Plains All American Pipeline - 10-Q quarterly report FY

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Table of Contents

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 March 31, 2026

☐ 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	The Nasdaq Global Select Market

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 May 1, 2026, there were 705,531,683 Common Units outstanding.

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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 March 31 , 202 6 and December 31, 202 5			3
Condensed Consolidated Statements of Operations: For the three months ended March 31 , 202 6 and 202 5			4
Condensed Consolidated Statements of Comprehensive Income: For the three months ended March 31 , 202 6 and 202 5			5
Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss): For the three months ended March 31 , 202 6 and 202 5			5
Condensed Consolidated Statements of Cash Flows: For the three months ended Mar ch 31 , 202 6 and 202 5			6
Condensed Consolidated Statements of Changes in Partners’ Capital: For the three months ended Mar ch 31 , 202 6 and 202 5			7
Notes to the Condensed Consolidated Financial Statements:
1. Organization and Basis of Consolidation and Presentation			8

2. Discontinued Operations			11
3. Revenues and Accounts Receivable			12
4. Net Income Per Common Unit			15
5. Inventory, Linefill and Long-term Inventory			17
6. Debt			18
7. Partners’ Capital and Distributions			19
8. Derivatives and Risk Management Activities			21
9. Related Party Transactions			24
10. Commitments and Contingencies			25
11. Segment Information			28


Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			33
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			52
Item 4. CONTROLS AND PROCEDURES			53

PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS			54
Item 1A. RISK FACTORS			54
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			54
Item 3. DEFAULTS UPON SENIOR SECURITIES			54
Item 4. MINE SAFETY DISCLOSURES			54
Item 5. OTHER INFORMATION			54
Item 6. EXHIBITS			55
SIGNATURES			59

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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)


	March 31, 2026		December 31, 2025
	(unaudited)
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	171	$	328

Trade accounts receivable and other receivables, net	4,821		3,598
Inventory	380		211
Current assets of discontinued operations (Note 2)	602		479
Other current assets	190		117
Total current assets	6,164		4,733

PROPERTY AND EQUIPMENT	22,687		22,536
Accumulated depreciation	(5,814)		(5,676)
Property and equipment, net	16,873		16,860

OTHER ASSETS
Investments in unconsolidated entities	2,838		2,846
Intangible assets, net	1,686		1,754
Linefill	876		900
Long-term operating lease right-of-use assets, net	197		198
Long-term inventory	315		214
Long-term assets of discontinued operations (Note 2)	2,537		2,557
Other long-term assets, net	150		107
Total assets	$	31,636	$	30,169

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES
Trade accounts payable	$	4,929	$	3,457
Short-term debt	420		563
Current liabilities of discontinued operations (Note 2)	561		382
Other current liabilities	634		529
Total current liabilities	6,544		4,931

LONG-TERM LIABILITIES
Senior notes, net	9,120		9,118
Other long-term debt, net	1,836		1,578
Long-term operating lease liabilities	202		202
Long-term liabilities of discontinued operations (Note 2)	665		606
Other long-term liabilities and deferred credits	449		654
Total long-term liabilities	12,272		12,158

COMMITMENTS AND CONTINGENCIES (NOTE 10)

PARTNERS’ CAPITAL
Series A preferred unitholders (58,411,908 and 58,411,908 units outstanding, respectively)	1,249		1,248
Series B preferred unitholders (800,000 and 800,000 units outstanding, respectively)	787		787
Common unitholders (705,531,683 and 705,520,697 units outstanding, respectively)	7,565		7,801
Total partners’ capital excluding noncontrolling interests	9,601		9,836
Noncontrolling interests	3,219		3,244
Total partners’ capital	12,820		13,080
Total liabilities and partners’ capital	$	31,636	$	30,169

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 OPERATIONS

(in millions, except per unit data)


	Three Months Ended March 31,
	2026		2025
	(unaudited)
REVENUES
Product sales revenues	$	12,026	$	11,046
Services revenues	444		431
Total revenues	12,470		11,477
COSTS AND EXPENSES
Purchases and related costs	11,493		10,517
Field operating costs	301		300
General and administrative expenses	81		85
Depreciation and amortization	243		232
Gains on asset sales and other, net	(53)		(13)
Total costs and expenses	12,065		11,121
OPERATING INCOME	405		356
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	89		103
Gain on investments in unconsolidated entities, net	—		31
Interest expense (net of capitalized interest of $2 and $2, respectively)	(167)		(127)
Other income, net	8		26

INCOME FROM CONTINUING OPERATIONS BEFORE TAX	335		389
Current income tax expense from continuing operations	(216)		(7)
Deferred income tax (expense)/benefit from continuing operations	215		(2)
INCOME FROM CONTINUING OPERATIONS, NET OF TAX	334		380




INCOME/(LOSS) FROM DISCONTINUED OPERATIONS, NET OF TAX (NOTE 2)	(103)		136
NET INCOME	231		516
Net income attributable to noncontrolling interests	(79)		(73)
NET INCOME ATTRIBUTABLE TO PAA	$	152	$	443

NET INCOME/(LOSS) PER COMMON UNIT (NOTE 4):
Net income/(loss) allocated to common unitholders — Basic and Diluted:
Continuing operations	$	203	$	207
Discontinued operations	(103)		136
Net income allocated to common unitholders — Basic and Diluted	$	100	$	343

Basic and diluted weighted average common units outstanding	706		704

Basic and diluted net income/(loss) per common unit:
Continuing operations	$	0.29	$	0.30
Discontinued operations	(0.15)		0.19
Basic and diluted net income per common unit	$	0.14	$	0.49

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 COMPREHENSIVE INCOME

(in millions)


	Three Months Ended March 31,
	2026		2025
	(unaudited)
Net income	$	231	$	516
Other comprehensive income/(loss)	(49)		5
Comprehensive income	182		521
Comprehensive income attributable to noncontrolling interests	(79)		(73)
Comprehensive income attributable to PAA	$	103	$	448

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, 2025	$	(29)	$	(872)	$	5	$	(896)

Reclassification adjustments	1		—		—		1

Currency translation adjustments	—		(50)		—		(50)

Total period activity	1		(50)		—		(49)
Balance at March 31, 2026	$	(28)	$	(922)	$	5	$	(945)


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

Reclassification adjustments	1		—		1
Unrealized loss on hedges	(1)		—		(1)
Currency translation adjustments	—		5		5

Total period activity	—		5		5
Balance at March 31, 2025	$	(44)	$	(1,034)	$	(1,078)

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)


	Three Months Ended March 31,
	2026		2025
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	231	$	516
Reconciliation of net income to net cash provided by operating activities:
(Income)/loss from discontinued operations, net of tax	103		(136)
Depreciation and amortization	243		232
Gains on asset sales and other, net	(53)		(13)


Deferred income tax expense/(benefit)	(215)		2




Equity earnings in unconsolidated entities	(89)		(103)
Distributions on earnings from unconsolidated entities	97		125
Gain on investments in unconsolidated entities, net	—		(31)
Other	29		19
Changes in assets and liabilities, net of acquisitions	54		(182)
Cash provided by operating activities - continuing operations	400		429
Cash provided by operating activities - discontinued operations	18		210
Net cash provided by operating activities	418		639

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	(88)		(624)

Additions to property, equipment and other	(130)		(140)
Cash paid for purchases of linefill	(2)		(6)
Proceeds from sales of assets	3		3


Investments in related party notes	—		(330)

Cash used in investing activities - continuing operations	(217)		(1,097)
Cash used in investing activities - discontinued operations	(16)		(52)
Net cash used in investing activities	(233)		(1,149)

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings under commercial paper program (Note 6)	116		71



Proceeds from the issuance of senior notes (Note 6)	—		998

Proceeds from the issuance of related party notes	—		330


Repurchase of Series A preferred units	—		(333)
Distributions paid to Series A preferred unitholders (Note 7)	(36)		(46)
Distributions paid to Series B preferred unitholders (Note 7)	(17)		(18)
Distributions paid to common unitholders (Note 7)	(295)		(267)
Distributions paid to noncontrolling interests (Note 7)	(103)		(132)
Contributions from noncontrolling interests	—		4


Other financing activities	(4)		(17)


Net cash provided by/(used in) financing activities	(339)		590

Effect of translation adjustment - continuing operations	(3)		(1)


Net increase/(decrease) in cash and cash equivalents and restricted cash	(157)		79
Cash and cash equivalents and restricted cash, beginning of period	328		348
Cash and cash equivalents and restricted cash, end of period	$	171	$	427

Cash paid for:
Interest, net of amounts capitalized	$	183	$	128
Income taxes, net of amounts refunded	$	28	$	27

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, 2025	$	1,248	$	787	$	7,801	$	9,836	$	3,244	$	13,080
Net income	36		16		100		152		79		231
Distributions (Note 7)	(36)		(16)		(295)		(347)		(103)		(450)
Other comprehensive loss	—		—		(49)		(49)		—		(49)



Other	1		—		8		9		(1)		8
Balance at March 31, 2026	$	1,249	$	787	$	7,565	$	9,601	$	3,219	$	12,820


	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	39		18		386		443		73		516
Distributions	(39)		(18)		(267)		(324)		(132)		(456)
Other comprehensive income	—		—		5		5		—		5
Repurchase of Series A preferred units	(270)		—		(43)		(313)		—		(313)

Contributions from noncontrolling interests	—		—		—		—		4		4
Other	1		—		7		8		—		8
Balance at March 31, 2025	$	1,245	$	787	$	7,600	$	9,632	$	3,228	$	12,860

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 publicly-traded 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 March 31, 2026, 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 March 31, 2026, 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 (“PMC 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 us, our 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


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

FASB	=	Financial Accounting Standards Board
GAAP	=	Generally accepted accounting principles in the United States
ICE	=	Intercontinental Exchange
ISDA	=	International Swaps and Derivatives Association




NGL	=	Natural gas liquids, including ethane, propane and butane
NYMEX	=	New York Mercantile Exchange

SEC	=	United States Securities and Exchange Commission
SOFR	=	Secured Overnight Financing Rate
TWh	=	Terawatt hour
U.S.	=	United States
USD	=	U.S. dollar

Basis of Consolidation and Presentation

The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our 2025 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. Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise.

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, 2025 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three months ended March 31, 2026 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.

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 PMC 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 May 2026.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

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

In June 2025, we entered into a forward currency instrument to hedge currency exchange risk associated with anticipated proceeds from the pending sale of our Canadian NGL Business. See Note 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 May 2026, based on existing contracts to be transferred and current market conditions as of March 31, 2026, we would recognize a liability of approximately $15 million.

