0001070423-24-000008 | 10-K | XBRL Viewer | Plains ALL American Pipeline LP

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Acquisitions, Divestitures and Other Transactions - Partners' Capital (Details) - Plains Oryx Permian Basin LLC - Joint Venture Transaction - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2021	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Partners’ capital, excluding noncontrolling interests		$ (26)	$ 3,256
Noncontrolling Interests
Business Acquisition [Line Items]
Partners’ capital, excluding noncontrolling interests		(16)	2,651
Partners’ Capital Excluding Noncontrolling Interests
Business Acquisition [Line Items]
Partners’ capital, excluding noncontrolling interests	$ 595	$ (10)	$ 605
Oryx Midstream Holdings LLC \| Noncontrolling Interests
Business Acquisition [Line Items]
Noncontrolling interests	2,635
Oryx Midstream Holdings LLC
Business Acquisition [Line Items]
Partners’ capital, excluding noncontrolling interests	$ 3,230

Derivatives and Risk Management Activities - Broker Receivable/Payable (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Derivative assets and liabilities
Initial margin	$ 77	$ 93
Variation margin returned	(65)	(236)
Letters of credit	(205)	(102)
Net broker payable	(13)	(168)
Exchange Traded
Derivative assets and liabilities
Letters of credit	$ (25)	$ (25)

Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 122	$ 143	$ 135
Liabilities incurred	2	2	2
Liabilities settled	(1)	(26)	(1)
Accretion expense	4	4	4
Revisions in estimated cash flows	(1)	(1)	3
Ending balance	$ 126	$ 122	$ 143

Organization and Basis of Consolidation and Presentation

12 Months Ended

Dec. 31, 2023

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Basis of Consolidation and Presentation

Organization

Plains All American Pipeline, L.P. (“PAA”) is a Delaware limited partnership formed in 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in this Form 10-K and unless the context indicates otherwise, the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAA and its subsidiaries.

Our 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 midstream service providers in North America, we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and natural gas liquids (“NGL”) producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. Our assets and the services we provide are primarily focused on and conducted through two operating segments: Crude Oil and NGL. See Note 19 for further discussion of our operating segments.

Our non-economic general partner interest is held by PAA GP LLC (“PAA GP”), a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP, as of December 31, 2023, AAP also owned a limited partner interest in us through its ownership of approximately 232.7 million of our common units (approximately 30% of our total outstanding common units and Series A preferred units combined). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole and managing member of GP LLC, and, at December 31, 2023, owned an approximate 84% limited partner interest in AAP. PAA GP Holdings LLC (“PAGP GP”) is the general partner of PAGP.

As the sole member of GP LLC, PAGP has responsibility for conducting our business and managing our operations; however, the board of directors of PAGP GP has ultimate responsibility for managing the business and affairs of PAGP, AAP and us. GP LLC employs our domestic officers and personnel; our Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC.

References to the “PAGP Entities” include PAGP GP, PAGP, GP LLC, AAP and PAA GP. References to our “general partner,” as the context requires, include any or all of the PAGP Entities. References to the “Plains Entities” include us, our subsidiaries and the PAGP Entities.

Definitions

Additional defined terms are 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
Bcf	=	Billion cubic feet
Btu	=	British thermal unit
CAD	=	Canadian dollar
CODM	=	Chief Operating Decision Maker
DERs	=	Distribution equivalent rights
EBITDA	=	Earnings before interest, taxes, depreciation and amortization
EPA	=	United States Environmental Protection Agency
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
Mcf	=	Thousand cubic feet
MMbls	=	Million barrels
MLP	=	Master limited partnership
NGL	=	Natural gas liquids, including ethane, propane and butane
NYMEX	=	New York Mercantile Exchange
SEC	=	United States Securities and Exchange Commission
SOFR	=	Secured Overnight Financing Rate
TWh	=	Terawatt hour
U.S.	=	United States
USD	=	United States dollar
WTI	=	West Texas Intermediate

Basis of Consolidation and Presentation

The accompanying financial statements and related notes present and discuss our consolidated financial position as of December 31, 2023 and 2022, 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, 2023, 2022 and 2021. 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.

The accompanying consolidated financial statements include the accounts of PAA 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.

Subsequent Events

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

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Non-Cancelable Commitments

We have commitments (some of which are leases) related to real property, equipment and operating facilities. We also incur costs associated with leased land, rights-of-way, permits and regulatory fees. Future noncancelable commitments related to these items at December 31, 2023 are summarized below (in millions):


	2024		2025		2026		2027		2028		Thereafter		Total
Leases (1)	$	100	$	85	$	64	$	55	$	49	$	286	$	639
Other commitments (2)	367		336		249		217		117		425		1,711
Total	$	467	$	421	$	313	$	272	$	166	$	711	$	2,350

(1)Includes both operating and finance leases as defined by FASB guidance. Leases are primarily for (i) railcars, (ii) office space, (iii) land, (iv) vehicles, (v) storage tanks and (vi) tractor trailers. See Note 13 for additional information.

(2)Primarily includes storage, transportation and pipeline throughput agreements, as well as certain rights-of-way easements. Expense associated with our storage, transportation and pipeline throughput agreements was approximately $396 million, $336 million and $270 million for 2023, 2022 and 2021, 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.

Derivatives and Risk Management Activities - Interest Rate Risk Hedging (Details) - Cash Flow Hedging $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) contract
8 forward starting swaps (30-year), 3.09%
Interest Rate Derivatives [Abstract]
Number of interest rate derivatives \| contract	8
Term of derivative contract	30 years
Notional amount of derivatives \| $	$ 200
Average rate locked (percent)	3.09%
4 forward starting swaps (30-year), 0.74%
Interest Rate Derivatives [Abstract]
Number of interest rate derivatives \| contract	4
Term of derivative contract	30 years
Notional amount of derivatives \| $	$ 100
Average rate locked (percent)	0.74%

Partners' Capital and Distributions - Income Allocation and Distributions to Unitholders (Details)	12 Months Ended
	Dec. 31, 2023
Partners' Capital Notes [Abstract]
Net income allocation (as a percent)	100.00%
Number of days after end of quarter within which distributions must be paid to unitholders (in days)	45 days

Organization and Basis of Consolidation and Presentation (Details) shares in Millions	12 Months Ended
	Dec. 31, 2023 segment shares
Organization and basis of presentation
Operating segments number \| segment	2
AAP \| PAGP
Organization and basis of presentation
Ownership interest (as a percent)	84.00%
PAA \| AAP
Organization and basis of presentation
Ownership interest (in units) \| shares	232.7
Ownership interest (as a percent)	30.00%

Debt - Maturities (Details) $ in Millions	12 Months Ended
Debt - Maturities (Details) $ in Millions	Dec. 31, 2023 USD ($)
Debt Disclosure [Abstract]
Weighted-average maturity of long-term debt	10 years
Maturities
2024	$ 750
2025	1,000
2026	750
2027	0
2028	0
Thereafter	$ 4,783

Partners' Capital and Distributions - Distributions to Noncontrolling Interests (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Partners Capital and Distribution [Line Items]
Distributions paid		$ 1,330	$ 1,083	$ 729
Noncontrolling Interests
Partners Capital and Distribution [Line Items]
Distributions paid		333	298	14
Cash Distribution \| Noncontrolling Interests \| Consolidated Joint Venture Entities
Partners Capital and Distribution [Line Items]
Distributions paid		333	298	14
Cash Distribution \| Noncontrolling Interests \| Plains Oryx Permian Basin LLC
Partners Capital and Distribution [Line Items]
Distributions paid	$ 54	249	273
Cash Distribution \| Noncontrolling Interests \| Cactus II Pipeline LLC
Partners Capital and Distribution [Line Items]
Distributions paid		63	4
Cash Distribution \| Noncontrolling Interests \| Red River
Partners Capital and Distribution [Line Items]
Distributions paid		$ 21	$ 21	$ 14

Acquisitions, Divestitures and Other Transactions - Other Acquisitions Narrative (Details) - USD ($) $ in Millions	1 Months Ended			3 Months Ended
	Nov. 30, 2023	Oct. 31, 2022	Jul. 31, 2022	Sep. 30, 2023
Certain Straddle Plants \| NGL
Business Acquisition [Line Items]
Obligation, processing capacity term (in years)		50 years
Asset acquisition, consideration transferred		$ 122
Revenue recognition term (in years)		50 years
Northern Delaware Basin Gathering System
Business Acquisition [Line Items]
Asset acquisition amount, net to our interest in the Permian JV	$ 88
Plains Oryx Permian Basin LLC
Business Acquisition [Line Items]
Consolidated subsidiary, ownership interest held by the parent (as a percent)	65.00%		65.00%	65.00%
Advantage Pipeline Holdings LLC
Business Acquisition [Line Items]
Cash consideration, including working capital and other adjustments			$ 74
Business acquisition amount, net to our interest in the Permian JV			$ 48
Additional interest acquired (as a percent)			50.00%
Business combination, step acquisition, equity interest in acquiree, including subsequent acquisition (as a percent)			100.00%
Subsidiary of LM Energy Partners \| Plains Oryx Permian Basin LLC \| Northern Delaware Basin Gathering System
Business Acquisition [Line Items]
Asset acquisition, consideration transferred	$ 135

Income Taxes

12 Months Ended

Dec. 31, 2023

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, 2023 and 2022, we had not recognized any material amounts in connection with uncertainty in income taxes.

U.S. Federal and State Taxes

As an MLP, we are not subject to U.S. federal income taxes; rather the tax effect of our operations is passed through to our unitholders. Although we are subject to state income taxes in some states, the impact to the years ended December 31, 2023, 2022, and 2021 was immaterial.

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 that 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

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


	Year Ended December 31,
	2023		2022		2021
Current income tax expense:
State income tax	$	2	$	1	$	2
Canadian federal and provincial income tax	143		83		48
Total current income tax expense	$	145	$	84	$	50

Deferred income tax expense/(benefit):
Canadian federal and provincial income tax	$	(24)	$	105	$	23
Total deferred income tax expense/(benefit)	$	(24)	$	105	$	23
Total income tax expense	$	121	$	189	$	73

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):


	Year Ended December 31,
	2023		2022		2021
Income before tax	$	1,623	$	1,417	$	721
Partnership earnings not subject to Canadian tax	(1,136)		(686)		(370)
	$	487	$	731	$	351
Canadian federal and provincial corporate tax rate	24%		24%		24%
Income tax expense at statutory rate	$	117	$	175	$	84


Canadian permanent differences	$	2	$	13	$	(13)
State income tax	2		1		2
Total income tax expense	$	121	$	189	$	73

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


	December 31,
	2023		2022
Deferred tax assets:

Lease liabilities	$	40	$	45

Other	45		16
Total deferred tax assets	85		61

Deferred tax liabilities:
Property and equipment in excess of tax values	(573)		(515)
Derivative instruments	(6)		(46)
Lease assets	(38)		(42)
Other	(3)		(3)
Total deferred tax liabilities	(620)		(606)
Net deferred tax liabilities	$	(535)	$	(545)

Balance sheet classification of deferred tax assets/(liabilities):

Other long-term liabilities and deferred credits	$	(535)	$	(545)
	$	(535)	$	(545)

Generally, tax returns for our Canadian entities are open to audit from 2017 through 2023. Our U.S. and state tax years are generally open to examination from 2020 to 2023.

As of December 31, 2023, in reference to tax years 2012 to 2018, 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. These notices include assessments, including penalties and interest, associated with these transfer pricing matters totaling approximately $165 million (based on the exchange rate as of December 31, 2023). 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 $87 million (based on the exchange rate as of December 31, 2023) 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, 2023, 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 taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480990/946-20-50-13

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

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-Name Accounting Standards Codification
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-URI https://asc.fasb.org//740/tableOfContent

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 14
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482685/740-10-50-14

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
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-Name Accounting Standards Codification
-Section 50
-Paragraph 21
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-URI https://asc.fasb.org//1943274/2147482685/740-10-50-21

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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-URI https://asc.fasb.org//1943274/2147482526/740-270-50-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
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-Paragraph 17
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482685/740-10-50-17

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.5.Q1)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479360/740-10-S99-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SAB Topic 11.C)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479360/740-10-S99-2

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482603/740-30-50-2

+ Details

Net Income Per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Basic and Diluted Net Income per Common Unit
Net income attributable to PAA	$ 1,230	$ 1,037	$ 593
Amounts allocated to participating securities	(10)	(5)	(2)
Other	5
Net income allocated to common unitholders — Basic	976	831	393
Net income allocated to common unitholders — Diluted	976	831	393
Series A Preferred Units
Basic and Diluted Net Income per Common Unit
Distributions to preferred unitholders	$ (173)	$ (149)	$ (149)
Series A Preferred Units \| Weighted Average
Net Income Per Common Unit
Antidilutive securities excluded from computation of net income per common unit (in units)	71	71	71
Series B Preferred Units
Basic and Diluted Net Income per Common Unit
Distributions to preferred unitholders	$ (76)	$ (52)	$ (49)
Common Units
Basic and Diluted Net Income per Common Unit
Basic weighted average common units outstanding (in units)	699	701	716
Diluted weighted average common units outstanding (in units)	699	701	716
Basic net income per common unit (in dollars per unit)	$ 1.40	$ 1.19	$ 0.55
Diluted net income per common unit (in dollars per unit)	$ 1.40	$ 1.19	$ 0.55

Acquisitions, Divestitures and Other Transactions - Cactus II Narrative (Details) $ in Millions	1 Months Ended
	Nov. 30, 2022 USD ($)	Dec. 31, 2023	Oct. 31, 2022
Cactus II Pipeline LLC
Business Acquisition [Line Items]
Ownership Interest in Unconsolidated Entity Prior to Acquisition (as a percent)			65.00%
Cactus II Pipeline LLC
Business Acquisition [Line Items]
Noncontrolling interest, ownership (as a percent)		30.00%
Cactus II Pipeline LLC \| Enbridge
Business Acquisition [Line Items]
Noncontrolling interest, ownership (as a percent)	30.00%
Cactus II Pipeline LLC
Business Acquisition [Line Items]
Additional interest acquired (as a percent)	5.00%
Business combination, step acquisition, equity interest in acquiree, including subsequent acquisition (as a percent)	70.00%
Business combination, step acquisition, equity interest in acquire (as a percent)			65.00%
Fair value amount	$ 1,140
Consideration transferred	1,556
Cactus II Pipeline LLC \| Gains/(losses) on investments in unconsolidated entities, net
Business Acquisition [Line Items]
Equity interest in acquiree, remeasurement gain	370
Cactus II Pipeline LLC \| Noncontrolling Interests
Business Acquisition [Line Items]
Noncontrolling interest, increase from business combination	$ 526
Cactus II Pipeline LLC \| Level 3 \| Measurement Input, Discount Rate \| Valuation Technique, Discounted Cash Flow
Business Acquisition [Line Items]
Business combination, measurement input	0.14
Cactus II Pipeline LLC \| Level 3 \| Measurement Input, Discount Rate \| Valuation Technique, Discounted Cash Flow \| Intangible Assets
Business Acquisition [Line Items]
Business combination, measurement input	0.18
Cactus II Pipeline LLC \| Western Midstream Partners, LP
Business Acquisition [Line Items]
Payments to acquire businesses, gross	$ 88
Cactus II Pipeline LLC \| Plains and Enbridge \| Western Midstream Partners, LP
Business Acquisition [Line Items]
Additional interest acquired (as a percent)	15.00%
Payments to acquire businesses, gross	$ 265
Cactus II Pipeline LLC \| Enbridge
Business Acquisition [Line Items]
Additional interest acquired (as a percent)	10.00%
Cactus II Pipeline LLC \| Enbridge \| Western Midstream Partners, LP
Business Acquisition [Line Items]
Payments to acquire businesses, gross	$ 177

Partners' Capital and Distributions - Noncontrolling Interests in Subsidiaries (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Nov. 30, 2022	Oct. 31, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2023
Plains Oryx Permian Basin LLC \| Joint Venture Transaction
Partners Capital and Distribution [Line Items]
Partners’ capital, excluding noncontrolling interests			$ (26)	$ 3,256
Plains Oryx Permian Basin LLC \| Noncontrolling Interests \| Joint Venture Transaction
Partners Capital and Distribution [Line Items]
Partners’ capital, excluding noncontrolling interests			(16)	2,651
Plains Oryx Permian Basin LLC \| Noncontrolling Interests \| Joint Venture Transaction \| Oryx Midstream Holdings LLC
Partners Capital and Distribution [Line Items]
Noncontrolling interest, increase from business combination		$ 2,635
Plains Oryx Permian Basin LLC \| Partners’ Capital Excluding Noncontrolling Interests \| Joint Venture Transaction
Partners Capital and Distribution [Line Items]
Partners’ capital, excluding noncontrolling interests		595	(10)	$ 605
Cactus II Pipeline LLC
Partners Capital and Distribution [Line Items]
Additional interest acquired (as a percent)	5.00%
Business combination, step acquisition, equity interest in acquiree, including subsequent acquisition (as a percent)	70.00%
Partners’ capital, excluding noncontrolling interests			526
Cactus II Pipeline LLC \| Noncontrolling Interests
Partners Capital and Distribution [Line Items]
Noncontrolling interest, increase from business combination	$ 526
Partners’ capital, excluding noncontrolling interests			$ 526
Oryx Midstream Holdings LLC \| Plains Oryx Permian Basin LLC \| Joint Venture Transaction
Partners Capital and Distribution [Line Items]
Partners’ capital, excluding noncontrolling interests		$ 3,230
Plains Oryx Permian Basin LLC
Partners Capital and Distribution [Line Items]
Noncontrolling interest, ownership (as a percent)					35.00%
Plains Oryx Permian Basin LLC \| Oryx Midstream Holdings LLC \| Joint Venture Transaction
Partners Capital and Distribution [Line Items]
Noncontrolling interest, ownership (as a percent)		35.00%
Noncontrolling interest, ownership (as a parent)		65.00%
Cactus II Pipeline LLC
Partners Capital and Distribution [Line Items]
Noncontrolling interest, ownership (as a percent)					30.00%
Cactus II Pipeline LLC \| Enbridge
Partners Capital and Distribution [Line Items]
Noncontrolling interest, ownership (as a percent)	30.00%
Red River Pipeline Company LLC
Partners Capital and Distribution [Line Items]
Noncontrolling interest, ownership (as a percent)					33.00%

Revenues and Accounts Receivable - Segment Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Total revenues	$ 48,712	$ 57,342	$ 42,078
Operating Segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	48,999	57,473	42,949
Other revenues	110	368	(511)
Total revenues	49,109	57,841	42,438
Operating Segments \| Crude Oil
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	47,146	54,929	40,550
Other revenues	28	151	(80)
Total revenues	47,174	55,080	40,470
Operating Segments \| NGL
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,853	2,544	2,399
Other revenues	82	217	(431)
Total revenues	1,935	2,761	1,968
Intersegment revenues elimination
Disaggregation of Revenue [Line Items]
Total revenues	$ (397)	$ (499)	$ (360)

- 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

- Definition

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.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 924
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SAB Topic 11.L)
-Publisher FASB
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

- Definition

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

+ References

+ Details

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2023
Audit Information [Abstract]
Auditor Firm ID	238
Auditor Name	PricewaterhouseCoopers LLP
Auditor Location	Houston, Texas

Related Party Transactions - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
GP
Related Party Transactions
Costs reimbursed to general partner	$ 546	$ 476	$ 467
Principal Owner \| AAP \| Minimum
Related Party Transactions
Ownership interest (as a percent)	10.00%
Class C Shares \| PAGP
Related Party Transactions
Ownership interest (in units)	539,445,289	528,442,538

Inventory, Linefill and Long-term Inventory - Components of Inventory, Linefill and Long-term Inventory (Details) bbl in Thousands, $ in Millions	Dec. 31, 2023 USD ($) $ / bbl bbl	Dec. 31, 2022 USD ($) $ / bbl bbl
Inventory by category
Inventory subtotal, carrying value	$ 548	$ 729
Linefill subtotal, carrying value	976	961
Long-term inventory subtotal, carrying value	265	284
Total	$ 1,789	$ 1,974
Crude oil
Inventory by category
Inventory, Volumes (in barrels) \| bbl	5,877	6,713
Linefill, Volumes (in barrels) \| bbl	15,409	15,480
Long-term inventory, Volumes (in barrels) \| bbl	3,256	3,102
Inventory subtotal, carrying value	$ 383	$ 452
Linefill subtotal, carrying value	909	906
Long-term inventory subtotal, carrying value	$ 232	$ 246
Inventory (Price/Unit of measure) (in dollars per unit) \| $ / bbl	65.17	67.33
Linefill (Price/Unit of measure) (in dollars per unit) \| $ / bbl	58.99	58.53
Long-term inventory (Price/Unit of measure) (in dollars per unit) \| $ / bbl	71.25	79.30
NGL
Inventory by category
Inventory, Volumes (in barrels) \| bbl	5,957	7,285
Linefill, Volumes (in barrels) \| bbl	2,168	1,876
Long-term inventory, Volumes (in barrels) \| bbl	1,326	1,066
Inventory subtotal, carrying value	$ 154	$ 270
Linefill subtotal, carrying value	67	55
Long-term inventory subtotal, carrying value	$ 33	$ 38
Inventory (Price/Unit of measure) (in dollars per unit) \| $ / bbl	25.85	37.06
Linefill (Price/Unit of measure) (in dollars per unit) \| $ / bbl	30.90	29.32
Long-term inventory (Price/Unit of measure) (in dollars per unit) \| $ / bbl	24.89	35.65
Other
Inventory by category
Inventory subtotal, carrying value	$ 11	$ 7

Intangible Asset, Net (Tables)

12 Months Ended

Dec. 31, 2023

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, 2023						December 31, 2022
	Estimated Useful Lives (Years)	Cost		Accumulated Amortization		Net		Cost		Accumulated Amortization		Net
Customer contracts and relationships	1 – 29	$	2,789	$	(932)	$	1,857	$	2,817	$	(695)	$	2,122

Other agreements	15 – 70	30		(12)		18		35		(12)		23
Intangible assets (1)		$	2,819	$	(944)	$	1,875	$	2,852	$	(707)	$	2,145

(1)We include rights-of-way, which are intangible assets, within property and equipment. See Note 6 for a discussion of property and equipment.

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):


2024	$	272
2025	$	249
2026	$	210
2027	$	187
2028	$	165

Debt - Commercial Paper and Credit Facilities (Details) $ in Millions	1 Months Ended	12 Months Ended
	Aug. 31, 2021 USD ($)	Dec. 31, 2023 USD ($) extension	Dec. 31, 2021 USD ($)	Aug. 31, 2023 USD ($)
Debt Instrument [Line Items]
Repayments of debt			$ 200
GO Zone Term Loans \| Term Loan
Debt Instrument [Line Items]
Repayments of debt	$ 200
Commercial Paper
Debt Instrument [Line Items]
Maximum aggregate borrowing capacity		$ 2,700
Senior Secured Hedged Inventory Facility
Debt Instrument [Line Items]
Maximum aggregate borrowing capacity		1,900
Committed borrowing capacity		$ 1,350
Number of years by which maturity date of credit facility may be extended (in years)		1 year
Senior Secured Hedged Inventory Facility \| Minimum
Debt Instrument [Line Items]
Credit facility extensions available \| extension		1
Senior Secured Hedged Inventory Facility \| Letters of credit
Debt Instrument [Line Items]
Committed borrowing capacity		$ 400
Senior Unsecured Revolving Credit Facility
Debt Instrument [Line Items]
Maximum aggregate borrowing capacity		2,100
Committed borrowing capacity		$ 1,350
Number of years by which maturity date of credit facility may be extended (in years)		1 year
Senior Unsecured Revolving Credit Facility \| Minimum
Debt Instrument [Line Items]
Credit facility extensions available \| extension		1
Senior Unsecured Revolving Credit 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

Revenues and Accounts Receivable - Contract Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Change in Contract Liabilities [Roll Forward]
Beginning balance	$ 229	$ 141
Amounts recognized as revenue	(42)	(26)
Additions	38	145
Other	3	(31)
Ending balance	$ 228	229
Gas Processing Agreement That Was Entered Into In Conjunction With The Purchase Of An Additional Ownership Interest In Certain Straddle Plants
Change in Contract Liabilities [Roll Forward]
Additions		$ 122
Revenue recognition term (in years)		50 years

Inventory, Linefill and Long-term Inventory (Tables)

12 Months Ended

Dec. 31, 2023

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, 2023						December 31, 2022
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	5,877	barrels	$	383	$	65.17	6,713	barrels	$	452	$	67.33
NGL	5,957	barrels	154		$	25.85	7,285	barrels	270		$	37.06

Other	N/A		11		N/A		N/A		7		N/A
Inventory subtotal			548						729

Linefill
Crude oil	15,409	barrels	909		$	58.99	15,480	barrels	906		$	58.53
NGL	2,168	barrels	67		$	30.90	1,876	barrels	55		$	29.32

Linefill subtotal			976						961

Long-term inventory
Crude oil	3,256	barrels	232		$	71.25	3,102	barrels	246		$	79.30
NGL	1,326	barrels	33		$	24.89	1,066	barrels	38		$	35.65
Long-term inventory subtotal			265						284

Total			$	1,789					$	1,974

(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, 2023						December 31, 2022
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	5,877	barrels	$	383	$	65.17	6,713	barrels	$	452	$	67.33
NGL	5,957	barrels	154		$	25.85	7,285	barrels	270		$	37.06

Other	N/A		11		N/A		N/A		7		N/A
Inventory subtotal			548						729

Linefill
Crude oil	15,409	barrels	909		$	58.99	15,480	barrels	906		$	58.53
NGL	2,168	barrels	67		$	30.90	1,876	barrels	55		$	29.32

Linefill subtotal			976						961

Long-term inventory
Crude oil	3,256	barrels	232		$	71.25	3,102	barrels	246		$	79.30
NGL	1,326	barrels	33		$	24.89	1,066	barrels	38		$	35.65
Long-term inventory subtotal			265						284

Total			$	1,789					$	1,974

Segment Information (Tables)

12 Months Ended

Dec. 31, 2023

Segment Reporting [Abstract]

Schedule of Segment Financial Data

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


	Crude Oil		NGL		Intersegment Revenues Elimination		Total
Year Ended December 31, 2023
Revenues (1):
Product sales	$	45,587	$	1,765	$	(378)	$	46,974
Services	1,587		170		(19)		1,738
Total revenues	$	47,174	$	1,935	$	(397)	$	48,712
Equity earnings in unconsolidated entities	$	369	$	—			$	369
Segment Adjusted EBITDA	$	2,163	$	522			$	2,685
Investment and acquisition capital expenditures (2) (3)	$	765	$	65			$	830
Maintenance capital expenditures (3)	$	145	$	86			$	231

As of December 31, 2023

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


	Crude Oil		NGL		Intersegment Revenues Elimination		Total
Year Ended December 31, 2022
Revenues (1):
Product sales	$	53,840	$	2,575	$	(467)	$	55,948
Services	1,240		186		(32)		1,394
Total revenues	$	55,080	$	2,761	$	(499)	$	57,342
Equity earnings in unconsolidated entities	$	403	$	—			$	403
Segment Adjusted EBITDA	$	1,986	$	518			$	2,504
Investment and acquisition capital expenditures (2) (3)	$	461	$	157			$	618
Maintenance capital expenditures (3)	$	112	$	99			$	211

As of December 31, 2022

Investments in unconsolidated entities	$	3,084	$	—			$	3,084


	Crude Oil		NGL		Intersegment Revenues Elimination		Total
Year Ended December 31, 2021
Revenues (1):
Product sales	$	39,395	$	1,829	$	(341)	$	40,883
Services	1,075		139		(19)		1,195
Total revenues	$	40,470	$	1,968	$	(360)	$	42,078
Equity earnings in unconsolidated entities	$	274	$	—			$	274
Segment Adjusted EBITDA	$	1,909	$	285			$	2,194
Investment and acquisition capital expenditures (2) (3)	$	212	$	57			$	269
Maintenance capital expenditures (3)	$	100	$	68			$	168

As of December 31, 2021

Investments in unconsolidated entities	$	3,805	$	—			$	3,805

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

(3)These amounts combined represent total capital expenditures.

