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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________________________________

FORM 10-Q

________________________________________________________________________________________________________________________________

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2025

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 1-14569

________________________________________________________________

PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)


Delaware						76-0582150
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

333 Clay Street, Suite 1600

Houston, Texas 77002

(Address of principal executive offices) (Zip code)

(713) 646-4100

(Registrant’s telephone number, including area code)

________________________________________________________________

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Units	PAA	Nasdaq

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☑ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☑ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☑

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☑ No

As of October 31, 2025, there were 705,497,770 Common Units outstanding.

Table of Contents

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS


			Page
PART I. FINANCIAL INFORMATION
Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
Condensed Consolidated Balance Sheets: As of September 30, 2025 and December 31, 2024			3
Condensed Consolidated Statements of Operations: For the three and nine months ended September 30, 2025 and 2024			4
Condensed Consolidated Statements of Comprehensive Income: For the three and nine months ended September 30, 2025 and 2024			5
Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss): For the nine months ended September 30, 2025 and 2024			5
Condensed Consolidated Statements of Cash Flows: For the nine months ended September 30, 2025 and 2024			6
Condensed Consolidated Statements of Changes in Partners’ Capital: For the three and nine months ended September 30, 2025 and 2024			7
Notes to the Condensed Consolidated Financial Statements:
1. Organization and Basis of Consolidation and Presentation			9

2. Discontinued Operations			12
3. Revenues and Accounts Receivable			13
4. Net Income Per Common Unit			17
5. Inventory, Linefill and Long-term Inventory			19
6. Debt			20
7. Partners’ Capital and Distributions			21
8. Derivatives and Risk Management Activities			23
9. Related Party Transactions			27
10. Commitments and Contingencies			28
11. Segment Information			31
12. Acquisitions			38

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			41
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			62
Item 4. CONTROLS AND PROCEDURES			63

PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS			65
Item 1A. RISK FACTORS			65
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			65
Item 3. DEFAULTS UPON SENIOR SECURITIES			65
Item 4. MINE SAFETY DISCLOSURES			65
Item 5. OTHER INFORMATION			65
Item 6. EXHIBITS			66
SIGNATURES			70

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)


	September 30, 2025		December 31, 2024
	(unaudited)
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	1,180	$	348

Trade accounts receivable and other receivables, net	3,623		3,679
Inventory	184		261
Current assets of discontinued operations (Note 2)	434		415
Other current assets	162		99
Total current assets	5,583		4,802

PROPERTY AND EQUIPMENT	19,678		18,528
Accumulated depreciation	(5,535)		(5,082)
Property and equipment, net	14,143		13,446

OTHER ASSETS
Investments in unconsolidated entities	2,873		2,811
Intangible assets, net	1,570		1,677
Linefill	933		904
Long-term operating lease right-of-use assets, net	184		189
Long-term inventory	227		242
Long-term assets of discontinued operations (Note 2)	2,479		2,349
Other long-term assets, net	109		142
Total assets	$	28,101	$	26,562

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES
Trade accounts payable	$	3,584	$	3,647
Short-term debt	1,010		407
Current liabilities of discontinued operations (Note 2)	283		350
Other current liabilities	488		546
Total current liabilities	5,365		4,950

LONG-TERM LIABILITIES
Senior notes, net	8,371		7,141
Other long-term debt, net	68		70
Long-term operating lease liabilities	188		192
Long-term liabilities of discontinued operations (Note 2)	597		576
Other long-term liabilities and deferred credits	523		537
Total long-term liabilities	9,747		8,516

COMMITMENTS AND CONTINGENCIES (NOTE 10)

PARTNERS’ CAPITAL
Series A preferred unitholders (58,411,908 and 71,090,468 units outstanding, respectively)	1,247		1,514
Series B preferred unitholders (800,000 and 800,000 units outstanding, respectively)	787		787
Common unitholders (705,497,770 and 703,770,300 units outstanding, respectively)	7,729		7,512
Total partners’ capital excluding noncontrolling interests	9,763		9,813
Noncontrolling interests	3,226		3,283
Total partners’ capital	12,989		13,096
Total liabilities and partners’ capital	$	28,101	$	26,562

The accompanying notes are an integral part of these condensed consolidated financial statements.

Table of Contents

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(unaudited)				(unaudited)
REVENUES
Product sales revenues	$	11,150	$	12,021	$	32,389	$	35,606
Services revenues	428		435		1,309		1,248
Total revenues	11,578		12,456		33,698		36,854
COSTS AND EXPENSES
Purchases and related costs	10,585		11,540		30,862		34,086
Field operating costs	288		408		873		962
General and administrative expenses	83		86		251		246
Depreciation and amortization	230		226		696		675
(Gains)/losses on asset sales, net	(92)		—		(64)		2
Total costs and expenses	11,094		12,260		32,618		35,971
OPERATING INCOME	484		196		1,080		883
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	96		97		292		298
Gain on investments in unconsolidated entities, net	—		—		31		—
Interest expense (net of capitalized interest of $4, $2, $9 and $7, respectively)	(135)		(113)		(395)		(318)


Other income, net	14		26		70		45

INCOME FROM CONTINUING OPERATIONS BEFORE TAX	459		206		1,078		908
Current income tax expense from continuing operations	(5)		(4)		(11)		(72)
Deferred income tax (expense)/benefit from continuing operations	(1)		(4)		(6)		1
INCOME FROM CONTINUING OPERATIONS, NET OF TAX	453		198		1,061		837




INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX (NOTE 2)	76		114		281		156
NET INCOME	529		312		1,342		993
Net income attributable to noncontrolling interests	(88)		(92)		(249)		(257)
NET INCOME ATTRIBUTABLE TO PAA	$	441	$	220	$	1,093	$	736

NET INCOME PER COMMON UNIT (NOTE 4):
Net income allocated to common unitholders — Basic and Diluted:
Continuing operations	$	311	$	43	$	599	$	384
Discontinued operations	76		114		281		156
Net income allocated to common unitholders — Basic and Diluted	$	387	$	157	$	880	$	540

Basic and diluted weighted average common units outstanding	704		702		704		702

Basic and diluted net income per common unit:
Continuing operations	$	0.44	$	0.06	$	0.85	$	0.55
Discontinued operations	$	0.11	$	0.16	$	0.40	$	0.22
Basic and diluted net income per common unit	$	0.55	$	0.22	$	1.25	$	0.77

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(unaudited)				(unaudited)
Net income	$	529	$	312	$	1,342	$	993
Other comprehensive income/(loss)	(51)		36		142		(68)
Comprehensive income	478		348		1,484		925
Comprehensive income attributable to noncontrolling interests	(88)		(92)		(249)		(257)
Comprehensive income attributable to PAA	$	390	$	256	$	1,235	$	668

The accompanying notes are an integral part of these condensed consolidated financial statements.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

(in millions)


	Derivative Instruments		Translation Adjustments		Other		Total
	(unaudited)
Balance at December 31, 2024	$	(44)	$	(1,039)	$	—	$	(1,083)

Reclassification adjustments	4		—		—		4
Unrealized gain on hedges	9		—		—		9
Currency translation adjustments	—		127		—		127
Other	—		—		2		2
Total period activity	13		127		2		142
Balance at September 30, 2025	$	(31)	$	(912)	$	2	$	(941)