Additionally, in connection with the pending Canadian NGL Business divestiture, we have continued to progress certain planning and restructuring activities within our organizational structure. Certain of these activities had income tax consequences that required recognition during the first quarter of 2026. PMC ULC contributed its crude oil assets to a newly formed, wholly-owned subsidiary, Plains Canada Liquid Pipelines ULC (“PCLP”). While this transaction is among entities under common control and recorded at a carry-over basis under GAAP, the applicable Canadian tax law recognizes the transaction at fair value, resulting in a new tax basis to PCLP as of March 31, 2026. Therefore, the transaction creates current tax expense of approximately $216 million as a result of basis recapture and capital gains taxed at the applicable rates. The transaction also created an approximately offsetting deferred tax benefit primarily resulting from the new tax basis in the assets received by PCLP. Since the transaction relates to our crude oil business, the tax impacts are presented in “Current income tax expense from continuing operations” and “Deferred income tax (expense)/benefit from continuing operations,” respectively, on our Condensed Consolidated Statements of Operations. Should the Canadian NGL Business divestiture not close due to unforeseen circumstances, we will evaluate options available to us under Canadian tax law that would materially reverse the current income tax expense and deferred income tax benefit described herein. Plans for certain future activities were finalized in the quarter and required recognition of tax expense that is presented within “Income from Discontinued Operations, Net of Tax” on our Condensed Consolidated Statements of Operations and is further discussed in Note 2.

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 2025 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the three months ended March 31, 2026 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):


	March 31, 2026		December 31, 2025
Assets:
Current assets:

Trade accounts receivable and other receivables, net	$	435	$	285
Inventory	102		176
Other current assets	65		18
Total current assets of discontinued operations	$	602	$	479

Long-term assets:
Property and equipment, net (1)	$	2,167	$	2,191

Linefill	76		70
Long-term operating lease right-of-use assets, net	136		138
Long-term inventory	39		38
Other long-term assets, net	119		120
Total long-term assets of discontinued operations	$	2,537	$	2,557

Liabilities:
Current liabilities:
Trade accounts payable	$	450	$	295

Other current liabilities	111		87
Total current liabilities of discontinued operations	$	561	$	382

Long-term liabilities:

Long-term operating lease liabilities	$	90	$	96
Other long-term liabilities and deferred credits	575		510
Total long-term liabilities of discontinued operations	$	665	$	606

(1)Amounts are net of accumulated depreciation of $862 million and $876 million as of March 31, 2026 and December 31, 2025, respectively.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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


	Three Months Ended March 31,
	2026		2025
Revenues:
Product sales	$	256	$	498
Services	38		36
Total revenues	294		534
Cost and Expenses:
Purchases and related costs	205		244
Field operating costs	71		68
General and administrative expenses	14		15
Depreciation and amortization	—		30
Losses on asset sales and other, net	32		—
Total costs and expenses	322		357

Income/(loss) from discontinued operations before tax	(28)		177
Current income tax expense	(44)		(39)
Deferred income tax expense	(31)		(2)
Income/(loss) from discontinued operations, net of tax	$	(103)	$	136

In connection with the planning and restructuring activities, we recorded deferred tax expense and a related liability of $77 million associated with the pending Canadian NGL Business divestiture, which is reflected within discontinued operations.

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 March 31,
	2026		2025
Crude Oil segment revenues from contracts with customers
Sales	$	12,012	$	11,008
Transportation	338		312
Terminalling, Storage and Other	94		88
Total Crude Oil segment revenues from contracts with customers	$	12,444	$	11,408

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Three Months Ended March 31,
	2026		2025
NGL segment revenues from contracts with customers
Sales	$	39	$	41

Terminalling, Storage and Other	2		—
Total NGL segment revenues from contracts with customers	$	41	$	41

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 (as described above for each segment) to total revenues of reportable segments and total revenues as disclosed in our Condensed Consolidated Statements of Operations (in millions):


Three Months Ended March 31, 2026	Crude Oil		NGL		Total
Revenues from contracts with customers	$	12,444	$	41	$	12,485
Other revenues	104		—		104
Total revenues of reportable segments	$	12,548	$	41	$	12,589
Intersegment revenues elimination					(119)
Total revenues					$	12,470

Three Months Ended March 31, 2025	Crude Oil		NGL		Total
Revenues from contracts with customers	$	11,408	$	41	$	11,449
Other revenues	31		—		31
Total revenues of reportable segments	$	11,439	$	41	$	11,480
Intersegment revenues elimination					(3)
Total revenues					$	11,477

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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	March 31, 2026		December 31, 2025
Billed and collected	Other current liabilities	$	23	$	47

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, 2025	$	87
Amounts recognized as revenue	(19)

Additions	5
Other (1)	(26)
Balance at March 31, 2026	$	47

(1)Amount represents a contract liability that was originally recognized under ASC 606. The underlying contract was subsequently renegotiated and ceased to meet the criteria in ASC 606 for a contract with a customer.

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 March 31, 2026 (in millions):


	Remainder of 2026		2027		2028		2029		2030		2031 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	296	$	363	$	326	$	230	$	152	$	837
Terminalling, storage and other agreement revenues	185		216		156		112		75		426
Total	$	481	$	579	$	482	$	342	$	227	$	1,263

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

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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 March 31, 2026 and December 31, 2025, 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):


	March 31, 2026		December 31, 2025
Trade accounts receivable arising from revenues from contracts with customers	$	5,408	$	3,639
Other trade accounts receivable and other receivables (1)	11,314		7,357
Impact due to contractual rights of offset with counterparties	(11,901)		(7,398)
Trade accounts receivable and other receivables, net	$	4,821	$	3,598

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

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 or loss from discontinued operations by the basic and diluted weighted average number of common units outstanding during the period.

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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 12 and Note 18 to our Consolidated Financial Statements included in Part IV of our 2025 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, the possible conversion of approximately 58 million and 63 million Series A preferred units, on a weighted-average basis, were excluded from the calculation of diluted net income per common unit for the three months ended March 31, 2026 and 2025, respectively, 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.

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 March 31,
	2026		2025
Basic and Diluted Net Income/(Loss) per Common Unit
Continuing Operations:
Income from continuing operations, net of tax	$	334	$	380
Net income attributable to noncontrolling interests	(79)		(73)
Net income from continuing operations attributable to PAA	255		307
Distributions to Series A preferred unitholders	(36)		(39)
Distributions to Series B preferred unitholders	(16)		(18)
Amounts allocated to participating securities	(1)		(1)
Impact from repurchase of Series A preferred units (1)	—		(43)
Other	1		1
Net income from continuing operations allocated to common unitholders - Basic and Diluted (2)	$	203	$	207

Discontinued Operations:
Net income/(loss) from discontinued operations allocated to common unitholders - Basic and Diluted (3)	$	(103)	$	136

Net income allocated to common unitholders — Basic and Diluted	$	100	$	343

Basic and diluted weighted average common units outstanding	706		704

Basic and diluted net income/(loss) per common unit:
Continuing operations	$	0.29	$	0.30
Discontinued operations	(0.15)		0.19
Basic and diluted net income per common unit	$	0.14	$	0.49

(1)We repurchased approximately 12.7 million Series A preferred units on January 31, 2025. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2025 Annual Report on Form 10-K 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 from continuing operations allocated to common unitholders.

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(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/(loss) from discontinued operations allocated to common unitholders is “Income/(loss) from discontinued operations, net of tax” as presented on our Condensed Consolidated Statements of Operations.

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):


	March 31, 2026						December 31, 2025
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	4,452	barrels	$	350	$	78.62	2,948	barrels	$	166	$	56.31
NGL	318	barrels	15		$	48.05	562	barrels	27		$	48.04

Other	N/A		15		N/A		N/A		18		N/A
Inventory subtotal			380						211

Linefill
Crude oil	14,834	barrels	875		$	58.99	15,112	barrels	898		$	59.42
NGL	32	barrels	1		$	39.97	33	barrels	2		$	60.61

Linefill subtotal			876						900

Long-term inventory
Crude oil	3,484	barrels	312		$	89.55	3,724	barrels	213		$	57.20
NGL	51	barrels	3		$	45.91	26	barrels	1		$	38.46
Long-term inventory subtotal			315						214

Total			$	1,571					$	1,325

(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):


	March 31, 2026		December 31, 2025
SHORT-TERM DEBT
Commercial paper notes, bearing a weighted-average interest rate of 4.1% and 3.9%, respectively (1)	$	411	$	554



Other	9		9
Total short-term debt	420		563

LONG-TERM DEBT
Senior notes, net of unamortized discounts and debt issuance costs of $63 and $65, respectively (2)	9,120		9,118
Commercial paper notes, bearing a weighted-average interest rate of 4.1% and 3.9%, respectively (3)	675		416
Term loan, net of debt issuance costs of $1 and $1, respectively, and bearing a weighted-average interest rate of 4.8% and 5.0%, respectively (4)	1,099		1,099
Other	62		63
Total long-term debt	10,956		10,696
Total debt (5)	$	11,376	$	11,259

(1)We classified these commercial paper notes as short-term as of March 31, 2026 and December 31, 2025, 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 March 31, 2026 and December 31, 2025, we classified our $750 million, 4.50% senior notes due December 2026 as long-term based on our ability and intent to refinance the notes on a long-term basis.

(3)As of March 31, 2026 and December 31, 2025, we classified a portion of our commercial paper notes as long-term based on our ability and intent to refinance such amounts on a long-term basis.

(4)The closing of the Canadian NGL Business divestiture will trigger mandatory prepayment of all amounts outstanding under the term loan agreement within seven business days of the closing of such divestiture. See Note 1 for additional information about the pending Canadian NGL Business divestiture.