Schedule of Reconciliation of Segment Adjusted EBITDA to Net Income/(Loss) Attributable to PAA

The following table reconciles Segment Adjusted EBITDA to Net income attributable to PAA (in millions):


	Year Ended December 31,
	2023		2022		2021
Segment Adjusted EBITDA	$	2,685	$	2,504	$	2,194
Adjustments (1):
Depreciation and amortization of unconsolidated entities (2)	(87)		(85)		(123)
Derivative activities and inventory valuation adjustments (3)	(159)		280		271
Long-term inventory costing adjustments (4)	(35)		4		94
Deficiencies under minimum volume commitments, net (5)	(12)		(7)		7
Equity-indexed compensation expense (6)	(36)		(32)		(19)
Foreign currency revaluation (7)	(24)		(4)		4
Line 901 incident (8)	(10)		(95)		(15)
Transaction-related expenses (9)	(1)		—		(16)
Segment amounts attributable to noncontrolling interests (10)	454		364		94
Depreciation and amortization	(1,048)		(965)		(774)
Gains/(losses) on asset sales and asset impairments, net	152		(269)		(592)
Gains/(losses) on investments in unconsolidated entities, net	28		346		2
Interest expense, net	(386)		(405)		(425)
Other income/(expense), net	102		(219)		19
Income before tax	1,623		1,417		721
Income tax expense	(121)		(189)		(73)
Net income	1,502		1,228		648
Net income attributable to noncontrolling interests	(272)		(191)		(55)
Net income attributable to PAA	$	1,230	$	1,037	$	593

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

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

(3)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.

(4)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.

(5)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.

(6)Our total equity-indexed compensation expense includes expense associated with awards that will be settled in units and awards that will be settled in cash. The awards that will be settled in units are included in our 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 our 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 17 for information regarding our equity-indexed compensation plans.

(7)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.

(8)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. See Note 18 for additional information regarding the Line 901 incident.

(9)Includes expenses associated with the Rattler Permian Transaction in 2023 and the Permian JV transaction in 2021. See Note 7 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, 2023 and 2021 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 (beginning October 2021), Cactus II (beginning November 2022) and Red River.

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)	2023		2022		2021
United States	$	42,308	$	46,903	$	34,458
Canada	6,404		10,439		7,620
	$	48,712	$	57,342	$	42,078

(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)	2023		2022
United States	$	18,591	$	18,655
Canada	3,820		3,802
	$	22,411	$	22,457

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

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Net income	$ 1,502	$ 1,228	$ 648
Other comprehensive income/(loss)	118	(101)	65
Comprehensive income	1,620	1,127	713
Comprehensive income attributable to noncontrolling interests	(272)	(191)	(55)
Comprehensive income attributable to PAA	$ 1,348	$ 936	$ 658

- Definition

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.

+ References + Details

- Definition

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

+ References + Details

- Definition

Amount after tax and reclassification adjustments of other comprehensive income (loss).

+ References

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The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

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+ Details

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2023

Schedule of Related Party Transactions

As of December 31, 2023, our outstanding related party note receivable and related party note payable balances were as follows (in millions):


	December 31, 2023
Related party note receivable (1)	$	379
Related party note payable (1)	$	379

(1)We have elected to present our related party notes with the same counterparty on a net basis on our Consolidated Balance Sheet because there is a legal right to offset and we intend to offset with the counterparty.

During the three years ended December 31, 2023, 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,
	2023		2022		2021



Revenues from related parties	$	48	$	45	$	33




Purchases and related costs from related parties	$	404	$	365	$	385

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


	December 31,
	2023		2022



Trade accounts receivable and other receivables, net from related parties (1)	$	63	$	45




Trade accounts payable to related parties (1) (2)	$	72	$	79

(1)Includes amounts related to transportation and storage services and amounts owed to us or advanced to us related to investment capital projects of equity method investees where we serve as construction manager.

(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.

Related Party Transactions

12 Months Ended

Dec. 31, 2023

Related Party Transactions

Ownership of PAGP Class C Shares

As of December 31, 2023 and 2022, we owned 539,445,289 and 528,442,538, respectively, Class C shares of PAGP. Each Class C share represents a non-economic limited partner interest in PAGP. The Class C shares function as a “pass-through” voting mechanism through which we vote at the direction of and as proxy for our common unitholders (other than AAP) and Series A preferred unitholders in such director elections. The number of Class C shares that we own is equal to the number of outstanding common units and Series A preferred units that are entitled to vote, pro rata with the holders of PAGP Class A and Class B shares, for the election of eligible PAGP GP directors. Common units held by AAP and Series B preferred units are not entitled to vote in the election of directors.

Reimbursement of Our General Partner and its Affiliates

Our general partner provides services necessary to manage and operate our business, properties and assets, including employing or retaining personnel. We do not pay our general partner a management fee, but we do reimburse our general partner for all direct and indirect costs it incurs or payments it makes on our behalf, including the costs of employee, officer and director compensation and benefits allocable to us as well as all other expenses necessary or appropriate to conduct our business. We record these costs on the accrual basis in the period in which our general partner incurs them. Our partnership agreement provides that our general partner will, in a manner it deems in its sole discretion to be reasonable, determine the expenses that are allocable to us. Total costs reimbursed by us to our general partner for the years ended December 31, 2023, 2022 and 2021 were $546 million, $476 million and $467 million, respectively.

Omnibus Agreement

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

•that we will pay all direct or indirect expenses of any of the PAGP Entities, other than income taxes, including, but not limited to, (i) compensation for the directors of PAGP GP, (ii) director and officer liability insurance, (iii) listing exchange fees, (iv) investor relations expenses and (v) fees related to legal, tax, financial advisory and accounting services. Amounts paid on behalf of the PAGP Entities during the years ended December 31, 2023, 2022 and 2021 were not material;

•the ability of PAGP 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 our common units from us; and

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

Promissory Notes with our General Partner

In March 2023, PAGP issued an unsecured promissory note to us with a face value of CAD$500 million (“related party note receivable”). Concurrently, we assigned PAGP our interest in an existing unsecured promissory note for the same face value amount due from a consolidated subsidiary (“related party note payable”). Both notes are due April 2027 and bear interest at a rate of 8.25% per annum, payable semi-annually.

Accrued and unpaid interest receivable/payable was $10 million as of December 31, 2023. Interest income/expense on the related party notes totaled $25 million for the year ended December 31, 2023.

As of December 31, 2023, our outstanding related party note receivable and related party note payable balances were as follows (in millions):


	December 31, 2023
Related party note receivable (1)	$	379
Related party note payable (1)	$	379

Transactions with Other Related Parties

Our other related parties include (i) entities in which we hold investments and account for under the equity method of accounting (see Note 8 for information regarding such entities) and (ii) principal owners and their affiliated entities. We recognize as our principal owners entities that have a designated representative on the board of directors of PAGP GP and/or own greater than 10% of the limited partner interests in AAP. Such limited partner interests in AAP translate into a significantly smaller indirect ownership interest in PAA. We also consider subsidiaries or funds identified as affiliated with principal owners to be related parties. As of December 31, 2023, no entities met the criteria to be recognized as a principal owner.

In August 2021, the board of directors of PAGP GP approved and adopted an amendment to PAGP GP’s limited liability company agreement (the “Amendment”) which eliminated all previously negotiated “director designation” rights and requires that all directors be subject to public election, including Kayne Anderson Capital Advisors, L.P.’s (“Kayne Anderson”) legacy contractual right to designate an individual to serve on the PAGP GP board without being subject to public election. The Amendment also eliminated all previously negotiated rights, including Kayne Anderson’s right, to appoint a PAGP GP board observer under certain circumstances. As a result of these changes, we no longer recognize Kayne Anderson and its affiliates as related parties.

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


	Year Ended December 31,
	2023		2022		2021



Revenues from related parties	$	48	$	45	$	33




Purchases and related costs from related parties	$	404	$	365	$	385

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


	December 31,
	2023		2022



Trade accounts receivable and other receivables, net from related parties (1)	$	63	$	45




Trade accounts payable to related parties (1) (2)	$	72	$	79

- 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
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+ Details

CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance	$ 13,325	$ 12,810	$ 9,738
Total period activity	118	(101)	65
Ending balance	13,732	13,325	12,810
Derivative Instruments
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance	(107)	(208)	(258)
Reclassification adjustments	11	7	31
Unrealized gain on hedges	15	94	19
Total period activity	26	101	50
Ending balance	(81)	(107)	(208)
Translation Adjustments
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance	(846)	(642)	(657)
Currency translation adjustments	91	(204)	15
Total period activity	91	(204)	15
Ending balance	(755)	(846)	(642)
Other
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance	(1)	(3)	(3)
Other	1	2
Total period activity	1	2
Ending balance		(1)	(3)
Total
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance	(954)	(853)	(918)
Reclassification adjustments	11	7	31
Unrealized gain on hedges	15	94	19
Currency translation adjustments	91	(204)	15
Other	1	2
Total period activity	118	(101)	65
Ending balance	$ (836)	$ (954)	$ (853)

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Series A Preferred Units
Units outstanding (in units)	71,090,468	71,090,468	71,090,468	71,090,468
Series B Preferred Units
Units outstanding (in units)	800,000	800,000	800,000	800,000
Common Units
Units outstanding (in units)	701,008,749	698,354,498	704,991,540	722,380,416

Debt - Schedule of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2023	Oct. 31, 2023	Jan. 31, 2023	Dec. 31, 2022
SHORT-TERM DEBT
Short-term debt	$ 446			$ 1,159
LONG-TERM DEBT
Senior notes, net of unamortized discounts and debt issuance costs	7,242			7,237
Noncurrent portion of other long-term debt	63			50
Total long-term debt	7,305			7,287
Total debt	7,751			8,446
Senior notes
LONG-TERM DEBT
Unamortized discounts and debt issuance costs	(41)			(46)
Senior notes, net of unamortized discounts and debt issuance costs	7,242			7,237
Debt instrument face value	7,300			8,400
Senior notes \| Level 2
LONG-TERM DEBT
Debt instrument fair value	$ 6,900			7,600
Senior notes \| 2.85% senior notes due January 2023
SHORT-TERM DEBT
Debt instrument, interest rate (as a percent)			2.85%
Senior notes \| 3.85% senior notes due October 2023
SHORT-TERM DEBT
Debt instrument, interest rate (as a percent)		3.85%
Senior notes \| 3.60% senior notes due November 2024
SHORT-TERM DEBT
Debt instrument, interest rate (as a percent)	3.60%
LONG-TERM DEBT
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 750			750
Senior notes \| 4.65% senior notes due October 2025
SHORT-TERM DEBT
Debt instrument, interest rate (as a percent)	4.65%
LONG-TERM DEBT
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 1,000			1,000
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
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
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
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
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
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
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
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
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
Other long-term debt
LONG-TERM DEBT
Noncurrent portion of other long-term debt	63			50
Line of Credit \| Commercial paper notes
SHORT-TERM DEBT
Short-term notes and borrowings	$ 433
Weighted average interest rate, short-term (as a percent)	5.80%
Senior notes \| 2.85% senior notes due January 2023
SHORT-TERM DEBT
Short-term notes and borrowings				$ 400
Debt instrument, interest rate (as a percent)				2.85%
Senior notes \| 3.85% senior notes due October 2023
SHORT-TERM DEBT
Short-term notes and borrowings				$ 700
Debt instrument, interest rate (as a percent)				3.85%
Other
SHORT-TERM DEBT
Short-term debt	$ 13			$ 59

Income Taxes - Components (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes - Components (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current income tax expense:
State income tax	$ 2	$ 1	$ 2
Canadian federal and provincial income tax	143	83	48
Total current income tax expense	145	84	50
Deferred income tax expense/(benefit):
Canadian federal and provincial income tax	(24)	105	23
Total deferred income tax expense/(benefit)	(24)	105	23
Total income tax expense	$ 121	$ 189	$ 73

- Definition

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

+ References + Details

Commitments and Contingencies

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments


	2024		2025		2026		2027		2028		Thereafter		Total
Leases (1)	$	100	$	85	$	64	$	55	$	49	$	286	$	639
Other commitments (2)	367		336		249		217		117		425		1,711
Total	$	467	$	421	$	313	$	272	$	166	$	711	$	2,350

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 accruals 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.

At December 31, 2023, our estimated undiscounted reserve for environmental liabilities (excluding liabilities related to the Line 901 incident, as discussed further below) totaled $56 million, of which $10 million was classified as short-term and $46 million was classified as long-term. At December 31, 2022, our estimated undiscounted reserve for environmental liabilities (excluding liabilities related to the Line 901 incident) totaled $55 million, of which $10 million was classified as short-term and $45 million was classified as long-term. Such short-term liabilities are reflected in “Other current liabilities” and long-term liabilities are reflected in “Other long-term liabilities and deferred credits” on our Consolidated Balance Sheets. At both December 31, 2023 and 2022, we had recorded receivables (excluding receivables related to the Line 901 incident) totaling $4 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, approximately $1 million of which for each period is reflected in “Other long-term assets, net” and the remainder is reflected in “Trade accounts receivable and other receivables, net” on our Consolidated Balance Sheets.

In some cases, the actual cash expenditures associated with these liabilities may not occur for three years or longer. 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 the reserve is 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 the reserve 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 crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. A portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert. Following the release, we shut down the pipeline and initiated our emergency response plan. A Unified Command, which included the United States Coast Guard, the EPA, the State of California Department of Fish and Wildlife (“CDFW”), the California Office of Spill Prevention and Response and the Santa Barbara Office of Emergency Management, was established for the response effort. Clean-up and remediation operations with respect to impacted shoreline and other areas has been determined by the Unified Command to be complete, and the Unified Command has been dissolved. Our estimate of the amount of oil spilled, based on relevant facts, data and information, and as set forth in the Consent Decree described below, is approximately 2,934 barrels; of this amount, we estimate that 598 barrels reached the Pacific Ocean.

As a result of the Line 901 incident, several governmental agencies and regulators initiated investigations into the Line 901 incident, various claims have been made against us and a number of lawsuits have been filed against us, the majority of which have been resolved. Set forth below is a brief summary of actions and matters that are currently pending or recently resolved.

As the “responsible party” for the Line 901 incident we are liable for various costs and for certain natural resource damages under the Oil Pollution Act. In this regard, following the Line 901 incident, we entered into a cooperative Natural Resource Damage Assessment (“NRDA”) process with the federal and state agencies designated or authorized by law to act as trustees for the natural resources of the United States and the State of California (collectively, the “Trustees”). Additionally, various government agencies sought to collect civil fines and penalties under applicable state and federal regulations. On March 13, 2020, the United States and the People of the State of California filed a civil complaint against Plains All American Pipeline, L.P. and Plains Pipeline L.P. along with a pre-negotiated settlement agreement in the form of a Consent Decree (the “Consent Decree”) that was signed by the United States Department of Justice, Environmental and Natural Resources Division, the United States Department of Transportation, Pipeline and Hazardous Materials Safety Administration, the EPA, CDFW, the California Department of Parks and Recreation, the California State Lands Commission, the California Department of Forestry and Fire Protection’s Office of the State Fire Marshal, Central Coast Regional Water Quality Control Board, and Regents of the University of California. The Consent Decree was approved and entered by the Federal District Court for the Central District of California on October 14, 2020. Pursuant to the terms of the Consent Decree, Plains paid $24 million in civil penalties and $22.325 million as compensation for injuries to, destruction of, loss of, or loss of use of natural resources resulting from the Line 901 incident. The Consent Decree, which resolved all regulatory claims related to the incident, also contains requirements for implementing certain agreed-upon injunctive relief, as well as requirements for potentially restarting Line 901 and the Sisquoc to Pentland portion of Line 903. On October 13, 2022, Plains sold Line 901 and the Sisquoc to Pentland portion of Line 903 to Pacific Pipeline Company, an indirect wholly owned subsidiary of Exxon Mobil Corporation. As required by the terms of the Consent Decree, such purchaser assumed responsibility for compliance with the Consent Decree as it relates to the future ownership and operation of Line 901 and the Sisquoc to Pentland portion of Line 903.

Following an investigation and grand jury proceedings, in May of 2016, PAA was charged by a California state grand jury, pursuant to an indictment filed in California Superior Court, Santa Barbara County (the “May 2016 Indictment”), with alleged violations of California law in connection with the Line 901 incident. Fifteen charges from the May 2016 Indictment were the subject of a jury trial in California Superior Court in Santa Barbara County, and the jury returned a verdict on September 7, 2018, pursuant to which we were (i) found guilty on one felony discharge count and eight misdemeanor counts (which included one reporting count, one strict liability discharge count and six strict liability animal takings counts) and (ii) found not guilty on one strict liability animal takings count. The remaining counts were subsequently dismissed by the Court. On April 25, 2019, PAA was sentenced to pay fines and penalties in the aggregate amount of just under $3.35 million for the convictions covered by the September 2018 jury verdict (the “2019 Sentence”). The fines and penalties imposed in connection with the 2019 Sentence have been paid. In September 2021, the Superior Court concluded a series of hearings on the issue of whether there were any “direct victims” of the spill that are entitled to restitution under applicable criminal law. Through a series of final orders issued at the trial court level and without affecting any rights of the claimants under civil law, the Court dismissed the vast majority of the claims and ruled that the claimants were not entitled to restitution under applicable criminal laws. The Court did award an aggregate amount of less than $150,000 to a handful of claimants and we settled with approximately 40 claimants before the hearings for aggregate consideration that is not material. The prosecution and certain separately represented claimants have appealed the Court’s rulings.

We also received several individual lawsuits and claims from companies, governmental agencies and individuals alleging damages arising out of the Line 901 incident. These lawsuits and claims generally seek restitution, compensatory and punitive damages, and/or injunctive relief. The majority of these lawsuits have been settled or dismissed by the court. In addition to the other lawsuits disclosed herein, the following lawsuits remain: (i) a lawsuit filed in the United States District Court for the Central District of California that was remanded to the California Superior Court in Santa Barbara County for lost revenue or profit asserted by a former oil producer that declared bankruptcy and shut in its offshore production platform following the Line 901 incident; (ii) a lawsuit filed by the California State Land Commission in California Superior Court in Santa Barbara County seeking lost royalties following the shut-down of Line 901, as well as costs related to the decommissioning of such platform, and (iii) lawsuits filed in California Superior Court in Santa Barbara County by various companies and individuals who provided labor, goods, or services associated with oil production activities they claim were disrupted following the Line 901 incident. We are vigorously defending these remaining lawsuits and believe we have strong defenses.

Furthermore, shortly following the Line 901 incident, we established a claims line and encouraged any parties that were damaged by the release to contact us to discuss their damage claims. We received a number of claims through the claims line and we have processed those claims and made payments as appropriate.

Additionally, a class action lawsuit was filed against us in United States District Court for the Central District of California in which the class plaintiffs seek a declaratory judgment that Plains’ right-of-way agreements would not allow Plains to lay a new pipeline to replace Line 901 and/or the non-operating segment of Line 903 without paying additional compensation. The purchaser of Line 901 and the Sisquoc to Pentland portion of Line 903 has assumed liability for these claims with respect to its interest in such acquired pipelines and Plains has been dismissed from this portion of the lawsuit. In the same proceeding, a small subset of plaintiffs are also claiming damages to compensate them for the alleged diminished value of their properties due to the stigma of the oil spill. We are vigorously defending against these stigma damages claims.

In a separate class action lawsuit that was pending in United States District Court for the Central District of California, the plaintiffs claimed two different classes of claimants were damaged by the release: (i) commercial fishermen who landed fish in certain specified fishing blocks in the waters off the coast of Southern California or persons or businesses who resold commercial seafood caught in those areas; and (ii) owners and lessees of residential beachfront properties, or properties with a private easement to a beach, where plaintiffs claim oil from the spill washed up. In 2022, in order to fully and finally resolve all claims and litigation for both classes, we reached an agreement to settle this case in exchange for a payment of $230 million (the “Class Action Settlement”). The Class Action Settlement was formally approved by the trial court on September 20, 2022, and we made the $230 million settlement payment on October 27, 2022 and the lawsuit was subsequently dismissed.

Plains formally submitted claims for reimbursement of the Class Action Settlement to our insurance carriers on November 7, 2022. To date, we have received payment of approximately $3.6 million from one insurer, which represents the final payment obligation of such insurer and brings the total amount collected from all insurers under such program to $275 million of the $500 million policy limits as of December 31, 2023. Insurers responsible for $185 million of the remaining $225 million of coverage formally communicated a denial of coverage for the Class Action Settlement generally alleging that some or all damages encompassed by the Class Action Settlement are not covered by their policies and that all or some portion of the $275 million for which Plains has already received insurance reimbursement does not properly exhaust the underlying policies that paid those sums. The insurer responsible for the final $40 million of coverage under such insurance program has not formally responded to our reimbursement demands. We have initiated final and binding arbitration proceedings against the insurers responsible for $175 million of coverage and intend to vigorously pursue recovery from our insurers of all amounts for which we have claimed reimbursement. We believe that our claim for reimbursement from our insurers of the Class Action Settlement payment is strong and that our ultimate recovery of such amounts is probable. Our belief is based on: (i) our analysis of the terms of the underlying insurance policies as applied to the facts and circumstances that comprise our claim for reimbursement, (ii) our experience with the cost submissions and timely collection of claims for the $275 million collected to date for this incident under the same insurance program as the denied claims, including from some of the same insurers who are now denying claims, (iii) our extensive legal review and assessment of the insurer’s claimed basis for denial of coverage, which review and assessment includes the advice of external legal counsel experienced in these type of matters and solidly supports our belief that our insurers are required to provide coverage based on the terms of the policies and the nature of our claims, and (iv) the financial strength of the insurance carriers as determined by an independent credit ratings agency. Various factors could impact the timing and amount of recovery of our insurance receivable, including future developments that adversely impact our assessment of the strength of our coverage claims, the outcome of any dispute resolution proceedings with respect to our coverage claims and the extent to which insurers may become insolvent in the future. An unfavorable resolution could have a material impact on our results of operations.

In connection with the foregoing, including the Class Action Settlement, we have made adjustments to our total estimated Line 901 costs and the portion of such costs that we believe are probable of recovery from insurance carriers, net of deductibles. Effective as of December 31, 2023, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $750 million, which includes actual and projected emergency response and clean-up costs, natural resource damage assessments, fines and penalties payable pursuant to the Consent Decree, certain third-party claims settlements (including the Class Action Settlement), and estimated costs associated with our remaining Line 901 lawsuits and claims as described above, 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 excluding future claims and lawsuits 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. Accordingly, our assumptions and estimates may turn out to be inaccurate and our total costs could turn out to be materially higher; therefore, we can provide no assurance that we will not have to accrue significant additional costs in the future with respect to the Line 901 incident.

During the years ended December 31, 2023, 2022 and 2021, we recognized costs, net of amounts probable of recovery from insurance carriers, of $10 million, $95 million and $15 million, respectively. As of December 31, 2023 and 2022, we had a remaining undiscounted gross liability of approximately $94 million and $105 million, respectively, related to the Line 901 incident, which aggregate amounts are reflected in “Current liabilities” on our Consolidated Balance Sheet. As discussed above, we maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such liabilities. As of December 31, 2023, our incurred costs for the Line 901 incident have exceeded our insurance coverage limit of $500 million related to our 2015 insurance program applicable to the Line 901 incident by $250 million. Through December 31, 2023, we had collected, subject to customary reservations, approximately $280 million out of the $505 million of release costs that we believe are probable of recovery from insurance carriers (including the 2015 insurance program and our directors and officers (D&O) insurance policies), net of deductibles. Therefore, as of December 31, 2023, we have recognized a long-term receivable of approximately $225 million for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected. We anticipate that the process to enforce our coverage claims with respect to the Class Action Settlement will take time and, accordingly, have recognized such amount as a long-term asset in “Other assets” on our Consolidated Balance Sheet.

