SEC Filing - Plains All American Pipeline

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paa-20260930

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________________________________

FORM 10-Q

________________________________________________________________________________________________________________________________

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

For the quarterly period ended September 30, 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 October 30, 2026, there were 707,937,400 Common Units outstanding.

Table of Contents

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS


			Page
PART I. FINANCIAL INFORMATION
Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
Condensed Consolidated Balance Sheets: As of September 30, 2026 and December 31, 2025			3
Condensed Consolidated Statements of Operations: For the three and nine months ended Se ptembe r 30, 2026 and 2025			4
Condensed Consolidated Statements of Comprehensive Income: For the three and nine months ended September 30, 2026 and 2025			5
Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss): For the nine months ended September 30, 2026 and 2025			5
Condensed Consolidated Statements of Cash Flows: For the nine months ended S eptember 30, 2026 and 2025			6
Condensed Consolidated Statements of Changes in Partners’ Capital: For the three and nine months ended September 30, 2026 and 2025			7
Notes to the Condensed Consolidated Financial Statements:
1. Organization and Basis of Consolidation and Presentation			9

2. Canadian NGL Business Divestiture and Discontinued Operations			11
3. Revenues and Accounts Receivable			13
4. Net Income /(Loss ) Per Common Unit			16
5. Inventory, Linefill and Long-term Inventory			18
6. Debt			19
7. Partners’ Capital and Distributions			21
8. Derivatives and Risk Management Activities			24
9. Related Party Transactions			27
10. Commitments and Contingencies			28
11. Segment Information			31
12. Other Transactions			31

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			32
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			53
Item 4. CONTROLS AND PROCEDURES			54

PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS			55
Item 1A. RISK FACTORS			55
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			55
Item 3. DEFAULTS UPON SENIOR SECURITIES			55
Item 4. MINE SAFETY DISCLOSURES			55
Item 5. OTHER INFORMATION			55
Item 6. EXHIBITS			56
SIGNATURES			60

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)


	September 30, 2026		December 31, 2025
	(unaudited)
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	879	$	328

Trade accounts receivable and other receivables, net	5,592		3,598
Inventory	343		211
Current assets of discontinued operations (Note 2)	—		479
Other current assets	132		117
Total current assets	6,946		4,733

PROPERTY AND EQUIPMENT	22,696		22,536
Accumulated depreciation	(5,939)		(5,676)
Property and equipment, net	16,757		16,860

OTHER ASSETS
Investments in unconsolidated entities	2,726		2,846
Intangible assets, net	1,535		1,754
Linefill	888		900
Long-term operating lease right-of-use assets, net	160		198
Long-term inventory	323		214
Long-term assets of discontinued operations (Note 2)	—		2,557
Other long-term assets, net	139		107
Total assets	$	29,474	$	30,169

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES
Trade accounts payable	$	5,643	$	3,457
Short-term debt (Note 6)	9		563
Current liabilities of discontinued operations (Note 2)	125		382
Other current liabilities	572		529
Total current liabilities	6,349		4,931

LONG-TERM LIABILITIES

Long-term debt (Note 6)	9,911		10,696
Long-term operating lease liabilities	183		202
Long-term liabilities of discontinued operations (Note 2)	—		606
Other long-term liabilities and deferred credits	379		654
Total long-term liabilities	10,473		12,158

COMMITMENTS AND CONTINGENCIES (NOTE 10)

PARTNERS’ CAPITAL
Series A preferred unitholders (0 and 58,411,908 units outstanding, respectively)	—		1,248
Series B preferred unitholders (800,000 and 800,000 units outstanding, respectively)	787		787
Common unitholders (707,937,400 and 705,520,697 units outstanding, respectively)	8,675		7,801
Total partners’ capital excluding noncontrolling interests	9,462		9,836
Noncontrolling interests	3,190		3,244
Total partners’ capital	12,652		13,080
Total liabilities and partners’ capital	$	29,474	$	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 September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
	(unaudited)				(unaudited)
REVENUES
Product sales revenues	$	14,700	$	11,150	$	43,946	$	32,389
Services revenues	473		428		1,388		1,309
Total revenues	15,173		11,578		45,334		33,698
COSTS AND EXPENSES
Purchases and related costs	14,030		10,585		42,078		30,862
Field operating costs	306		288		934		873
General and administrative expenses	78		83		270		251
Depreciation and amortization	235		230		721		696
(Gains)/losses on asset sales, asset impairments and other, net	8		(92)		14		(64)
Total costs and expenses	14,657		11,094		44,017		32,618
OPERATING INCOME	516		484		1,317		1,080
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	85		96		263		292
Gain on/(impairment of) investments in unconsolidated entities, net	(68)		—		(68)		31
Interest expense (net of capitalized interest of $2, $4, $5 and $9, respectively)	(131)		(135)		(451)		(395)
Other income, net	19		14		69		70