(5)Our fixed-rate senior notes had a face value of approximately $9.2 billion at both March 31, 2026 and December 31, 2025. We estimated the aggregate fair value of these notes as of March 31, 2026 and December 31, 2025 to be approximately $8.9 billion and $9.0 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 and our term loan approximate fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, commercial paper program and term loan are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

Borrowings and Repayments

Total borrowings under our credit facilities and commercial paper program for the three months ended March 31, 2026 and 2025 were approximately $26.5 billion and $12.9 billion, respectively. Total repayments under our commercial paper program were approximately $26.4 billion and $12.8 billion for the three months ended March 31, 2026 and 2025, 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 March 31, 2026 and December 31, 2025, we had outstanding letters of credit of $118 million and $95 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, 2025	58,411,908	800,000	705,520,697

Issuances of common units under equity-indexed compensation plans	—	—	10,986
Outstanding at March 31, 2026	58,411,908	800,000	705,531,683


	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

Distributions to Our Unitholders

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 12 to our Consolidated Financial Statements included in Part IV of our 2025 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 three months of 2026 (in millions, except per unit data):


			Series A Preferred Unitholders
Distribution Payment Date	Record Date (1)	Distribution Period	Cash Distribution		Distribution per Unit


May 15, 2026 (2)	May 1, 2026	January 1, 2026 through March 31, 2026	$	36	$	0.615
February 13, 2026	January 30, 2026	October 1, 2025 through December 31, 2025	$	36	$	0.615

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

(2)At March 31, 2026, such amount was accrued as distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

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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 (or the immediately succeeding Business Day). See Note 12 to our Consolidated Financial Statements included in Part IV of our 2025 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


May 15, 2026 (2)	May 1, 2026	February 15, 2026 through May 14, 2026	$	16	$	19.84
February 17, 2026	February 2, 2026	November 15, 2025 through February 14, 2026	$	17	$	21.02

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

(2)At March 31, 2026, approximately $8 million of accrued distributions payable to our Series B preferred unitholders was included in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

Common Unit Distributions. The following table details distributions to our common unitholders paid during or pertaining to the first three months of 2026 (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


May 15, 2026	May 1, 2026	January 1, 2026 through March 31, 2026	$	198	$	97	$	295	$	0.4175
February 13, 2026	January 30, 2026	October 1, 2025 through December 31, 2025	$	198	$	97	$	295	$	0.4175

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

Noncontrolling Interests in Subsidiaries

As of March 31, 2026, 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 March 31,
	2026		2025
Permian JV	$	84	$	105
Cactus II	15		22
Red River	4		5
	$	103	$	132

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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.

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 March 31, 2026 and December 31, 2025, 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 March 31, 2026, net derivative positions related to these activities included:

•A net long position of 11.4 million barrels associated with our crude oil purchases, which will be unwound ratably through June 2026 to match monthly average pricing.

•A net short time spread position of 2.9 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through July 2026.

•A net crude oil basis spread position of 1.6 million barrels at multiple locations through March 2027. These derivatives allow us to lock in grade and location basis differentials.

•A net short position of 9.5 million barrels through December 2029 related to anticipated net sales of crude oil inventory.

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

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


	Three Months Ended March 31,
	2026		2025
Product sales revenues	$	88	$	(1)
Field operating costs	1		(2)

Net gain/(loss) from commodity derivative activity	$	89	$	(3)

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):


	March 31, 2026		December 31, 2025
Initial margin	$	82	$	16
Variation margin posted/(returned)	(152)		4
Letters of credit	(18)		(1)
Net broker receivable/(payable)	$	(88)	$	19

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.


	March 31, 2026								December 31, 2025
					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	$	247	$	(103)	$	(88)	$	56	$	18	$	(24)	$	19	$	13
Other long-term assets, net	1		—		—		1		1		—		—		1
Derivative Liabilities
Other current liabilities	—		(17)		—		(17)		(1)		—		—		(1)
Other long-term liabilities and deferred credits	6		(4)		—		2		10		(8)		—		2
Total	$	254	$	(124)	$	(88)	$	42	$	28	$	(32)	$	19	$	15

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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.

As of March 31, 2026, there was a net loss of $28 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.

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


	Three Months Ended March 31,
	2026		2025
Interest rate derivatives, net	$	—	$	(1)

At March 31, 2026 and December 31, 2025, we did not have any interest rate hedges recorded on our Condensed Consolidated Balance Sheets.

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 March 31, 2026, the sale of the Canadian NGL Business is probable and the fair value of the instrument is an asset of $61 million, presented in “Other current assets” on our Condensed Consolidated Balance Sheet. For the three months ended March 31, 2026, we recognized a gain of $53 million, which was included in “Gains on asset sales and other, net” on our Condensed Consolidated Statements of Operations. As of March 31, 2026, 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 $1.39. 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 March 31, 2026						Fair Value as of December 31, 2025
Recurring Fair Value Measures (1)	Level 1		Level 2		Total			Level 1		Level 2		Total
Commodity derivatives	$	99	$	31	$	130		$	(2)	$	(2)	$	(4)

Foreign currency derivatives	—		61		61			—		8		8

Total net derivative asset/(liability)	$	99	$	92	$	191		$	(2)	$	6	$	4

(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.

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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 17 to our Consolidated Financial Statements included in Part IV of our 2025 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

We and certain Plains entities have issued promissory notes to facilitate financing. Our outstanding related party notes receivable and related party notes payable balances were as follows (in millions):


	March 31, 2026		December 31, 2025
Related party notes receivable (1)	$	1,317	$	1,339
Related party notes payable (1)	$	1,317	$	1,339

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

Accrued and unpaid interest receivable/payable was $7 million and $30 million as of March 31, 2026 and December 31, 2025, respectively. Interest income/expense on the related party notes totaled $23 million and $20 million for the three months ended March 31, 2026 and 2025, respectively.

Transactions with Other Related Parties

During the three months ended March 31, 2026 and 2025, 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 March 31,
	2026		2025
Revenues from related parties	$	13	$	11

Purchases and related costs from related parties	$	74	$	97

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


	March 31, 2026		December 31, 2025
Trade accounts receivable and other receivables, net from related parties (1)	$	33	$	49

Trade accounts payable to related parties (1) (2)	$	51	$	64

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

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

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.

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.

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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):


	March 31, 2026		December 31, 2025
Other current liabilities	$	8	$	13
Other long-term liabilities and deferred credits	66		70
Total	$	74	$	83

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 March 31, 2026, 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.

During the three months ended March 31, 2026 and 2025, we did not recognize any costs related to the Line 901 incident. As of March 31, 2026 and December 31, 2025, we had a remaining undiscounted gross liability of approximately $23 million and $22 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 $295 million of the $500 million available under our 2015 insurance program. With respect to the Line 901 incident, we do not have any amounts recorded as receivables that are recognized on our Condensed Consolidated Balance Sheets as of March 31, 2026 and December 31, 2025.

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. The only 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 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 $15 million. Through March 31, 2026, we incurred $12 million in connection with clean-up and remediation activities.

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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 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 March 31, 2026
Revenues (1):
Product sales	$	12,106	$	39	$	(119)	$	12,026
Services	442		2		—		444
Total revenues	12,548		41		(119)		12,470

Significant segment expenses:
Purchases and related costs (1)	(11,579)		(33)		119		(11,493)
Field operating costs	(291)		(10)		—		(301)
Segment general and administrative expenses	(76)		(5)		—		(81)
Total significant segment expenses	(11,946)		(48)		119		(11,875)

Equity earnings in unconsolidated entities	89		—

Other segment items (2):
Depreciation and amortization of unconsolidated entities (3)	20		—
Derivative activities and inventory valuation adjustments (4)	130		—
Long-term inventory costing adjustments (5)	(112)		—
Deficiencies under minimum volume commitments, net (6)	(32)		—
Equity-indexed compensation expense (7)	10		—
Foreign currency revaluation (8)	(4)		—


Segment amounts attributable to noncontrolling interests (9)	(121)		—
Total other segment items	(109)		—

Segment Adjusted EBITDA	$	582	$	(7)

Investment and acquisition capital expenditures (10) (11)	$	171	$	—			$	171
Maintenance capital expenditures (11)	$	35	$	—			$	35

As of March 31, 2026
Investments in unconsolidated entities	$	2,838	$	—			$	2,838

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	Crude Oil		NGL		Intersegment Elimination		Total
Three Months Ended March 31, 2025
Revenues (1):
Product sales	$	11,008	$	41	$	(3)	$	11,046
Services	431		—		—		431
Total revenues	11,439		41		(3)		11,477

Significant segment expenses:
Purchases and related costs (1)	(10,488)		(32)		3		(10,517)
Field operating costs	(292)		(8)		—		(300)
Segment general and administrative expenses	(79)		(6)		—		(85)
Total significant segment expenses	(10,859)		(46)		3		(10,902)

Equity earnings in unconsolidated entities	103		—

Other segment items (2):
Depreciation and amortization of unconsolidated entities (3)	20		—
Derivative activities and inventory valuation adjustments (4)	(24)		—

Deficiencies under minimum volume commitments, net (6)	(7)		—
Equity-indexed compensation expense (7)	9		—


Transaction-related expenses (12)	5		—
Segment amounts attributable to noncontrolling interests (9)	(127)		—
Total other segment items	(124)		—

Segment Adjusted EBITDA	$	559	$	(5)

Investment and acquisition capital expenditures (10) (11)	$	785	$	—			$	785
Maintenance capital expenditures (11)	$	31	$	2			$	33

As of December 31, 2025
Investments in unconsolidated entities	$	2,846	$	—			$	2,846

(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 18 to our Consolidated Financial Statements included in Part IV of our 2025 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)Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River.

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

(11)These amounts combined represent total capital expenditures.

(12)Primarily related to deal-specific costs incurred during the periods presented.

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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 March 31,
	2026		2025
Segment Adjusted EBITDA	$	575	$	554
Total other segment items (1)	109		124
Depreciation and amortization	(243)		(232)
Gains on asset sales and other, net	53		13
Gain on investments in unconsolidated entities, net	—		31
Interest expense, net	(167)		(127)
Other income, net	8		26
Income from continuing operations before tax	335		389
Income tax expense from continuing operations	(1)		(9)
Income from continuing operations, net of tax	$	334	$	380

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

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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 2025 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. We will divest the Canadian NGL Business as part of the sale, which includes substantially all of our NGL assets; the NGL assets that we will retain are located in the United States. This transaction is expected to close in May 2026. 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 $152 million for the three months ended March 31, 2026 compared to net income attributable to PAA of $443 million for the first three months of 2025. 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 March 31,				Variance
	2026		2025		$		%
Product sales revenues	$	12,026	$	11,046	$	980	9	%
Services revenues	444		431		13		3	%
Purchases and related costs	(11,493)		(10,517)		(976)		(9)	%
Field operating costs	(301)		(300)		(1)		—	%
General and administrative expenses	(81)		(85)		4		5	%
Depreciation and amortization	(243)		(232)		(11)		(5)	%
Gains on asset sales and other, net	53		13		40		308	%
Equity earnings in unconsolidated entities	89		103		(14)		(14)	%
Gain on investments in unconsolidated entities, net	—		31		(31)		(100)	%
Interest expense, net (1)	(167)		(127)		(40)		(31)	%
Other income, net (1)	8		26		(18)		(69)	%
Income tax expense from continuing operations	(1)		(9)		8		89	%
Income from continuing operations, net of tax	334		380		(46)		(12)	%


Income/(loss) from discontinued operations, net of tax	(103)		136		(239)		(176)	%
Net income	231		516		(285)		(55)	%
Net income attributable to noncontrolling interests	(79)		(73)		(6)		(8)	%
Net income attributable to PAA	$	152	$	443	$	(291)	(66)	%

Basic and diluted net income/(loss) per common unit:
Continuing operations	$	0.29	$	0.30	$	(0.01)	(3)	%
Discontinued operations	(0.15)		0.19		(0.34)		(179)	%
Basic and diluted net income per common unit	$	0.14	$	0.49	$	(0.35)	(71)	%

Basic and diluted weighted average common units outstanding	706		704		2		—	%

(1)“Interest expense, net” and “Other income, net” each include $23 million for the three months ended March 31, 2026 and $20 million for the three months ended March 31, 2025 related to interest on promissory notes by and among us and certain Plains entities.