We have completed the required clean-up and remediation work as determined by the Unified Command and the Unified Command has been dissolved; however, we expect to make payments for additional legal, professional and regulatory costs during future periods. 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 lawsuits will have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

Other Litigation Matters. 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. We believe the claims are without merit and that the outcome of the lawsuit will not have a material adverse effect on our financial condition, results of operations or cash flows. We intend to vigorously defend against the claims asserted in this lawsuit.

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 1,502	$ 1,228	$ 648
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	1,048	965	774
(Gains)/losses on asset sales and asset impairments, net (Note 6, Note 7)	(152)	269	592
Equity-indexed compensation expense	50	40	23
Deferred income tax expense/(benefit)	(24)	105	23
Gains on sales of linefill	(2)	(35)
(Gain)/loss on foreign currency revaluation	8	41	(7)
Settlement of terminated interest rate hedging instruments	80	42
Change in fair value of Preferred Distribution Rate Reset Option (Note 12)	(58)	189	(14)
Equity earnings in unconsolidated entities	(369)	(403)	(274)
Distributions on earnings from unconsolidated entities	458	488	431
(Gains)/losses on investments in unconsolidated entities, net (Note 7, Note 8)	(28)	(346)	(2)
Other	20	16	29
Changes in assets and liabilities, net of acquisitions:
Trade accounts receivable and other	213	649	(2,179)
Inventory	223	(10)	(18)
Trade accounts payable and other	(242)	(830)	1,970
Net cash provided by operating activities	2,727	2,408	1,996
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired (Note 7)	(425)	(149)	(32)
Investments in unconsolidated entities (Note 8)	(33)	(14)	(94)
Additions to property, equipment and other	(559)	(455)	(336)
Cash paid for purchases of linefill	(23)	(84)	(37)
Proceeds from sales of assets (Note 7)	328	60	881
Cash received from sales of linefill	9	72	3
Other investing activities	1	44	1
Net cash provided by/(used in) investing activities	(702)	(526)	386
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) under commercial paper program (Note 10)	433		(545)
Net repayments under senior secured hedged inventory facility (Note 10)			(167)
Repayment of GO Zone term loans (Note 10)			(200)
Repayments of senior notes (Note 10)	(1,100)	(750)
Repurchase of common units (Note 11)		(74)	(178)
Distributions paid to noncontrolling interests (Note 11)	(333)	(298)	(14)
Contributions from noncontrolling interests	106	26	1
Other financing activities	(93)	(53)	(166)
Net cash used in financing activities	(1,976)	(1,931)	(1,984)
Effect of translation adjustment		(3)	(5)
Net increase/(decrease) in cash and cash equivalents and restricted cash	49	(52)	393
Cash and cash equivalents and restricted cash, beginning of period	401	453	60
Cash and cash equivalents and restricted cash, end of period	450	401	453
Cash paid for:
Interest, net of amounts capitalized	377	393	401
Income taxes, net of amounts refunded	69	112	76
Series A Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions paid to unitholders (Note 11)	(166)	(149)	(149)
Series B Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions paid to unitholders (Note 11)	(75)	(49)	(49)
Common Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions paid to unitholders (Note 11)	$ (748)	$ (584)	$ (517)

Property and Equipment - Components of Property and Equipment, Net (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Property and Equipment
Property and equipment, gross	$ 21,143	$ 20,020
Accumulated depreciation	(5,361)	(4,770)
Property and equipment, net	15,782	15,250
Pipeline systems \| Crude Oil
Property and Equipment
Property and equipment, gross	14,265	13,303
Pipeline systems \| NGL
Property and Equipment
Property and equipment, gross	$ 506	458
Pipeline systems \| Minimum \| Crude Oil
Property and Equipment
Estimated Useful Lives (Years)	10 years
Pipeline systems \| Minimum \| NGL
Property and Equipment
Estimated Useful Lives (Years)	10 years
Pipeline systems \| Maximum \| Crude Oil
Property and Equipment
Estimated Useful Lives (Years)	50 years
Pipeline systems \| Maximum \| NGL
Property and Equipment
Estimated Useful Lives (Years)	50 years
Crude oil storage and terminal facilities \| Crude Oil
Property and Equipment
Property and equipment, gross	$ 2,664	2,631
Crude oil storage and terminal facilities \| Minimum \| Crude Oil
Property and Equipment
Estimated Useful Lives (Years)	10 years
Crude oil storage and terminal facilities \| Maximum \| Crude Oil
Property and Equipment
Estimated Useful Lives (Years)	50 years
NGL storage, terminal, fractionation and processing facilities \| NGL
Property and Equipment
Property and equipment, gross	$ 2,554	2,445
NGL storage, terminal, fractionation and processing facilities \| Minimum \| NGL
Property and Equipment
Estimated Useful Lives (Years)	10 years
NGL storage, terminal, fractionation and processing facilities \| Maximum \| NGL
Property and Equipment
Estimated Useful Lives (Years)	50 years
Office property and equipment and rolling stock
Property and Equipment
Property and equipment, gross	$ 556	656
Office property and equipment and rolling stock \| Minimum
Property and Equipment
Estimated Useful Lives (Years)	2 years
Office property and equipment and rolling stock \| Maximum
Property and Equipment
Estimated Useful Lives (Years)	50 years
Construction in progress
Property and Equipment
Property and equipment, gross	$ 257	201
Land and other
Property and Equipment
Property and equipment, gross	$ 341	$ 326

Inventory, Linefill and Long-term Inventory

12 Months Ended

Dec. 31, 2023

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, 2023, 2022 or 2021.

Linefill in assets we own is recorded at historical cost and consists of crude oil and NGL. 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 6 for further discussion regarding impairment of long-lived assets. During 2023, 2022 and 2021, 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, 2023						December 31, 2022
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	5,877	barrels	$	383	$	65.17	6,713	barrels	$	452	$	67.33
NGL	5,957	barrels	154		$	25.85	7,285	barrels	270		$	37.06

Other	N/A		11		N/A		N/A		7		N/A
Inventory subtotal			548						729

Linefill
Crude oil	15,409	barrels	909		$	58.99	15,480	barrels	906		$	58.53
NGL	2,168	barrels	67		$	30.90	1,876	barrels	55		$	29.32

Linefill subtotal			976						961

Long-term inventory
Crude oil	3,256	barrels	232		$	71.25	3,102	barrels	246		$	79.30
NGL	1,326	barrels	33		$	24.89	1,066	barrels	38		$	35.65
Long-term inventory subtotal			265						284

Total			$	1,789					$	1,974

Derivatives and Risk Management Activities - Financial Impact (Details) - Derivatives Not Designated as a Hedge - Commodity Derivatives - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	$ (32)	$ 238	$ (639)
Product sales revenues
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	13	179	(710)
Field operating costs
Impact of derivative activities recognized in earnings
Total gain (loss) on derivatives recognized in net income	$ (45)	$ 59	$ 71

Segment Information

12 Months Ended

Dec. 31, 2023

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. The NGL segment includes our NGL pipelines, NGL storage, natural gas processing and NGL fractionation facilities and related NGL marketing activities. Our crude oil and NGL marketing activities are included in the respective reporting segments as their 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 each of our segments.

Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below) and maintenance capital. The measure of Segment Adjusted EBITDA forms the basis of our internal financial reporting and is the primary performance measure 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) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus (d) our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities, further adjusted (e) 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 (f) to exclude the portion of all preceding items that is attributable to noncontrolling interests (“Segment amounts attributable to noncontrolling interests”).

Segment Adjusted EBITDA excludes depreciation and amortization. As an MLP, we make quarterly distributions of our “available cash” (as defined in our partnership agreement) to our unitholders. 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 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 are classified as maintenance capital, which is deducted in determining “available cash.” 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 for each segment (in millions):


	Crude Oil		NGL		Intersegment Revenues Elimination		Total
Year Ended December 31, 2023
Revenues (1):
Product sales	$	45,587	$	1,765	$	(378)	$	46,974
Services	1,587		170		(19)		1,738
Total revenues	$	47,174	$	1,935	$	(397)	$	48,712
Equity earnings in unconsolidated entities	$	369	$	—			$	369
Segment Adjusted EBITDA	$	2,163	$	522			$	2,685
Investment and acquisition capital expenditures (2) (3)	$	765	$	65			$	830
Maintenance capital expenditures (3)	$	145	$	86			$	231

As of December 31, 2023

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


	Crude Oil		NGL		Intersegment Revenues Elimination		Total
Year Ended December 31, 2022
Revenues (1):
Product sales	$	53,840	$	2,575	$	(467)	$	55,948
Services	1,240		186		(32)		1,394
Total revenues	$	55,080	$	2,761	$	(499)	$	57,342
Equity earnings in unconsolidated entities	$	403	$	—			$	403
Segment Adjusted EBITDA	$	1,986	$	518			$	2,504
Investment and acquisition capital expenditures (2) (3)	$	461	$	157			$	618
Maintenance capital expenditures (3)	$	112	$	99			$	211

As of December 31, 2022

Investments in unconsolidated entities	$	3,084	$	—			$	3,084


	Crude Oil		NGL		Intersegment Revenues Elimination		Total
Year Ended December 31, 2021
Revenues (1):
Product sales	$	39,395	$	1,829	$	(341)	$	40,883
Services	1,075		139		(19)		1,195
Total revenues	$	40,470	$	1,968	$	(360)	$	42,078
Equity earnings in unconsolidated entities	$	274	$	—			$	274
Segment Adjusted EBITDA	$	1,909	$	285			$	2,194
Investment and acquisition capital expenditures (2) (3)	$	212	$	57			$	269
Maintenance capital expenditures (3)	$	100	$	68			$	168

As of December 31, 2021

Investments in unconsolidated entities	$	3,805	$	—			$	3,805

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

(3)These amounts combined represent total capital expenditures.

Segment Adjusted EBITDA Reconciliation

The following table reconciles Segment Adjusted EBITDA to Net income attributable to PAA (in millions):


	Year Ended December 31,
	2023		2022		2021
Segment Adjusted EBITDA	$	2,685	$	2,504	$	2,194
Adjustments (1):
Depreciation and amortization of unconsolidated entities (2)	(87)		(85)		(123)
Derivative activities and inventory valuation adjustments (3)	(159)		280		271
Long-term inventory costing adjustments (4)	(35)		4		94
Deficiencies under minimum volume commitments, net (5)	(12)		(7)		7
Equity-indexed compensation expense (6)	(36)		(32)		(19)
Foreign currency revaluation (7)	(24)		(4)		4
Line 901 incident (8)	(10)		(95)		(15)
Transaction-related expenses (9)	(1)		—		(16)
Segment amounts attributable to noncontrolling interests (10)	454		364		94
Depreciation and amortization	(1,048)		(965)		(774)
Gains/(losses) on asset sales and asset impairments, net	152		(269)		(592)
Gains/(losses) on investments in unconsolidated entities, net	28		346		2
Interest expense, net	(386)		(405)		(425)
Other income/(expense), net	102		(219)		19
Income before tax	1,623		1,417		721
Income tax expense	(121)		(189)		(73)
Net income	1,502		1,228		648
Net income attributable to noncontrolling interests	(272)		(191)		(55)
Net income attributable to PAA	$	1,230	$	1,037	$	593

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

(2)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 (beginning October 2021), Cactus II (beginning November 2022) and Red River.

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)	2023		2022		2021
United States	$	42,308	$	46,903	$	34,458
Canada	6,404		10,439		7,620
	$	48,712	$	57,342	$	42,078

(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)	2023		2022
United States	$	18,591	$	18,655
Canada	3,820		3,802
	$	22,411	$	22,457

(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

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-22

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-15

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 31
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-31

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 42
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-42

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 40
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-40

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org//280/tableOfContent

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 26
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-26

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 34
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-34

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 41
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-41

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-21

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-21

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

+ Details

Acquisitions, Divestitures and Other Transactions - Divestitures Narrative (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended	12 Months Ended
	Feb. 28, 2023	Aug. 31, 2021	Jun. 30, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jul. 31, 2021
Divestitures
Gains/(losses) on asset sales and asset impairments, net				$ 152	$ (269)	$ (592)
Proceeds from sales of assets				328	60	$ 881
Deferred losses on hedges remaining in other comprehensive income				$ (10,422)	(10,057)
Assets Sold Primarily Consisted Of Land And Related Assets In Long Beach, California, As Well As Line 901 And The Sisquoc To Pentland Portion Of Line 903 \| Disposed of by Sale \| (Gains)/Losses On Asset Sales and Asset Impairments, Net
Divestitures
Gain from sale of assets					61
Pine Prairie and Southern Pines Natural Gas Storage Facilities \| Disposed of by Sale \| (Gains)/Losses On Asset Sales and Asset Impairments, Net
Divestitures
Non-cash impairment losses upon classification to assets held for sale			$ 475
Pine Prairie and Southern Pines Natural Gas Storage Facilities \| Held for Sale
Divestitures
Assets held for sale, current							$ 832
Pine Prairie and Southern Pines Natural Gas Storage Facilities \| Held for Sale \| Derivative Instruments
Divestitures
Deferred losses on hedges remaining in other comprehensive income							$ 18
Crude Oil \| Assets Sold Primarily Consisted Of Land And Related Assets In Long Beach, California, As Well As Line 901 And The Sisquoc To Pentland Portion Of Line 903 \| Disposed of by Sale
Divestitures
Proceeds from sales of assets					60
Crude Oil \| Pine Prairie and Southern Pines Natural Gas Storage Facilities \| Disposed of by Sale
Divestitures
Proceeds from sales of assets		$ 850
Keyera Fort Saskatchewan Facility
Divestitures
Non-operated/undivided joint interest rate, sold	21.00%
Proceeds from divestiture of interest in joint venture	$ 270
Gains/(losses) on asset sales and asset impairments, net	$ 140
Keyera Fort Saskatchewan Facility \| Other current assets
Divestitures
Assets held-for-sale					$ 130

Net Income Per Common Unit (Tables)

12 Months Ended

Dec. 31, 2023

Earnings Per Share [Abstract]

Computation of Basic and Diluted Net Income per Common Unit

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


	Year Ended December 31,
	2023		2022		2021
Basic and Diluted Net Income per Common Unit
Net income attributable to PAA	$	1,230	$	1,037	$	593
Distributions to Series A preferred unitholders	(173)		(149)		(149)
Distributions to Series B preferred unitholders	(76)		(52)		(49)
Amounts allocated to participating securities	(10)		(5)		(2)
Other	5		—		—
Net income allocated to common unitholders (1)	$	976	$	831	$	393

Basic and diluted weighted average common units outstanding	699		701		716

Basic and diluted net income per common unit	$	1.40	$	1.19	$	0.55

(1)We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (i.e., undistributed loss), if any, are allocated to the common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method.

Intangible Asset, Net - Schedule of Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Finite-Lived Intangible Assets
Cost	$ 2,819	$ 2,852
Accumulated Amortization	(944)	(707)
Net	1,875	2,145
Customer contracts and relationships
Finite-Lived Intangible Assets
Cost	2,789	2,817
Accumulated Amortization	(932)	(695)
Net	$ 1,857	2,122
Customer contracts and relationships \| Minimum
Finite-Lived Intangible Assets
Finite-lived intangible asset, useful life (in years)	1 year
Customer contracts and relationships \| Maximum
Finite-Lived Intangible Assets
Finite-lived intangible asset, useful life (in years)	29 years
Other agreements
Finite-Lived Intangible Assets
Cost	$ 30	35
Accumulated Amortization	(12)	(12)
Net	$ 18	$ 23
Other agreements \| Minimum
Finite-Lived Intangible Assets
Finite-lived intangible asset, useful life (in years)	15 years
Other agreements \| Maximum
Finite-Lived Intangible Assets
Finite-lived intangible asset, useful life (in years)	70 years

Leases - Lease Costs (Details) - USD ($) $ in Millions	12 Months Ended
Leases - Lease Costs (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Operating lease cost	$ 86	$ 91	$ 96
Short-term lease cost	15	18	19
Other	8	15	14
Total lease cost	$ 109	$ 124	$ 129

Leases - Maturity of Lease Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Operating
2024	$ 80
2025	68
2026	51
2027	43
2028	34
Thereafter	238
Total	514
Less: Present value discount	(171)
Lease liabilities	343	$ 379
Finance
2024	20
2025	17
2026	13
2027	12
2028	15
Thereafter	48
Total	125
Less: Present value discount	(49)
Lease liabilities	76	60
Equity Method Investees \| Agreement to Store at Facilities Owned by Equity Method Investee \| Equity Method Investee That Owns Leased Storage Tanks
Finance
2024	6
2025	6
2026	6
2027	6
2028	6
Thereafter	45
Lease liabilities	$ 34	$ 35
Ownership interest in unconsolidated entity (as a percent)	50.00%

Investments in Unconsolidated Entities

12 Months Ended

Dec. 31, 2023

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, 2023	Investment Balance December 31,

Entity (1)	Type of Operation		2023		2022
BridgeTex Pipeline Company, LLC (“BridgeTex”)	Crude Oil Pipeline	20%	$	363	$	403

Capline Pipeline Company LLC (“Capline”)	Crude Oil Pipeline	54%	535		539
Diamond Pipeline LLC	Crude Oil Pipeline	50%	450		460
Eagle Ford Pipeline LLC	Crude Oil Pipeline	50%	370		371
Eagle Ford Terminals Corpus Christi LLC	Crude Oil Terminal and Dock	50%	116		118
OMOG JV LLC (“OMOG”) (2)	Crude Oil Pipeline	—%	—		211
Saddlehorn Pipeline Company, LLC	Crude Oil Pipeline	30%	192		197
White Cliffs Pipeline, LLC	Crude Oil Pipeline	36%	138		150
Wink to Webster Pipeline LLC (“W2W Pipeline”) (3)	Crude Oil Pipeline	16%	380		357
Other investments			276		278
Total Investments in Unconsolidated Entities			$	2,820	$	3,084

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

(2)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 Note 7 for additional information.

(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.

Acquisitions

During the fourth quarter of 2022, through a non-monetary transaction, we acquired an additional interest in OMOG in exchange for the contribution of portions of two pipeline systems. After the transaction, our ownership interest in OMOG increased to 57% from 40%. Subsequent to this transaction, we continued to account for OMOG as an equity method investment because the joint venture partner still retained substantive participating rights. The transaction resulted in a loss of approximately $25 million, which represents the difference between the fair value and historical book value of the assets contributed. This loss is reflected in “Gains/(losses) on investments in unconsolidated entities, net” on our Consolidated Statement of Operations. 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 Note 7 for additional information.

In July 2022, we acquired the remaining 50% interest in Advantage. Prior to the acquisition, our 50% interest in Advantage was accounted for as an equity method investment. See Note 7 for additional information.

In November 2022, we acquired an additional 5% interest in Cactus II which, combined with changes in governance, resulted in our obtaining control of the entity. We now reflect Cactus II as a consolidated subsidiary in our Consolidated Financial Statements. See Note 7 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, 2023, 2022 and 2021, we made cash contributions of $29 million, $13 million and $82 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 $229 million and $204 million at December 31, 2023 and 2022, 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, 2023 and 2022 was attributable to goodwill related to our ownership interest in BridgeTex and Capline 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,
	2023		2022
Current assets	$	528	$	471
Noncurrent assets	$	7,194	$	7,579
Current liabilities	$	476	$	252
Noncurrent liabilities	$	5	$	8


	Year Ended December 31,
	2023		2022		2021
Revenues	$	1,667	$	1,726	$	1,320
Operating income	$	921	$	1,004	$	505
Net income	$	947	$	1,011	$	506

Equity-Indexed Compensation Plans

12 Months Ended

Dec. 31, 2023

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 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 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 PAA unit at each balance sheet date and adjusted for the present value of any distributions that are estimated to occur on the underlying 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 as of December 31, 2023 (in millions):


LTIP						LTIP Awards Authorized
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)						43.5

(1)Of the 43.5 million total awards authorized, 17.4 million awards are currently available for future grant. The remaining balance has already vested or is currently outstanding.

As of December 31, 2023, 12.2 million LTIP awards were outstanding. Of the awards outstanding, 9.6 million include associated DERs. At December 31, 2023, certain of the outstanding LTIP awards were considered probable of vesting and such awards are expected to vest at various dates between May 2024 and August 2028. As of December 31, 2023, the outstanding awards that are considered probable of vesting have a remaining unrecognized fair value of approximately $73 million.

Leases - Lessor Future Minimum Lease Revenue (Details) $ in Millions	Dec. 31, 2023 USD ($)
Leases [Abstract]
2024	$ 24
2025	18
2026	15
2027	16
2028	16
Thereafter	$ 154

Debt - Debt Covenants (Details) $ in Millions	12 Months Ended
Debt - Debt Covenants (Details) $ in Millions	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 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	$ 205	$ 102
Letters of credit \| Maximum
Debt Instrument [Line Items]
Periods for which letters of credit are issued (in days)	70 days
Credit Agreements and Commercial Paper Program
Debt Instrument [Line Items]
Total borrowings	$ 18,100	25,000	$ 32,500
Total repayments	$ 17,700	$ 25,000	$ 33,200

Equity-Indexed Compensation Plans (Details) shares in Millions, $ in Millions	Dec. 31, 2023 USD ($) shares
Equity-Indexed Compensation Plans
LTIP awards authorized (in units)	43.5
LTIP awards available (in units)	17.4
LTIP awards outstanding (in units)	12.2
LTIP awards outstanding including DERs (in units)	9.6
Probable vesting, unrecognized fair value \| $	$ 73
Plains All American 2021 Long-Term Incentive Plan
Equity-Indexed Compensation Plans
LTIP awards authorized (in units)	28.8
Plains All American PNG Successor Long-Term Incentive Plan
Equity-Indexed Compensation Plans
LTIP awards authorized (in units)	1.3
Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan
Equity-Indexed Compensation Plans
LTIP awards authorized (in units)	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
-SubTopic 10
-Name Accounting Standards Codification
-Section 35
-Paragraph 1D
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480483/718-10-35-1D

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

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Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

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-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480429/718-10-50-2

+ Details

Acquisitions, Divestitures and Other Transactions - Schedule of Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Millions	Sep. 30, 2023	Nov. 30, 2022	Oct. 31, 2021
OMOG JV LLC and Southern Delaware Gathering Assets
Business Acquisition [Line Items]
Finite-lived intangible asset, useful life (in years)	10 years
Property and equipment	$ 484
Intangible assets	34
Working capital and other assets and liabilities	14
Identifiable assets acquired and liabilities assumed	$ 532
OMOG JV LLC and Southern Delaware Gathering Assets \| Minimum
Business Acquisition [Line Items]
Estimated Useful Lives (Years)	3 years
OMOG JV LLC and Southern Delaware Gathering Assets \| Maximum
Business Acquisition [Line Items]
Estimated Useful Lives (Years)	30 years
Cactus II Pipeline LLC
Business Acquisition [Line Items]
Finite-lived intangible asset, useful life (in years)		20 years
Property and equipment		$ 1,174
Intangible assets		428
Working capital and other assets and liabilities		(46)
Identifiable assets acquired and liabilities assumed		$ 1,556
Cactus II Pipeline LLC \| Minimum
Business Acquisition [Line Items]
Estimated Useful Lives (Years)		3 years
Cactus II Pipeline LLC \| Maximum
Business Acquisition [Line Items]
Estimated Useful Lives (Years)		50 years
Plains Oryx Permian Basin LLC \| Oryx Midstream Holdings LLC \| Joint Venture Transaction
Business Acquisition [Line Items]
Finite-lived intangible asset, useful life (in years)			20 years
Property and equipment			$ 1,886
Intangible assets			1,247
Investment in unconsolidated entities			103
Working capital and other assets and liabilities			(6)
Identifiable assets acquired and liabilities assumed			$ 3,230
Plains Oryx Permian Basin LLC \| Oryx Midstream Holdings LLC \| Joint Venture Transaction \| Minimum
Business Acquisition [Line Items]
Estimated Useful Lives (Years)			3 years
Plains Oryx Permian Basin LLC \| Oryx Midstream Holdings LLC \| Joint Venture Transaction \| Maximum
Business Acquisition [Line Items]
Estimated Useful Lives (Years)			30 years

Leases

12 Months Ended

Dec. 31, 2023

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 railcars, office space, land, vehicles, and storage tanks, and our finance leases primarily relate to tractor trailers, land, 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 57 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	2023		2022		2021
Operating lease cost	$	86	$	91	$	96
Short-term lease cost	15		18		19
Other (1)	8		15		14
Total lease cost	$	109	$	124	$	129

(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,
	2023		2022		2021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	81	$	92	$	91
Operating cash flows for finance leases	$	6	$	6	$	7
Financing cash flows for finance leases	$	11	$	12	$	11

Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications:
Operating leases	$	32	$	43	$	94
Finance leases	$	27	$	2	$	1

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


	December 31,
	2023		2022
Weighted-average remaining lease term (in years):
Operating leases	13		12
Finance leases	8		9

Weighted-average discount rate:
Operating leases	4.9	%	4.3	%
Finance leases	11.3	%	12.3	%

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	2023		2022
Assets
Operating lease right-of-use assets	Long-term operating lease right-of-use assets, net	$	313	$	349

Finance lease right-of-use assets (1)	Property and equipment	$	144	$	124
	Accumulated depreciation	(46)		(41)
	Property and equipment, net	$	98	$	83

Total lease right-of-use assets		$	411	$	432

Liabilities
Operating lease liabilities
Current	Other current liabilities	$	69	$	71
Noncurrent	Long-term operating lease liabilities	274		308
Total operating lease liabilities		$	343	$	379

Finance lease liabilities (1)
Current	Short-term debt	$	13	$	10
Noncurrent	Other long-term debt, net	63		50
Total finance lease liabilities		$	76	$	60

Total lease liabilities		$	419	$	439

(1)Includes right-of-use assets of $28 million and $30 million and lease liabilities of $34 million and $35 million as of December 31, 2023 and 2022, respectively, associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest.