	Derivative Instruments		Translation Adjustments		Other		Total
	(unaudited)
Balance at December 31, 2023	$	(81)	$	(755)	$	—	$	(836)

Reclassification adjustments	6		—		—		6
Unrealized gain on hedges	9		—		—		9
Currency translation adjustments	—		(84)		—		(84)
Other	—		—		1		1
Total period activity	15		(84)		1		(68)
Balance at September 30, 2024	$	(66)	$	(839)	$	1	$	(904)

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	Nine Months Ended September 30,
	2025		2024
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,342	$	993
Reconciliation of net income to net cash provided by operating activities:
Income from discontinued operations, net of tax	(281)		(156)
Depreciation and amortization	696		675
(Gains)/losses on asset sales, net	(64)		2


Deferred income tax expense/(benefit)	6		(1)

(Gain)/loss on foreign currency revaluation	19		(12)
Settlement of terminated interest rate hedging instruments (Note 8)	7		57

Equity earnings in unconsolidated entities	(292)		(298)
Distributions on earnings from unconsolidated entities	369		383
Gain on investments in unconsolidated entities, net (Note 12)	(31)		—
Other	47		52
Changes in assets and liabilities, net of acquisitions	18		(98)
Cash provided by operating activities - continuing operations	1,836		1,597
Cash provided by operating activities - discontinued operations	314		166
Net cash provided by operating activities	2,150		1,763

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	(865)		(144)
Investments in unconsolidated entities	—		(4)
Additions to property, equipment and other	(495)		(342)
Cash paid for purchases of linefill	(17)		(21)
Proceeds from sales of assets	27		6


Investments in related party notes (Note 9)	(330)		(629)
Other investing activities	—		3
Cash used in investing activities - continuing operations	(1,680)		(1,131)
Cash used in investing activities - discontinued operations	(151)		(109)
Net cash used in investing activities	(1,831)		(1,240)

CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments under commercial paper program (Note 6)	(393)		(433)



Proceeds from the issuance of senior notes (Note 6)	2,246		650

Proceeds from the issuance of related party notes (Note 9)	330		629

Repurchase of common units	(8)		—
Repurchase of Series A preferred units (Note 7)	(333)		—
Distributions paid to Series A preferred unitholders (Note 7)	(118)		(131)
Distributions paid to Series B preferred unitholders (Note 7)	(53)		(59)
Distributions paid to common unitholders (Note 7)	(802)		(668)
Distributions paid to noncontrolling interests (Note 7)	(339)		(310)
Contributions from noncontrolling interests	34		40


Other financing activities	(64)		(48)


Net cash provided by/(used in) financing activities	500		(330)

Effect of translation adjustment - continuing operations	13		(7)
Effect of translation adjustment - discontinued operations	—		4

Net increase in cash and cash equivalents and restricted cash	832		190
Cash and cash equivalents and restricted cash, beginning of period	348		450
Cash and cash equivalents and restricted cash, end of period	$	1,180	$	640

Cash paid for:
Interest, net of amounts capitalized	$	382	$	269
Income taxes, net of amounts refunded	$	80	$	236

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(in millions)


	Limited Partners						Partners’ Capital Excluding Noncontrolling Interests		Noncontrolling Interests		Total Partners’ Capital
	Preferred Unitholders				Common Unitholders
	Series A		Series B
	(unaudited)
Balance at December 31, 2024	$	1,514	$	787	$	7,512	$	9,813	$	3,283	$	13,096
Net income	110		53		930		1,093		249		1,342
Distributions (Note 7)	(110)		(53)		(802)		(965)		(339)		(1,304)
Other comprehensive income	—		—		142		142		—		142
Repurchase of Series A preferred units (Note 7)	(270)		—		(43)		(313)		—		(313)
Repurchase of common units	—		—		(8)		(8)		—		(8)
Contributions from noncontrolling interests	—		—		—		—		34		34
Other	3		—		(2)		1		(1)		—
Balance at September 30, 2025	$	1,247	$	787	$	7,729	$	9,763	$	3,226	$	12,989

	Limited Partners						Partners’ Capital Excluding Noncontrolling Interests		Noncontrolling Interests		Total Partners’ Capital
	Preferred Unitholders				Common Unitholders
	Series A		Series B
	(unaudited)
Balance at June 30, 2025	$	1,246	$	787	$	7,673	$	9,706	$	3,243	$	12,949
Net income	36		18		387		441		88		529
Distributions (Note 7)	(36)		(18)		(267)		(321)		(110)		(431)
Other comprehensive loss	—		—		(51)		(51)		—		(51)

Contributions from noncontrolling interests	—		—		—		—		5		5

Other	1		—		(13)		(12)		—		(12)
Balance at September 30, 2025	$	1,247	$	787	$	7,729	$	9,763	$	3,226	$	12,989

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(continued)

(in millions)


	Limited Partners						Partners’ Capital Excluding Noncontrolling Interests		Noncontrolling Interests		Total Partners’ Capital
	Preferred Unitholders				Common Unitholders
	Series A		Series B
	(unaudited)
Balance at December 31, 2023	$	1,509	$	787	$	8,126	$	10,422	$	3,310	$	13,732
Net income	131		59		546		736		257		993
Distributions	(131)		(59)		(668)		(858)		(310)		(1,168)
Other comprehensive loss	—		—		(68)		(68)		—		(68)

Contributions from noncontrolling interests	—		—		—		—		40		40
Other	4		—		(1)		3		—		3
Balance at September 30, 2024	$	1,513	$	787	$	7,935	$	10,235	$	3,297	$	13,532

	Limited Partners						Partners’ Capital Excluding Noncontrolling Interests		Noncontrolling Interests		Total Partners’ Capital
	Preferred Unitholders				Common Unitholders
	Series A		Series B
	(unaudited)
Balance at June 30, 2024	$	1,512	$	787	$	7,977	$	10,276	$	3,302	$	13,578
Net income	44		19		157		220		92		312
Distributions	(44)		(19)		(223)		(286)		(113)		(399)
Other comprehensive income	—		—		36		36		—		36

Contributions from noncontrolling interests	—		—		—		—		16		16
Other	1		—		(12)		(11)		—		(11)
Balance at September 30, 2024	$	1,513	$	787	$	7,935	$	10,235	$	3,297	$	13,532

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1—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-Q 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 crude oil midstream service providers in North America, we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. Our assets and the services we provide are primarily focused on and conducted through two operating segments: Crude Oil and Natural Gas Liquids (“NGL”). See Note 11 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 September 30, 2025, AAP also owned a limited partner interest in us through its ownership of approximately 233.0 million of our common units (approximately 31% 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 September 30, 2025, owned an approximate 85% 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 our “general partner,” as the context requires, include any or all of PAGP GP, PAGP, GP LLC, AAP and PAA GP. References to “Plains entities,” as the context requires, include any or all of PAA and its subsidiaries and our general partner.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Definitions

Additional defined terms may be used in this Form 10-Q 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
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

LTIP	=	Long-term incentive plan
Mcf	=	Thousand cubic feet
MMbls	=	Million barrels
NGL	=	Natural gas liquids, including ethane, propane and butane
NYMEX	=	New York Mercantile Exchange
OECD	=	Organisation for Economic Co-operation and Development
SEC	=	United States Securities and Exchange Commission
SOFR	=	Secured Overnight Financing Rate
TWh	=	Terawatt hour
USD	=	United States dollar
WTI	=	West Texas Intermediate