(2)See Note 2 to our Condensed Consolidated Financial Statements for a reconciliation of the line items comprising income/(loss) from discontinued operations, net of tax.

Continuing Operations

The following discussion of our results of operations focuses on our continuing operations.

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Revenues and Purchases

Fluctuations in our revenues and purchases and related costs are primarily associated with our merchant activities and are generally explained by changes in commodity prices and the impact of gains and losses related to derivative instruments used to manage our commodity price exposure. Because both product sales revenues and purchases and related costs are generally based off of the same pricing indices, the market price of the commodities will not necessarily have an impact on the absolute margins related to those sales and purchases.

A majority of our crude oil sales and purchases are indexed to the prompt month price of the NYMEX Light, Sweet crude oil futures contract (“NYMEX Price”). The following table presents the range of the NYMEX Price over the last two years (in dollars per barrel):


	NYMEX Price
	Low		High		Average
Three Months Ended March 31, 2026	$	56	$	105	$	73
Three Months Ended March 31, 2025	$	66	$	80	$	71

Product sales revenues (including the impact of derivative mark-to-market valuations) and purchases increased for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to higher crude oil sales volumes and commodity prices in the 2026 period.

Services revenues for the three months ended March 31, 2026 increased compared to the same period in 2025 primarily due to the impact of recently completed acquisitions, including our acquisition of the Cactus III pipeline in the fourth quarter of 2025, partially offset by the impact from certain Permian long-haul pipeline contract rates resetting to market during 2025.

See further discussion of net revenues (defined as revenues less purchases and related costs) in the “—Analysis of Operating Segments” section below.

Field Operating Costs

See discussion of field operating costs in the “—Analysis of Operating Segments” section below.

General and Administrative Expenses

The decrease in general and administrative expenses for the three months ended March 31, 2026 compared to the same period in 2025 was primarily due to (i) the recognition in the 2025 period of acquisition-related transaction costs and (ii) lower information systems costs in the 2026 period primarily due to the completion of certain systems conversion and integration work.

Depreciation and Amortization

The increase in depreciation and amortization for the three months ended March 31, 2026 compared to the same period in 2025 was largely driven by recently completed acquisitions.

Gains on Asset Sales and Other, Net

In connection with the pending sale of the Canadian NGL Business, we entered into a deal-contingent forward currency instrument to hedge the currency exchange risk associated with the sale in CAD. The 2026 period was impacted by the mark-to-market of this instrument. See Note 8 to our Condensed Consolidated Financial Statements for additional information regarding this instrument and our derivatives and hedging activities. See Note 1 to our Condensed Consolidated Financial Statements for additional information regarding the pending sale of the Canadian NGL Business.

Equity Earnings

See discussion of Equity earnings in unconsolidated entities in the “—Analysis of Operating Segments” section below.

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Gain on Investments in Unconsolidated Entities, Net

In the first quarter of 2025, we recognized a gain of $31 million related to our acquisition of the remaining 50% interest in Cheyenne Pipeline LLC through a non-monetary transaction.

Interest Expense, Net and Other Income, Net

For the three months ended March 31, 2026 and 2025, “Interest expense, net” and “Other income, net” each include interest expense and interest income associated with promissory notes payable and receivable by and among us and certain Plains entities. These amounts are excluded from our non-GAAP performance measures Adjusted EBITDA and Implied DCF. As such, the interest expense and interest income associated with these notes are presented on a net basis in the reconciliation of these metrics to Net Income. See the “—Non-GAAP Financial Measures” section below.

The following table summarizes the components impacting Interest expense, net (in millions):


	Three Months Ended March 31,
	2026		2025
Interest expense on third-party borrowings (1)	$	146	$	109
Interest expense on related party promissory notes (2)	23		20
Capitalized interest	(2)		(2)
	$	167	$	127

(1)The increase in interest expense for the three-month 2026 period compared to the same period in 2025 was primarily driven by higher weighted-average debt outstanding in the 2026 period from (i) the issuance of an aggregate of $3.0 billion of senior notes during 2025 and (ii) higher commercial paper and term loan borrowings in the 2026 period, primarily related to the funding of the Cactus III acquisition in November 2025, partially offset by (iii) the repayment of $1.0 billion of senior notes in October 2025. See Note 6 to our Condensed Consolidated Financial Statements for additional information regarding our outstanding debt.

(2)Represents interest expense associated with promissory notes by and among us and certain Plains entities, as described above.

The following table summarizes the components impacting Other income, net (in millions):


	Three Months Ended March 31,
	2026		2025
Interest income on related party promissory notes (1)	$	23	$	20

Net loss on foreign currency revaluation (2)	(12)		—



Contingent consideration fair value adjustment (3)	(6)		—
Other	3		6
	$	8	$	26

(1)Represents interest income associated with promissory notes by and among us and certain Plains entities, as described above.

(2)The activity during the periods presented was primarily related to the impact from the change in the CAD to USD exchange rate on the portion of our intercompany net investment that is not long-term in nature.

(3)Represents the change in the estimated fair value during the period of certain potential earnout payments primarily associated with our Cactus III acquisition.

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Income Tax Expense from Continuing Operations

The net favorable income tax variance for the three months ended March 31, 2026 compared to the same period in 2025 was primarily due to lower income within our Canadian operations as impacted by fluctuations of derivative mark-to-market valuations. In addition, tax expense was impacted by our continued progression of certain planning and restructuring activities within our organizational structure in connection with the pending Canadian NGL Business divestiture. Certain of these activities had income tax consequences that required recognition during the first quarter of 2026, including (i) current income tax expense of $216 million as a result of basis recapture and capital gains taxed at the applicable rates and (ii) an approximately offsetting deferred tax benefit primarily resulting from the transfer of the crude oil assets from PMC ULC to PCLP. See Note 1 to our Condensed Consolidated Financial Statements for additional information.

Non-GAAP Financial Measures

To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future and to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. The primary additional measures used by management are Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied distributable cash flow (“DCF”), Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions.

Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF are reconciled to Net Income, and Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions are reconciled to Net Cash Provided by Operating Activities, the most directly comparable measures as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our Condensed Consolidated Financial Statements and accompanying notes. See “—Liquidity and Capital Resources—Non-GAAP Financial Liquidity Measures” for additional information regarding Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions.

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Non-GAAP Financial Performance Measures

Adjusted EBITDA is defined as earnings from continuing operations and discontinued operations before (i) interest expense, (ii) income tax (expense)/benefit from continuing operations and discontinued operations, (iii) depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, of unconsolidated entities) from continuing operations and discontinued operations, (iv) gains and losses on asset sales, asset impairments and other, net from continuing operations and discontinued operations, (v) gains on investments in unconsolidated entities, net and (vi) interest income on promissory notes by and among us and certain Plains entities, and (vii) adjusted for certain selected items impacting comparability. Adjusted EBITDA attributable to PAA excludes the portion of Adjusted EBITDA that is attributable to noncontrolling interests.

Management believes that the presentation of Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF provides useful information to investors regarding our performance and results of operations because these measures, when used to supplement related GAAP financial measures, (i) provide additional information about our operating performance and ability to fund distributions to our unitholders through cash generated by our operations, (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions and (iii) present measures that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These non-GAAP financial performance measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) 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, (iii) long-term inventory costing adjustments, (iv) items that are not indicative of our operating results and/or (v) other items that we believe should be excluded in understanding our operating performance. These measures may further be adjusted to include amounts related to deficiencies associated with minimum volume commitments whereby we have billed the counterparties for their deficiency obligation and such amounts are recognized as deferred revenue in “Other current liabilities” in our Condensed Consolidated Financial Statements. We also adjust for amounts billed by our equity method investees related to deficiencies under minimum volume commitments. Such amounts are presented net of applicable amounts subsequently recognized into revenue. We have defined all such items as “selected items impacting comparability.” We do not necessarily consider all of our selected items impacting comparability to be non-recurring, infrequent or unusual, but we believe that an understanding of these selected items impacting comparability is material to the evaluation of our operating results and prospects.

Although we present selected items impacting comparability that management considers in evaluating our performance, you should also be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions, divestitures, investment capital projects and numerous other factors as discussed, as applicable, in “—Analysis of Operating Segments.”

Discontinued Operations. Management believes that the presentation of certain Non-GAAP financial performance measures, such as Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied DCF, and certain Non-GAAP financial liquidity measures, such as Adjusted Free Cash Flow and Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities), on a consolidated basis (e.g., the aggregate of continuing operations and discontinued operations) provides more relevant and useful information regarding our performance and results of operations than presenting such metrics only on a continuing operations or discontinued operations basis. In addition, as the potential sale of the Canadian NGL Business is not anticipated to close until May 2026, management continues to view the Canadian NGL Business as a component of our overall company performance and ability to fund distributions to our unitholders in the near term.