The following table presents the maturity of undiscounted cash flows for future minimum lease payments under noncancelable leases as of December 31, 2023 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions):


	Operating		Finance (2)
Future minimum lease payments (1):
2024	$	80	$	20
2025	68		17
2026	51		13
2027	43		12
2028	34		15
Thereafter	238		48
Total	514		125
Less: Present value discount	(171)		(49)
Lease liabilities	$	343	$	76

(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 2024 through 2028 and approximately $45 million thereafter associated with leased storage tanks owned by an equity method investee, in which we own a 50% interest.

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 NGL and (ii) transporting crude oil and NGL. 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,
	2023		2022		2021
Operating lease revenue (1)	$	32	$	29	$	28

(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, 2023. 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 18 years. The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions):


	2024		2025		2026		2027		2028		Thereafter
Future minimum lease revenue	$	24	$	18	$	15	$	16	$	16	$	154

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	2023		2022		2021
Operating lease cost	$	86	$	91	$	96
Short-term lease cost	15		18		19
Other (1)	8		15		14
Total lease cost	$	109	$	124	$	129

(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,
	2023		2022		2021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	81	$	92	$	91
Operating cash flows for finance leases	$	6	$	6	$	7
Financing cash flows for finance leases	$	11	$	12	$	11

Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications:
Operating leases	$	32	$	43	$	94
Finance leases	$	27	$	2	$	1

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


	December 31,
	2023		2022
Weighted-average remaining lease term (in years):
Operating leases	13		12
Finance leases	8		9

Weighted-average discount rate:
Operating leases	4.9	%	4.3	%
Finance leases	11.3	%	12.3	%

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	2023		2022
Assets
Operating lease right-of-use assets	Long-term operating lease right-of-use assets, net	$	313	$	349

Finance lease right-of-use assets (1)	Property and equipment	$	144	$	124
	Accumulated depreciation	(46)		(41)
	Property and equipment, net	$	98	$	83

Total lease right-of-use assets		$	411	$	432

Liabilities
Operating lease liabilities
Current	Other current liabilities	$	69	$	71
Noncurrent	Long-term operating lease liabilities	274		308
Total operating lease liabilities		$	343	$	379

Finance lease liabilities (1)
Current	Short-term debt	$	13	$	10
Noncurrent	Other long-term debt, net	63		50
Total finance lease liabilities		$	76	$	60

Total lease liabilities		$	419	$	439


	Operating		Finance (2)
Future minimum lease payments (1):
2024	$	80	$	20
2025	68		17
2026	51		13
2027	43		12
2028	34		15
Thereafter	238		48
Total	514		125
Less: Present value discount	(171)		(49)
Lease liabilities	$	343	$	76

(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,
	2023		2022		2021
Operating lease revenue (1)	$	32	$	29	$	28

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


	2024		2025		2026		2027		2028		Thereafter
Future minimum lease revenue	$	24	$	18	$	15	$	16	$	16	$	154

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	2023		2022		2021
Operating lease cost	$	86	$	91	$	96
Short-term lease cost	15		18		19
Other (1)	8		15		14
Total lease cost	$	109	$	124	$	129

(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,
	2023		2022		2021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	81	$	92	$	91
Operating cash flows for finance leases	$	6	$	6	$	7
Financing cash flows for finance leases	$	11	$	12	$	11

Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications:
Operating leases	$	32	$	43	$	94
Finance leases	$	27	$	2	$	1

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


	December 31,
	2023		2022
Weighted-average remaining lease term (in years):
Operating leases	13		12
Finance leases	8		9

Weighted-average discount rate:
Operating leases	4.9	%	4.3	%
Finance leases	11.3	%	12.3	%

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	2023		2022
Assets
Operating lease right-of-use assets	Long-term operating lease right-of-use assets, net	$	313	$	349

Finance lease right-of-use assets (1)	Property and equipment	$	144	$	124
	Accumulated depreciation	(46)		(41)
	Property and equipment, net	$	98	$	83

Total lease right-of-use assets		$	411	$	432

Liabilities
Operating lease liabilities
Current	Other current liabilities	$	69	$	71
Noncurrent	Long-term operating lease liabilities	274		308
Total operating lease liabilities		$	343	$	379

Finance lease liabilities (1)
Current	Short-term debt	$	13	$	10
Noncurrent	Other long-term debt, net	63		50
Total finance lease liabilities		$	76	$	60

Total lease liabilities		$	419	$	439


	Operating		Finance (2)
Future minimum lease payments (1):
2024	$	80	$	20
2025	68		17
2026	51		13
2027	43		12
2028	34		15
Thereafter	238		48
Total	514		125
Less: Present value discount	(171)		(49)
Lease liabilities	$	343	$	76

(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,
	2023		2022		2021
Operating lease revenue (1)	$	32	$	29	$	28

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


	2024		2025		2026		2027		2028		Thereafter
Future minimum lease revenue	$	24	$	18	$	15	$	16	$	16	$	154

Acquisitions, Divestitures and Other Transactions - Pro Forma (Details) - Plains Oryx Permian Basin LLC - Oryx Midstream Holdings LLC - Joint Venture Transaction $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) $ / shares
Business Acquisition [Line Items]
Total revenues	$ 42,359
Net income attributable to PAA	524
Net income allocated to common unitholders	$ 324
Basic net income per common unit (in dollar per unit) \| $ / shares	$ 0.45
Diluted net income per common unit (in dollar per unit) \| $ / shares	$ 0.45

Segment Information - Reconciliation of Segment Adjusted EBITDA (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Segment Adjusted EBITDA	$ 2,685	$ 2,504	$ 2,194
Adjustments:
Depreciation and amortization of unconsolidated entities	(87)	(85)	(123)
Derivative activities and inventory valuation adjustments	(159)	280	271
Long-term inventory costing adjustments	(35)	4	94
Deficiencies under minimum volume commitments, net	(12)	(7)	7
Equity-indexed compensation expense	(36)	(32)	(19)
Foreign currency revaluation	(24)	(4)	4
Transaction-related expenses	(1)		(16)
Segment amounts attributable to noncontrolling interests	454	364	94
Depreciation and amortization	(1,048)	(965)	(774)
Gains/(losses) on asset sales and asset impairments, net	152	(269)	(592)
Gains/(losses) on investments in unconsolidated entities, net	28	346	2
Interest expense, net	(386)	(405)	(425)
Other income/(expense), net	102	(219)	19
INCOME BEFORE TAX	1,623	1,417	721
Income tax expense	(121)	(189)	(73)
NET INCOME	1,502	1,228	648
Net income attributable to noncontrolling interests	(272)	(191)	(55)
NET INCOME ATTRIBUTABLE TO PAA	1,230	1,037	593
Line 901 Incident
Adjustments:
Line 901 incident	$ (10)	$ (95)	$ (15)

Property and Equipment

12 Months Ended

Dec. 31, 2023

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,
		2023		2022
Crude oil pipeline systems	10 - 50	$	14,265	$	13,303
Crude oil storage and terminal facilities	10 - 50	2,664		2,631
NGL storage, terminal, fractionation and processing facilities	10 - 50	2,554		2,445
NGL pipeline systems	10 - 50	506		458
Office property and equipment and rolling stock	2 - 50	556		656
Construction in progress	N/A	257		201
Land and other	N/A	341		326
Property and equipment, gross (1)		21,143		20,020
Accumulated depreciation		(5,361)		(4,770)
Property and equipment, net		$	15,782	$	15,250

(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, 2023, 2022 and 2021 was $733 million, $707 million and $652 million, respectively.

As of December 31, 2023, 2022 and 2021, we incurred liabilities of $55 million, $46 million and $48 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.

We did not recognize any material impairments during the year ended December 31, 2023.

During the third quarter of 2022, we temporarily ceased service on a crude oil pipeline in California as a precautionary measure following a routine inspection and initiated a program of additional tests and inspections. After assessing the results of such tests and the changing operating conditions of our California assets, we determined that we had a triggering event due to the effect on future cash flows for certain of our assets that required us to assess the recoverability of our carrying value of our California crude oil assets (which includes the temporarily idled pipeline) reported in our Crude Oil segment. 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. We recognized a non-cash loss of approximately $330 million, which amount is reflected in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statement of Operations. Our estimated fair values (which we consider a Level 3 measurement in the fair value hierarchy) were based upon a discounted cash flow approach utilizing various assumptions and the application of a discount rate of approximately 15%, which represents our estimate of the cost of capital of a theoretical market participant for the asset group. Such assumptions included (but were not limited to) (i) future commodity volumes (consistent with historical information and estimates of future drilling and completion activity), (ii) tariff rates, (iii) estimated fixed and variable costs, (iv) the length of time the assets operate and (v) the amount for which assets in the asset group could be sold.

During the year ended December 31, 2021, we recognized approximately $220 million of non-cash impairment losses related to certain crude oil storage terminal assets included in our Crude Oil segment. This amount is reflected in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statements of Operations. Decreased demand for our services related to changing market conditions resulted in decreases in expected future cash flows for certain of our assets, which was a triggering event that required us to assess the recoverability of our 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 (which we consider a Level 3 measurement in the fair value hierarchy) was primarily based upon an assumption for the amount for which the relevant assets and land could be sold.

Partners' Capital and Distributions - Preferred Unit Distributions (Details) - USD ($) $ / shares in Units, $ in Millions			12 Months Ended
	Feb. 15, 2024	Feb. 14, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Series A Preferred Units \| Other current liabilities
Partners Capital and Distribution [Line Items]
Distributions payable			$ 44
Series B Preferred Units \| Other current liabilities
Partners Capital and Distribution [Line Items]
Distributions payable			10
Cash Distribution \| Series A Preferred Units
Partners Capital and Distribution [Line Items]
Cash distribution			$ 166	$ 149	$ 149
Distribution per unit (in dollars per unit)			$ 2.34	$ 2.10	$ 2.10
Cash Distribution \| Series A Preferred Units \| Subsequent Event
Partners Capital and Distribution [Line Items]
Cash distribution		$ 44
Cash Distribution \| Series B Preferred Units
Partners Capital and Distribution [Line Items]
Cash distribution			$ 75	$ 49	$ 49
Distribution per unit (in dollars per unit)			$ 93.43	$ 61.25	$ 61.25
Cash Distribution \| Series B Preferred Units \| Subsequent Event
Partners Capital and Distribution [Line Items]
Cash distribution	$ 20
Distribution per unit (in dollars per unit)	$ 24.92

Debt (Tables)

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Schedule of Debt

Debt consisted of the following (in millions):


	December 31, 2023		December 31, 2022
SHORT-TERM DEBT
Commercial paper notes, bearing a weighted-average interest rate of 5.8% (1)	$	433	$	—

Senior notes:

2.85% senior notes due January 2023	—		400
3.85% senior notes due October 2023	—		700

Other	13		59
Total short-term debt	446		1,159

LONG-TERM DEBT
Senior notes:


3.60% senior notes due November 2024 (2)	750		750
4.65% senior notes due October 2025	1,000		1,000
4.50% senior notes due December 2026	750		750
3.55% senior notes due December 2029	1,000		1,000
3.80% senior notes due September 2030	750		750
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	(41)		(46)
Senior notes, net of unamortized discounts and debt issuance costs	7,242		7,237
Other long-term debt:



Other	63		50
Total long-term debt	7,305		7,287
Total debt (3)	$	7,751	$	8,446

(1)We classified these commercial paper notes as short-term as of December 31, 2023, 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, 2023, we classified our 3.60%, $750 million senior notes due November 2024 as long-term based on our ability and intent to refinance these notes on a long-term basis.

(3)Our fixed-rate senior notes had a face value of approximately $7.3 billion and $8.4 billion at December 31, 2023 and 2022, respectively. We estimated the aggregate fair value of these notes to be approximately $6.9 billion and $7.6 billion at December 31, 2023 and 2022, respectively. Our 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 our commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

Schedule of Senior Unsecured Notes

During the three years ended December 31, 2023, we repaid the following senior unsecured notes in full (in millions):


Year	Description	Repayment Date
2023	$700 million 3.85% Senior Notes due October 2023	October 2023	(1)

2023	$400 million 2.85% Senior Notes due January 2023	January 2023	(1)

2022	$750 million 3.65% Senior Notes due June 2022	March 2022	(1)

(1)We repaid these senior notes with cash on hand and borrowings under our 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)
2024	$	750
2025	$	1,000
2026	$	750
2027	$	—
2028	$	—
Thereafter	$	4,783

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
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-Name Accounting Standards Codification
-Section 55
-Paragraph 69B
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481568/470-20-55-69B

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
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-Name Accounting Standards Codification
-Section 55
-Paragraph 69E
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481568/470-20-55-69E

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.12-04(a))
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-URI https://asc.fasb.org//1943274/2147480678/235-10-S99-3

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
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Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
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-Section 45
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Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 7: 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 10: http://fasb.org/us-gaap/role/ref/legacyRef
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+ Details

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Statement [Abstract]
Interest expense, capitalized interest	$ 10	$ 5	$ 18

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
REVENUES
Total revenues	$ 48,712	$ 57,342	$ 42,078
COSTS AND EXPENSES
Purchases and related costs	44,531	53,176	38,504
Field operating costs	1,425	1,315	1,065
General and administrative expenses	350	325	292
Depreciation and amortization	1,048	965	774
(Gains)/losses on asset sales and asset impairments, net (Note 6, Note 7)	(152)	269	592
Total costs and expenses	47,202	56,050	41,227
OPERATING INCOME	1,510	1,292	851
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	369	403	274
Gains/(losses) on investments in unconsolidated entities, net (Note 7, Note 8)	28	346	2
Interest expense (net of capitalized interest of $10, $5 and $18, respectively)	(386)	(405)	(425)
Other income/(expense), net	102	(219)	19
INCOME BEFORE TAX	1,623	1,417	721
Current income tax expense	(145)	(84)	(50)
Deferred income tax (expense)/benefit	24	(105)	(23)
NET INCOME	1,502	1,228	648
Net income attributable to noncontrolling interests	(272)	(191)	(55)
NET INCOME ATTRIBUTABLE TO PAA	1,230	1,037	593
NET INCOME PER COMMON UNIT (NOTE 4):
Net income allocated to common unitholders — Basic	976	831	393
Net income allocated to common unitholders — Diluted	$ 976	$ 831	$ 393
Common Units
NET INCOME PER COMMON UNIT (NOTE 4):
Basic weighted average common units outstanding (in units)	699	701	716
Diluted weighted average common units outstanding (in units)	699	701	716
Basic net income per common unit (in dollars per unit)	$ 1.40	$ 1.19	$ 0.55
Diluted net income per common unit (in dollars per unit)	$ 1.40	$ 1.19	$ 0.55
Product sales revenues
REVENUES
Total revenues	$ 46,974	$ 55,948	$ 40,883
Services revenues
REVENUES
Total revenues	$ 1,738	$ 1,394	$ 1,195

Revenues and Accounts Receivable - Disaggregation of Revenue (Details) - Operating Segments - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 48,999	$ 57,473	$ 42,949
Crude Oil
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	47,146	54,929	40,550
Crude Oil \| Sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	45,621	53,822	39,635
Crude Oil \| Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,144	745	484
Crude Oil \| Terminalling, Storage and Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	381	362	431
NGL
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,853	2,544	2,399
NGL \| Sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,729	2,414	2,292
NGL \| Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	30	30	25
NGL \| Terminalling, Storage and Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 94	$ 100	$ 82

- 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

- Definition

+ References

+ Details

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
CURRENT ASSETS
Cash and cash equivalents	$ 450	$ 401
Trade accounts receivable and other receivables, net	3,760	3,907
Inventory	548	729
Other current assets	155	318
Total current assets	4,913	5,355
PROPERTY AND EQUIPMENT	21,143	20,020
Accumulated depreciation	(5,361)	(4,770)
Property and equipment, net	15,782	15,250
OTHER ASSETS
Investments in unconsolidated entities	2,820	3,084
Intangible assets, net	1,875	2,145
Linefill	976	961
Long-term operating lease right-of-use assets, net	313	349
Long-term inventory	265	284
Other long-term assets, net	411	464
Total assets	27,355	27,892
CURRENT LIABILITIES
Trade accounts payable	3,844	4,044
Short-term debt	446	1,159
Other current liabilities	713	688
Total current liabilities	5,003	5,891
LONG-TERM LIABILITIES
Senior notes, net	7,242	7,237
Other long-term debt, net	63	50
Long-term operating lease liabilities	274	308
Other long-term liabilities and deferred credits	1,041	1,081
Total long-term liabilities	8,620	8,676
COMMITMENTS AND CONTINGENCIES (NOTE 18)
PARTNERS’ CAPITAL
Total partners’ capital excluding noncontrolling interests	10,422	10,057
Noncontrolling interests	3,310	3,268
Total partners’ capital	13,732	13,325
Total liabilities and partners’ capital	27,355	27,892
Series A Preferred Units
PARTNERS’ CAPITAL
Partners' capital	1,509	1,505
Series B Preferred Units
PARTNERS’ CAPITAL
Partners' capital	787	787
Common Units
PARTNERS’ CAPITAL
Partners' capital	$ 8,126	$ 7,765

Revenues and Accounts Receivable

12 Months Ended

Dec. 31, 2023

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,
	2023		2022		2021
Crude Oil segment revenues from contracts with customers
Sales	$	45,621	$	53,822	$	39,635
Transportation	1,144		745		484
Terminalling, Storage and Other	381		362		431
Total Crude Oil segment revenues from contracts with customers	$	47,146	$	54,929	$	40,550


	Year Ended December 31,
	2023		2022		2021
NGL segment revenues from contracts with customers
Sales	$	1,729	$	2,414	$	2,292
Transportation	30		30		25
Terminalling, Storage and Other	94		100		82

Total NGL segment revenues from contracts with customers	$	1,853	$	2,544	$	2,399

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 and NGL on pipelines and trucks. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil and NGL 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 and from NGL fractionation and isomerization service. 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. Natural gas storage related activities fees were recognized in the period the natural gas moved across our header system. Fees from NGL fractionation and isomerization services and gas processing services are recognized in the period when the services are performed.

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, 2023	Crude Oil		NGL		Total
Revenues from contracts with customers	$	47,146	$	1,853	$	48,999
Other revenues	28		82		110
Total revenues of reportable segments	$	47,174	$	1,935	$	49,109
Intersegment revenues elimination					(397)
Total revenues					$	48,712


Year Ended December 31, 2022	Crude Oil		NGL		Total
Revenues from contracts with customers	$	54,929	$	2,544	$	57,473
Other revenues	151		217		368
Total revenues of reportable segments	$	55,080	$	2,761	$	57,841
Intersegment revenues elimination					(499)
Total revenues					$	57,342


Year Ended December 31, 2021	Crude Oil		NGL		Total
Revenues from contracts with customers	$	40,550	$	2,399	$	42,949
Other revenues	(80)		(431)		(511)
Total revenues of reportable segments	$	40,470	$	1,968	$	42,438
Intersegment revenues elimination					(360)
Total revenues					$	42,078

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	2023		2022
Billed and collected	Other current liabilities	$	77	$	104

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, 2021	$	141
Amounts recognized as revenue	(26)

Additions (1)	145
Other	(31)
Balance at December 31, 2022	$	229
Amounts recognized as revenue	(42)
Additions	38
Other	3
Balance at December 31, 2023	$	228

(1)Includes approximately $122 million associated with a gas processing agreement that was entered into in conjunction with the purchase of an additional ownership interest in certain straddle plants. Such amount is expected to be recognized as revenue over a 50-year term. See Note 7 for additional information.

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, 2023 (in millions):


	2024		2025		2026		2027		2028		2029 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	375	$	329	$	156	$	109	$	80	$	194
Terminalling, storage and other agreement revenues	234		149		114		101		83		688
Total	$	609	$	478	$	270	$	210	$	163	$	882

(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, including pipelines where there are no or limited alternative pipeline transportation options, (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, 2023 and 2022, 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,
	2023		2022
Trade accounts receivable arising from revenues from contracts with customers	$	3,999	$	4,141
Other trade accounts receivables and other receivables (1)	7,535		7,216
Impact due to contractual rights of offset with counterparties	(7,774)		(7,450)
Trade accounts receivable and other receivables, net	$	3,760	$	3,907

(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 9
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-9

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

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-15

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-12

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

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

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

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

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-13

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
-Topic 606
-Publisher FASB
-URI https://asc.fasb.org//606/tableOfContent

+ Details

Partners' Capital and Distributions

12 Months Ended

Dec. 31, 2023

Partners' Capital Notes [Abstract]

Partners' Capital and Distributions

Partners’ Capital and Distributions

Units Outstanding

At December 31, 2023, partners’ capital consisted of outstanding common units and Series A and Series B preferred units, which represent limited partner interests in us and which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges as outlined in our partnership agreement. Our general partner has a non-economic interest in us.

Series A Preferred Units

Our Series A preferred units were issued in a private placement in 2016 at a price of $26.25 per unit (the “Issue Price”). The Series A preferred units represent limited partner interests in us, rank pari passu with our Series B preferred units, and senior to our common units and to each other class or series of our equity securities with respect to distribution rights and rights upon liquidation. The holders of the Series A preferred units receive cumulative quarterly distributions, subject to customary antidilution adjustments, to unitholders of record within 45 days following the end of each quarter.

The initial Series A preferred unit distribution was equal to $0.525 per unit ($2.10 per unit annualized). After the fifth anniversary of the January 28, 2016 issuance date (the “Issuance Date”) of the Series A preferred units, the holders of the 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 12 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.

We may redeem all or any portion of the outstanding Series A preferred units (subject to certain redemption size limitations and limited to two redemption transactions) in exchange for cash, common units (valued at 95% of the volume-weighted average price of our common units for a trading period specified in our partnership agreement) or a combination of cash and common units at a redemption price equal to 110% of the Issue Price, plus any accrued and unpaid distributions. The holders may convert their Series A preferred units into common units, generally on a one-for-one basis and subject to customary anti-dilution adjustments, at any time, in whole or in part, subject to certain minimum conversion amounts (and not more often than once per quarter). The Series A preferred units vote on an as-converted basis with our common units on the election of directors and have certain other class voting rights with respect to any amendment to our partnership agreement that would adversely affect any rights, preferences or privileges of the Series A preferred units. In addition, upon certain events involving a change of control, the holders of the Series A preferred units may elect, among other potential elections, to convert the Series A preferred units into common units at the then applicable conversion rate.

Series B Preferred Units

Our Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in us (the “Series B preferred units”) were issued in 2017 at a price to the public of $1,000 per unit. Our Series B preferred units represent perpetual equity interests in us, have no stated maturity or mandatory redemption date and are not redeemable at the option of the holders under any circumstances. Holders of the Series B preferred units generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our partnership agreement that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series B preferred units, (ii) the creation or issuance of any parity securities if the cumulative distributions payable on then outstanding Series B preferred units are in arrears, (iii) the creation or issuance of any senior securities and (iv) the payment of distributions to our common unitholders out of capital surplus. The Series B preferred units rank, as to the payment of distributions and amounts payable on a liquidation event, pari passu with our outstanding Series A preferred units and senior to our common units.

The Series B preferred units have a liquidation preference of $1,000 per unit. Holders of our Series B preferred units are entitled to receive, when, as and if declared by our general partner out of legally available funds for such purpose, cumulative semiannual or quarterly cash distributions, as applicable. Through November 15, 2022, distributions on the Series B preferred units were paid semiannually in arrears on the 15th day of May and November. After November 15, 2022, distributions are payable quarterly in arrears on the 15th day of February, May, August and November of each year. 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 0.26121%, plus 4.11% per annum. The distribution rate for the quarterly distribution paid on February 15, 2024 was 9.75093% per annum ($24.92 per Series B preferred unit).

At any time, we may redeem the Series B preferred units, at our option, in whole or in part, at a redemption price of $1,000 per Series B preferred unit plus an amount equal to all accumulated and unpaid distributions thereon to, but not including, the date of redemption, whether or not declared.

The following table presents the activity for our preferred and common units:


	Limited Partners
	Series A Preferred Units	Series B Preferred Units	Common Units
Outstanding at December 31, 2020	71,090,468	800,000	722,380,416



Repurchase and cancellation of common units under the Common Equity Repurchase Program	—	—	(18,061,583)
Issuances of common units under equity-indexed compensation plans	—	—	672,707
Outstanding at December 31, 2021	71,090,468	800,000	704,991,540
Repurchase and cancellation of common units under the Common Equity Repurchase Program	—	—	(7,251,361)
Issuances of common units under equity-indexed compensation plans	—	—	614,319
Outstanding at December 31, 2022	71,090,468	800,000	698,354,498

Issuances of common units under equity-indexed compensation plans	—	—	2,654,251
Outstanding at December 31, 2023	71,090,468	800,000	701,008,749

Common Equity Repurchase Program. In November 2020, the board of directors of PAGP GP 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 our common units and/or PAGP 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 us or PAGP to acquire a particular number of common units or PAGP Class A shares. Any common units or PAGP Class A shares that are repurchased will be canceled. PAGP Class C shares held by us associated with any publicly held common units that are repurchased will also be canceled. See Note 16 for additional information regarding our ownership of PAGP Class C shares.

There were no repurchases under the Program during the year ended December 31, 2023. During the years ended December 31, 2022 and 2021, we repurchased common units under the Program through open market purchases for a total purchase price of $74 million and $178 million, respectively, including commissions and fees. The repurchased common units were canceled immediately upon acquisition, as were the PAGP Class C shares held by us associated with the repurchased common units. At December 31, 2023, the remaining available capacity under the Program was $198 million.

Income Allocation

We allocate net income for partners’ capital presentation purposes by applying the allocation methodology in our partnership agreement. Net income is allocated 100% to our common unitholders, after giving effect to income allocations for cash distributions to our Series A preferred unitholders and guaranteed payments attributable to our Series B preferred unitholders.