Basis of Consolidation and Presentation

The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our 2024 Annual Report on Form 10-K. The accompanying condensed 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. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. The condensed consolidated balance sheet data as of December 31, 2024 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three and nine months ended September 30, 2025 should not be taken as indicative of results to be expected for the entire year. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany balances and transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications had no impact on net income or total partners’ capital.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Pending Sale of Canadian NGL Business

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

We determined that in conjunction with entering into the SPA, the operations of the Canadian NGL Business meet the criteria for classification as held for sale and for discontinued operations reporting, as the sale will represent a strategic shift that will have a major effect on our operations and financial results. Accordingly, the assets and liabilities of the Canadian NGL Business have been classified as held for sale, and the balance sheet, results of operations and cash flows of the Canadian NGL Business have been presented as discontinued operations in our condensed consolidated financial statements. Unless otherwise indicated, the disclosures included within the accompanying notes to the condensed consolidated financial statements relate to our continuing operations and exclude amounts related to discontinued operations. These changes have been applied retrospectively to all periods presented. Discontinued operations are not presented separately within our Condensed Consolidated Statements of Comprehensive Income, Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss) or the Condensed Consolidated Statements of Changes in Partners’ Capital. See Note 2 for additional information regarding discontinued operations. All significant intercompany balances and transactions between the Canadian NGL Business and our continuing operations have been eliminated.

While we will divest the Canadian NGL Business as part of the sale, we will retain substantially all NGL assets in the United States and will also retain all crude oil assets in Canada. Prior to its classification as held for sale and presentation as discontinued operations, the Canadian NGL Business was part of our NGL reportable segment.

In June 2025, we entered into a forward currency instrument to hedge currency exchange risk associated with anticipated proceeds from the pending sale of our Canadian NGL Business. See Note 8 for additional information.

In connection with and contingent upon closing of the pending sale, we and Keyera entered into an agreement for certain hedging arrangements and payments relating to the differential between the price of natural gas and the extracted NGL commodities (“Frac Spread”) for a twelve-month period commencing the first month after the closing date. As a result of this arrangement, we will guarantee a minimum Frac Spread margin on certain volumes. The recognition of an asset or liability will be dependent upon the terms of the specific contracts transferred as part of the sale of the Canadian NGL Business and the market conditions at that time the sale closes. We do not expect any liability we might recognize as a result of this agreement to have a material adverse effect on our consolidated financial condition, results of operations or cash flows; for example, if the sale closed during the first quarter of 2026, based on existing contracts to be transferred and current market conditions as of September 30, 2025, we would recognize a liability of approximately $45 million.

Subsequent Events

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

Recent Accounting Pronouncements, Disclosure Rules and Other Legislation

Except as discussed in our 2024 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the nine months ended September 30, 2025 that are of significance or potential significance to us.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 2— Discontinued Operations

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

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


	September 30, 2025		December 31, 2024
Assets:
Current assets:

Trade accounts receivable and other receivables, net	$	165	$	222
Inventory	223		178
Other current assets	46		15
Total current assets of discontinued operations	$	434	$	415

Long-term assets:
Property and equipment, net (1)	$	2,125	$	1,978

Linefill	69		64
Long-term operating lease right-of-use assets, net	134		143
Long-term inventory	38		38
Other long-term assets, net	113		126
Total long-term assets of discontinued operations	$	2,479	$	2,349

Liabilities:
Current liabilities:
Trade accounts payable	$	193	$	234

Other current liabilities	90		116
Total current liabilities of discontinued operations	$	283	$	350

Long-term liabilities:

Long-term operating lease liabilities	$	101	$	121
Other long-term liabilities and deferred credits	496		455
Total long-term liabilities of discontinued operations	$	597	$	576

(1)Amounts are net of accumulated depreciation of $866 million and $794 million as of September 30, 2025 and December 31, 2024, respectively.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Revenues:
Product sales	$	139	$	261	$	818	$	715
Services	37		26		102		102
Total revenues	176		287		920		817
Cost and Expenses:
Purchases and related costs	(7)		17		245		247
Field operating costs	68		75		190		229
General and administrative expenses	10		12		36		41
Depreciation and amortization	—		31		57		94
(Gains)/losses on asset sales, net	2		1		15		(1)
Total costs and expenses	73		136		543		610

Income from discontinued operations before tax	103		151		377		207
Current income tax expense	(7)		(16)		(61)		(71)
Deferred income tax (expense)/benefit	(20)		(21)		(35)		20
Income from discontinued operations, net of tax	$	76	$	114	$	281	$	156

Note 3—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):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Crude Oil segment revenues from contracts with customers
Sales	$	11,116	$	12,046	$	32,351	$	35,560
Transportation	337		321		990		915
Terminalling, Storage and Other	84		100		258		286
Total Crude Oil segment revenues from contracts with customers	$	11,537	$	12,467	$	33,599	$	36,761


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
NGL segment revenues from contracts with customers
Sales	$	22	$	19	$	88	$	101

Terminalling, Storage and Other	2		1		4		5
Total NGL segment revenues from contracts with customers	$	24	$	20	$	92	$	106

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 Condensed Consolidated Statements of Operations.

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

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

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

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Three Months Ended September 30, 2025	Crude Oil		NGL		Total
Revenues from contracts with customers	$	11,537	$	24	$	11,561
Other revenues	22		—		22
Total revenues of reportable segments	$	11,559	$	24	$	11,583
Intersegment revenues elimination					(5)
Total revenues					$	11,578

Three Months Ended September 30, 2024	Crude Oil		NGL		Total
Revenues from contracts with customers	$	12,467	$	20	$	12,487
Other revenues	(23)		—		(23)
Total revenues of reportable segments	$	12,444	$	20	$	12,464
Intersegment revenues elimination					(8)
Total revenues					$	12,456

Nine Months Ended September 30, 2025	Crude Oil		NGL		Total
Revenues from contracts with customers	$	33,599	$	92	$	33,691
Other revenues	21		—		21
Total revenues of reportable segments	$	33,620	$	92	$	33,712
Intersegment revenues elimination					(14)
Total revenues					$	33,698

Nine Months Ended September 30, 2024	Crude Oil		NGL		Total
Revenues from contracts with customers	$	36,761	$	106	$	36,867

Total revenues of reportable segments	$	36,761	$	106	$	36,867
Intersegment revenues elimination					(13)
Total revenues					$	36,854

Minimum Volume Commitments. We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. 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):


Counterparty Deficiencies	Financial Statement Classification	September 30, 2025		December 31, 2024
Billed and collected	Other current liabilities	$	57	$	83

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


	Contract Liabilities
Balance at December 31, 2024	$	87
Amounts recognized as revenue	(40)

Additions	19

Balance at September 30, 2025	$	66

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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 September 30, 2025 (in millions):


	Remainder of 2025		2026		2027		2028		2029		2030 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	79	$	286	$	243	$	205	$	106	$	425
Terminalling, storage and other agreement revenues	59		232		203		148		105		492
Total	$	138	$	518	$	446	$	353	$	211	$	917

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

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

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

•Acreage dedications;

•Buy/sell arrangements with future committed volumes;

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

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

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

Trade Accounts Receivable and Other Receivables, Net

At September 30, 2025 and December 31, 2024, substantially all of our trade accounts receivable were less than 30 days past their invoice date. Our expected credit losses are immaterial. Although we consider our credit procedures to be adequate to mitigate any significant credit losses, the actual amount of current and future credit losses could vary significantly from estimated amounts.