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The following tables set forth the reconciliation of the non-GAAP financial performance measures Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF to Net Income (in millions):


	Three Months Ended March 31,				Variance
	2026		2025		$		%
Net income (1)	$	231	$	516	$	(285)	(55)	%
Interest expense, net of certain items (2)	144		107		37		35	%
Income tax expense from continuing operations	1		9		(8)		(89)	%
Income tax expense from discontinued operations (3)	75		41		34		83	%
Depreciation and amortization from continuing operations	243		232		11		5	%
Depreciation and amortization from discontinued operations (3)	—		30		(30)		(100)	%
Gains on asset sales and other, net from continuing operations	(53)		(13)		(40)		(308)	%
Losses on asset sales and other, net from discontinued operations (3)	32		—		32		N/A
Gain on investments in unconsolidated entities, net	—		(31)		31		100	%
Depreciation and amortization of unconsolidated entities (4)	20		20		—		—	%
Selected Items Impacting Comparability (1):
Derivative activities and inventory valuation adjustments	289		(34)		323		**
Long-term inventory costing adjustments	(114)		(3)		(111)		**
Deficiencies under minimum volume commitments, net	(32)		(7)		(25)		**
Rail fleet amortization expense related to discontinued operations (5)	(7)		—		(7)		**
Equity-indexed compensation expense	10		9		1		**
Foreign currency revaluation	(6)		—		(6)		**

Transaction-related expenses	—		5		(5)		**

Selected Items Impacting Comparability - Segment Adjusted EBITDA (1) (6)	140		(30)		170		**

Foreign currency revaluation (7)	13		—		13		**
Contingent consideration fair value adjustment (8)	6		—		6		**

Selected Items Impacting Comparability - Adjusted EBITDA (1) (9)	159		(30)		189		**
Adjusted EBITDA (1) (9)	$	852	$	881	$	(29)	(3)	%
Adjusted EBITDA attributable to noncontrolling interests (10)	(122)		(127)		5		4	%
Adjusted EBITDA attributable to PAA (1)	$	730	$	754	$	(24)	(3)	%

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	Three Months Ended March 31,				Variance
	2026		2025		$		%
Adjusted EBITDA (1) (9) (11)	$	852	$	881	$	(29)	(3)	%
Interest expense, net of certain non-cash and other items (12)	(140)		(104)		(36)		(35)	%
Maintenance capital from continuing operations (13)	(35)		(33)		(2)		(6)	%
Maintenance capital from discontinued operations (13)	(11)		(8)		(3)		(38)	%
Investment capital of noncontrolling interests (14)	(24)		(30)		6		20	%
Current income tax expense from continuing operations, net of certain tax effects related to the pending Canadian NGL Business divestiture (15)	—		(7)		7		100	%
Current income tax expense from discontinued operations (3)	(44)		(39)		(5)		(13)	%
Distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings (16)	(11)		(2)		(9)		**
Distributions to noncontrolling interests (17)	(103)		(132)		29		22	%
Implied DCF (1)	$	484	$	526	$	(42)	(8)	%
Preferred unit distributions (17)	(53)		(64)		11		17	%
Implied DCF Available to Common Unitholders (1)	$	431	$	462	$	(31)	(7)	%
Common unit cash distributions (17)	(295)		(267)
Implied DCF Excess (1) (18)	$	136	$	195

** Indicates that variance as a percentage is not meaningful.

(1)Includes results from continuing operations and discontinued operations.

(2)Represents “Interest expense, net” as reported on our Condensed Consolidated Statements of Operations, net of interest income associated with promissory notes by and among us and certain Plains entities.

(3)See Note 2 to our Condensed Consolidated Financial Statements for additional information.

(4)We exclude our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities when reviewing Adjusted EBITDA, similar to our consolidated assets.

(5)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. Management believes that the presentation of Adjusted EBITDA and Implied DCF on a consolidated basis (e.g., the aggregate of continuing operations and discontinued operations) provides more relevant and useful information regarding our performance and results of operations than presenting such metrics only on a continuing operations or discontinued operations basis. We therefore include an adjustment for the impact of amortization of the rail fleet associated with the Canadian NGL Business in our calculation of Adjusted EBITDA. See Note 1 to our Condensed Consolidated Financial Statements for additional information regarding the pending sale of the Canadian NGL Business. Also see the “—Non-GAAP Financial Measures” section above.

(6)For a more detailed discussion of these selected items impacting comparability, see the footnotes to the segment financial data tables in Note 11 to our Condensed Consolidated Financial Statements.

(7)During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability.

(8)We agreed to potential earnout payments associated with recently completed acquisitions, primarily our Cactus III acquisition. We consider the non-cash change in the estimated fair value of such earnout payments as a selected item impacting comparability.

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(9)“Other income, net” on our Condensed Consolidated Statements of Operations, excluding interest income associated with promissory notes by and among us and certain Plains entities, adjusted for selected items impacting comparability (“Adjusted other income, net”) is included in Adjusted EBITDA and excluded from Segment Adjusted EBITDA.

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

(11)See the table above for a reconciliation from Net Income to Adjusted EBITDA.

(12)Amount excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps and is net of interest income associated with promissory notes by and among us and certain Plains entities.

(13)Maintenance capital expenditures are defined as capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets.

(14)Investment capital expenditures attributable to noncontrolling interests that reduce Implied DCF available to PAA common unitholders.

(15)For the three months ended March 31, 2026, amount excludes approximately $216 million of current income tax expense associated with certain planning and restructuring activities within our organizational structure in connection with the pending Canadian NGL Business divestiture that had income tax consequences that required recognition during the first quarter of 2026. See Note 1 to our Condensed Consolidated Financial Statements for additional information.

(16)Comprised of cash distributions received from unconsolidated entities less equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization, including write-downs related to cancelled projects, and selected items impacting comparability of unconsolidated entities).

(17)Cash distributions paid during the period presented.

(18)Excess DCF is retained to establish reserves for debt repayment, future distributions, common equity repurchases, capital expenditures and other partnership purposes.

Analysis of Operating Segments

We manage our operations through two operating segments: Crude Oil and NGL. Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA. See Note 11 to our Condensed Consolidated Financial Statements for our definition of Segment Adjusted EBITDA and a reconciliation of Segment Adjusted EBITDA to Income from Continuing Operations, Net of Tax. See Note 20 to our Consolidated Financial Statements included in Part IV of our 2025 Annual Report on Form 10-K for our definition of maintenance capital.

Crude Oil Segment

Our Crude Oil segment operations generally consist of gathering and transporting crude oil using pipelines (including gathering systems), trucks and, at times, on barges or railcars, in addition to providing terminalling, storage and other related services utilizing our integrated assets across the United States and Canada. Our assets provide services to third parties as well as to our merchant activities. Our merchant activities include the purchase of crude oil supply and the movement of this supply on our assets or third-party assets to sales locations, including our terminals, third-party connecting carriers, regional hubs or to refineries. Our merchant activities are governed by our risk management policies.

Our Crude Oil segment generates revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees, month-to-month and multi-year storage and terminalling agreements and the sale of gathered and bulk-purchased crude oil. Tariffs and other fees on our pipeline systems are typically based on volumes transported and vary by receipt point and delivery point. Fees for our terminalling and storage services are based on capacity leases and throughput volumes. Generally, results from our merchant activities are impacted by (i) increases or decreases in our lease gathering crude oil purchases volumes and (ii) volatility in commodity price differentials, particularly grade and location differentials, as well as time spreads. The segment results also include the direct fixed and variable field costs of operating the crude oil assets, as well as an allocation of indirect operating and general and administrative costs.

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The following tables set forth our operating results from our Crude Oil segment:


Operating Results (1)	Three Months Ended March 31,				Variance
(in millions)	2026		2025		$		%
Revenues	$	12,548	$	11,439	$	1,109	10	%
Purchases and related costs	(11,579)		(10,488)		(1,091)		(10)	%
Field operating costs	(291)		(292)		1		—	%
Segment general and administrative expenses (2)	(76)		(79)		3		4	%
Equity earnings in unconsolidated entities	89		103		(14)		(14)	%

Other segment items (3):
Depreciation and amortization of unconsolidated entities	20		20		—		**
Derivative activities and inventory valuation adjustments	130		(24)		154		**
Long-term inventory costing adjustments	(112)		—		(112)		**
Deficiencies under minimum volume commitments, net	(32)		(7)		(25)		**
Equity-indexed compensation expense	10		9		1		**
Foreign currency revaluation	(4)		—		(4)		**

Transaction-related expenses	—		5		(5)		**
Segment amounts attributable to noncontrolling interests	(121)		(127)		6		**
Segment Adjusted EBITDA	$	582	$	559	$	23	4	%

Maintenance capital expenditures	$	35	$	31	$	4	13	%


	Three Months Ended March 31,		Variance
Average Volumes	2026	2025	Volumes	%

Crude oil pipeline tariff (by region) (4) (5)
Permian Basin	7,774	6,869	905	13	%
South Texas / Eagle Ford	514	492	22	4	%
Mid-Continent	475	415	60	14	%




Other	1,276	1,310	(34)	(3)	%
Total crude oil pipeline tariff	10,039	9,086	953	10	%

** Indicates that variance as a percentage is not meaningful.

(1)Revenues and costs and expenses include intersegment amounts.

(2)Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.

(3)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 11 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.

(4)Average daily volumes in thousands of barrels per day calculated as the total volumes (attributable to our interest for assets owned by unconsolidated entities or through undivided joint interests) for the period divided by the number of days in the period. Volumes associated with acquisitions represent total volumes for the number of days we actually owned the assets divided by the number of days in the period.

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(5)Includes volumes (attributable to our interest) from assets owned by unconsolidated entities.

Segment Adjusted EBITDA

Crude Oil Segment Adjusted EBITDA for the three months ended March 31, 2026 increased versus comparable results for the three months ended March 31, 2025. The benefit to the 2026 period results from (i) contributions from recently completed acquisitions and (ii) volume growth across our pipeline systems was partially offset by (iii) the impact from certain Permian long-haul contract rates resetting to market in 2025.

The following is a more detailed discussion of the significant factors impacting Segment Adjusted EBITDA for the three months ended March 31, 2026 compared to the same periods in 2025.

Net Revenues and Equity Earnings. Our results were favorably impacted by (i) contributions from recently completed acquisitions in the Permian Basin and South Texas regions, including our Cactus III acquisition completed in the fourth quarter of 2025, and (ii) volume growth across our pipeline systems largely driven by increased production in the Permian Basin region. These favorable impacts were partially offset by (iii) the impact from certain Permian long-haul contract rates resetting to market in 2025, including on certain of our equity method investments.

Field Operating Costs. Field operating costs were relatively flat for the three months ended March 31, 2026 compared to the same period in 2025. The impact to the 2026 period from (i) lower environmental remediation expense and (ii) lower employee-related costs and fuel expenses associated with the divestiture of certain trucking operations was mostly offset by (iii) incremental operating costs associated with recently completed acquisitions.

Maintenance Capital

The increase in maintenance capital spending for the three months ended March 31, 2026 compared to the same period in 2025 was primarily due to higher costs resulting from timing of certain pipeline integrity activities.

NGL Segment

Our NGL segment operations involve NGL storage and terminalling from our NGL assets located in the United States. Our NGL segment revenues are primarily derived from (i) providing storage and/or terminalling services at these facilities to third-party customers for a fee and (ii) the transport, storage and sale of specification NGL products. The segment results also include the direct fixed and variable field costs of operating our four NGL facilities, as well as an allocation of indirect operating costs and general and administrative expenses.

The following table sets forth our operating results from our NGL segment:


Operating Results (1)	Three Months Ended March 31,				Variance
(in millions)	2026		2025		$		%
Revenues	$	41	$	41	$	—	—	%
Purchases and related costs	(33)		(32)		(1)		(3)	%
Field operating costs (2)	(10)		(8)		(2)		(25)	%
Segment general and administrative expenses (2) (3)	(5)		(6)		1		17	%







Segment Adjusted EBITDA	$	(7)	$	(5)	$	(2)	(40)	%

Maintenance capital expenditures	$	—	$	2	$	(2)	(100)	%

(1)Revenues and costs and expenses include intersegment amounts.

(2)Field operating costs and segment general and administrative expenses include certain costs that are part of the overhead of continuing operations.