For purposes of determining basic and diluted net income per common unit, income is allocated as prescribed in FASB guidance for calculating earnings per unit, including a deduction to income available to common unitholders for distributions attributable to the period on our Series A and Series B preferred units. See Note 4 for additional information.

Distributions to Unitholders

In accordance with our partnership agreement, after making distributions to holders of our outstanding preferred units, we distribute the remainder of our available cash to common unitholders of record within 45 days following the end of each quarter. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter, less reserves established in the discretion of our general partner for future requirements. Our available cash also includes cash on hand resulting from borrowings made after the end of the quarter.

Preferred Unit Distributions

Series A Preferred Unit Distributions. The following table details distributions paid to our Series A preferred unitholders during the years presented (in millions, except unit data):


	Series A Preferred Unitholders


Year	Cash Distribution		Distribution per Unit
2023	$	166		$	2.34
2022	$	149		$	2.10
2021	$	149		$	2.10

On February 14, 2024, we paid a cash distribution of $44 million to our Series A preferred unitholders. At December 31, 2023, such amount was accrued as distributions payable in “Other current liabilities” on our Consolidated Balance Sheet.

Series B Preferred Unit Distributions. The following table details distributions paid to our Series B preferred unitholders during the years presented (in millions, except unit data):


	Series B Preferred Unitholders


Year	Cash Distribution		Distribution per Unit
2023	$	75	$	93.43
2022	$	49	$	61.25
2021	$	49	$	61.25

On February 15, 2024, we paid a cash distribution of $20 million ($24.92 per unit) to our Series B preferred unitholders. At December 31, 2023, approximately $10 million of accrued distributions payable to our Series B preferred unitholders was included in “Other current liabilities” on our Consolidated Balance Sheet.

Common Unit Distributions

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


	Distributions Paid						Distributions per common unit
Year	Public		AAP		Total
2023	$	492	$	256	$	748	$	1.0700
2022	$	383	$	201	$	584	$	0.8325
2021	$	341	$	176	$	517	$	0.7200

On January 8, 2024, we declared a cash distribution of $0.3175 per unit on our outstanding common units. The total distribution of $223 million was paid on February 14, 2024 to unitholders of record at the close of business on January 31, 2024, for the period from October 1, 2023 through December 31, 2023. Of this amount, approximately $74 million was paid to AAP.

Noncontrolling Interests in Subsidiaries

As of December 31, 2023, noncontrolling interests in our subsidiaries consisted of (i) a 35% interest in the Permian JV, (ii) a 30% interest in Cactus II and (iii) 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.

In November 2022, we acquired an additional 5% interest in Cactus II which, combined with changes in governance, resulted in our obtaining control of the entity. We own 70% of Cactus II and reflect the entity as a consolidated subsidiary in our Consolidated Financial Statements, with Enbridge’s 30% interest accounted for as a noncontrolling interest. This transaction resulted in the recognition of partners’ capital attributable to noncontrolling interests of approximately $526 million. See Note 7 for more details regarding this transaction.

In October 2021, we formed a joint venture, the Permian JV, with Oryx Midstream. We own 65% of the Permian JV and consolidate based on control, with Oryx Midstream’s 35% interest accounted for as a noncontrolling interest. This transaction resulted in the recognition of partners’ capital attributable to noncontrolling interests of approximately $2.6 billion and an increase to our partners’ capital excluding noncontrolling interests of approximately $595 million. See Note 7 for more details regarding this transaction.

Distributions to Noncontrolling Interests

Pursuant to the terms of the governing documents for the Permian JV, with the exception of the initial distribution paid in the first quarter of 2022, distributions of available cash from the Permian JV are subject to a tiered modified sharing arrangement. See Note 7 for additional information. Cash available for distribution is cash on hand less the amount of cash required to fund normal operations and capital projects. Distributions from Cactus II and Red River are paid in proportion to each owners interest in the entity. The following table details distributions paid to noncontrolling interests during the years presented (in millions):


	2023		2022		2021
Permian JV (1)	$	249	$	273	$	—
Cactus II	63		4		—
Red River	21		21		14
	$	333	$	298	$	14

(1)The initial distribution from the Permian JV was paid during the first quarter of 2022, with approximately $54 million paid to noncontrolling interests.

Acquisitions, Divestitures and Other Transactions - Rattler Permian Transaction Narrative (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended
	Nov. 30, 2023	Jul. 31, 2022	Sep. 30, 2023	Jun. 30, 2023	Sep. 30, 2022
OMOG JV LLC (“OMOG”)
Business Acquisition [Line Items]
Ownership Interest in Unconsolidated Entity Prior to Acquisition (as a percent)					40.00%
OMOG JV LLC (“OMOG”) \| Plains Oryx Permian Basin LLC
Business Acquisition [Line Items]
Ownership Interest in Unconsolidated Entity Prior to Acquisition (as a percent)				57.00%
Plains Oryx Permian Basin LLC
Business Acquisition [Line Items]
Consolidated subsidiary, ownership interest held by the parent (as a percent)	65.00%	65.00%	65.00%
OMOG JV LLC and Southern Delaware Gathering Assets
Business Acquisition [Line Items]
Business acquisition amount, net to our interest in the Permian JV			$ 191
Consideration transferred			294
Business combination, consideration transferred, including equity interest in acquire held prior to combination			$ 532
OMOG JV LLC and Southern Delaware Gathering Assets \| Level 3 \| Measurement Input, Discount Rate \| Valuation Technique, Discounted Cash Flow \| Minimum \| Intangible Assets
Business Acquisition [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 Acquisition [Line Items]
Business combination, measurement input			0.23
OMOG JV LLC and Southern Delaware Gathering Assets \| Rattler \| Plains Oryx Permian Basin LLC
Business Acquisition [Line Items]
Cash consideration, including working capital and other adjustments			$ 294
OMOG JV LLC (“OMOG”)
Business Acquisition [Line Items]
Additional interest acquired (as a percent)			43.00%
Fair value amount			$ 239
OMOG JV LLC (“OMOG”) \| Plains Oryx Permian Basin LLC
Business Acquisition [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 (“OMOG”) \| Gains/(losses) on investments in unconsolidated entities, net
Business Acquisition [Line Items]
Equity interest in acquiree, remeasurement gain			$ 29
OMOG JV LLC (“OMOG”) \| Level 3 \| Measurement Input, Discount Rate \| Valuation Technique, Discounted Cash Flow
Business Acquisition [Line Items]
Business combination, measurement input			0.11
OMOG JV LLC (“OMOG”) \| Rattler
Business Acquisition [Line Items]
Additional interest acquired (as a percent)			43.00%
OMOG JV LLC (“OMOG”) \| Rattler \| Plains Oryx Permian Basin LLC
Business Acquisition [Line Items]
Additional interest acquired (as a percent)			43.00%

Related Party Transactions - Transactions with Other Related Parties (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Related Party Transactions
Revenues from related parties	$ 48,712	$ 57,342	$ 42,078
Purchases and related costs from related parties	404	365	385
Trade accounts receivable and other receivables, net from related parties	3,760	3,907
Trade accounts payable to related parties	3,844	4,044
Affiliated Entity
Related Party Transactions
Revenues from related parties	48	45	$ 33
Trade accounts receivable and other receivables, net from related parties	63	45
Trade accounts payable to related parties	$ 72	$ 79

- Definition

+ References

+ Details

Leases - Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Lessee, Lease, Assets and Liabilities [Line Items]
Long-term operating lease right-of-use assets, net	$ 313	$ 349
Finance lease right-of-use assets, gross	144	124
Finance lease right-of-use assets, accumulated depreciation	(46)	(41)
Finance lease right-of-use assets, net	$ 98	$ 83
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	$ 411	$ 432
Operating lease liabilities
Operating lease liabilities, current	$ 69	$ 71
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other current liabilities	Other current liabilities
Long-term operating lease liabilities	$ 274	$ 308
Total operating lease liabilities	343	379
Finance lease liabilities
Finance lease liabilities, current	$ 13	$ 10
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Short-term debt	Short-term debt
Finance lease liabilities, noncurrent	$ 63	$ 50
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other long-term debt, net	Other long-term debt, net
Total finance lease liabilities	$ 76	$ 60
Total lease liabilities	419	439
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	28	30
Finance lease liabilities
Total finance lease liabilities	$ 34	$ 35
Ownership interest in unconsolidated entity (as a percent)	50.00%

Cover - USD ($)
$ in Billions

12 Months Ended

Dec. 31, 2023

Feb. 16, 2024

Jun. 30, 2023

Cover [Abstract]

Document Type

10-K

Document Annual Report

true

Document Period End Date

Dec. 31, 2023

Current Fiscal Year End Date

--12-31

Document Transition Report

false

Entity File Number

1-14569

Entity Registrant Name

PLAINS ALL AMERICAN PIPELINE LP

Entity Incorporation, State or Country Code

Entity Tax Identification Number

76-0582150

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

Entity Address, Postal Zip Code

77002

City Area Code

713

Local Phone Number

646-4100

Title of 12(b) Security

Common Units

Trading Symbol

PAA

Security Exchange Name

NASDAQ

Entity Well-known Seasoned Issuer

Yes

Entity Voluntary Filers

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

$ 6.4

Entity Common Stock Outstanding (in units)

701,071,031

Documents Incorporated by Reference

Portions of the registrant’s definitive Proxy Statement to be filed pursuant to Regulation 14A pertaining to the 2024 Annual Meeting of Unitholders 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

0001070423

Amendment Flag

false

Document Fiscal Year Focus

2023

Document Fiscal Period Focus

Derivatives and Risk Management Activities - Net Unrealized Gain/(Loss) Recognized in AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivatives, Fair Value [Line Items]
Proceeds from settlement of interest rate hedging instruments	$ 80	$ 42
Other current assets
Derivatives, Fair Value [Line Items]
Interest Rate Cash Flow Hedge Derivative at Fair Value, Net	51	75
Other long-term assets, net
Derivatives, Fair Value [Line Items]
Interest Rate Cash Flow Hedge Derivative at Fair Value, Net	4	45
Interest Rate Swap Terminated \| Cash Flow Hedging
Derivatives, Fair Value [Line Items]
Notional amount of derivatives	200
Proceeds from settlement of interest rate hedging instruments	80
Interest Rate Derivatives
Derivatives, Fair Value [Line Items]
Interest rate derivatives, net	15	$ 94	$ 19
AOCI Cash Flow Hedge
Derivatives, Fair Value [Line Items]
Net gain/(loss) deferred in AOCI	(81)
AOCI Cash Flow Hedge \| Interest Rate Swap Terminated \| Cash Flow Hedging
Derivatives, Fair Value [Line Items]
Net gain/(loss) deferred in AOCI	$ 73

Inventory, Linefill and Long-term Inventory - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Inventory Disclosure [Abstract]
Charge related to the write-down of inventory	$ 0	$ 0	$ 0

Acquisitions, Divestitures and Other Transactions - Schedule of Amortization Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Sep. 30, 2023	Nov. 30, 2022	Oct. 31, 2021
Business Acquisition [Line Items]
Expected amortization, year one	$ 272
Expected amortization, year two	249
Expected amortization, year three	210
Expected amortization, year four	187
Expected amortization, year five	165
OMOG JV LLC and Southern Delaware Gathering Assets
Business Acquisition [Line Items]
Finite-lived intangible asset, useful life (in years)				10 years
OMOG JV LLC and Southern Delaware Gathering Assets \| Customer relationships
Business Acquisition [Line Items]
Finite-lived intangible asset, useful life (in years)				10 years
Amortization	4
Expected amortization, year one	8
Expected amortization, year two	10
Expected amortization, year three	4
Expected amortization, year four	3
Expected amortization, year five	2
Cactus II Pipeline LLC
Business Acquisition [Line Items]
Finite-lived intangible asset, useful life (in years)					20 years
Cactus II Pipeline LLC \| Customer relationships
Business Acquisition [Line Items]
Finite-lived intangible asset, useful life (in years)					20 years
Amortization	61	$ 13
Expected amortization, year one	51
Expected amortization, year two	47
Expected amortization, year three	32
Expected amortization, year four	32
Plains Oryx Permian Basin LLC \| Customer relationships \| Joint Venture Transaction
Business Acquisition [Line Items]
Finite-lived intangible asset, useful life (in years)						20 years
Amortization	138	$ 142	$ 28
Expected amortization, year one	127
Expected amortization, year two	117
Expected amortization, year three	$ 106

Derivatives and Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2023

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,
	2023		2022		2021
Product sales revenues	$	13	$	179	$	(710)
Field operating costs	(45)		59		71
Net gain/(loss) from commodity derivative activity	$	(32)	$	238	$	(639)

Schedule of Net Broker Receivable (Payable)

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


	December 31,
	2023		2022
Initial margin	$	77	$	93
Variation margin returned	(65)		(236)
Letters of credit	(25)		(25)
Net broker payable	$	(13)	$	(168)

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, 2023								December 31, 2022
					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	$	153	$	(79)	$	(13)	$	61	$	300	$	(71)	$	(168)	$	61
Other long-term assets, net	3		—		—		3		9		(5)		—		4
Derivative Liabilities
Other current liabilities	1		(64)		—		(63)		2		(13)		—		(11)
Other long-term liabilities and deferred credits	1		(15)		—		(14)		—		—		—		—
Total	$	158	$	(158)	$	(13)	$	(13)	$	311	$	(89)	$	(168)	$	54

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

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


	Year Ended December 31,
	2023		2022		2021
Interest rate derivatives, net	$	15	$	94	$	19

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, 2023								Fair Value as of December 31, 2022
Recurring Fair Value Measures (1)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivatives	$	9	$	(9)	$	—	$	—	$	(7)	$	229	$	—	$	222
Interest rate derivatives	—		55		—		55		—		120		—		120
Preferred Distribution Rate Reset Option	—		—		—		—		—		—		(189)		(189)

Total net derivative asset/(liability)	$	9	$	46	$	—	$	55	$	(7)	$	349	$	(189)	$	153

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

Schedule of Reconciliation of Changes in Fair Value of Derivatives Classified as Level 3

The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 (in millions):


	Year Ended December 31,
	2023		2022
Beginning Balance	$	(189)	$	(2)
Net gains/(losses) for the period included in earnings	58		(189)
Settlements	131		2

Ending Balance	$	—	$	(189)

Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period	$	—	$	(189)

Commodity Derivatives

Derivatives and Risk Management Activities

Schedule of Open Derivative Contracts

The following table summarizes our open derivative positions utilized to hedge the price risk associated with anticipated purchases and sales related to our natural gas processing and NGL fractionation activities as of December 31, 2023.


	Notional Volume (Short)/Long	Remaining Tenor
Natural gas purchases	78.2 Bcf	December 2025
Propane sales	(14.1) MMbls	December 2025
Butane sales	(2.5) MMbls	December 2024
Condensate sales	(3.1) MMbls	December 2024

Fuel gas requirements (1)	7.1 Bcf	December 2024
Power supply requirements (1)	2.4 TWh	December 2030

(1)Positions to hedge a portion of our power supply and fuel gas requirements at our Canadian natural gas processing and fractionation plants.

Interest Rate Derivatives

Derivatives and Risk Management Activities

Schedule of Terms of Forward Starting Interest Rate Derivatives

The following table summarizes the terms of our outstanding interest rate derivatives as of December 31, 2023 (notional amounts in millions):

Hedged Transaction

Number and Types of

Derivatives Employed

Notional

Amount

Expected

Termination Date

Average Rate Locked

Accounting

Treatment

Anticipated interest payments

8 forward starting swaps

(30-year)

200

6/15/2026

3.09

Cash flow hedge

Anticipated interest payments

4 forward starting swaps

(30-year)

100

6/14/2024

0.74

Cash flow hedge

Investments in Unconsolidated Entities - Summarized Financial Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Investments in Unconsolidated Entities
Current assets	$ 4,913	$ 5,355
Current liabilities	5,003	5,891
Noncurrent liabilities	8,620	8,676
Revenues	48,712	57,342	$ 42,078
Operating income	1,510	1,292	851
Equity Method Investment, Nonconsolidated Investee
Investments in Unconsolidated Entities
Current assets	528	471
Noncurrent assets	7,194	7,579
Current liabilities	476	252
Noncurrent liabilities	5	8
Revenues	1,667	1,726	1,320
Operating income	921	1,004	505
Net income	$ 947	$ 1,011	$ 506

- Definition

Sum of the carrying amounts as of the balance sheet date of all assets that are expected to be realized in cash, sold, or consumed within one year (or the normal operating cycle, if longer). Assets are probable future economic benefits obtained or controlled by an entity as a result of past transactions or events.

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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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Partners' Capital and Distributions - Activity for Series A and B Preferred Units and Common Units (Details) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Series A Preferred Units
Activity for preferred units and common units
Outstanding, beginning of period (in units)	71,090,468	71,090,468	71,090,468
Outstanding, end of period (in units)	71,090,468	71,090,468	71,090,468
Series B Preferred Units
Activity for preferred units and common units
Outstanding, beginning of period (in units)	800,000	800,000	800,000
Outstanding, end of period (in units)	800,000	800,000	800,000
Common Units
Activity for preferred units and common units
Outstanding, beginning of period (in units)	698,354,498	704,991,540	722,380,416
Repurchase and cancellation of common units under the Common Equity Repurchase Program (in units)		(7,251,361)	(18,061,583)
Issuance of common units under equity-indexed compensation plans (in units)	2,654,251	614,319	672,707
Outstanding, end of period (in units)	701,008,749	698,354,498	704,991,540

Pay vs Performance Disclosure - USD ($) $ in Millions	12 Months Ended
Pay vs Performance Disclosure - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net Income (Loss)	$ 1,230	$ 1,037	$ 593

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

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-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-30

Reference 30: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (f)
-Publisher FASB
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Reference 31: http://www.xbrl.org/2003/role/disclosureRef
-Topic 260
-SubTopic 10
-Name Accounting Standards Codification
-Section 45
-Paragraph 60B
-Subparagraph (a)
-Publisher FASB
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Reference 32: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
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-Section 50
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-Publisher FASB
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Reference 33: http://www.xbrl.org/2003/role/disclosureRef
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-Section 50
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Reference 34: http://www.xbrl.org/2003/role/disclosureRef
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Reference 36: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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-Paragraph 1A
-Subparagraph (a)
-Publisher FASB
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Reference 37: http://www.xbrl.org/2003/role/disclosureRef
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-Paragraph 2
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-Paragraph 1
-Subparagraph (SX 210.9-04(22))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147483589/942-220-S99-1

+ Details

Commitments and Contingencies - Legal, Environmental or Regulatory (Details)			1 Months Ended		9 Months Ended	12 Months Ended			14 Months Ended	104 Months Ended
	Oct. 27, 2022 USD ($)	Oct. 14, 2020 USD ($)	Sep. 30, 2021 USD ($)	May 31, 2015 bbl	Sep. 20, 2022 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2023 USD ($)	Apr. 25, 2019 USD ($)	Sep. 07, 2018 count
Line 901 Incident
Legal, Environmental or Regulatory Matters
Estimated size of release (in bbl) \| bbl				2,934
Estimated size of release to reach Pacific Ocean (in bbl) \| bbl				598
Recoveries from insurance carriers										$ 280,000,000
Aggregate total estimated costs						$ 750,000,000			$ 750,000,000	750,000,000
Significant costs related to legal and environmental remediation matters						10,000,000	$ 95,000,000	$ 15,000,000
Total release costs probable of recovery						505,000,000			505,000,000	505,000,000
Line 901 Incident \| Civil Penalties \| Judicial Ruling
Legal, Environmental or Regulatory Matters
Penalties or compensation paid		$ 24,000,000
Line 901 Incident \| Compensation for Injuries to, Destruction of, Loss of Use of, Natural Resources \| Judicial Ruling
Legal, Environmental or Regulatory Matters
Penalties or compensation paid		$ 22,325,000
Line 901 Incident \| May 2016 Indictment
Legal, Environmental or Regulatory Matters
Number of felony charges found guilty \| count												1
Number of misdemeanor charges found guilty \| count												8
Number of misdemeanor charges found guilty, reporting \| count												1
Number of misdemeanor charges found guilty, strict liability discharge \| count												1
Number of misdemeanor charges found guilty, strict liability animal takings \| count												6
Number of misdemeanor charges not guilty, strict liability animal takings \| count												1
Line 901 Incident \| May 2016 Indictment \| Judicial Ruling
Legal, Environmental or Regulatory Matters
Fines or penalties assessed											$ 3,350,000
Line 901 Incident \| May 2016 Indictment \| Maximum \| Judicial Ruling
Legal, Environmental or Regulatory Matters
Amount awarded to claimants by court			$ 150,000
Line 901 Incident \| Class Action Lawsuit Claim of Damages \| Pending Litigation
Legal, Environmental or Regulatory Matters
Litigation settlement agreement amount, subject to approval					$ 230,000,000
Line 901 Incident \| Class Action Lawsuit Claim of Damages \| Settled Litigation
Legal, Environmental or Regulatory Matters
Payments for legal settlements	$ 230,000,000
Line 901 2015 Insurance Program
Legal, Environmental or Regulatory Matters
Recoveries from insurance carriers										275,000,000
Coverage limit under insurance program						500,000,000			500,000,000	500,000,000
Exceeded coverage limit under insurance program						250,000,000			250,000,000	250,000,000
Claim for Reimbursement From Insurance
Legal, Environmental or Regulatory Matters
Recoveries from insurance carriers									3,600,000
Receivable for remaining portion of release costs probable of recovery from insurance						225,000,000			225,000,000	225,000,000
Denial of Insurance Coverage
Legal, Environmental or Regulatory Matters
Receivable for remaining portion of release costs probable of recovery from insurance						185,000,000			185,000,000	185,000,000
Response to Request for Reimbursement Not Received
Legal, Environmental or Regulatory Matters
Receivable for remaining portion of release costs probable of recovery from insurance						40,000,000			40,000,000	40,000,000
Arbitration Proceedings Against Insurers
Legal, Environmental or Regulatory Matters
Receivable for remaining portion of release costs probable of recovery from insurance						175,000,000			175,000,000	175,000,000
Other long-term assets, net \| Line 901 Incident
Legal, Environmental or Regulatory Matters
Receivable for remaining portion of release costs probable of recovery from insurance						225,000,000			225,000,000	225,000,000
Current liabilities \| Line 901 Incident
Legal, Environmental or Regulatory Matters
Remaining undiscounted liability						94,000,000	105,000,000		94,000,000	94,000,000
Excluding Line 901 Incident
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities						56,000,000	55,000,000		56,000,000	56,000,000
Estimated undiscounted reserve for environmental liabilities, short-term						$ 10,000,000	$ 10,000,000		$ 10,000,000	$ 10,000,000
Estimated undiscounted reserve for environmental liabilities, short-term [Extensible Enumeration]						Other current liabilities	Other current liabilities		Other current liabilities	Other current liabilities
Estimated undiscounted reserve for environmental liabilities, long-term						$ 46,000,000	$ 45,000,000		$ 46,000,000	$ 46,000,000
Estimated undiscounted reserve for environmental liabilities, long-term [Extensible Enumeration]						Other long-term liabilities and deferred credits	Other long-term liabilities and deferred credits		Other long-term liabilities and deferred credits	Other long-term liabilities and deferred credits
Amounts probable of recovery under insurance and from third parties under indemnification agreements						$ 4,000,000	$ 4,000,000		$ 4,000,000	$ 4,000,000
Excluding Line 901 Incident \| Other long-term assets, net
Legal, Environmental or Regulatory Matters
Amounts probable of recovery under insurance and from third parties under indemnification agreements						$ 1,000,000	$ 1,000,000		$ 1,000,000	$ 1,000,000

Leases - Other Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Operating cash flows for operating leases	$ 81	$ 92	$ 91
Operating cash flows for finance leases	6	6	7
Financing cash flows for finance leases	11	12	11
Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications, operating leases	32	43	94
Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications, finance leases	$ 27	$ 2	$ 1
Weighted-average remaining lease term (in years):
Operating lease, weighted-average lease term	13 years	12 years
Finance lease, weighted-average lease term	8 years	9 years
Weighted-average discount rate:
Operating lease, weighted-average discount rate	4.90%	4.30%
Finance lease, weighted-average discount rate	11.30%	12.30%

Investments in Unconsolidated Entities (Tables)

12 Months Ended

Dec. 31, 2023

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, 2023	Investment Balance December 31,

Entity (1)	Type of Operation		2023		2022
BridgeTex Pipeline Company, LLC (“BridgeTex”)	Crude Oil Pipeline	20%	$	363	$	403

Capline Pipeline Company LLC (“Capline”)	Crude Oil Pipeline	54%	535		539
Diamond Pipeline LLC	Crude Oil Pipeline	50%	450		460
Eagle Ford Pipeline LLC	Crude Oil Pipeline	50%	370		371
Eagle Ford Terminals Corpus Christi LLC	Crude Oil Terminal and Dock	50%	116		118
OMOG JV LLC (“OMOG”) (2)	Crude Oil Pipeline	—%	—		211
Saddlehorn Pipeline Company, LLC	Crude Oil Pipeline	30%	192		197
White Cliffs Pipeline, LLC	Crude Oil Pipeline	36%	138		150
Wink to Webster Pipeline LLC (“W2W Pipeline”) (3)	Crude Oil Pipeline	16%	380		357
Other investments			276		278
Total Investments in Unconsolidated Entities			$	2,820	$	3,084

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

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,
	2023		2022
Current assets	$	528	$	471
Noncurrent assets	$	7,194	$	7,579
Current liabilities	$	476	$	252
Noncurrent liabilities	$	5	$	8


	Year Ended December 31,
	2023		2022		2021
Revenues	$	1,667	$	1,726	$	1,320
Operating income	$	921	$	1,004	$	505
Net income	$	947	$	1,011	$	506

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense

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


	Year Ended December 31,
	2023		2022		2021
Current income tax expense:
State income tax	$	2	$	1	$	2
Canadian federal and provincial income tax	143		83		48
Total current income tax expense	$	145	$	84	$	50