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


	September 30, 2025		December 31, 2024
Trade accounts receivable arising from revenues from contracts with customers	$	3,835	$	3,922
Other trade accounts receivable and other receivables (1)	7,839		7,339
Impact due to contractual rights of offset with counterparties	(8,051)		(7,582)
Trade accounts receivable and other receivables, net	$	3,623	$	3,679

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

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Note 4—Net Income Per Common Unit

We calculate basic and diluted net income per common unit by dividing income from continuing operations attributable to PAA (after deducting amounts allocated to the preferred unitholders and participating securities) and income from discontinued operations 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 and Note 17 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for a discussion of our Series A preferred units and equity-indexed compensation plan awards. When applying the if-converted method prescribed by FASB guidance, on a weighted-average basis, for the three and nine months ended September 30, 2025, the possible conversion of approximately 58 million and 60 million Series A preferred units, respectively, and for each of the three and nine months ended September 30, 2024, the possible conversion of approximately 71 million Series A preferred units were excluded from the calculation of diluted net income per common unit as the effect was antidilutive. 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 period 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.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Basic and Diluted Net Income per Common Unit
Continuing Operations:
Income from continuing operations, net of tax	$	453	$	198	$	1,061	$	837
Net income attributable to noncontrolling interests	(88)		(92)		(249)		(257)
Net income from continuing operations attributable to PAA	365		106		812		580
Distributions to Series A preferred unitholders	(36)		(44)		(110)		(131)
Distributions to Series B preferred unitholders	(18)		(19)		(53)		(59)
Amounts allocated to participating securities	(1)		(1)		(10)		(9)
Impact from repurchase of Series A preferred units (1)	—		—		(43)		—
Other	1		1		3		3
Net income from continuing operations allocated to common unitholders - Basic and Diluted (2)	$	311	$	43	$	599	$	384

Discontinued Operations:
Net income from discontinued operations allocated to common unitholders - Basic and Diluted (3)	$	76	$	114	$	281	$	156

Net income allocated to common unitholders — Basic and Diluted	$	387	$	157	$	880	$	540

Basic and diluted weighted average common units outstanding	704		702		704		702

Basic and diluted net income per common unit:
Continuing operations	$	0.44	$	0.06	$	0.85	$	0.55
Discontinued operations	0.11		0.16		0.40		0.22
Basic and diluted net income per common unit	$	0.55	$	0.22	$	1.25	$	0.77

(1)We repurchased approximately 12.7 million Series A preferred units on January 31, 2025. See Note 7 for additional information. The difference between the cash we paid for the repurchase of such units and their carrying value on our balance sheet is considered a return to Series A preferred unitholders for the calculation of net income allocated to common unitholders.

(2)We calculate net income from continuing operations 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.

(3)Net income from discontinued operations allocated to common unitholders is Income from discontinued operations, net of tax as presented on our Condensed Consolidated Statements of Operations.

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Note 5—Inventory, Linefill and Long-term Inventory

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


	September 30, 2025						December 31, 2024
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	2,021	barrels	$	122	$	60.37	3,321	barrels	$	221	$	66.55
NGL	1,035	barrels	51		$	49.28	603	barrels	26		$	43.12

Other	N/A		11		N/A		N/A		14		N/A
Inventory subtotal			184						261

Linefill
Crude oil	15,762	barrels	932		$	59.13	15,463	barrels	903		$	58.40
NGL	32	barrels	1		$	31.25	32	barrels	1		$	31.25

Linefill subtotal			933						904

Long-term inventory
Crude oil	3,640	barrels	226		$	62.09	3,413	barrels	238		$	69.73
NGL	26	barrels	1		$	38.46	90	barrels	4		$	44.44
Long-term inventory subtotal			227						242

Total			$	1,344					$	1,407

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

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Note 6—Debt

Debt consisted of the following (in millions):


	September 30, 2025		December 31, 2024
SHORT-TERM DEBT
Commercial paper notes, bearing a weighted-average interest rate of 4.6% (1)	$	—	$	393


Senior notes:
4.65% senior notes due October 2025 (2)	1,000		—

Other	10		14
Total short-term debt	1,010		407

LONG-TERM DEBT
Senior notes, net of unamortized discounts and debt issuance costs of $62 and $42, respectively (2)	8,371		7,141


Other	68		70
Total long-term debt	8,439		7,211
Total debt (3)	$	9,449	$	7,618

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

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

(3)Our fixed-rate senior notes had a face value of approximately $9.4 billion and $7.2 billion as of September 30, 2025 and December 31, 2024, respectively. We estimated the aggregate fair value of these notes as of September 30, 2025 and December 31, 2024 to be approximately $9.2 billion and $6.7 billion, 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.

Senior Notes

In January 2025, we completed the offering of $1.0 billion, 5.95% senior notes due June 2035 at a public offering price of 99.761%. Interest payments are due on June 15 and December 15 of each year, commencing on June 15, 2025.

In September 2025, we completed the offering of $700 million, 4.70% senior notes due January 2031 and $550 million, 5.60% senior notes due January 2036 at a public offering price of 99.865% and 99.798%, respectively. Interest payments on these notes are due on January 15 and July 15 of each year, commencing on January 15, 2026.

Borrowings and Repayments

Total borrowings under our commercial paper program for the nine months ended September 30, 2025 and 2024 were approximately $38.7 billion and $20.7 billion, respectively. Total repayments under our commercial paper program were approximately $39.1 billion and $21.1 billion for the nine months ended September 30, 2025 and 2024, 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.

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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. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At September 30, 2025 and December 31, 2024, we had outstanding letters of credit of $70 million and $90 million, respectively.

Note 7—Partners’ Capital and Distributions

Units Outstanding

The following tables present the activity for our preferred and common units:


	Limited Partners
	Series A Preferred Units	Series B Preferred Units	Common Units
Outstanding at December 31, 2024	71,090,468	800,000	703,770,300
Repurchase of Series A preferred units	(12,678,560)	—	—
Issuances of common units under equity-indexed compensation plans	—	—	5,650
Outstanding at March 31, 2025	58,411,908	800,000	703,775,950
Repurchase and cancellation of common units under the Common Equity Repurchase Program	—	—	(476,695)
Issuances of common units under equity-indexed compensation plans	—	—	5,197
Outstanding at June 30, 2025	58,411,908	800,000	703,304,452

Issuances of common units under equity-indexed compensation plans	—	—	2,193,318

Outstanding at September 30, 2025	58,411,908	800,000	705,497,770


	Limited Partners
	Series A Preferred Units	Series B Preferred Units	Common Units
Outstanding at December 31, 2023	71,090,468	800,000	701,008,749


Issuances of common units under equity-indexed compensation plans	—	—	62,282
Outstanding at March 31, 2024	71,090,468	800,000	701,071,031

Issuances of common units under equity-indexed compensation plans	—	—	10,268
Outstanding at June 30, 2024	71,090,468	800,000	701,081,299

Issuances of common units under equity-indexed compensation plans	—	—	2,587,760
Outstanding at September 30, 2024	71,090,468	800,000	703,669,059

Repurchase of Series A Preferred Units

On January 31, 2025, we repurchased approximately 12.7 million of our outstanding Series A preferred units from EnCap Flatrock Midstream at the issue price of $26.25 per unit for a purchase price of approximately $333 million, plus accrued and unpaid distributions through January 30, 2025 of approximately $10 million. EnCap Flatrock Midstream is affiliated with EnCap Investments, L.P., an entity that is associated with a member of the board of directors of PAGP GP. The repurchase also resulted in a reduction to the related Preferred Distribution Rate Reset Option liability. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for additional information regarding the Preferred Distribution Rate Reset Option. The difference between the cash we paid for the repurchase of such units and their carrying value on our balance sheet was $43 million. Such amount was considered a return to Series A preferred unitholders and thus reduced amounts attributable to our common unitholders in our Condensed Consolidated Statement of Changes in Partners’ Capital and the calculation of net income per common unit.