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(3)Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.

Segment Adjusted EBITDA

NGL Segment Adjusted EBITDA loss for the period presented was largely driven by costs that are part of the overhead of our NGL activities and are included in continuing operations as they are not related to contracts or arrangements that will be included in the sale of the Canadian NGL Business. These costs include information technology, insurance and other shared services costs.

Liquidity and Capital Resources

General

Our primary sources of liquidity are (i) cash flow from operating activities and (ii) borrowings under our credit facilities or commercial paper program. In addition, we may supplement these primary sources of liquidity with proceeds from asset sales, and in the past have utilized funds received from sales of equity and debt securities. Our primary cash requirements include, but are not limited to, (i) ordinary course of business uses, such as the payment of amounts related to the purchase of crude oil, NGL and other products, payment of other expenses and interest payments on outstanding debt, (ii) investment and maintenance capital activities, (iii) acquisitions of assets or businesses, (iv) repayment of principal on our long-term debt and (v) distributions to our unitholders and noncontrolling interests. In addition, we may use cash for repurchases of common equity. We generally expect to fund our short-term cash requirements through cash flow generated from operating activities and/or borrowings under our credit facilities or commercial paper program. In addition, we generally expect to fund our long-term needs, such as those resulting from investment capital activities, acquisitions or refinancing our long-term debt, through a variety of sources, which may include any or a combination of the sources listed above.

As of March 31, 2026, although we had a working capital deficit of $380 million, we had approximately $1.8 billion of liquidity available to meet our ongoing operating, investing and financing needs, subject to continued covenant compliance, as noted below (in millions):


	As of March 31, 2026
Availability under senior unsecured revolving credit facility (1) (2)	$	1,350
Availability under senior secured hedged inventory facility (1) (2)	1,344
Amounts outstanding under commercial paper program	(1,086)
Subtotal	1,608
Cash and cash equivalents	171
Total	$	1,779

(1)Represents availability prior to giving effect to borrowings outstanding under our commercial paper program, which reduce available capacity under our credit facilities.

(2)Available capacity under our senior unsecured revolving credit facility and senior secured hedged inventory facility was reduced by outstanding letters of credit issued under these facilities of less than $1 million and $6 million, respectively.

Usage of our credit facilities, and, in turn, our commercial paper program, is subject to ongoing compliance with covenants. The credit agreements for our revolving credit facilities (which impact our ability to access our commercial paper program because they provide the financial backstop that supports our short-term credit ratings), the term loan and the indentures governing our senior notes contain cross-default provisions. A default under our credit agreements, term loan or indentures would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with the provisions in our credit agreements and term loan agreement, our ability to make distributions of available cash is not restricted. We were in compliance with the covenants contained in our credit agreements, term loan and indentures as of March 31, 2026.

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We believe that we have, and will continue to have, the ability to access our commercial paper program and credit facilities, which we use to meet our short-term cash needs. We believe that our financial position remains strong and we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow, including extended disruptions in the financial markets and/or energy price volatility resulting from current macroeconomic and geopolitical conditions, including actions by the Organization of Petroleum Exporting Countries (OPEC). A prolonged material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity and cost of borrowing. Our borrowing capacity and borrowing costs are also impacted by our credit rating. See Item 1A. “Risk Factors” included in our 2025 Annual Report on Form 10-K for further discussion regarding risks that may impact our liquidity and capital resources.

Non-GAAP Financial Liquidity Measures

Management uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. Adjusted Free Cash Flow is defined as Net cash provided by operating activities, less Net cash provided by/(used in) investing activities, which primarily includes acquisition, investment and maintenance capital expenditures, investments in unconsolidated entities and related party notes and the impact from the purchase and sale of linefill, net of proceeds from the sales of assets and further impacted by distributions to and contributions from noncontrolling interests and proceeds from the issuance of related party notes. Adjusted Free Cash Flow is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Adjusted Free Cash Flow after Distributions. Also see “Results of Operations—Non-GAAP Financial Measures” above for more information about our non-GAAP measures.

The following table sets forth the reconciliation of the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions from Net Cash Provided by Operating Activities and includes results from continuing operations and discontinued operations for all periods presented (in millions):


	Three Months Ended March 31,
		2026		2025
Net cash provided by operating activities		$	418	$	639
Adjustments to reconcile net cash provided by operating activities to adjusted free cash flow:
Net cash used in investing activities (1)		(233)		(1,149)
Cash contributions from noncontrolling interests		—		4
Cash distributions paid to noncontrolling interests (2)		(103)		(132)
Proceeds from the issuance of related party notes (1)		—		330

Adjusted Free Cash Flow		$	82	$	(308)
Cash distributions (3)		(348)		(331)
Adjusted Free Cash Flow after Distributions (4)		$	(266)	$	(639)

(1)Certain Plains entities have issued promissory notes by and among such entities to facilitate financing. “Proceeds from the issuance of related party notes” has an equal and offsetting cash outflow associated with our investment in related party notes, which is included as a component of “Net cash used in investing activities.” See Note 9 to our Condensed Consolidated Financial Statements for additional information on our related party notes.

(2)Cash distributions paid during the period presented.

(3)Cash distributions paid to our preferred and common unitholders during the period presented.

(4)Excess Adjusted Free Cash Flow after Distributions is retained to establish reserves for future distributions, capital expenditures, debt reduction and other partnership purposes. Adjusted Free Cash Flow after Distributions shortages, if any, may be funded from previously established reserves, cash on hand or from borrowings under our credit facilities or commercial paper program.

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Cash Flow from Operating Activities

For a comprehensive discussion of the primary drivers of cash flow from operating activities, including the impact of varying market conditions and the timing of settlement of our derivatives, see Item 7. “Liquidity and Capital Resources—Cash Flow from Operating Activities” included in our 2025 Annual Report on Form 10-K.

Net cash provided by operating activities from continuing operations for the first three months of 2026 and 2025 was $400 million and $429 million, respectively, and primarily resulted from earnings from our operations. In addition, both periods were also impacted by changes in net operating working capital items, while the 2026 period was impacted by higher margin requirements related to our hedging activities.

Investing Activities

Capital Expenditures

In addition to our operating needs, we also use cash for our investment capital projects, maintenance capital activities and acquisition activities. We fund these expenditures with cash generated by operating activities, financing activities and/or proceeds from asset sales. In the near term, we do not plan to issue common equity to fund such expenditures. The following table summarizes our investment, maintenance and acquisition capital expenditures related to continuing operations and discontinued operations (in millions):


	Net to PAA (1) (2)				Consolidated (2)				Continuing Operations
	Three Months Ended March 31,				Three Months Ended March 31,				Three Months Ended March 31,
Capital Expenditures (3) (4)	2026		2025		2026		2025		2026		2025
Crude Oil:
Investment capital	$	58	$	89	$	83	$	120	$	83	$	120
Maintenance capital	30		28		35		31		35		31
Acquisition capital	88		613		88		665		88		665
	$	176	$	730	$	206	$	816	$	206	$	816

NGL:
Investment capital	$	3	$	41	$	3	$	41	$	—	$	—
Maintenance capital	11		10		11		10		—		2

	$	14	$	51	$	14	$	51	$	—	$	2

Total:
Investment capital	$	61	$	130	$	86	$	161	$	83	$	120
Maintenance capital	41		38		46		41		35		33
Acquisition capital	88		613		88		665		88		665
	$	190	$	781	$	220	$	867	$	206	$	818

(1)Excludes expenditures attributable to noncontrolling interests, which primarily relate to the Permian JV. Includes results from continuing operations and discontinued operations for all periods presented.

(2)Includes results from continuing operations and discontinued operations for all periods presented. Capital expenditures related to discontinued operations were $3 million and $11 million for investment and maintenance capital for the three months ended March 31, 2026, respectively. Capital expenditures for investment and maintenance capital related to discontinued operations were $41 million and $8 million for the three months ended March 31, 2025, respectively. There was no investment capital or acquisition capital related to discontinued operations for any period presented.

(3)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.”

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(4)Contributions to unconsolidated entities, accounted for under the equity method of accounting, that are related to investment capital projects by such entities are recognized in “Investment capital.” Acquisitions of initial investments or additional interests in unconsolidated entities are included in “Acquisition capital.”

Projected 2026 Capital Expenditures. Total investment capital for the year ending December 31, 2026 is currently projected to be approximately $440 million ($350 million net to our interest), which includes approximately $15 million related to discontinued operations. Approximately half of our projected investment capital expenditures are expected to be invested in the Permian JV assets. Additionally, maintenance capital for 2026 is currently projected to be approximately $205 million ($185 million net to our interest), which includes approximately $30 million related to discontinued operations. Note that potential variation to current capital cost estimates may result from (i) changes to project design, (ii) final cost of materials and labor, (iii) timing of incurrence of costs due to uncontrollable factors such as receipt of permits or regulatory approvals and weather and (iv) timely closing of the Canadian NGL Business divestiture.

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 PMC ULC, our wholly-owned subsidiary that owns substantially all of the Canadian NGL Business. This transaction is expected to close in May 2026. We expect to receive net proceeds from the sale of approximately $3.3 billion, after taxes and expenses. Any proceeds from the pending sale of the Canadian NGL Business will be used to reduce leverage, including outstanding borrowings under our commercial paper program and term loan. See Note 1 to our Condensed Consolidated Financial Statements for additional information regarding the pending sale of the Canadian NGL Business.

Ongoing Activities Related to Strategic Transactions

We are continuously engaged in the evaluation of potential transactions that support our current business strategy. In the past, such transactions have included the acquisition of assets that complement our existing footprint, the sale of non-core assets, the sale of partial interests in assets to strategic joint venture partners, and large investment capital projects. With respect to a potential acquisition or divestiture, we may conduct an auction process or participate in an auction process conducted by a third-party or we may negotiate a transaction with one or a limited number of potential sellers (in the case of an acquisition) or buyers (in the case of a divestiture). Such transactions could have a material effect on our financial condition and results of operations.

We typically do not announce a transaction until after we have executed a definitive agreement. In certain cases, in order to protect our business interests or for other reasons, we may defer public announcement of a transaction until closing or a later date. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future efforts with respect to any such transactions will be successful, and we can provide no assurance that our financial expectations with respect to such transactions will ultimately be realized. See Item 1A. “Risk Factors—Risks Related to Our Business—Acquisitions and divestitures involve risks that may adversely affect our business” included in our 2025 Annual Report on Form 10-K.

Financing Activities

Our financing activities primarily relate to funding investment capital projects, acquisitions and refinancing of our debt maturities, as well as short-term working capital (including borrowings for NYMEX and ICE margin deposits) and hedged inventory borrowings related to our NGL business and contango market activities, and the payment of distributions to our unitholders and noncontrolling interests.