Deferred income tax expense/(benefit):
Canadian federal and provincial income tax	$	(24)	$	105	$	23
Total deferred income tax expense/(benefit)	$	(24)	$	105	$	23
Total income tax expense	$	121	$	189	$	73

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):


	Year Ended December 31,
	2023		2022		2021
Income before tax	$	1,623	$	1,417	$	721
Partnership earnings not subject to Canadian tax	(1,136)		(686)		(370)
	$	487	$	731	$	351
Canadian federal and provincial corporate tax rate	24%		24%		24%
Income tax expense at statutory rate	$	117	$	175	$	84


Canadian permanent differences	$	2	$	13	$	(13)
State income tax	2		1		2
Total income tax expense	$	121	$	189	$	73

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,
	2023		2022
Deferred tax assets:

Lease liabilities	$	40	$	45

Other	45		16
Total deferred tax assets	85		61

Deferred tax liabilities:
Property and equipment in excess of tax values	(573)		(515)
Derivative instruments	(6)		(46)
Lease assets	(38)		(42)
Other	(3)		(3)
Total deferred tax liabilities	(620)		(606)
Net deferred tax liabilities	$	(535)	$	(545)

Balance sheet classification of deferred tax assets/(liabilities):

Other long-term liabilities and deferred credits	$	(535)	$	(545)
	$	(535)	$	(545)

Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Level 3
Rollforward of Level 3 Net Asset/(Liability)
Beginning Balance	$ (189)	$ (2)
Net gains/(losses) for the period included in earnings	$ 58	$ (189)
Net gains/(losses) for the period included in earnings [Extensible Enumeration]	Total revenues	Total revenues
Settlements	$ 131	$ 2
Ending Balance		(189)
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period		$ (189)
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period [Extensible Enumeration]	Other income/(expense), net	Other income/(expense), net
Recurring Fair Value Measures
Recurring Fair Value Measurements
Total net derivative asset/(liability)	$ 55	$ 153
Recurring Fair Value Measures \| Commodity Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)		222
Recurring Fair Value Measures \| Interest Rate Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	55	120
Recurring Fair Value Measures \| Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Total net derivative asset/(liability)		(189)
Recurring Fair Value Measures \| Level 1
Recurring Fair Value Measurements
Total net derivative asset/(liability)	9	(7)
Recurring Fair Value Measures \| Level 1 \| Commodity Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	9	(7)
Recurring Fair Value Measures \| Level 1 \| Interest Rate Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	0	0
Recurring Fair Value Measures \| Level 1 \| Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Total net derivative asset/(liability)	0	0
Recurring Fair Value Measures \| Level 2
Recurring Fair Value Measurements
Total net derivative asset/(liability)	46	349
Recurring Fair Value Measures \| Level 2 \| Commodity Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(9)	229
Recurring Fair Value Measures \| Level 2 \| Interest Rate Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	55	120
Recurring Fair Value Measures \| Level 2 \| Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Total net derivative asset/(liability)	0	0
Recurring Fair Value Measures \| Level 3
Recurring Fair Value Measurements
Total net derivative asset/(liability)		(189)
Recurring Fair Value Measures \| Level 3 \| Commodity Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	0	0
Recurring Fair Value Measures \| Level 3 \| Interest Rate Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	$ 0	0
Recurring Fair Value Measures \| Level 3 \| Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Total net derivative asset/(liability)		$ (189)

Revenues and Accounts Receivable (Tables)

12 Months Ended

Dec. 31, 2023

Revenue from Contract with Customer [Abstract]

Schedule of Disaggregation of Revenue

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,
	2023		2022		2021
Crude Oil segment revenues from contracts with customers
Sales	$	45,621	$	53,822	$	39,635
Transportation	1,144		745		484
Terminalling, Storage and Other	381		362		431
Total Crude Oil segment revenues from contracts with customers	$	47,146	$	54,929	$	40,550


	Year Ended December 31,
	2023		2022		2021
NGL segment revenues from contracts with customers
Sales	$	1,729	$	2,414	$	2,292
Transportation	30		30		25
Terminalling, Storage and Other	94		100		82

Total NGL segment revenues from contracts with customers	$	1,853	$	2,544	$	2,399

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, 2023	Crude Oil		NGL		Total
Revenues from contracts with customers	$	47,146	$	1,853	$	48,999
Other revenues	28		82		110
Total revenues of reportable segments	$	47,174	$	1,935	$	49,109
Intersegment revenues elimination					(397)
Total revenues					$	48,712


Year Ended December 31, 2022	Crude Oil		NGL		Total
Revenues from contracts with customers	$	54,929	$	2,544	$	57,473
Other revenues	151		217		368
Total revenues of reportable segments	$	55,080	$	2,761	$	57,841
Intersegment revenues elimination					(499)
Total revenues					$	57,342


Year Ended December 31, 2021	Crude Oil		NGL		Total
Revenues from contracts with customers	$	40,550	$	2,399	$	42,949
Other revenues	(80)		(431)		(511)
Total revenues of reportable segments	$	40,470	$	1,968	$	42,438
Intersegment revenues elimination					(360)
Total revenues					$	42,078

Schedule of Contract with Customer, Counterparty Deficiencies


		December 31,
Counterparty Deficiencies	Financial Statement Classification	2023		2022
Billed and collected	Other current liabilities	$	77	$	104

Schedule of Contracts with Customers, Change in 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, 2021	$	141
Amounts recognized as revenue	(26)

Additions (1)	145
Other	(31)
Balance at December 31, 2022	$	229
Amounts recognized as revenue	(42)
Additions	38
Other	3
Balance at December 31, 2023	$	228


	December 31,
	2023		2022
Trade accounts receivable arising from revenues from contracts with customers	$	3,999	$	4,141
Other trade accounts receivables and other receivables (1)	7,535		7,216
Impact due to contractual rights of offset with counterparties	(7,774)		(7,450)
Trade accounts receivable and other receivables, net	$	3,760	$	3,907

(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, 2023 (in millions):


	2024		2025		2026		2027		2028		2029 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	375	$	329	$	156	$	109	$	80	$	194
Terminalling, storage and other agreement revenues	234		149		114		101		83		688
Total	$	609	$	478	$	270	$	210	$	163	$	882

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

Equity-Indexed Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2023

Share-Based Payment Arrangement [Abstract]

Schedule of LTIP Awards Authorized

The following is a summary of the awards authorized under our LTIPs as of December 31, 2023 (in millions):


LTIP						LTIP Awards Authorized
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)						43.5

(1)Of the 43.5 million total awards authorized, 17.4 million awards are currently available for future grant. The remaining balance has already vested or is currently outstanding.

Revenues and Accounts Receivable - Narrative (Details)	12 Months Ended
Revenues and Accounts Receivable - Narrative (Details)	Dec. 31, 2023	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Substantially all trade accounts receivable, net, maximum age of balances past their scheduled invoice date (in days)	30 days	30 days

Acquisitions, Divestitures and Other Transactions

12 Months Ended

Dec. 31, 2023

Business Combination and Asset Acquisition [Abstract]

Acquisitions, Divestitures and Other Transactions

Acquisitions

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 “Gains/(losses) 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 $4 million during the year ended December 31, 2023, and the future amortization expense through 2028 is estimated as follows (in millions):



2024	$	8
2025	$	10
2026	$	4
2027	$	3
2028	$	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.

Cactus II

In November 2022, we and Enbridge Inc. (“Enbridge”) purchased Western Midstream Partners, LP (“WES”)’s 15% interest in Cactus II Pipeline, LLC (“Cactus II”) for an aggregate amount of $265 million. Enbridge acquired 10% and we acquired 5% of Cactus II, with each paying a proportionate share ($177 million and $88 million, respectively) of the aggregate purchase price. We and Enbridge are now the sole owners of Cactus II, with 70% and 30% respective ownership interests. We will continue to serve as operator. We previously accounted for our 65% interest in Cactus II as an equity method investment. In addition to the change in ownership, there were changes in governance which led to a change in control. We now control Cactus II and reflect Cactus II as a consolidated subsidiary in our Consolidated Financial Statements, with Enbridge’s 30% interest reflected as a noncontrolling interest.

The acquisition was accounted for as a business combination achieved in stages, or a “step acquisition”, using the acquisition method of accounting. As the majority owner and the controlling entity, we are considered the acquirer and the Cactus II predecessor business was recorded based on the fair value of the assets acquired and liabilities assumed, with Enbridge’s 30% interest in Cactus II of $526 million recognized as noncontrolling interest in partners’ capital.

As a result of us obtaining control over Cactus II, our previously held 65% interest in Cactus II was remeasured to its fair value of $1.140 billion 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 WES for its 15% interest in Cactus II and (ii) a discounted cash flow approach. The discounted cash flow approach utilized a discount rate of approximately 14%, based on the estimate of the risk that a theoretical market participant would assign to the business. Prior to the acquisition, we had a preexisting relationship with Cactus II, through one of our consolidated joint ventures, for certain capacity lease agreements. The portion of the fair value of Cactus II associated with these agreements is eliminated in consolidation. Accounting for such impact, the remeasurement of our investment in Cactus II to fair value resulted in a gain of $370 million. This gain has been recognized in the line item “Gains/(losses) on investments in unconsolidated entities, net” on our Consolidated Statement of Operations

In accordance with applicable accounting guidance, the fair value of Cactus II following the acquisition is utilized as the consideration transferred for the purchase price allocation. The consideration transferred of $1.556 billion excludes the value associated with the capacity lease agreements described above as such value is eliminated for our Consolidated Financial Statements.

The determination of the fair value of the assets acquired and liabilities assumed was estimated in accordance with the applicable accounting guidance. The analysis was performed based on estimates that are reflective of market participant assumptions. The following table reflects our determination of the fair value of those assets and liabilities (in millions):


Identifiable Assets Acquired and Liabilities Assumed:	Estimated Useful Lives (in years)	Recognized Amount
Property and equipment	3-50	$	1,174
Intangible assets	20	428
Working capital and other assets and liabilities	N/A	(46)
		$	1,556

The fair value of the tangible assets is a Level 3 measurement in the fair value hierarchy and was determined using a market approach for rights-of-way and a cost approach for other tangible assets, which were 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 a discount rate of approximately 18%, 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 20 years. The value assigned to such intangible assets will be amortized to earnings under the declining balance method of amortization. Amortization expense was approximately $61 million and $13 million during the years ended December 31, 2023 and 2022, respectively, and the future amortization expense through 2027 is estimated as follows (in millions):



2024	$	51
2025	$	47
2026	$	32
2027	$	32

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

Other Acquisitions

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.

During the year ended December 31, 2022, we also completed the following acquisitions:

•the acquisition in July 2022 of the remaining 50% interest in Advantage Pipeline Holdings LLC (“Advantage”) for $74 million (approximately $48 million net to our 65% interest in the Permian JV), including cash paid for working capital. As a result of this transaction, we now own 100% of Advantage and its subsidiaries and such entities are reflected as consolidated subsidiaries in our Consolidated Financial Statements.

•the acquisition in October 2022 of an additional ownership interest in certain straddle plants included in our NGL segment in a non-cash transaction whereby we agreed to provide processing capacity over a 50-year term at specified terms and conditions. This transaction was accounted for as an asset acquisition. The fair value of the straddle plant assets acquired and liabilities assumed was approximately $122 million, and we recognized an equally offsetting contract liability that will be amortized on a straight-line basis into “Services revenue” over the 50-year term of the agreement.

Asset Exchange

In June 2021, we closed on an asset exchange agreement (the “Asset Exchange”) with Inter Pipeline Ltd., through which we acquired additional interests in two straddle plants included in our NGL segment that we currently operate, in exchange for a pipeline and related storage and truck offload facilities previously included in our Crude Oil segment and cash consideration of $32 million, including working capital and other adjustments. We recognized a gain of $106 million on the divestiture of the pipeline and related storage and truck offload facilities, which is included in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statement of Operations, based on the difference between the fair value of the divested assets and their carrying value.

Joint Venture Transaction

In October 2021, we and Oryx Midstream completed the merger, in a cashless, debt-free transaction, of our respective Permian Basin assets, operations and commercial activities into a newly formed joint venture, the Permian JV. The Permian JV includes all of Oryx Midstream’s Permian Basin assets and, with the exception of our long-haul pipeline systems and certain of our intra-basin terminal assets, the vast majority of our assets located within the Permian Basin. We own 65% of the Permian JV, operate the combined assets and reflect the Permian JV as a consolidated subsidiary in our consolidated financial statements.

The formation of the joint venture was accounted for as a business combination using the acquisition method of accounting. As the majority owner and the controlling entity, we are considered the acquirer and the transfer of our predecessor business to the joint venture was accounted for at historical cost, while the Oryx Midstream predecessor business was recorded based on the fair value of the assets acquired and liabilities assumed. In accordance with applicable accounting guidance, the fair value of Oryx Midstream’s ownership interest in the joint venture following the formation of $3.230 billion is utilized as the consideration transferred for the purchase price allocation.

The combination of the historical cost and fair value, discussed above, resulted in net assets of the joint venture of approximately $7.529 billion upon formation. Oryx Midstream’s 35% interest in the net assets of the Permian JV was recognized as noncontrolling interest in partners’ capital. The difference between the noncontrolling interest recognized and the fair value of Oryx Midstream’s assets acquired and liabilities assumed was recorded as an increase to our partners’ capital excluding noncontrolling interests.

The following table presents the amounts recognized in partners’ capital associated with this transaction (in millions):


	Recognized Amount
Noncontrolling interests	$	2,635

Partners’ capital, excluding noncontrolling interests	595
	$	3,230

The fair value of the $3.230 billion consideration is a Level 3 measurement in the fair value hierarchy and was determined by valuing both the enterprise value of Oryx Midstream’s Permian Basin business and the enterprise value of our Permian Basin assets that were contributed to the joint venture. The enterprise value of Oryx Midstream’s Permian Basin business was calculated by weighting the results of (i) a discounted cash flow approach and (ii) a guideline public company method (“GPCM”). The value of our Permian Basin assets that were contributed to the joint venture was based on a GPCM. The discounted cash flow approach utilized a discount rate of 12%, based on our estimate of the risk that a theoretical market participant would assign to the business. The projection of future crude volumes gathered and transported was also a key assumption in the discounted cash flow approach and was based on projected rig activity on the associated acreage. The GPCM applies market multiples to estimated earnings to derive the fair value. The GPCM values for Oryx Midstream’s Permian Basin business and for our Permian Basin assets that were contributed to the joint venture assumed market multiples ranging from 9.5 to 11.0, which were derived from assumptions of market multiples for similar businesses.


Identifiable Assets Acquired and Liabilities Assumed	Estimated Useful Lives (in years)	Recognized Amount
Property and equipment	3-30	$	1,886
Intangible assets	20	1,247
Investment in unconsolidated entities	N/A	103

Working capital and other assets and liabilities	N/A	(6)
		$	3,230

The fair value of the tangible assets is a Level 3 measurement in the fair value hierarchy and was determined using a 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 a discount rate of 16%, 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 gathered and transported was also a key assumption in the valuation of the intangible assets and was based on projected rig activity on the associated acreage.

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 20 years. The value assigned to such intangible assets will be amortized to earnings under the declining balance method of amortization. Amortization expense was approximately $138 million, $142 million and $28 million during the years ended December 31, 2023, 2022 and 2021, respectively, and the future amortization expense through 2026 is estimated as follows (in millions):




2024	$	127
2025	$	117
2026	$	106

During the year ended December 31, 2021, we incurred approximately $17 million of transaction-related costs associated with the joint venture formation transaction. Such costs are reflected as a component of “General and administrative expenses” on our Consolidated Statements of Operations.

Distributions of available cash from the Permian JV to us and Oryx Midstream are subject to a tiered modified sharing arrangement (“MSA”) for up to ten years. Pursuant to the terms of the governing documents for the Permian JV, the MSA will terminate in October 2031, or sooner if Oryx Midstream exercises its right to terminate the MSA at any time by delivery of written notice to us. Upon termination of the MSA, monthly distributions of available cash will be paid 65% to PAA and 35% to Oryx. Through the third quarter of 2022, the Permian JV made quarterly distributions, but starting in December 2022, the Permian JV began making monthly distributions to the members after renegotiation of the MSA.

Under the MSA, distributions will be allocated as follows (in millions):


	Available Cash	Distributions Percentages
Tier	Annualized	PAA	Oryx
1	Up to $300	50%	50%
2	$300 - $428	100%	—%
3	$428 - $815	65%	35%
4	$815 and above	70%	30%

Oryx Midstream is a portfolio company of Stonepeak Infrastructure Partners (“Stonepeak”). Affiliates of Stonepeak own approximately 8.9% of our outstanding Series A preferred units, which equates to less than 1% of our outstanding common units and Series A preferred units (our “common unit equivalents”) combined.

Pro Forma and Other Financial Results

Financial results of the Permian JV have been included in the results of operations within the Crude Oil segment since the date of the formation. Disclosure of the revenues and earnings from the Oryx Midstream predecessor business for the period subsequent to the joint venture formation is not practicable as it is not being operated as a standalone subsidiary. The following selected unaudited pro forma results of operations were derived from the historical financial statements of PAA and Oryx Midstream, and gives effect to the joint venture formation as if it had occurred on January 1, 2021. The pro forma results of operations do not include any cost savings or other synergies that may result from the Permian JV or any estimated costs that have been or will be incurred by us to integrate Oryx Midstream’s assets. These results are not necessarily indicative of the results that might have actually occurred had the merger taken place on January 1, 2021; furthermore, this financial information is not intended to be a projection of future results (in millions, except per unit amounts):


	Year Ended
	December 31, 2021
Total revenues	$	42,359
Net income attributable to PAA	$	524
Net income allocated to common unitholders	$	324
Basic and diluted net income per common unit	$	0.45

Divestitures

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”). Upon the sale of this facility, we recognized a gain of approximately $140 million which is included in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statement of Operations.

During the year ended December 31, 2022, we sold certain non-core assets for total proceeds of $60 million. The assets sold primarily consisted of land and related assets in Long Beach, California, as well as Line 901 and the Sisquoc to Pentland portion of Line 903. These assets were previously reported in our Crude Oil segment. We recognized gains of $61 million related to these asset sales, a portion of which relates to the transfer of an asset retirement obligation to the purchaser. Such amounts are included in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statement of Operations.

In August 2021, we sold our Pine Prairie and Southern Pines natural gas storage facilities, which were included in our Crude Oil segment for periods prior to the sale, for net proceeds of approximately $850 million, including working capital adjustments. Prior to the sale, we classified the assets related to this transaction (primarily “Property and equipment”), valued at the lower of the carrying amount or fair value less costs to sell, of approximately $832 million as assets held for sale with approximately $18 million of deferred losses on hedges remaining in other comprehensive income until the closing of the sale. Upon classification of the assets to held for sale in the second quarter of 2021, we recognized a non-cash impairment loss of $475 million which is included in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statement of Operations.

Insider Trading Arrangements	3 Months Ended
Insider Trading Arrangements	Dec. 31, 2023
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

Revenues and Accounts Receivable - Counterparty Deficiencies (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Contract With Customer, Asset And Liability [Line Items]
Counterparty deficiencies, billed and collected	$ 228	$ 229	$ 141
Minimum Volume Commitments
Contract With Customer, Asset And Liability [Line Items]
Counterparty deficiencies, billed and collected	$ 77	$ 104

Intangible Asset, Net - Amortization Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense for finite-lived intangible assets	$ 308	$ 254	$ 122
Estimated amortization expense related to finite-lived intangible assets for the next five years
Expected amortization, year one	272
Expected amortization, year two	249
Expected amortization, year three	210
Expected amortization, year four	187
Expected amortization, year five	$ 165

Segment Information - Segment Financial Data (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenue
Revenues	$ 48,712	$ 57,342	$ 42,078
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	369	403	274
Segment Adjusted EBITDA	2,685	2,504	2,194
Investment and acquisition capital expenditures	830	618	269
Maintenance capital expenditures	231	211	168
Investments in unconsolidated entities	2,820	3,084	3,805
Product sales revenues
Revenue
Revenues	46,974	55,948	40,883
Services
Revenue
Revenues	1,738	1,394	1,195
Operating Segments
Revenue
Revenues	49,109	57,841	42,438
Intersegment Revenues Elimination
Revenue
Revenues	(397)	(499)	(360)
Intersegment Revenues Elimination \| Product sales revenues
Revenue
Revenues	(378)	(467)	(341)
Intersegment Revenues Elimination \| Services
Revenue
Revenues	(19)	(32)	(19)
Crude Oil
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	369	403	274
Segment Adjusted EBITDA	2,163	1,986	1,909
Investment and acquisition capital expenditures	765	461	212
Maintenance capital expenditures	145	112	100
Investments in unconsolidated entities	2,820	3,084	3,805
Crude Oil \| Operating Segments
Revenue
Revenues	47,174	55,080	40,470
Crude Oil \| Operating Segments \| Product sales revenues
Revenue
Revenues	45,587	53,840	39,395
Crude Oil \| Operating Segments \| Services
Revenue
Revenues	1,587	1,240	1,075
NGL
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment Adjusted EBITDA	522	518	285
Investment and acquisition capital expenditures	65	157	57
Maintenance capital expenditures	86	99	68
NGL \| Operating Segments
Revenue
Revenues	1,935	2,761	1,968
NGL \| Operating Segments \| Product sales revenues
Revenue
Revenues	1,765	2,575	1,829
NGL \| Operating Segments \| Services
Revenue
Revenues	$ 170	$ 186	$ 139

Net Income Per Common Unit

12 Months Ended

Dec. 31, 2023

Earnings Per Share [Abstract]

Net Income Per Common Unit

After consideration of distributions to preferred unitholders, basic and diluted net income per common unit is determined pursuant to the two-class method as prescribed in FASB guidance. This method is an earnings allocation formula that is used to determine allocations to our limited partners and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings or distributions in excess of earnings. Under the two-class method, net income is reduced by distributions pertaining to the period, and all remaining earnings or distributions in excess of earnings are then allocated to our common unitholders and participating securities based on their respective rights to share in distributions, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. Participating securities include equity-indexed compensation plan awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units.

We calculate basic and diluted net income per common unit by dividing net income attributable to PAA (after deducting amounts allocated to the preferred unitholders and participating securities) by the basic and diluted weighted average number of common units outstanding during the period.

The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units and (ii) our equity-indexed compensation plan awards. See Note 11 for additional information regarding our Series A preferred units. See Note 17 for a complete discussion of our equity-indexed compensation plan awards. When applying the if-converted method prescribed by FASB guidance, the possible conversion of approximately 71 million Series A preferred units, on a weighted-average basis, were excluded from the calculation of diluted net income per common unit for the years ended December 31, 2023, 2022 and 2021 as the effect was antidilutive for all periods. Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that are deemed to be dilutive during the year are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.

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


	Year Ended December 31,
	2023		2022		2021
Basic and Diluted Net Income per Common Unit
Net income attributable to PAA	$	1,230	$	1,037	$	593
Distributions to Series A preferred unitholders	(173)		(149)		(149)
Distributions to Series B preferred unitholders	(76)		(52)		(49)
Amounts allocated to participating securities	(10)		(5)		(2)
Other	5		—		—
Net income allocated to common unitholders (1)	$	976	$	831	$	393

Basic and diluted weighted average common units outstanding	699		701		716

Basic and diluted net income per common unit	$	1.40	$	1.19	$	0.55

Acquisitions, Divestitures and Other Transactions - Joint Venture Transaction Narrative (Details) - USD ($)
$ in Millions

1 Months Ended

3 Months Ended

12 Months Ended

Nov. 30, 2023

Jul. 31, 2022

Oct. 31, 2021

Sep. 30, 2023

Dec. 31, 2023

Dec. 31, 2021

Joint Venture Transaction | Plains Oryx Permian Basin LLC | Level 3

Business Acquisition [Line Items]

Identifiable assets acquired and liabilities assumed

$ 3,230

Joint Venture Transaction | Plains Oryx Permian Basin LLC | Level 3 | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow

Business Acquisition [Line Items]

Business combination, measurement input

0.12

Business Acquisition [Line Items]

Business combination, measurement input

0.16

Business Acquisition [Line Items]

Business combination, measurement input

9.5

Business Acquisition [Line Items]

Business combination, measurement input

11.0

Joint Venture Transaction | Plains Oryx Permian Basin LLC | Plains Oryx Permian Basin LLC

Business Acquisition [Line Items]

Members' equity

$ 7,529

Joint Venture Transaction | Oryx Midstream Holdings LLC | Plains Oryx Permian Basin LLC

Business Acquisition [Line Items]

Consideration transferred

3,230

Identifiable assets acquired and liabilities assumed

$ 3,230

Transaction-related costs

$ 17

Schedule of Partners' Capital

The following table presents the amounts recognized in partners’ capital associated with this transaction (in millions):


	Recognized Amount
Noncontrolling interests	$	2,635

Partners’ capital, excluding noncontrolling interests	595
	$	3,230

Schedule of Pro Forma Information

These results are not necessarily indicative of the results that might have actually occurred had the merger taken place on January 1, 2021; furthermore, this financial information is not intended to be a projection of future results (in millions, except per unit amounts):


	Year Ended
	December 31, 2021
Total revenues	$	42,359
Net income attributable to PAA	$	524
Net income allocated to common unitholders	$	324
Basic and diluted net income per common unit	$	0.45

Modified Sharing Arrangement | Plains Oryx Permian Basin LLC

Business Acquisition [Line Items]

Schedule of Modified Revenue Sharing Arrangement

Under the MSA, distributions will be allocated as follows (in millions):


	Available Cash	Distributions Percentages
Tier	Annualized	PAA	Oryx
1	Up to $300	50%	50%
2	$300 - $428	100%	—%
3	$428 - $815	65%	35%
4	$815 and above	70%	30%

Modified Sharing Arrangement | Oryx Midstream Holdings LLC | Plains Oryx Permian Basin LLC

Business Acquisition [Line Items]

Distribution percentage after termination of modified sharing arrangement

65.00%

Modified Sharing Arrangement | Oryx Midstream Holdings LLC | Plains Oryx Permian Basin LLC | Maximum

Business Acquisition [Line Items]

Modified revenue sharing arrangement, term

10 years

Modified Sharing Arrangement | Oryx Midstream Holdings LLC | Plains Oryx Permian Basin LLC | Plains Oryx Permian Basin LLC

Business Acquisition [Line Items]

Distribution percentage after termination of modified sharing arrangement

35.00%

Plains Oryx Permian Basin LLC

Business Acquisition [Line Items]

Consolidated subsidiary, ownership interest held by the parent (as a percent)

65.00%

Noncontrolling interest, ownership (as a percent)

35.00%

Plains Oryx Permian Basin LLC | Joint Venture Transaction

Business Acquisition [Line Items]

Consolidated subsidiary, ownership interest held by the parent (as a percent)

65.00%

Plains Oryx Permian Basin LLC | Joint Venture Transaction | Plains Oryx Permian Basin LLC

Business Acquisition [Line Items]

Noncontrolling interest, ownership (as a percent)

35.00%

Plains Oryx Permian Basin LLC | Joint Venture Transaction | Oryx Midstream Holdings LLC

Business Acquisition [Line Items]

Noncontrolling interest, ownership (as a percent)

35.00%

PAA | Stonepeak Infrastructure Partners | Stonepeak Infrastructure Partners, Affiliates | Series A Preferred Units

Business Acquisition [Line Items]

Ownership interest (as a percent)

8.90%

PAA | Stonepeak Infrastructure Partners | Stonepeak Infrastructure Partners, Affiliates | Maximum | Limited Partners

Business Acquisition [Line Items]

Ownership interest (as a percent)

1.00%

Major Customers and Concentration of Credit Risk	12 Months Ended
Major Customers and Concentration of Credit Risk	Dec. 31, 2023
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 26%, 20% and 15% of our revenues for the years ended December 31, 2023, 2022 and 2021, respectively. BP p.l.c. and its subsidiaries accounted for 10% of our revenues for the years ended December 31, 2023 and 2021. Marathon Petroleum Corporation and its subsidiaries accounted for 12% of our revenues for the year ended December 31, 2021. No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2023. 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 3 for additional discussion of our accounts receivable and our review of credit exposure.