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Distributions

Series A Preferred Unit Distributions. Distributions on the Series A preferred units accumulate and are payable quarterly within 45 days following the end of each quarter. See Note 11 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for additional information regarding Series A preferred unit distributions. The following table details distributions to our Series A preferred unitholders paid during or pertaining to the first nine months of 2025 (in millions, except per unit data):


			Series A Preferred Unitholders
Distribution Payment Date	Record Date (1)	Distribution Period	Cash Distribution		Distribution per Unit
November 14, 2025 (2)	October 31, 2025	July 1, 2025 through September 30, 2025	$	36	$	0.615
August 14, 2025	July 31, 2025	April 1, 2025 through June 30, 2025	$	36	$	0.615
May 15, 2025	May 1, 2025	January 1, 2025 through March 31, 2025	$	36	$	0.615
February 14, 2025	January 31, 2025	October 1, 2024 through December 31, 2024	$	36	$	0.615

(1)Payable to unitholders of record at the close of business on the applicable Record Date.

(2)At September 30, 2025, such amount was accrued as distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

Series B Preferred Unit Distributions. Distributions on the Series B preferred units accumulate and are payable quarterly in arrears on the 15th day of February, May, August and November. See Note 11 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for additional information regarding Series B preferred unit distributions. The following table details distributions paid or to be paid to our Series B preferred unitholders (in millions, except per unit data):


			Series B Preferred Unitholders
Distribution Payment Date	Record Date (1)	Distribution Period	Cash Distribution		Distribution per Unit
November 17, 2025 (2)	November 3, 2025	August 15, 2025 through November 14, 2025	$	18	$	21.93
August 15, 2025	August 1, 2025	May 15, 2025 through August 14, 2025	$	18	$	22.23
May 15, 2025	May 1, 2025	February 15, 2025 through May 14, 2025	$	17	$	21.49
February 18, 2025	February 3, 2025	November 15, 2024 through February 14, 2025	$	18	$	22.73

(1)Payable to unitholders of record at the close of business on the applicable Record Date.

(2)At September 30, 2025, approximately $9 million of accrued distributions payable to our Series B preferred unitholders was included in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

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Common Unit Distributions. The following table details distributions to our common unitholders paid during or pertaining to the first nine months of 2025 (in millions, except per unit data):


			Distributions						Distribution per Common Unit
Distribution Payment Date	Record Date (1)	Distribution Period	Common Unitholders				Total Cash Distribution
			Public		AAP
November 14, 2025	October 31, 2025	July 1, 2025 through September 30, 2025	$	180	$	88	$	268	$	0.38
August 14, 2025	July 31, 2025	April 1, 2025 through June 30, 2025	$	179	$	88	$	267	$	0.38
May 15, 2025	May 1, 2025	January 1, 2025 through March 31, 2025	$	179	$	88	$	267	$	0.38
February 14, 2025	January 31, 2025	October 1, 2024 through December 31, 2024	$	179	$	88	$	267	$	0.38

(1)Payable to unitholders of record at the close of business on the applicable Record Date.

Noncontrolling Interests in Subsidiaries

As of September 30, 2025, noncontrolling interests in our subsidiaries consisted of (i) a 35% interest in Plains Oryx Permian Basin LLC (the “Permian JV”), (ii) a 30% interest in Cactus II Pipeline LLC (“Cactus II”) and (iii) a 33% interest in Red River Pipeline Company LLC (“Red River”).

Distributions to Noncontrolling Interests

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Permian JV	$	85	$	87	$	268	$	235
Cactus II	21		20		59		56
Red River	4		6		12		19
	$	110	$	113	$	339	$	310

Note 8—Derivatives and Risk Management Activities

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

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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 Condensed 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 September 30, 2025 and December 31, 2024, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our exchange-traded derivatives transacted through a clearing brokerage account, as described below, we do not require our non-cleared derivative counterparties to post collateral with us.

Commodity Price Risk Hedging

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

In the normal course of our operations, we purchase and sell commodities. We use derivatives to manage the associated risks and, in certain circumstances, to optimize profits. As of September 30, 2025, net derivative positions related to these activities included:

•A net long position of 9.4 million barrels associated with our crude oil purchases, which will be unwound ratably through December 2025 to match monthly average pricing.

•A net short time spread position of 2.1 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through April 2026.

•A net crude oil basis spread position of 2.5 million barrels at multiple locations through December 2026. These derivatives allow us to lock in grade and location basis differentials.

•A net short position of 5.7 million barrels through December 2029 related to anticipated net sales of crude oil inventory.

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

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

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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):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Product sales revenues	$	13	$	(36)	$	(29)	$	(64)
Field operating costs	—		(4)		3		(9)

Net gain/(loss) from commodity derivative activity	$	13	$	(40)	$	(26)	$	(73)

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


	September 30, 2025		December 31, 2024
Initial margin	$	45	$	16
Variation margin posted/(returned)	(8)		15
Letters of credit	(1)		(9)
Net broker receivable	$	36	$	22

The following table reflects the Condensed 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 Condensed Consolidated Balance Sheet when the legal right of offset exists. Amounts in the table below are presented in millions.


	September 30, 2025								December 31, 2024
					Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet						Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet
	Commodity Derivatives								Commodity Derivatives
	Assets		Liabilities						Assets		Liabilities
Derivative Assets
Other current assets	$	14	$	(14)	$	36	$	36	$	25	$	(24)	$	22	$	23
Other long-term assets, net	1		—		—		1		—		—		—		—
Derivative Liabilities
Other current liabilities	—		—		—		—		(5)		5		—		—
Other long-term liabilities and deferred credits	4		(9)		—		(5)		2		(6)		—		(4)
Total	$	19	$	(23)	$	36	$	32	$	22	$	(25)	$	22	$	19

Interest Rate Risk Hedging

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

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The following table summarizes the terms of our outstanding interest rate derivatives as of September 30, 2025 (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

During the three months ended September 30, 2025, we terminated $200 million of notional hedging instruments for proceeds of $7 million, which was recorded in AOCI. As of September 30, 2025, there was a net loss of $31 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. 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 September 30, 2025; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Interest rate derivatives, net	$	4	$	(9)	$	9	$	9

At September 30, 2025, the net fair value of our interest rate hedges, which was included in “Other current assets” on our Condensed Consolidated Balance Sheet, totaled $29 million. At December 31, 2024, the net fair value of our interest rate hedges, which was included in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet, totaled $27 million.