Borrowings and Repayments Under Credit Agreements and Term Loan

During the three months ended March 31, 2026 and 2025, we had net borrowings under our credit facilities and commercial paper program of $116 million and $71 million, respectively. The net borrowings resulted primarily from funding needs for capital investments, inventory purchases and other general partnership purposes.

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Common Equity Repurchase Program

There were no repurchases under the Common Equity Repurchase Program (the “Program”) during the three months ended March 31, 2026 or 2025. At March 31, 2026, the remaining available capacity under the Program was $190 million. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2025 Annual Report on Form 10-K for additional information regarding the Program.

Registration Statements

We periodically access the capital markets for both equity and debt financing. We have filed with the SEC a shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to a specified amount of debt or equity securities (“Traditional Shelf”), under which we had approximately $1.1 billion of unsold securities available at March 31, 2026. We also have access to a universal shelf registration statement (“WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. We did not conduct any offerings under our Traditional Shelf or WKSI Shelf during the three months ended March 31, 2026.

Distributions to Our Unitholders

Series A preferred unitholders. On May 15, 2026, we will pay a quarterly cash distribution of approximately $0.615 per unit to Series A preferred unitholders of record at the close of business on May 1, 2026 for the period from January 1, 2026 through March 31, 2026.

Series B preferred unitholders. On May 15, 2026, we will pay a quarterly cash distribution of approximately $19.84 per unit to Series B preferred unitholders of record at the close of business on May 1, 2026 for the period from February 15, 2026 through May 14, 2026.

Common Unitholders. On May 15, 2026, we will pay a quarterly cash distribution of $0.4175 per common unit ($1.67 per unit on an annualized basis) to common unitholders of record at the close of business on May 1, 2026 for the period from January 1, 2026 through March 31, 2026.

See Note 7 to our Condensed Consolidated Financial Statements for details of distributions paid during or pertaining to the first three months of 2026.

Distributions to Noncontrolling Interests

Distributions to noncontrolling interests represent amounts paid on interests in consolidated entities that are not owned by us. As of March 31, 2026, noncontrolling interests in our subsidiaries consisted of (i) a 35% interest in the Permian JV, (ii) a 30% interest in Cactus II and (iii) a 33% interest in Red River. See Note 7 to our Condensed Consolidated Financial Statements for details of distributions paid to noncontrolling interests during the three months ended March 31, 2026.

Contingencies

For a discussion of contingencies that may impact us, see Note 10 to our Condensed Consolidated Financial Statements.

Commitments

Purchase Obligations. In the ordinary course of doing business, we purchase crude oil from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years, with a limited number of contracts with remaining terms extending up to 10 years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy or who have provided credit support we consider adequate.

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The following table includes our best estimate of the amount and timing of these payments as of March 31, 2026 (in millions):


	Remainder of 2026		2027		2028		2029		2030		2031 and Thereafter		Total
Crude oil and other purchases (1)	$	28,719	$	31,573	$	27,559	$	25,162	$	21,152	$	43,525	$	177,690

(1)Amounts are primarily based on estimated volumes and market prices based on average activity during March 2026. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.

Letters of Credit. In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil and NGL. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the product is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At March 31, 2026 and December 31, 2025, we had outstanding letters of credit of approximately $118 million and $95 million, respectively.

Recent Accounting Pronouncements

See Note 1 to our Condensed Consolidated Financial Statements.

FORWARD-LOOKING STATEMENTS

All statements included in this report, other than statements of historical fact, are forward-looking statements, including but not limited to statements incorporating the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast,” as well as similar expressions and statements regarding our business strategy, plans and objectives for future operations. The absence of such words, expressions or statements, however, does not mean that the statements are not forward-looking. Any such forward-looking statements reflect our current views with respect to future events, based on what we believe to be reasonable assumptions. Certain factors could cause actual results or outcomes to differ materially from the results or outcomes anticipated in the forward-looking statements. The most important of these factors include, but are not limited to:

•risks related to the Canadian NGL Business divestiture (as defined herein), including the risk that the Canadian NGL Business divestiture is not consummated on the terms expected or on the anticipated schedule, or at all, and the effect of the announcement or pendency of the Canadian NGL Business divestiture on our business relationships, operating results, employees, stakeholders and business generally;

•general economic, market or business conditions in the United States and elsewhere (including the potential for a recession or significant slowdown in economic activity levels, the risk of persistently high inflation and supply chain issues, the impact of global public health events, such as pandemics, on demand and growth, and the timing, pace and extent of economic recovery) that impact (i) demand for crude oil, drilling and production activities and therefore the demand for the midstream services we provide and (ii) commercial opportunities available to us;

•declines in global crude oil demand and/or crude oil prices or other factors that correspondingly lead to a significant reduction of North American crude oil and NGL production (whether due to reduced producer cash flow to fund drilling activities or the inability of producers to access capital, or both, the unavailability of pipeline and/or storage capacity, the shutting-in of production by producers, government-mandated pro-ration orders, or other factors), which in turn could result in significant declines in the actual or expected volume of crude oil and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets and/or the reduction of the margins we can earn or the commercial opportunities that might otherwise be available to us;

•impacts of global geopolitical events, including conflicts in the Middle East and elsewhere, on commodity price volatility and crude oil supply and demand, as well as broader impacts on financial markets and the global macroeconomic environment;

•fluctuations in refinery capacity and other factors affecting demand for various grades of crude oil and NGL and resulting changes in pricing conditions or transportation throughput requirements;

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•unanticipated changes in crude oil and NGL market structure, grade differentials and volatility (or lack thereof);

•the effects of competition and capacity overbuild in areas where we operate, including downward pressure on rates, volumes and margins, contract renewal risk and the risk of loss of business to other midstream operators who are willing or under pressure to aggressively reduce transportation rates in order to capture or preserve customers;

•the availability of, and our ability to consummate, acquisitions, divestitures, joint ventures or other strategic opportunities and realize benefits therefrom, including the Canadian NGL Business divestiture (as defined herein);

•the successful operation of joint ventures and joint operating arrangements we enter into from time to time, whether relating to assets operated by us or by third parties, and the successful integration and future performance of acquired assets or businesses;

•environmental liabilities, litigation or other events that are not covered by an indemnity, insurance or existing reserves;

•negative societal sentiment regarding the hydrocarbon energy industry and the continued development and consumption of hydrocarbons, which could influence consumer preferences and governmental or regulatory actions that adversely impact our business;

•the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event that materially impacts our operations, including cyber or other attacks on our or our service providers’ electronic and computer systems;

•weather interference with business operations or project construction, including the impact of extreme weather events or conditions (including hurricanes, floods, wildfires and drought);

•the impact of current and future laws, rulings, legislation, governmental regulations, executive orders, trade policies, trade tariffs, accounting standards and statements, and related interpretations that (i) prohibit, restrict or regulate the development of oil and gas resources and the related infrastructure on lands dedicated to or served by our pipelines, (ii) negatively impact our ability to develop, operate or repair midstream assets, or (iii) otherwise negatively impact our business or increase our exposure to risk;

•negative impacts on production levels in the Permian Basin or elsewhere due to issues associated with (or laws, rules or regulations relating to) hydraulic fracturing and related activities (including wastewater injection or disposal), including earthquakes, subsidence, expansion or other issues;

•the pace of development of natural gas or other infrastructure and its impact on expected crude oil production growth in the Permian Basin;

•the refusal or inability of our customers or counterparties to perform their obligations under their contracts with us (including commercial contracts, asset sale agreements and other agreements), whether justified or not and whether due to financial constraints (such as reduced creditworthiness, liquidity issues or insolvency), market constraints, legal constraints (including governmental orders or guidance), the exercise of contractual or common law rights that allegedly excuse their performance (such as force majeure or similar claims) or other factors;

•loss of key personnel and inability to attract and retain new talent;

•disruptions to futures markets for crude oil, NGL and other petroleum products, which may impair our ability to execute our commercial or hedging strategies;

•the effectiveness of our risk management activities;

•shortages or cost increases of supplies, materials or labor;

•maintenance of our credit ratings and ability to receive open credit from our suppliers and trade counterparties;

•our inability to perform our obligations under our contracts, whether due to non-performance by third parties, including our customers or counterparties, market constraints, third-party constraints, supply chain issues, legal constraints (including governmental orders or guidance), or other factors or events;

•the incurrence of costs and expenses related to unexpected or unplanned capital or maintenance expenditures, third-party claims or other factors;

•failure to implement or capitalize, or delays in implementing or capitalizing, on investment capital projects, whether due to permitting delays, permitting withdrawals or other factors;

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•failure to implement or realize anticipated benefits from operational and organizational streamlining and efficiency efforts and initiatives;

•tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, investment capital projects, working capital requirements and the repayment or refinancing of indebtedness;

•the amplification of other risks caused by volatile or closed financial markets, capital constraints, liquidity concerns and inflation;

•the use or availability of third-party assets upon which our operations depend and over which we have little or no control;

•the currency exchange rate of the Canadian dollar to the United States dollar;

•the deferral of current revenue recognition attributable to deficiency payments received from customers who fail to ship or move their minimum contracted volumes;

•significant under-utilization of our assets and facilities;

•increased costs, or lack of availability, of insurance;

•fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans;

•risks related to the development and operation of our assets; and

•other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, as well as in the processing, transportation, fractionation, storage and marketing of NGL.

Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read “Risk Factors” discussed in Item 1A of our 2025 Annual Report on Form 10-K. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various market risks, including commodity price risk, interest rate risk and currency exchange rate risk. We use various derivative instruments to manage such risks and, in certain circumstances, to realize incremental margin during volatile market conditions. Our risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our exchange-cleared and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. We have a risk management function that has direct responsibility and authority for our risk policies, related controls around commercial activities and certain aspects of corporate risk management. Our risk management function also approves all new risk management strategies through a formal process. The following discussion addresses each category of risk.

Commodity Price Risk

We use derivative instruments to hedge price risk associated with the following:

•Crude oil

We utilize crude oil derivatives to hedge commodity price risk inherent in our pipeline, terminalling and merchant activities. Our objectives for these derivatives include hedging changes in inventory positions associated with our lease gathering activities, anticipated purchases and sales, stored inventory and basis differentials. We manage these exposures with various instruments including futures, forwards, swaps and options.

See Note 8 to our Condensed Consolidated Financial Statements for further discussion regarding our hedging strategies and objectives.

The fair value of our commodity derivatives and the change in fair value as of March 31, 2026 that would be expected from a 10% price increase or decrease is shown in the table below (in millions):


	Fair Value		Effect of 10% Price Increase		Effect of 10% Price Decrease
Crude oil	$	130	$	20	$	(20)


Total fair value	$	130

The fair values presented in the table above reflect the sensitivity of the derivative instruments only and do not include the effect of the underlying hedged commodity. Price-risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in near-term commodity prices, the fair value of our derivative portfolio would typically change less than that shown in the table as changes in near-term prices are not typically mirrored in delivery months further out.