Leases - Narrative (Details)	12 Months Ended
Leases - Narrative (Details)	Dec. 31, 2023
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)	57 years
Lessee, leases, renewal term (in years)	25 years
Lessor, Lease, Description [Line Items]
Lessor, operating lease, term of contract	18 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 (as a percent)	50.00%

Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2023

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,
		2023		2022
Crude oil pipeline systems	10 - 50	$	14,265	$	13,303
Crude oil storage and terminal facilities	10 - 50	2,664		2,631
NGL storage, terminal, fractionation and processing facilities	10 - 50	2,554		2,445
NGL pipeline systems	10 - 50	506		458
Office property and equipment and rolling stock	2 - 50	556		656
Construction in progress	N/A	257		201
Land and other	N/A	341		326
Property and equipment, gross (1)		21,143		20,020
Accumulated depreciation		(5,361)		(4,770)
Property and equipment, net		$	15,782	$	15,250

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

Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions	12 Months Ended
	Dec. 31, 2023 TWh bbl Bcf
Crude Oil Purchases \| Long
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	6.3
Time Spread on Hedging Anticipated Crude Oil Lease Gathering Purchases \| Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	5.6
Crude Oil Basis Spread Position
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	2.3
Anticipated Net Sales of Crude Oil and NGL Inventory \| Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	18.2
Natural Gas Purchases for Processing and Operational Needs \| Long
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf) \| Bcf	78.2
Propane Contracts Related to Subsequent Sale of Products \| Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	14.1
Butane Contracts Related to Subsequent Sale of Products \| Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	2.5
Condensate Contracts Related to Subsequent Sale of Products \| Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	3.1
Fuel Gas Requirements \| Long
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf) \| Bcf	7.1
Power Supply Requirements \| Long
Commodity Price Risk Hedging:
Derivative position notional amount (in terawatt hours) \| TWh	2.4

Income Taxes - Narrative (Details) - Canadian Tax Authorities - Foreign $ in Millions	Dec. 31, 2023 USD ($)
Income Tax Examination [Line Items]
Amount of assessments received, including penalty and interest	$ 165
Other long-term assets, net
Income Tax Examination [Line Items]
Amount of disputed assessments paid	$ 87

Leases (Tables)

12 Months Ended

Dec. 31, 2023

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	2023		2022		2021
Operating lease cost	$	86	$	91	$	96
Short-term lease cost	15		18		19
Other (1)	8		15		14
Total lease cost	$	109	$	124	$	129

(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,
	2023		2022		2021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	81	$	92	$	91
Operating cash flows for finance leases	$	6	$	6	$	7
Financing cash flows for finance leases	$	11	$	12	$	11

Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications:
Operating leases	$	32	$	43	$	94
Finance leases	$	27	$	2	$	1

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


	December 31,
	2023		2022
Weighted-average remaining lease term (in years):
Operating leases	13		12
Finance leases	8		9

Weighted-average discount rate:
Operating leases	4.9	%	4.3	%
Finance leases	11.3	%	12.3	%

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	2023		2022
Assets
Operating lease right-of-use assets	Long-term operating lease right-of-use assets, net	$	313	$	349

Finance lease right-of-use assets (1)	Property and equipment	$	144	$	124
	Accumulated depreciation	(46)		(41)
	Property and equipment, net	$	98	$	83

Total lease right-of-use assets		$	411	$	432

Liabilities
Operating lease liabilities
Current	Other current liabilities	$	69	$	71
Noncurrent	Long-term operating lease liabilities	274		308
Total operating lease liabilities		$	343	$	379

Finance lease liabilities (1)
Current	Short-term debt	$	13	$	10
Noncurrent	Other long-term debt, net	63		50
Total finance lease liabilities		$	76	$	60

Total lease liabilities		$	419	$	439

Schedule of Finance Lease Maturity


	Operating		Finance (2)
Future minimum lease payments (1):
2024	$	80	$	20
2025	68		17
2026	51		13
2027	43		12
2028	34		15
Thereafter	238		48
Total	514		125
Less: Present value discount	(171)		(49)
Lease liabilities	$	343	$	76

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

Schedule of Operating Lease Maturity


	Operating		Finance (2)
Future minimum lease payments (1):
2024	$	80	$	20
2025	68		17
2026	51		13
2027	43		12
2028	34		15
Thereafter	238		48
Total	514		125
Less: Present value discount	(171)		(49)
Lease liabilities	$	343	$	76

(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,
	2023		2022		2021
Operating lease revenue (1)	$	32	$	29	$	28

(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):


	2024		2025		2026		2027		2028		Thereafter
Future minimum lease revenue	$	24	$	18	$	15	$	16	$	16	$	154

Acquisitions, Divestitures and Other Transactions (Tables)

12 Months Ended

Dec. 31, 2023

OMOG JV LLC and Southern Delaware Gathering Assets

Business Acquisition [Line Items]

Schedule of Assets Acquired and Liabilities Assumed

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

OMOG JV LLC and Southern Delaware Gathering Assets | Customer relationships

Business Acquisition [Line Items]

Schedule of Amortization Expense

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



2024	$	8
2025	$	10
2026	$	4
2027	$	3
2028	$	2

Cactus II Pipeline LLC

Business Acquisition [Line Items]

Schedule of Assets Acquired and Liabilities Assumed

The following table reflects our determination of the fair value of those assets and liabilities (in millions):


Identifiable Assets Acquired and Liabilities Assumed:	Estimated Useful Lives (in years)	Recognized Amount
Property and equipment	3-50	$	1,174
Intangible assets	20	428
Working capital and other assets and liabilities	N/A	(46)
		$	1,556

Cactus II Pipeline LLC | Customer relationships

Business Acquisition [Line Items]

Schedule of Amortization Expense

Amortization expense was approximately $61 million and $13 million during the years ended December 31, 2023 and 2022, respectively, and the future amortization expense through 2027 is estimated as follows (in millions):



2024	$	51
2025	$	47
2026	$	32
2027	$	32

Plains Oryx Permian Basin LLC | Modified Sharing Arrangement

Business Acquisition [Line Items]

Schedule of Modified Revenue Sharing Arrangement

Under the MSA, distributions will be allocated as follows (in millions):


	Available Cash	Distributions Percentages
Tier	Annualized	PAA	Oryx
1	Up to $300	50%	50%
2	$300 - $428	100%	—%
3	$428 - $815	65%	35%
4	$815 and above	70%	30%

Plains Oryx Permian Basin LLC | Oryx Midstream Holdings LLC | Joint Venture Transaction

Business Acquisition [Line Items]

Schedule of Assets Acquired and Liabilities Assumed

The following table reflects our determination of the fair value of those assets and liabilities (in millions):


Identifiable Assets Acquired and Liabilities Assumed	Estimated Useful Lives (in years)	Recognized Amount
Property and equipment	3-30	$	1,886
Intangible assets	20	1,247
Investment in unconsolidated entities	N/A	103

Working capital and other assets and liabilities	N/A	(6)
		$	3,230

Schedule of Partners' Capital

The following table presents the amounts recognized in partners’ capital associated with this transaction (in millions):


	Recognized Amount
Noncontrolling interests	$	2,635

Partners’ capital, excluding noncontrolling interests	595
	$	3,230

Schedule of Pro Forma Information


	Year Ended
	December 31, 2021
Total revenues	$	42,359
Net income attributable to PAA	$	524
Net income allocated to common unitholders	$	324
Basic and diluted net income per common unit	$	0.45

Plains Oryx Permian Basin LLC | Customer relationships | Joint Venture Transaction

Business Acquisition [Line Items]

Schedule of Amortization Expense

Amortization expense was approximately $138 million, $142 million and $28 million during the years ended December 31, 2023, 2022 and 2021, respectively, and the future amortization expense through 2026 is estimated as follows (in millions):




2024	$	127
2025	$	117
2026	$	106

Leases - Lessor Operating Lease Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Lessor, Lease, Description [Line Items]
Operating lease revenue	$ 32	$ 29	$ 28
Services
Lessor, Lease, Description [Line Items]
Operating lease, lease income, statement of income [extensible enumeration]	Total revenues	Total revenues	Total revenues

Acquisitions, Divestitures and Other Transactions - Modified Sharing Arrangement (Details) - Plains Oryx Permian Basin LLC - Modified Sharing Arrangement	Dec. 31, 2023
Up to $300
Business Acquisition [Line Items]
Modified sharing arrangement, distribution (as a percent)	50.00%
$300 - $428
Business Acquisition [Line Items]
Modified sharing arrangement, distribution (as a percent)	100.00%
$428 - $815
Business Acquisition [Line Items]
Modified sharing arrangement, distribution (as a percent)	65.00%
$815 and above
Business Acquisition [Line Items]
Modified sharing arrangement, distribution (as a percent)	70.00%
Oryx Midstream Holdings LLC \| Up to $300
Business Acquisition [Line Items]
Modified sharing arrangement, distribution (as a percent)	50.00%
Oryx Midstream Holdings LLC \| $428 - $815
Business Acquisition [Line Items]
Modified sharing arrangement, distribution (as a percent)	35.00%
Oryx Midstream Holdings LLC \| $815 and above
Business Acquisition [Line Items]
Modified sharing arrangement, distribution (as a percent)	30.00%

Debt - Senior Notes (Details) - USD ($) $ in Millions	1 Months Ended			12 Months Ended
Debt - Senior Notes (Details) - USD ($) $ in Millions	Oct. 31, 2023	Jan. 31, 2023	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Repayments of senior notes				$ 1,100	$ 750
Senior notes \| 3.85% senior notes due October 2023
Debt Instrument [Line Items]
Repayments of senior notes	$ 700
Debt instrument, interest rate (as a percent)	3.85%
Senior notes \| 2.85% senior notes due January 2023
Debt Instrument [Line Items]
Repayments of senior notes		$ 400
Debt instrument, interest rate (as a percent)		2.85%
Senior notes \| 3.65% senior notes due June 2022
Debt Instrument [Line Items]
Repayments of senior notes			$ 750
Debt instrument, interest rate (as a percent)			3.65%
Consolidated finance subsidiary co-issuer
Debt Instrument [Line Items]
Consolidated subsidiary, ownership interest held by the parent (as a percent)				100.00%

- 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/2003/role/disclosureRef
-Topic 835
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Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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-Subparagraph (SX 210.12-04(a))
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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/exampleRef
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Reference 6: http://www.xbrl.org/2003/role/exampleRef
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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/exampleRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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Reference 11: http://www.xbrl.org/2003/role/exampleRef
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
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-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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Reference 15: http://www.xbrl.org/2003/role/disclosureRef
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Reference 16: http://www.xbrl.org/2003/role/disclosureRef
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Reference 17: http://www.xbrl.org/2003/role/disclosureRef
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Reference 18: http://www.xbrl.org/2003/role/disclosureRef
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Reference 19: http://www.xbrl.org/2003/role/disclosureRef
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Reference 20: http://www.xbrl.org/2003/role/disclosureRef
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Reference 21: http://www.xbrl.org/2003/role/disclosureRef
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Reference 22: http://www.xbrl.org/2003/role/disclosureRef
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Reference 24: http://www.xbrl.org/2003/role/disclosureRef
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Reference 25: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Income Taxes - Reconciliation and Deferred Tax Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Examination [Line Items]
Income before tax	$ 1,623	$ 1,417	$ 721
Partnership earnings not subject to Canadian tax	(1,136)	(686)	(370)
Partnership earnings subject to Canadian tax	$ 487	$ 731	$ 351
Canadian federal and provincial corporate tax rate	24.00%	24.00%	24.00%
Income tax expense at statutory rate	$ 117	$ 175	$ 84
Canadian permanent differences	2	13	(13)
State income tax	2	1	2
Total income tax expense	121	189	$ 73
Deferred tax assets:
Lease liabilities	40	45
Other	45	16
Total deferred tax assets	85	61
Deferred tax liabilities:
Property and equipment in excess of tax values	(573)	(515)
Derivative instruments	(6)	(46)
Lease assets	(38)	(42)
Other	(3)	(3)
Total deferred tax liabilities	(620)	(606)
Net deferred tax liabilities	(535)	(545)
Other long-term liabilities and deferred credits
Deferred tax liabilities:
Other long-term liabilities and deferred credits	$ (535)	$ (545)

Property and Equipment - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property and Equipment
Depreciation expense		$ 733	$ 707	$ 652
Construction in progress expenditures incurred but not yet paid		$ 55	$ 46	48
Level 3 \| Measurement Input, Discount Rate \| Valuation Technique, Discounted Cash Flow
Property and Equipment
Discount rate, asset impairment analysis, cost of capital, theoretical market participant (as a percent)	15.00%
Crude Oil \| California assets
Property and Equipment
Non-cash impairment losses, long-lived assets	$ 330
Impairment, long-lived asset, held-for-use, statement of income [extensible enumeration]	Gains/(losses) on asset sales and asset impairments, net
Crude Oil \| Crude oil storage terminal assets
Property and Equipment
Non-cash impairment losses, long-lived assets				$ 220
Impairment, long-lived asset, held-for-use, statement of income [extensible enumeration]				Gains/(losses) on asset sales and asset impairments, net

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2023

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, 2023, 2022 and 2021, the revaluation of foreign currency transactions and monetary assets and liabilities resulted in the recognition of a net loss of $8 million, a net loss of $41 million and a net gain of $7 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, 2023 and 2022, trade accounts payable included $26 million and $25 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 11 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, certain processing and fractionation facilities 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, 2023, 2022 and 2021 (in millions):


	December 31,
	2023		2022		2021
Beginning balance	$	122	$	143	$	135
Liabilities incurred	2		2		2
Liabilities settled (1)	(1)		(26)		(1)
Accretion expense	4		4		4
Revisions in estimated cash flows	(1)		(1)		3
Ending balance	$	126	$	122	$	143

(1)The 2022 amount primarily relates to the transfer of liabilities to the third party purchaser associated with the sale of Line 901 and the Sisquoc to Pentland portion of Line 903 pipeline. See Note 7 and Note 18 for additional information.

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 derivatives and interest rate 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 12 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 common unit, (iii) inventory, linefill and long-term inventory, (iv) property and equipment, (v) acquisitions, (vi) investments in unconsolidated entities, (vii) intangible assets, (viii) income allocation for partners’ capital presentation purposes, (ix) derivatives and risk management activities, (x) leases, (xi) income taxes, (xii) equity-indexed compensation and (xiii) legal and environmental matters.

Recent Accounting Pronouncements

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 intend to provide the required disclosures prospectively for annual periods beginning after December 15, 2024.

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 intend to provide the required disclosures beginning with our annual report for the year ended December 31, 2024.

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 intend to adopt this guidance for joint venture formations on January 1, 2025.

In October 2021, the FASB issued ASU 2021-08, Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. This guidance requires that an acquirer recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with Topic 606, Revenue from Contracts with Customers, as if it had originated the contracts. The guidance is effective prospectively for interim and annual periods beginning after December 15, 2022, with early adoption permitted. We adopted this guidance as of January 1, 2023, and our adoption did not have a material impact on our financial position, results of operations or cash flows.

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. This guidance was effective prospectively upon issuance through December 31, 2022. In December 2022, the FASB issued ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, which defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. We will continue to apply applicable expedients and exceptions to contract modifications through December 31, 2024, as applicable.

Derivatives and Risk Management Activities - Offsetting Asset and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Derivative Asset Positions
Effect of Collateral Netting	$ (13)	$ (168)
Commodity Derivatives
Derivative Asset Positions
Effect of Collateral Netting	(13)	(168)
Derivative Liability Positions
Gross Position - Asset	158	311
Gross Position - Liability	(158)	(89)
Net Carrying Value Presented on the Balance Sheet, Total	(13)	54
Other current assets \| Commodity Derivatives
Derivative Asset Positions
Gross Position - Asset	153	300
Gross Position - Liability	(79)	(71)
Effect of Collateral Netting	(13)	(168)
Net Carrying Value Presented on the Balance Sheet	61	61
Other long-term assets, net \| Commodity Derivatives
Derivative Asset Positions
Gross Position - Asset	3	9
Gross Position - Liability		(5)
Net Carrying Value Presented on the Balance Sheet	3	4
Other current liabilities \| Commodity Derivatives
Derivative Liability Positions
Gross Position - Asset	1	2
Gross Position - Liability	(64)	(13)
Net Carrying Value Presentation on the Balance Sheet	(63)	(11)
Other long-term liabilities and deferred credits \| Commodity Derivatives
Derivative Liability Positions
Gross Position - Asset	1	0
Gross Position - Liability	(15)	0
Net Carrying Value Presentation on the Balance Sheet	$ (14)	$ 0

Partners' Capital and Distributions - Common Equity Repurchase Program (Details) - Common Equity Repurchase Program - Common Units - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Nov. 30, 2020
Partners Capital and Distribution [Line Items]
Stock repurchase program, authorized amount				$ 500
Common equity repurchase program, repurchased amount	$ 0	$ 74	$ 178
Common equity repurchase program, remaining amount	$ 198
Maximum
Partners Capital and Distribution [Line Items]
Stock repurchase program, authorized amount				$ 500

Debt

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Debt

Debt consisted of the following (in millions):


	December 31, 2023		December 31, 2022
SHORT-TERM DEBT
Commercial paper notes, bearing a weighted-average interest rate of 5.8% (1)	$	433	$	—

Senior notes:

2.85% senior notes due January 2023	—		400
3.85% senior notes due October 2023	—		700

Other	13		59
Total short-term debt	446		1,159

LONG-TERM DEBT
Senior notes:


3.60% senior notes due November 2024 (2)	750		750
4.65% senior notes due October 2025	1,000		1,000
4.50% senior notes due December 2026	750		750
3.55% senior notes due December 2029	1,000		1,000
3.80% senior notes due September 2030	750		750
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	(41)		(46)
Senior notes, net of unamortized discounts and debt issuance costs	7,242		7,237
Other long-term debt:



Other	63		50
Total long-term debt	7,305		7,287
Total debt (3)	$	7,751	$	8,446

(2)As of December 31, 2023, we classified our 3.60%, $750 million senior notes due November 2024 as long-term based on our ability and intent to refinance these notes on a long-term basis.

Commercial Paper Program

We have a commercial paper program under which we 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 our senior unsecured revolving credit facility and our senior secured hedged inventory facility; as such, any borrowings under our commercial paper program reduce the available capacity under these facilities.

Credit Agreements

Senior secured hedged inventory facility. We have 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. In August 2023, we extended the maturity date of the facility to August 2026 for each existing lender.

Senior unsecured revolving credit facility. We have 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. In August 2023, we extended the maturity date of the facility to August 2028 for each extending lender. The maturity date with respect to the non-extending lender (which represents a commitment of approximately $64 million out of total commitments of $1.35 billion from all lenders) remains August 2027.

GO Zone term loans. In August 2021, in connection with the sale of the Southern Pines natural gas storage facility, we repaid $200 million of term loans (the “Go Zone term loans”) that were initially assumed in connection with our acquisition of that facility. See Note 7 for additional information.

Senior Notes

Our 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. We may, at our 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. Our senior notes are not guaranteed by any of our subsidiaries.

Senior Notes Repayments. During the three years ended December 31, 2023, we repaid the following senior unsecured notes in full (in millions):


Year	Description	Repayment Date
2023	$700 million 3.85% Senior Notes due October 2023	October 2023	(1)

2023	$400 million 2.85% Senior Notes due January 2023	January 2023	(1)

2022	$750 million 3.65% Senior Notes due June 2022	March 2022	(1)

(1)We repaid these senior notes with cash on hand and borrowings under our commercial paper program.

Maturities

The weighted average maturity of our senior notes outstanding at December 31, 2023 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)
2024	$	750
2025	$	1,000
2026	$	750
2027	$	—
2028	$	—
Thereafter	$	4,783

Covenants and Compliance

The credit agreements for our revolving credit facilities (which impact our ability to access our commercial paper program because they provide the financial backstop that supports our short-term credit ratings) and the indentures governing our senior notes contain cross-default provisions. Our 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, the agreements contain various covenants limiting our ability to, among other things:

•grant liens on certain property;

•incur indebtedness, including finance leases;

•sell substantially all of our assets or enter into a merger or consolidation;

•engage in certain transactions with affiliates; and

•enter into certain burdensome agreements.

The credit agreements for our senior unsecured revolving credit facility and senior secured hedged inventory facility treat a change of control as an event of default and also require us 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 our credit agreements or indentures would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with the provisions contained in our credit agreements, our ability to make distributions of available cash is not restricted. As of December 31, 2023, we were in compliance with the covenants contained in our credit agreements and indentures.

Borrowings and Repayments

Total borrowings under our credit facilities and commercial paper program for the years ended December 31, 2023, 2022 and 2021 were approximately $18.1 billion, $25.0 billion and $32.5 billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately $17.7 billion, $25.0 billion and $33.2 billion for the years ended December 31, 2023, 2022 and 2021, 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, 2023 and 2022, we had outstanding letters of credit of $205 million and $102 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.

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+ Details

Commitments and Contingencies - Commitments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Leases
2024	$ 100
2025	85
2026	64
2027	55
2028	49
Thereafter	286
Total	639
Other commitments
2024	367
2025	336
2026	249
2027	217
2028	117
Thereafter	425
Total	1,711
Total
2024	467
2025	421
2026	313
2027	272
2028	166
Thereafter	711
Total	2,350
Expenses associated with agreements	$ 396	$ 336	$ 270

Derivatives and Risk Management Activities - Preferred Distribution Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jan. 31, 2023
Derivatives and Risk Management Activities
Gain/(loss) recognized	$ 58	$ (189)	$ 14
Preferred Distribution Rate Reset Option \| Derivatives Not Designated as a Hedge
Derivatives and Risk Management Activities
Derivative liability		$ 189		$ 131
Derivative liability, statement of financial position [extensible enumeration]		Other long-term liabilities and deferred credits
Preferred Distribution Rate Reset Option \| Derivatives Not Designated as a Hedge \| Other Income/(Expense), Net
Derivatives and Risk Management Activities
Gain/(loss) recognized	$ 58	$ (189)	$ 14

- 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.

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+ Details

Derivatives and Risk Management Activities

12 Months Ended

Dec. 31, 2023

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 optimize our profits while managing our exposure to commodity price risk and interest 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 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, 2023 and 2022, 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 to optimize profits. As of December 31, 2023, net derivative positions related to these activities included:

•A net long position of 6.3 million barrels associated with our crude oil purchases, which was unwound ratably during January 2024 to match monthly average pricing.

•A net short time spread position of 5.6 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through January 2025.

•A net crude oil basis spread position of 2.3 million barrels at multiple locations through December 2024. These derivatives allow us to lock in grade and location basis differentials.

•A net short position of 18.2 million barrels through March 2025 related to anticipated net sales of crude oil and NGL inventory.

We purchase natural gas for processing and operational needs. Additionally, we purchase NGL mix for fractionation and sell the resulting individual specification products (including ethane, propane, butane and condensate). In conjunction with these activities, we hedge the price risk associated with the purchase of the natural gas and the subsequent sale of the individual specification products. The following table summarizes our open derivative positions utilized to hedge the price risk associated with anticipated purchases and sales related to our natural gas processing and NGL fractionation activities as of December 31, 2023.


	Notional Volume (Short)/Long	Remaining Tenor
Natural gas purchases	78.2 Bcf	December 2025
Propane sales	(14.1) MMbls	December 2025
Butane sales	(2.5) MMbls	December 2024
Condensate sales	(3.1) MMbls	December 2024

Fuel gas requirements (1)	7.1 Bcf	December 2024
Power supply requirements (1)	2.4 TWh	December 2030

(1)Positions to hedge a portion of our power supply and fuel gas requirements at our Canadian natural gas processing and fractionation plants.