Currency Exchange Rate Risk Hedging

In connection with the pending sale of the Canadian NGL Business, we entered into a forward currency instrument (CAD$4.5 billion notional amount) to hedge currency exchange risk. The instrument is contingent upon the sale occurring and will settle at closing. The cost of the deal-contingent structure is embedded in the hedge rate. As of September 30, 2025, the sale of the Canadian NGL Business is probable and the fair value of the instrument is a $41 million asset, presented in “Other current assets” on our Condensed Consolidated Balance Sheet. For the three and nine months ended September 30, 2025, we recognized the gains of $90 million and $41 million, respectively, which was included in “(Gains)/losses on asset sales, net” on our Condensed Consolidated Statements of Operations. As of September 30, 2025, for the periods covered by the instrument, the average fixed USD to CAD rate of the instrument is $1.37 and the average forward USD to CAD rate is $1.38. See Note 1 for additional information regarding the pending sale of the Canadian NGL Business.

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 September 30, 2025				Fair Value as of December 31, 2024
Recurring Fair Value Measures (1)	Level 2		Total			Level 1		Level 2		Total
Commodity derivatives	$	(4)	$	(4)		$	11	$	(14)	$	(3)
Interest rate derivatives	29		29			—		27		27
Foreign currency derivatives	41		41			—		—		—

Total net derivative asset/(liability)	$	66	$	66		$	11	$	13	$	24

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

Level 1

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

Level 2

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

Note 9—Related Party Transactions

See Note 16 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for a complete discussion of related parties, including the determination of our related parties and nature of involvement with such related parties.

Promissory Notes with our General Partner

In February 2025, a consolidated subsidiary issued an additional unsecured promissory note to PAGP with a face value of CAD$473 million (approximately $330 million). Concurrently, PAGP issued an unsecured promissory note to us for the same face value amount. These notes are due June 2035 and bear interest at a rate of 5.75% per annum, payable semi-annually. The interest rate for such notes was determined in accordance with the arm’s-length principle set forth in the OECD Guidelines and the transfer pricing provisions of Section 247 of Canada’s Income Tax Act. In connection with the issuance of these related party notes, we received cash from PAGP of approximately $330 million, which is reflected in “Proceeds from the issuance of related party notes” (a component of cash flows from financing activities), and we paid an equal and offsetting amount of cash to PAGP, which is reflected in “Investments in related party notes” (a component of cash flows from investing activities) on our Condensed Consolidated Statement of Cash Flows.

Accrued and unpaid interest receivable/payable was $7 million and $27 million as of September 30, 2025 and December 31, 2024, respectively. Interest income/expense on the related party notes totaled $23 million and $65 million for the three and nine months ended September 30, 2025, respectively, and $16 million and $31 million for the three and nine months ended September 30, 2024, respectively.

As of September 30, 2025 and December 31, 2024, our outstanding related party notes receivable and related party notes payable balances were as follows (in millions):


	September 30, 2025		December 31, 2024
Related party notes receivable (1)	$	1,321	$	948
Related party notes payable (1)	$	1,321	$	948

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

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Transactions with Other Related Parties

During the three and nine months ended September 30, 2025 and 2024, we recognized sales and transportation revenues, purchased petroleum products and utilized transportation and storage services from related parties. These transactions were conducted at posted tariff rates or prices that we believe approximate market.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Revenues from related parties	$	12	$	12	$	35	$	34

Purchases and related costs from related parties	$	89	$	103	$	285	$	296

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


	September 30, 2025		December 31, 2024
Trade accounts receivable and other receivables, net from related parties (1)	$	55	$	40

Trade accounts payable to related parties (1) (2)	$	72	$	66

(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.

Note 10—Commitments and 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.

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.

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

Environmental — General

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

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

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

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

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


	September 30, 2025		December 31, 2024
Other current liabilities	$	15	$	11
Other long-term liabilities and deferred credits	73		69
Total	$	88	$	80

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

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Specific Legal, Environmental or Regulatory Matters

Line 901 Incident. In May 2015 we experienced a release of crude oil from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. Effective as of September 30, 2025, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $870 million, which includes actual emergency response and clean-up costs, natural resource damage assessments, fines and penalties incurred, certain third-party claims settlements, and estimated costs associated with our remaining Line 901 lawsuits and claims as described below, as well as estimates for certain legal fees and statutory interest where applicable. We accrue such estimates of aggregate total costs to “Field operating costs” in our Condensed Consolidated Statements of Operations. This estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the resolution of certain third-party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and (ii) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. Our estimate does not include any lost revenue associated with the shutdown of Line 901 or 903 and does not include any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, with respect to potential losses that we regard as only reasonably possible or remote, we have made assumptions regarding the strength of our legal position based on our assessment of the relevant facts and applicable law and precedent; if our assumptions regarding such matters turn out to be inaccurate (i.e., we are found to be liable under circumstances where we regard the likelihood of loss as being only reasonably possible or remote), we could be responsible for significant costs and expenses that are not currently included in our estimates and accruals. In addition, for any potential losses that we regard as probable and for which we have accrued an estimate of the potential losses, our estimates regarding damages, legal fees, court costs and interest could turn out to be inaccurate and the actual losses we incur could be significantly higher than the amounts included in our estimates and accruals. Also, the amount of time it takes for us to resolve all of the current and future lawsuits and claims that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated. 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 nine months ended September 30, 2025, we did not recognize any costs related to the Line 901 incident. During the nine months ended September 30, 2024, we recognized costs, net of amounts probable of recovery from insurance (as applicable) of $120 million. As of September 30, 2025 and December 31, 2024, we had a remaining undiscounted gross liability of approximately $3 million and $5 million, respectively, related to the Line 901 incident, which aggregate amounts are reflected in “Current liabilities” on our Condensed Consolidated Balance Sheet.

We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such liabilities. To date, we have collected approximately $275 million of the $500 million available under our 2015 insurance program. We have submitted insurance claims seeking reimbursement for additional legal fees and settlements relating to the Line 901 incident. Such claims, in the aggregate, exceed the $215 million of insurance coverage remaining under the 2015 program. Since we lack certainty at this time as to if or when these claims will be reimbursed by the carriers, we have elected not to accrue for a receivable in connection with these claims. As such, with respect to the Line 901 incident, we do not have any amounts recorded as receivables that are recognized on our Condensed Consolidated Balance Sheets as of September 30, 2025 and December 31, 2024.

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

L48 Pipeline Release. In March of 2025, our subsidiary, Pacific Pipeline System LLC, experienced a crude oil release of approximately 125 barrels on a segment of the Line 48 pipeline in Carson, California. Clean-up and remediation activities were conducted in cooperation with applicable state and federal regulatory agencies. An investigation by the California Office of the State Fire Marshall is not complete. To date no charges, fines or penalties have been assessed against us with respect to this release; however, it is possible that charges, fines or penalties may be assessed against us in the future. We provided notification to our applicable insurance carriers and intend to pursue reimbursement of any costs incurred in excess of our $10 million self-insured retention. We estimate that the aggregate cost to clean-up and remediate the site will be approximately $20 million. Through September 30, 2025, we incurred $12 million in connection with clean-up and remediation activities.