Interest Rate Risk

Debt. Our use of variable rate debt and any forecasted issuances of fixed rate debt expose us to interest rate risk. Therefore, from time to time, we use interest rate derivatives to hedge interest rate risk associated with anticipated interest payments and, in certain cases, outstanding debt instruments. We did not have any interest rate derivatives as of March 31, 2026. All of our senior notes are fixed rate notes and thus are not subject to interest rate risk. Our variable rate debt outstanding, approximately $2.185 billion, was subject to interest rate resets that generally occur within one month or less. The average interest rate on variable rate debt that was outstanding during the three months ended March 31, 2026 was approximately 4.4%, based upon rates in effect during such period. See Note 6 to our Condensed Consolidated Financial Statements for additional information regarding our debt arrangements.

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Series B Preferred Units. Distributions on the Series B preferred units accumulate and are payable quarterly in arrears on the 15th day of February, May, August and November. Distributions on the Series B preferred units accumulate based on the applicable three-month SOFR, plus certain adjustments. Based upon the Series B preferred units outstanding at March 31, 2026 and the liquidation preference of $1,000 per unit, a change of 100 basis points in interest rates would increase or decrease the annual distributions on the Series B preferred units by approximately $8 million. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2025 Annual Report on Form 10-K for additional information regarding our Series B preferred unit distributions.

Currency Exchange Rate Risk

We use foreign currency derivatives to hedge foreign currency exchange rate risk associated with our exposure to fluctuations in the USD-to-CAD exchange rate. The fair value of our foreign currency derivatives was an an asset of $61 million as of March 31, 2026. A 10% increase in the exchange rate (USD-to-CAD) would have resulted in an increase of $324 million to the fair value of our foreign currency derivatives. A 10% decrease in the exchange rate (USD-to-CAD) would have resulted in a decrease of $324 million to the fair value of our foreign currency derivatives. See Note 8 to our Condensed Consolidated Financial Statements for additional information regarding our currency exchange rate risk hedging.

Item 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We maintain written disclosure controls and procedures, which we refer to as our “DCP.” Our DCP is designed to ensure that information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 (the “Exchange Act”) is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.

Applicable SEC rules require an evaluation of the effectiveness of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our DCP as of March 31, 2026, the end of the period covered by this report, and, based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our DCP is effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the first quarter of 2026 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Certifications

The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a) are filed with this report as Exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350 are furnished with this report as Exhibits 32.1 and 32.2.

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

The information required by this item is included in Note 10 to our Condensed Consolidated Financial Statements, and is incorporated herein by reference thereto.

Item 1A. RISK FACTORS

For a discussion of our risk factors, see Item 1A. of our 2025 Annual Report on Form 10-K. Those risks and uncertainties are not the only ones facing us and there may be additional matters of which we are unaware or that we currently consider immaterial. All of those risks and uncertainties could adversely affect our business, financial condition and/or results of operations.

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Sales of Unregistered Securities

None.

Issuer Purchases of Equity Securities

None.

Item 3. DEFAULTS UPON SENIOR SECURITIES

None.

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

Item 5. OTHER INFORMATION

During the quarter ended March 31, 2026, none of our directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) adopted or terminated any Rule 10b5-1 trading arrangement or any non-Rule 10b5-1 trading arrangement (as defined in Item 408 of Regulation S-K).

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Item 6. EXHIBITS


Exhibit No.		Description

3.1	—	Seventh Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P., dated as of October 10, 2017 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 12, 2017).

3.2	—	Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.3	—	Amendment No. 1 dated December 31, 2010 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.9 to our Annual Report on Form 10-K for the year ended December 31, 2010).

3.4	—	Amendment No. 2 dated January 1, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2010).

3.5	—	Amendment No. 3 dated June 30, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.7 to our Annual Report on Form 10-K for the year ended December 31, 2013).

3.6	—	Amendment No. 4 dated January 1, 2013 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P (incorporated by reference to Exhibit 3.8 to our Annual Report on Form 10-K for the year ended December 31, 2013).

3.7	—	Amendment No. 5 dated December 1, 2019 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.7 to our Annual Report on Form 10-K for the year ended December, 31, 2019).

3.8	—	Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.3 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.9	—	Amendment No. 1 dated January 1, 2013 to the Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. (incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2013).

3.10	—	Seventh Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated November 15, 2016 (incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K filed November 21, 2016).

3.11	—	Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. dated November 15, 2016 (incorporated by reference to Exhibit 3.4 to our Current Report on Form 8-K filed November 21, 2016).

3.12	—	Amendment No. 1 dated September 26, 2018 to the Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 2, 2018).

3.13	—	Amendment No. 2 dated May 23, 2019 to the Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed May 30, 2019).

3.14	—	Amendment No. 3 dated August 17, 2023 to the Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed August 21, 2023).

3.15	—	Certificate of Incorporation of PAA Finance Corp. (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2006).

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3.16	—	Bylaws of PAA Finance Corp. (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.11 to our Annual Report on Form 10-K for the year ended December 31, 2006).

3.17	—	Limited Liability Company Agreement of PAA GP LLC dated December 28, 2007 (incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K filed January 4, 2008).

3.18	—	Certificate of Limited Partnership of Plains GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to PAGP’s Registration Statement on Form S-1 (333-190227) filed July 29, 2013).

3.19	—	Second Amended and Restated Agreement of Limited Partnership of Plains GP Holdings, L.P. dated November 15, 2016 (incorporated by reference to Exhibit 3.2 to PAGP’s Current Report on Form 8-K filed November 21, 2016).

3.20	—	Amendment No. 1 dated April 6, 2020 to the Second Amended and Restated Agreement of Limited Partnership of Plains GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to PAGP’s Current Report on Form 8-K filed April 9, 2020).

3.21	—	Certificate of Formation of PAA GP Holdings LLC (incorporated by reference to Exhibit 3.3 to PAGP’s Registration Statement on Form S-1 (333-190227) filed July 29, 2013).

3.22	—	Fourth Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC dated effective as of August 19, 2021 (incorporated by reference to Exhibit 3.21 to our Annual Report on Form 10-K for the year ended December 31, 2021).

4.1	—	Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).

4.2	—	Sixth Supplemental Indenture (Series A and Series B 6.70% Senior Notes due 2036) dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed May 12, 2006).

4.3	—	Tenth Supplemental Indenture (Series A and Series B 6.650% Senior Notes due 2037) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed October 30, 2006).

4.4	—	Twenty-First Supplemental Indenture (5.15% Senior Notes due 2042) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed March 26, 2012).

4.5	—	Twenty-Third Supplemental Indenture (4.30% Senior Notes due 2043) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 12, 2012).

4.6	—	Twenty-Fifth Supplemental Indenture (4.70% Senior Notes due 2044) dated April 23, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed April 29, 2014).

4.7	—	Twenty-Eighth Supplemental Indenture (4.90% Senior Notes due 2045) dated December 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 11, 2014).

4.8	—	Thirtieth Supplemental Indenture (4.50% Senior Notes due 2026) dated November 22, 2016, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed November 29, 2016).

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4.9	—	Thirty-First Supplemental Indenture (3.55% Senior Notes due 2029) dated September 16, 2019, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed September 17, 2019).

4.10	—	Thirty-Second Supplemental Indenture (3.80% Senior Notes due 2030) dated June 11, 2020, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed June 11, 2020).

4.11	—	Thirty-Third Supplemental Indenture (5.70% Senior Notes due 2034) dated June 27, 2024, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed June 27, 2024).

4.12	—	Thirty-Fourth Supplemental Indenture (5.950% Senior Notes due 2035) dated January 15, 2025, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed January 15, 2025).

4.13	—	Thirty-Fifth Supplemental Indenture (4.70% Senior Notes due 2031) dated September 8, 2025, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed September 8, 2025).

4.14	—	Thirty-Sixth Supplemental Indenture (5.60% Senior Notes due 2036) dated September 8, 2025, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed September 8, 2025).

4.15	—	Registration Rights Agreement dated September 3, 2009 by and between Plains All American Pipeline, L.P. and Vulcan Gas Storage LLC (incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-3, File No. 333-162477).

4.16	—	Registration Rights Agreement dated as of January 28, 2016 among Plains All American Pipeline, L.P. and the Purchasers named therein (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed February 2, 2016).

4.17	—	Registration Rights Agreement by and among Plains All American Pipeline, L.P. and the Holders defined therein, dated November 15, 2016 (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed November 21, 2016).

4.18	—	Description of Our Securities (incorporated by reference to Exhibit 4.17 to our Annual Report on Form 10-K for the year ended December 31, 2024).

10.1	—	Third Amendment to Credit Agreement, dated as of February 26, 2026 , by and among Plains All American Pipeline, L.P., Plains Canada Liquid Pipelines ULC, Bank of America, N.A., as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed March 3, 2 026 ).

10.2	—	Third Amendment to Fourth Amended and Restated Credit Agreement, dated as of February 26, 2026, by and among Plains Marketing, L.P., Plains Canada Liquid Pipelines ULC, Plains All American Pipeline, L.P., Bank of America, N.A., as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed March 3, 2026).

31.1 †	—	Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

31.2 †	—	Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

32.1 ††	—	Certification of Principal Executive Officer pursuant to 18 U.S.C. 1350.

32.2 ††	—	Certification of Principal Financial Officer pursuant to 18 U.S.C. 1350.

101.INS†	—	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

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101.SCH†	—	Inline XBRL Taxonomy Extension Schema Document

101.CAL†	—	Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF†	—	Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB†	—	Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE†	—	Inline XBRL Taxonomy Extension Presentation Linkbase Document

104†	—	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

† Filed herewith.

†† Furnished herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	PLAINS ALL AMERICAN PIPELINE, L.P.

	By:	PAA GP LLC,
		its general partner

	By:	Plains AAP, L.P.,
		its sole member

	By:	PLAINS ALL AMERICAN GP LLC,
		its general partner

	By:	/s/ Willie Chiang
		Willie Chiang,
		Chief Executive Officer and President of Plains All American GP LLC
		(Principal Executive Officer)

May 8, 2026

	By:	/s/ Al Swanson
		Al Swanson,
		Executive Vice President and Chief Financial Officer of Plains All American GP LLC
		(Principal Financial Officer)

May 8, 2026

	By:	/s/ Chris Herbold
		Chris Herbold,
		Senior Vice President, Finance and Chief Accounting Officer of Plains All American GP LLC
		(Principal Accounting Officer)

May 8, 2026

Plains All American Pipeline - 10-Q quarterly report FY

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