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,
	2023		2022		2021
Product sales revenues	$	13	$	179	$	(710)
Field operating costs	(45)		59		71
Net gain/(loss) from commodity derivative activity	$	(32)	$	238	$	(639)

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/(payable) (in millions):


	December 31,
	2023		2022
Initial margin	$	77	$	93
Variation margin returned	(65)		(236)
Letters of credit	(25)		(25)
Net broker payable	$	(13)	$	(168)


	December 31, 2023								December 31, 2022
					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	$	153	$	(79)	$	(13)	$	61	$	300	$	(71)	$	(168)	$	61
Other long-term assets, net	3		—		—		3		9		(5)		—		4
Derivative Liabilities
Other current liabilities	1		(64)		—		(63)		2		(13)		—		(11)
Other long-term liabilities and deferred credits	1		(15)		—		(14)		—		—		—		—
Total	$	158	$	(158)	$	(13)	$	(13)	$	311	$	(89)	$	(168)	$	54

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.

The following table summarizes the terms of our outstanding interest rate derivatives as of December 31, 2023 (notional amounts in millions):

Hedged Transaction

Number and Types of

Derivatives Employed

Notional

Amount

Expected

Termination Date

Average Rate Locked

Accounting

Treatment

Anticipated interest payments

8 forward starting swaps

(30-year)

200

6/15/2026

3.09

Cash flow hedge

Anticipated interest payments

4 forward starting swaps

(30-year)

100

6/14/2024

0.74

Cash flow hedge

During the year ended December 31, 2023, we terminated $200 million of notional interest hedging instruments previously expected to terminate in June 2023 for proceeds of $80 million, of which $73 million was recorded in AOCI. As of December 31, 2023, there was a net loss of $81 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, 2023; 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/(loss) recognized in AOCI for derivatives (in millions):


	Year Ended December 31,
	2023		2022		2021
Interest rate derivatives, net	$	15	$	94	$	19

At December 31, 2023, the net fair value of our interest rate hedges, which were included in “Other current assets” and “Other long-term assets, net” on our Consolidated Balance Sheet, totaled $51 million and $4 million, respectively. At December 31, 2022, the net fair value of these hedges totaled $75 million and $45 million, which were included in “Other current assets” and “Other long-term assets, net”, respectively.

Preferred Distribution Rate Reset Option

In January 2023, we 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, our partnership agreement, and recorded at fair value on our Consolidated Balance Sheet. The fair value of the Preferred Distribution Rate Reset Option, which was included in “Other long-term liabilities and deferred credits” on our Consolidated Balance Sheet, totaled $189 million at December 31, 2022. The Preferred Distribution Rate Reset Option was settled when we received notice that the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option. The fair value of the Preferred Distribution Rate Reset Option on the settlement date was $131 million. 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/(expense), net” in our Consolidated Statements of Operations. For the years ended December 31, 2023, 2022 and 2021, we recognized a gain of $58 million, a net loss of $189 million, and a net gain of $14 million, respectively. See Note 11 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, 2023								Fair Value as of December 31, 2022
Recurring Fair Value Measures (1)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivatives	$	9	$	(9)	$	—	$	—	$	(7)	$	229	$	—	$	222
Interest rate derivatives	—		55		—		55		—		120		—		120
Preferred Distribution Rate Reset Option	—		—		—		—		—		—		(189)		(189)

Total net derivative asset/(liability)	$	9	$	46	$	—	$	55	$	(7)	$	349	$	(189)	$	153

(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 and over-the-counter commodity 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.

Level 3

Level 3 of the fair value hierarchy includes the Preferred Distribution Rate Reset Option contained in our partnership agreement which was classified as an embedded derivative. As discussed above, the Preferred Distribution Rate Reset Option was settled on January 31, 2023. The fair value of the Preferred Distribution Rate Reset Option was based on a Monte Carlo valuation model that estimated the fair value of the Series A preferred units with and without the Preferred Distribution Rate Reset Option. This model relied on assumptions for forecasts for the ten-year U.S. Treasury rate, our common unit price, and default probabilities which impacted timing estimates as to when the option would be exercised.

Rollforward of Level 3 Net Asset/(Liability)

The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 (in millions):


	Year Ended December 31,
	2023		2022
Beginning Balance	$	(189)	$	(2)
Net gains/(losses) for the period included in earnings	58		(189)
Settlements	131		2

Ending Balance	$	—	$	(189)

Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period	$	—	$	(189)

Partners' Capital and Distributions - Common Unit Distributions (Details) - USD ($) $ / shares in Units, $ in Millions			12 Months Ended
	Feb. 14, 2024	Jan. 08, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Distribution Made to Limited Partner [Line Items]
Distributions paid			$ 1,330	$ 1,083	$ 729
Common Units \| Cash Distribution
Distribution Made to Limited Partner [Line Items]
Distributions paid			$ 748	$ 584	$ 517
Distributions per common unit (in dollars per unit)			$ 1.0700	$ 0.8325	$ 0.7200
Common Units \| Cash Distribution \| Fourth Quarter Distribution \| Subsequent Event
Distribution Made to Limited Partner [Line Items]
Distributions paid	$ 223
Distribution per common unit declared (in dollars per unit)		$ 0.3175
Common Units \| Cash Distribution \| Public
Distribution Made to Limited Partner [Line Items]
Distributions paid			$ 492	$ 383	$ 341
Common Units \| Cash Distribution \| AAP
Distribution Made to Limited Partner [Line Items]
Distributions paid			$ 256	$ 201	$ 176
Common Units \| Cash Distribution \| AAP \| Fourth Quarter Distribution \| Subsequent Event
Distribution Made to Limited Partner [Line Items]
Distributions paid	$ 74

Acquisitions, Divestitures and Other Transactions - Asset Exchange Narrative (Details) $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2021 USD ($) plant	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Business Acquisition [Line Items]
Gain on divestiture of assets		$ 152	$ (269)	$ (592)
Inter Pipeline Ltd \| Asset Exchange Transaction \| (Gains)/Losses On Asset Sales and Asset Impairments, Net
Business Acquisition [Line Items]
Gain on divestiture of assets	$ 106
Additional Interests in Straddle Plants \| Inter Pipeline Ltd \| Asset Exchange Transaction
Business Acquisition [Line Items]
Cash consideration, including working capital and other adjustments	$ 32
Additional Interests in Straddle Plants \| Inter Pipeline Ltd \| NGL \| Asset Exchange Transaction
Business Acquisition [Line Items]
Number of straddle plants, additional interests acquired \| plant	2

Investments in Unconsolidated Entities - Equity Method Investments (Details) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2022 USD ($) Pipeline	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Nov. 30, 2022	Sep. 30, 2022	Jul. 31, 2022	Jun. 30, 2022
Investments in Unconsolidated Entities
Investments in unconsolidated entities	$ 3,084	$ 2,820	$ 3,084	$ 3,805
Gains/(losses) on investments in unconsolidated entities, net		28	346	2
Capital contributions to equity method investees excluding capitalized interest		29	13	$ 82
Amount by which investments in unconsolidated entities exceeded our share of the underlying equity in the net assets	204	$ 229	204
Advantage Pipeline Holdings LLC
Investments in Unconsolidated Entities
Additional interest acquired (as a percent)							50.00%
Cactus II Pipeline LLC
Investments in Unconsolidated Entities
Additional interest acquired (as a percent)					5.00%
BridgeTex Pipeline Company, LLC (“BridgeTex”)
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)		20.00%
Investments in unconsolidated entities	403	$ 363	403
Capline Pipeline Company LLC (“Capline”)
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)		54.00%
Investments in unconsolidated entities	539	$ 535	539
Diamond Pipeline LLC
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)		50.00%
Investments in unconsolidated entities	460	$ 450	460
Eagle Ford Pipeline LLC
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)		50.00%
Investments in unconsolidated entities	371	$ 370	371
Eagle Ford Terminals Corpus Christi LLC
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)		50.00%
Investments in unconsolidated entities	118	$ 116	118
OMOG JV LLC (“OMOG”)
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)						40.00%
Investments in unconsolidated entities	$ 211		$ 211
OMOG JV LLC (“OMOG”) \| Acquisition of Additional Interest in Exchange for Contribution of Pipeline Assets
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)	57.00%		57.00%
Number of pipelines or partial pipelines contributed \| Pipeline	2
Gains/(losses) on investments in unconsolidated entities, net	$ (25)
Saddlehorn Pipeline Company, LLC
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)		30.00%
Investments in unconsolidated entities	197	$ 192	$ 197
White Cliffs Pipeline, LLC
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)		36.00%
Investments in unconsolidated entities	150	$ 138	150
Wink to Webster Pipeline LLC (“W2W Pipeline”)
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)		16.00%
Investments in unconsolidated entities	357	$ 380	357
Other investments
Investments in Unconsolidated Entities
Investments in unconsolidated entities	$ 278	$ 276	$ 278
Advantage Pipeline Holdings LLC
Investments in Unconsolidated Entities
Ownership interest in unconsolidated entity (as a percent)								50.00%

Partners' Capital and Distributions (Tables)

12 Months Ended

Dec. 31, 2023

Partners Capital and Distribution [Line Items]

Schedule of Activity for Preferred Units and Common Units

The following table presents the activity for our preferred and common units:


	Limited Partners
	Series A Preferred Units	Series B Preferred Units	Common Units
Outstanding at December 31, 2020	71,090,468	800,000	722,380,416



Repurchase and cancellation of common units under the Common Equity Repurchase Program	—	—	(18,061,583)
Issuances of common units under equity-indexed compensation plans	—	—	672,707
Outstanding at December 31, 2021	71,090,468	800,000	704,991,540
Repurchase and cancellation of common units under the Common Equity Repurchase Program	—	—	(7,251,361)
Issuances of common units under equity-indexed compensation plans	—	—	614,319
Outstanding at December 31, 2022	71,090,468	800,000	698,354,498

Issuances of common units under equity-indexed compensation plans	—	—	2,654,251
Outstanding at December 31, 2023	71,090,468	800,000	701,008,749

Schedule of Distributions to Noncontrolling Interests

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


	2023		2022		2021
Permian JV (1)	$	249	$	273	$	—
Cactus II	63		4		—
Red River	21		21		14
	$	333	$	298	$	14

(1)The initial distribution from the Permian JV was paid during the first quarter of 2022, with approximately $54 million paid to noncontrolling interests.

Series A Preferred Units

Partners Capital and Distribution [Line Items]

Schedule of Distributions

Series A Preferred Unit Distributions. The following table details distributions paid to our Series A preferred unitholders during the years presented (in millions, except unit data):


	Series A Preferred Unitholders


Year	Cash Distribution		Distribution per Unit
2023	$	166		$	2.34
2022	$	149		$	2.10
2021	$	149		$	2.10

Series B Preferred Units

Partners Capital and Distribution [Line Items]

Schedule of Distributions

Series B Preferred Unit Distributions. The following table details distributions paid to our Series B preferred unitholders during the years presented (in millions, except unit data):


	Series B Preferred Unitholders


Year	Cash Distribution		Distribution per Unit
2023	$	75	$	93.43
2022	$	49	$	61.25
2021	$	49	$	61.25

Common Units

Partners Capital and Distribution [Line Items]

Schedule of Distributions

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


	Distributions Paid						Distributions per common unit
Year	Public		AAP		Total
2023	$	492	$	256	$	748	$	1.0700
2022	$	383	$	201	$	584	$	0.8325
2021	$	341	$	176	$	517	$	0.7200

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions	Total	Plains Oryx Permian Basin LLC Joint Venture Transaction	Cactus II Pipeline LLC	Partners’ Capital Excluding Noncontrolling Interests	Partners’ Capital Excluding Noncontrolling Interests Plains Oryx Permian Basin LLC Joint Venture Transaction	Noncontrolling Interests	Noncontrolling Interests Plains Oryx Permian Basin LLC Joint Venture Transaction	Noncontrolling Interests Cactus II Pipeline LLC	Limited Partners Series A Preferred Units Partners’ Capital Excluding Noncontrolling Interests	Limited Partners Series B Preferred Units Partners’ Capital Excluding Noncontrolling Interests	Limited Partners Common Units Partners’ Capital Excluding Noncontrolling Interests	Limited Partners Common Units Partners’ Capital Excluding Noncontrolling Interests Plains Oryx Permian Basin LLC Joint Venture Transaction
Beginning balance at Dec. 31, 2020	$ 9,738			$ 9,593		$ 145			$ 1,505	$ 787	$ 7,301
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	648			593		55			149	49	395
Distributions (Note 11)	(729)			(715)		(14)			(149)	(49)	(517)
Other comprehensive income/(loss)	65			65							65
Equity-indexed compensation expense	19			19							19
Repurchase of common units (Note 11)	(178)			(178)							(178)
Contributions from noncontrolling interests	1					1
Partners' capital impact of business combination (Note 7)		$ 3,256			$ 605		$ 2,651					$ 605
Other	(10)			(10)							(10)
Ending balance at Dec. 31, 2021	12,810			9,972		2,838			1,505	787	7,680
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	1,228			1,037		191			149	52	836
Distributions (Note 11)	(1,083)			(785)		(298)			(149)	(52)	(584)
Other comprehensive income/(loss)	(101)			(101)							(101)
Equity-indexed compensation expense	32			32							32
Repurchase of common units (Note 11)	(74)			(74)							(74)
Contributions from noncontrolling interests	26					26
Partners' capital impact of business combination (Note 7)		$ (26)	$ 526		$ (10)		$ (16)	$ 526				$ (10)
Other	(13)			(14)		1					(14)
Ending balance at Dec. 31, 2022	13,325			10,057		3,268			1,505	787	7,765
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	1,502			1,230		272			173	76	981
Distributions (Note 11)	(1,330)			(997)		(333)			(173)	(76)	(748)
Other comprehensive income/(loss)	118			118							118
Equity-indexed compensation expense	36			36							36
Contributions from noncontrolling interests	106					106
Other	(25)			(22)		(3)			4		(26)
Ending balance at Dec. 31, 2023	$ 13,732			$ 10,422		$ 3,310			$ 1,509	$ 787	$ 8,126

Summary of Significant Accounting Policies - Various Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Foreign Currency Transactions/Translation
Gain (loss) on revaluation of foreign currency transactions and monetary assets and liabilities	$ (8)	$ (41)	$ 7
Cash and Cash Equivalents and Restricted Cash
Outstanding checks included in accounts payable that were reclassified from cash and cash equivalents	$ 26	$ 25

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2023

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, 2023, 2022 and 2021 (in millions):


	December 31,
	2023		2022		2021
Beginning balance	$	122	$	143	$	135
Liabilities incurred	2		2		2
Liabilities settled (1)	(1)		(26)		(1)
Accretion expense	4		4		4
Revisions in estimated cash flows	(1)		(1)		3
Ending balance	$	126	$	122	$	143

Revenues and Accounts Receivable - Trade Accounts Receivable and Other Receivables (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Trade accounts receivable arising from revenues from contracts with customers	$ 3,999	$ 4,141
Other trade accounts receivables and other receivables	7,535	7,216
Impact due to contractual rights of offset with counterparties	(7,774)	(7,450)
Trade accounts receivable and other receivables, net	$ 3,760	$ 3,907

Related Party Transactions - Promissory Notes with our General Partner (Details) $ in Millions, $ in Millions	10 Months Ended	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2023 CAD ($)
Related Party Transactions
Related party interest expense		$ 386	$ 405	$ 425
8.25% note due April 2027 \| PAGP \| GP
Related Party Transactions
Related party note receivable	$ 379	379			$ 500
Related party note payable	$ 379	379			$ 500
Related party note payable and receivable interest rate (as a percent)	8.25%
Related party interest receivable	$ 10	10
Related party interest payable	$ 10	10
Related party interest income		25
Related party interest expense		$ 25

Partners' Capital and Distributions - Preferred Unit Issuance (Details)				1 Months Ended	12 Months Ended
	Feb. 15, 2024 $ / shares	Jan. 31, 2023 $ / shares	Oct. 10, 2017 $ / shares	May 31, 2023 $ / shares	Dec. 31, 2023 transaction $ / shares	Dec. 31, 2022 $ / shares	Dec. 31, 2021 $ / shares	Aug. 15, 2023	Nov. 15, 2022 $ / shares	Jan. 28, 2016 $ / shares
Partners Capital and Distribution [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
Partners Capital and Distribution [Line Items]
Shares issued, price per share (in dollars per unit)										$ 26.25
Quarterly distributions per unit (in dollars per unit)				$ 0.585	$ 0.525
Annualized distribution rate (in dollars per unit)		$ 2.46			$ 2.10
Distribution rate reset, basis spread on variable rate (as a percent)					5.85%
Distribution rate (as a percent)		9.375%
Number of redemptions transactions limited to \| transaction					2
Value of common units if exchanged for redemption of preferred units, as a percentage of weighted average price (as a percent)					95.00%
Redemption price as a percentage of issue price (as a percent)					110.00%
Series A preferred unit conversion ratio					1
Series A Preferred Units \| Cash Distribution
Partners Capital and Distribution [Line Items]
Distribution per unit (in dollars per unit)					$ 2.34	$ 2.10	$ 2.10
Series B Preferred Units
Partners Capital and Distribution [Line Items]
Sale of units, price per unit (in dollars per unit)			$ 1,000
Liquidation preference (in dollars per unit)					$ 1,000
Dividend rate percentage (as a percent)					6.125%
Distribution rate (in dollars per unit)					$ 61.25
Preferred unit, distribution percentage spread (as a percent)								4.11%	4.11%
Preferred unit, credit percentage spread (as a percent)								0.26121%
Redemption price (in dollars per unit)									$ 1,000
Series B Preferred Units \| Cash Distribution
Partners Capital and Distribution [Line Items]
Distribution per unit (in dollars per unit)					$ 93.43	$ 61.25	$ 61.25
Series B Preferred Units \| Subsequent Event
Partners Capital and Distribution [Line Items]
Dividend rate percentage (as a percent)	9.75093%
Series B Preferred Units \| Subsequent Event \| Cash Distribution
Partners Capital and Distribution [Line Items]
Distribution per unit (in dollars per unit)	$ 24.92

Intangible Asset, Net

12 Months Ended

Dec. 31, 2023

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Asset, Net

Intangible Assets, Net

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


		December 31, 2023						December 31, 2022
	Estimated Useful Lives (Years)	Cost		Accumulated Amortization		Net		Cost		Accumulated Amortization		Net
Customer contracts and relationships	1 – 29	$	2,789	$	(932)	$	1,857	$	2,817	$	(695)	$	2,122

Other agreements	15 – 70	30		(12)		18		35		(12)		23
Intangible assets (1)		$	2,819	$	(944)	$	1,875	$	2,852	$	(707)	$	2,145

(1)We include rights-of-way, which are intangible assets, within property and equipment. See Note 6 for a discussion of property and equipment.

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, 2023.

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, 2023, 2022 and 2021 was $308 million, $254 million and $122 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):


2024	$	272
2025	$	249
2026	$	210
2027	$	187
2028	$	165

Segment Information - Geographic Data (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Geographic Data
Revenues	$ 48,712	$ 57,342	$ 42,078
Long-lived assets	22,411	22,457
United States
Geographic Data
Revenues	42,308	46,903	34,458
Long-lived assets	18,591	18,655
Canada
Geographic Data
Revenues	6,404	10,439	$ 7,620
Long-lived assets	$ 3,820	$ 3,802

- Definition

+ References

+ Details

Major Customers and Concentration of Credit Risk (Details) - Revenues - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
ExxonMobil Corporation
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue (as a percent)	26.00%	20.00%	15.00%
BP p.l.c and subsidiaries
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue (as a percent)	10.00%		10.00%
Marathon Petroleum Corporation
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue (as a percent)			12.00%

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2023
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, 2023 and 2022, 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, 2023, 2022 and 2021. 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. The accompanying consolidated financial statements include the accounts of PAA 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.
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, 2023 and 2022, trade accounts payable included $26 million and $25 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 11 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, certain processing and fractionation facilities 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 derivatives and interest rate 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	Recent Accounting Pronouncements 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 intend to provide the required disclosures prospectively for annual periods beginning after December 15, 2024. 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 intend to provide the required disclosures beginning with our annual report for the year ended December 31, 2024. 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 intend to adopt this guidance for joint venture formations on January 1, 2025. In October 2021, the FASB issued ASU 2021-08, Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. This guidance requires that an acquirer recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with Topic 606, Revenue from Contracts with Customers, as if it had originated the contracts. The guidance is effective prospectively for interim and annual periods beginning after December 15, 2022, with early adoption permitted. We adopted this guidance as of January 1, 2023, and our adoption did not have a material impact on our financial position, results of operations or cash flows. In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. This guidance was effective prospectively upon issuance through December 31, 2022. In December 2022, the FASB issued ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, which defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. We will continue to apply applicable expedients and exceptions to contract modifications through December 31, 2024, as applicable.
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 and NGL on pipelines and trucks. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil and NGL 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 and from NGL fractionation and isomerization service. 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. Natural gas storage related activities fees were recognized in the period the natural gas moved across our header system. Fees from NGL fractionation and isomerization services and gas processing services are recognized in the period when the services are performed. 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 Common Unit	After consideration of distributions to preferred unitholders, basic and diluted net income per common unit is determined pursuant to the two-class method as prescribed in FASB guidance. This method is an earnings allocation formula that is used to determine allocations to our limited partners and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings or distributions in excess of earnings. Under the two-class method, net income is reduced by distributions pertaining to the period, and all remaining earnings or distributions in excess of earnings are then allocated to our common unitholders and participating securities based on their respective rights to share in distributions, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. Participating securities include equity-indexed compensation plan awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units. We calculate basic and diluted net income per common unit by dividing net income attributable to PAA (after deducting amounts allocated to the preferred unitholders and participating securities) by the basic and diluted weighted average number of common units outstanding during the period. The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units and (ii) our equity-indexed compensation plan awards. See Note 11 for additional information regarding our Series A preferred units. See Note 17 for a complete discussion of our equity-indexed compensation plan awards. When applying the if-converted method prescribed by FASB guidance, the possible conversion of approximately 71 million Series A preferred units, on a weighted-average basis, were excluded from the calculation of diluted net income per common unit for the years ended December 31, 2023, 2022 and 2021 as the effect was antidilutive for all periods. Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that are deemed to be dilutive during the year are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (i.e., undistributed loss), if any, are allocated to the common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method.
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, 2023, 2022 or 2021. Linefill in assets we own is recorded at historical cost and consists of crude oil and NGL. 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 6 for further discussion regarding impairment of long-lived assets. During 2023, 2022 and 2021, 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, 2023, 2022 and 2021, we made cash contributions of $29 million, $13 million and $82 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 $229 million and $204 million at December 31, 2023 and 2022, 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, 2023 and 2022 was attributable to goodwill related to our ownership interest in BridgeTex and Capline 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.
Income Allocation	We allocate net income for partners’ capital presentation purposes by applying the allocation methodology in our partnership agreement. Net income is allocated 100% to our common unitholders, after giving effect to income allocations for cash distributions to our Series A preferred unitholders and guaranteed payments attributable to our Series B preferred unitholders. For purposes of determining basic and diluted net income per common unit, income is allocated as prescribed in FASB guidance for calculating earnings per unit, including a deduction to income available to common unitholders for distributions attributable to the period on our Series A and Series B preferred units. See Note 4 for additional information.
Derivatives	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 optimize our profits while managing our exposure to commodity price risk and interest 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 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. 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.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.
Derivative Hedge Accounting Documentation	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.
Derivative Hedge Effectiveness Determination	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.
Derivatives That Qualify for Hedge Accounting	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 Do Not Qualify for Hedge Accounting	Derivatives that are not designated in a hedging relationship for accounting purposes are recognized in earnings each period.
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 railcars, office space, land, vehicles, and storage tanks, and our finance leases primarily relate to tractor trailers, land, 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 57 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 NGL and (ii) transporting crude oil and NGL. 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.
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.
Reimbursement of Expenses of Our General Partner and its Affiliates	Reimbursement of Our General Partner and its Affiliates Our general partner provides services necessary to manage and operate our business, properties and assets, including employing or retaining personnel. We do not pay our general partner a management fee, but we do reimburse our general partner for all direct and indirect costs it incurs or payments it makes on our behalf, including the costs of employee, officer and director compensation and benefits allocable to us as well as all other expenses necessary or appropriate to conduct our business. We record these costs on the accrual basis in the period in which our general partner incurs them. Our partnership agreement provides that our general partner will, in a manner it deems in its sole discretion to be reasonable, determine the expenses that are allocable to us.
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 PAA unit at each balance sheet date and adjusted for the present value of any distributions that are estimated to occur on the underlying 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.
Loss Contingencies	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.
Environmental Matters	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 accruals 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.
Segment Reporting	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. The NGL segment includes our NGL pipelines, NGL storage, natural gas processing and NGL fractionation facilities and related NGL marketing activities. Our crude oil and NGL marketing activities are included in the respective reporting segments as their 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 each of our segments. Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below) and maintenance capital. The measure of Segment Adjusted EBITDA forms the basis of our internal financial reporting and is the primary performance measure 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) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus (d) our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities, further adjusted (e) 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 (f) to exclude the portion of all preceding items that is attributable to noncontrolling interests (“Segment amounts attributable to noncontrolling interests”). Segment Adjusted EBITDA excludes depreciation and amortization. As an MLP, we make quarterly distributions of our “available cash” (as defined in our partnership agreement) to our unitholders. 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 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 are classified as maintenance capital, which is deducted in determining “available cash.” 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.

Revenues and Accounts Receivable - Performance Obligations (Details) $ in Millions	Dec. 31, 2023 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 609
Remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 478
Remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 270
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	$ 210
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	$ 163
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	$ 882
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: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 375
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: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 329
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: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 156
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	$ 109
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	$ 80
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	$ 194
Remaining performance obligation, expected timing of satisfaction, period
Terminalling, storage and other agreement revenues \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 234
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: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 149
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: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 114
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	$ 101
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	$ 83
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	$ 688
Remaining performance obligation, expected timing of satisfaction, period