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

Louisiana Coastal Erosion Lawsuit. Various coastal parishes, the State of Louisiana and some of its departments have filed lawsuits in Louisiana against a number of energy companies seeking damages for coastal erosion in connection with oil and gas operations in Louisiana. One of our subsidiaries has been named in such a lawsuit filed by The Louisiana Department of Wildlife and Fisheries (“LADWF”). LADWF filed a lawsuit in the 24th Judicial District Court of Jefferson Parish, Louisiana on October 30, 2023 against our subsidiary, Plains Pipeline, L.P., Chevron Pipe Line Company, BP Oil Pipeline Company and Arrowhead Gulf Coast Pipeline, LLC (collectively, “Defendants”), as the former and current parties to certain pipeline right of way agreements (“ROWs”) in the vicinity of the Elmer Island Wildlife Refuge. LADWF alleges that the Defendants breached the terms of the ROWs by failing to prevent erosion and seeks restoration of the Wildlife Refuge or alternatively monetary compensatory damages including restoration costs, legal fees and disgorgement of profits derived from the alleged trespass. Our subsidiary owned and operated a pipeline in the vicinity of the refuge from 2006 through 2016. In October 2025, the court limited the time period for which LADWF may pursue damages to the period of its ownership of the subject property, which began in 2014. We believe the claims in the lawsuit lack merit and intend to vigorously defend this lawsuit in coordination with the other Defendants.

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Note 11—Segment Information

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

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

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

Segment Adjusted EBITDA excludes depreciation and amortization. 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 made to replace and/or refurbish partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as maintenance capital, which is deducted in determining “available cash.” Maintenance capital is reviewed by our CODM on a segment basis. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are charged to expense as incurred. Assets are not reviewed by our CODM on a segmented basis; therefore, such information is not presented.

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


	Crude Oil		NGL		Intersegment Elimination		Total
Three Months Ended September 30, 2025
Revenues (1):
Product sales	$	11,132	$	22	$	(4)	$	11,150
Services	427		2		(1)		428
Total revenues	11,559		24		(5)		11,578

Significant segment expenses:
Purchases and related costs (1)	(10,572)		(18)		5		(10,585)
Field operating costs	(281)		(7)		—		(288)
Segment general and administrative expenses	(74)		(9)		—		(83)
Total significant segment expenses	(10,927)		(34)		5		(10,956)

Equity earnings in unconsolidated entities	96		—

Other segment items (2):
Depreciation and amortization of unconsolidated entities (3)	21		—
Derivative activities and inventory valuation adjustments (4)	(30)		—
Long-term inventory costing adjustments (5)	10		—
Deficiencies under minimum volume commitments, net (6)	(6)		—
Equity-indexed compensation expense (7)	10		—
Foreign currency revaluation (8)	(3)		—


Segment amounts attributable to noncontrolling interests (10)	(137)		—
Total other segment items	(135)		—

Segment Adjusted EBITDA	$	593	$	(10)

Investment and acquisition capital expenditures (11) (12)	$	305	$	—			$	305
Maintenance capital expenditures (12)	$	36	$	—			$	36

As of September 30, 2025
Investments in unconsolidated entities	$	2,873	$	—			$	2,873

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	Crude Oil		NGL		Intersegment Elimination		Total
Nine Months Ended September 30, 2025
Revenues (1):
Product sales	$	32,313	$	88	$	(12)	$	32,389
Services	1,307		4		(2)		1,309
Total revenues	33,620		92		(14)		33,698

Significant segment expenses:
Purchases and related costs (1)	(30,802)		(74)		14		(30,862)
Field operating costs	(853)		(20)		—		(873)
Segment general and administrative expenses	(229)		(22)		—		(251)
Total significant segment expenses	(31,884)		(116)		14		(31,986)

Equity earnings in unconsolidated entities	292		—

Other segment items (2):
Depreciation and amortization of unconsolidated entities (3)	62		—
Derivative activities and inventory valuation adjustments (4)	(2)		—
Long-term inventory costing adjustments (5)	27		—
Deficiencies under minimum volume commitments, net (6)	(21)		—
Equity-indexed compensation expense (7)	28		—
Foreign currency revaluation (8)	6		—

Transaction-related expenses (9)	7		—
Segment amounts attributable to noncontrolling interests (10)	(402)		—
Total other segment items	(295)		—

Segment Adjusted EBITDA	$	1,733	$	(24)

Investment and acquisition capital expenditures (11) (12)	$	1,308	$	—			$	1,308
Maintenance capital expenditures (12)	$	110	$	2			$	112

As of September 30, 2025
Investments in unconsolidated entities	$	2,873	$	—			$	2,873

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	Crude Oil		NGL		Intersegment Elimination		Total
Three Months Ended September 30, 2024
Revenues (1):
Product sales	$	12,009	$	19	$	(7)	$	12,021
Services	435		1		(1)		435
Total revenues	12,444		20		(8)		12,456

Significant segment expenses:
Purchases and related costs (1)	(11,529)		(19)		8		(11,540)
Field operating costs	(400)		(8)		—		(408)
Segment general and administrative expenses	(78)		(8)		—		(86)
Total significant segment expenses	(12,007)		(35)		8		(12,034)

Equity earnings in unconsolidated entities	97		—

Other segment items (2):
Depreciation and amortization of unconsolidated entities (3)	22		—
Derivative activities and inventory valuation adjustments (4)	(13)		—
Long-term inventory costing adjustments (5)	34		—
Deficiencies under minimum volume commitments, net (6)	15		—
Equity-indexed compensation expense (7)	9		—
Foreign currency revaluation (8)	2		—
Line 901 incident (13)	120		—

Segment amounts attributable to noncontrolling interests (10)	(146)		—
Total other segment items	43		—

Segment Adjusted EBITDA	$	577	$	(15)

Investment and acquisition capital expenditures (11) (12)	$	106	$	—			$	106
Maintenance capital expenditures (12)	$	48	$	2			$	50

As of December 31, 2024
Investments in unconsolidated entities	$	2,811	$	—			$	2,811

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	Crude Oil		NGL		Intersegment Elimination		Total
Nine Months Ended September 30, 2024
Revenues (1):
Product sales	$	35,515	$	103	$	(12)	$	35,606
Services	1,246		3		(1)		1,248
Total revenues	36,761		106		(13)		36,854

Significant segment expenses:
Purchases and related costs (1)	(34,014)		(85)		13		(34,086)
Field operating costs	(938)		(24)		—		(962)
Segment general and administrative expenses	(223)		(23)		—		(246)
Total significant segment expenses	(35,175)		(132)		13		(35,294)

Equity earnings in unconsolidated entities	298		—

Other segment items (2):
Depreciation and amortization of unconsolidated entities (3)	59		—
Derivative activities and inventory valuation adjustments (4)	20		—
Long-term inventory costing adjustments (5)	10		—
Deficiencies under minimum volume commitments, net (6)	10		—
Equity-indexed compensation expense (7)	28		—
Foreign currency revaluation (8)	(18)		—
Line 901 incident (13)	120		—

Segment amounts attributable to noncontrolling interests (10)	(406)		—
Total other segment items	(177)		—

Segment Adjusted EBITDA	$	1,707	$	(26)

Investment and acquisition capital expenditures (11) (12)	$	367	$	—			$	367
Maintenance capital expenditures (12)	$	135	$	5			$	140

As of December 31, 2024
Investments in unconsolidated entities	$	2,811	$	—			$	2,811

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

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

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

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

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

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

(7)Our total equity-indexed compensation expense includes expense associated with awards that will be settled in 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 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for a discussion regarding our equity-indexed compensation plans.

