023, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.

Letters of Credit

In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil and NGL. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil or NGL is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At December 31, 2025 and 2024, we had outstanding letters of credit of $95 million and $90 million, respectively.

Debt Issuance Costs

Costs incurred in connection with the issuance of senior notes are recorded as a direct deduction from the related debt liability and are amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization.

- 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
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-URI https://asc.fasb.org/1943274/2147481544/470-10-50-6

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-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

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-SubTopic 30
-Name Accounting Standards Codification
-Section 45
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482925/835-30-45-2

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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1I

+ Details

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Deferred tax assets:
Investment in partnerships	$ 151	$ 436
Net operating losses	985	784
Derivative instruments	0	6
Lease liabilities	10	8
Other	7	8
Total deferred tax assets	1,153	1,242
Deferred tax liabilities:
Property and equipment in excess of tax values	(204)	(188)
Lease assets	(9)	(10)
Other	(1)	0
Total deferred tax liabilities	(214)	(198)
Net deferred tax assets	939	1,044
Deferred tax asset	1,136	1,220
Deferred tax asset
Deferred tax liabilities:
Deferred tax asset	1,136	1,220
Other long-term liabilities and deferred credits
Deferred tax liabilities:
Other long-term liabilities and deferred credits	$ (197)	$ (176)

Revenues and Accounts Receivable - Performance Obligations (Details) $ in Millions	Dec. 31, 2025 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 639
Remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 541
Remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 449
Remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2029-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 319
Remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2030-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 224
Remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2031-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 1,258
Remaining performance obligation, expected timing of satisfaction, period
Pipeline revenues supported by minimum volume commitments and capacity agreements \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 398
Remaining performance obligation, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and capacity agreements \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 330
Remaining performance obligation, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and capacity agreements \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 296
Remaining performance obligation, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and capacity agreements \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2029-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 210
Remaining performance obligation, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and capacity agreements \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2030-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 152
Remaining performance obligation, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and capacity agreements \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2031-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 835
Remaining performance obligation, expected timing of satisfaction, period
Terminalling, storage and other agreement revenues \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 241
Remaining performance obligation, expected timing of satisfaction, period	1 year
Terminalling, storage and other agreement revenues \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 211
Remaining performance obligation, expected timing of satisfaction, period	1 year
Terminalling, storage and other agreement revenues \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 153
Remaining performance obligation, expected timing of satisfaction, period	1 year
Terminalling, storage and other agreement revenues \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2029-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 109
Remaining performance obligation, expected timing of satisfaction, period	1 year
Terminalling, storage and other agreement revenues \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2030-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 72
Remaining performance obligation, expected timing of satisfaction, period	1 year
Terminalling, storage and other agreement revenues \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2031-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 423
Remaining performance obligation, expected timing of satisfaction, period