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

(9)Primarily related to acquisitions completed during the first nine months of 2025. See Note 12 for information regarding these transactions.

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

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

(12)These amounts combined represent total capital expenditures.

(13)Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. See Note 10 for additional information regarding the Line 901 incident.

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Segment Adjusted EBITDA Reconciliation

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Segment Adjusted EBITDA	$	583	$	562	$	1,709	$	1,681
Total other segment items (1)	135		(43)		295		177
Depreciation and amortization	(230)		(226)		(696)		(675)
(Gains)/losses on asset sales, net	92		—		64		(2)
Gain on investments in unconsolidated entities, net	—		—		31		—
Interest expense, net	(135)		(113)		(395)		(318)
Other income, net	14		26		70		45
Income from continuing operations before tax	459		206		1,078		908
Income tax expense from continuing operations	(6)		(8)		(17)		(71)
Income from continuing operations, net of tax	$	453	$	198	$	1,061	$	837

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

Note 12— Acquisitions

Ironwood Midstream

Ironwood Midstream. On January 31, 2025, we acquired Ironwood Midstream Energy Partners II, LLC (“Ironwood Midstream”), which owns a gathering system in the Eagle Ford Basin, for approximately $481 million in cash from EnCap Flatrock Midstream. The Ironwood Midstream acquisition is accounted for in our Crude Oil segment. In January 2025, in a separate transaction, we also repurchased from EnCap Flatrock Midstream, a portion of our outstanding Series A preferred units. EnCap Flatrock Midstream is affiliated with EnCap Investments, L.P., an entity that is associated with a member of the board of directors of PAGP GP. See Note 7 for additional information.

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


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

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

The fair value of intangible asset is comprised of customer relationships that will be amortized over their useful lives, which have a remaining weighted average life of approximately 16 years. The value assigned to such intangible asset will be amortized to earnings under the declining balance method of amortization. Amortization expense was approximately $1 million and $3 million during the three and nine months ended September 30, 2025, respectively, and the future amortization expense for the remainder of 2025 through 2029 is estimated as follows (in millions):


Remainder of 2025	$	1
2026	$	5
2027	$	4
2028	$	3
2029	$	3

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.

Other Acquisitions

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

Cheyenne Pipeline. In February 2025, through a non-monetary transaction, we acquired the remaining 50% interest in Cheyenne Pipeline LLC (“Cheyenne”) in exchange for the termination of certain obligations. The transaction resulted in a net gain of approximately $31 million, which represents the difference between the fair value of the entity and the historical book value of our investment. This gain is reflected in “Gain on investments in unconsolidated entities, net” on our Condensed Consolidated Statement of Operations. Prior to this transaction, our 50% interest in Cheyenne was accounted for as an equity method investment, reported in our Crude Oil segment.

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

BridgeTex Pipeline. In July 2025, we acquired an additional 20% interest in BridgeTex Pipeline Company, LLC (“BridgeTex”) for approximately $180 million. As a result of this transaction, we now own a 40% interest in BridgeTex and continue to account for our interest in BridgeTex, which is reported in our Crude Oil segment, as an equity method investment.

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EPIC Pipeline. On October 31, 2025, we purchased an aggregate 55% equity interest in EPIC Crude Holdings, LP (“EPIC Crude Holdings”), which owns the EPIC Crude Oil Pipeline (“EPIC Pipeline”), from subsidiaries of Diamondback Energy, Inc. and Kinetik Holdings Inc., for approximately $1.57 billion, subject to certain adjustments and inclusive of approximately $600 million of debt assumed. We also agreed to a potential earnout payment of $193 million contingent upon the formal sanctioning before the end of 2027 of one or more expansions of EPIC Pipeline that in the aggregate will increase the capacity of the pipeline to at least 900,000 barrels per day. In a separate transaction, effective November 1, 2025, we acquired the remaining 45% equity interest in EPIC Crude Holdings from a portfolio company of Ares Private Equity funds for approximately $1.33 billion, subject to certain adjustments and inclusive of approximately $500 million of debt assumed. We also agreed to a potential earnout payment to the seller of up to $157 million depending on the timing and amount of incremental expansion capacity up to 300,000 barrels per day in excess of 650,000 barrels per day that is formally sanctioned before the end of 2028.

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

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical Consolidated Financial Statements and accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations as presented in our 2024 Annual Report on Form 10-K. For more detailed information regarding the basis of presentation for the following financial information, see the Condensed Consolidated Financial Statements and related notes that are contained in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Our discussion and analysis includes the following:

•Executive Summary

•Results of Operations

•Liquidity and Capital Resources

•Recent Accounting Pronouncements

•Forward-Looking Statements

Executive Summary

Company Overview

Pending Sale of Canadian NGL Business

On June 17, 2025, we entered into a definitive SPA with Keyera, pursuant to which Keyera agreed to acquire all of the issued and outstanding shares of Plains Midstream Canada ULC, our wholly-owned subsidiary that owns substantially all of the Canadian NGL Business. This transaction supports our strategic objective to focus on our core midstream crude oil operations and to reduce exposure to commodity price fluctuations and seasonality. While we will divest the Canadian NGL Business as part of the sale, we will retain substantially all NGL assets in the United States and will also retain all crude oil assets in Canada. This transaction is expected to close in the first quarter of 2026, subject to the satisfaction or waiver of customary closing conditions, including receipt of regulatory approvals. We determined that in conjunction with entering into the SPA, the operations of the Canadian NGL Business meet the criteria for classification as held for sale and for discontinued operations reporting, as the sale will represent a strategic shift that will have a major effect on our operations and financial results. We have applied these changes retrospectively to all periods presented. See Note 1 and Note 2 to our Condensed Consolidated Financial Statements for additional information.

Unless otherwise indicated, the discussion below relates to our continuing operations and excludes amounts related to discontinued operations.

Overview of Operating Results

We recognized net income attributable to PAA of $1.093 billion for the nine months ended September 30, 2025 compared to net income attributable to PAA of $736 million for the first nine months of 2024. See the “Results of Operations” section below for discussion of significant drivers of our results from continuing operations.

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Results of Operations

Consolidated Results

The following table sets forth an overview of our consolidated financial results calculated in accordance with GAAP (in millions, except per unit data):


	Three Months Ended September 30,				Variance				Nine Months Ended September 30,				Variance
	2025		2024		$		%		2025		2024		$		%
Product sales revenues	$	11,150	$	12,021	$	(871)	(7)	%	$	32,389	$	35,606	$	(3,217)	(9)	%
Services revenues	428		435		(7)		(2)	%	1,309		1,248		61		5	%
Purchases and related costs	(10,585)		(11,540)		955		8	%	(30,862)		(34,086)		3,224		9	%
Field operating costs	(288)		(408)		120		29	%	(873)		(962)		89		9	%
General and administrative expenses	(83)		(86)		3		3	%	(251)		(246)		(5)

PLAINS ALL AMERICAN PIPELINE LP 10-Q