INCOME FROM CONTINUING OPERATIONS BEFORE TAX	421		459		1,130		1,078
Current income tax (expense)/benefit from continuing operations	4		(5)		(319)		(11)
Deferred income tax (expense)/benefit from continuing operations	(12)		(1)		210		(6)
INCOME FROM CONTINUING OPERATIONS, NET OF TAX	413		453		1,021		1,061




INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX (NOTE 2)	40		76		1,588		281
NET INCOME	453		529		2,609		1,342
Net income attributable to noncontrolling interests	(90)		(88)		(264)		(249)
NET INCOME ATTRIBUTABLE TO PAA	$	363	$	441	$	2,345	$	1,093

NET INCOME/(LOSS) PER COMMON UNIT (NOTE 4):
Net income/(loss) allocated to common unitholders — Basic and Diluted:
Continuing operations	$	(81)	$	311	$	239	$	599
Discontinued operations	40		76		1,588		281
Net income/(loss) allocated to common unitholders — Basic and Diluted	$	(41)	$	387	$	1,827	$	880

Basic and diluted weighted average common units outstanding	707		704		706		704
Basic and diluted net income/(loss) per common unit:
Continuing operations	$	(0.12)	$	0.44	$	0.34	$	0.85
Discontinued operations	0.06		0.11		$	2.25	$	0.40
Basic and diluted net income/(loss) per common unit	$	(0.06)	$	0.55	$	2.59	$	1.25

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 September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
	(unaudited)				(unaudited)
Net income	$	453	$	529	$	2,609	$	1,342
Other comprehensive income/(loss)	1		(51)		(61)		142
Comprehensive income	454		478		2,548		1,484
Comprehensive income attributable to noncontrolling interests	(90)		(88)		(264)		(249)
Comprehensive income attributable to PAA	$	364	$	390	$	2,284	$	1,235

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	3		—		—		3

Currency translation adjustments	—		(59)		—		(59)
Other	—		—		(5)		(5)
Total period activity	3		(59)		(5)		(61)
Balance at September 30, 2026	$	(26)	$	(931)	$	—	$	(957)


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

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

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	Nine Months Ended September 30,
	2026		2025
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	2,609	$	1,342
Reconciliation of net income to net cash provided by operating activities:
Income from discontinued operations, net of tax	(1,588)		(281)
Depreciation and amortization	721		696
(Gains)/losses on asset sales, asset impairments and other, net	14		(64)


Deferred income tax expense/(benefit)	(210)		6

(Gain)/loss on foreign currency revaluation	(15)		19
Settlement of terminated interest rate hedging instruments	—		7

Equity earnings in unconsolidated entities	(263)		(292)
Distributions on earnings from unconsolidated entities	313		369
(Gain on)/impairment of investments in unconsolidated entities, net	68		(31)
Other	46		47
Changes in assets and liabilities, net of acquisitions	188		18
Cash provided by operating activities - continuing operations	1,883		1,836
Cash provided by operating activities - discontinued operations	159		314
Net cash provided by operating activities	2,042		2,150

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	(150)		(865)

Additions to property, equipment and other	(407)		(495)
Cash paid for purchases of linefill	(12)		(17)

Proceeds from sales of assets	35		27

Cash received from sales of linefill	37		—
Investments in related party notes	—		(330)
Other investing activities	20		—
Cash used in investing activities - continuing operations	(477)		(1,680)
Cash provided by/(used in) investing activities - discontinued operations	3,480		(151)
Net cash provided by/(used in) investing activities	3,003		(1,831)

CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments under commercial paper program (Note 6)	(970)		(393)



Repayment under term loan (Note 6)	(1,100)		—
Proceeds from the issuance of senior notes (Note 6)	—		2,246
Proceeds from the issuance of junior subordinated notes (Note 6)	1,500		—
Repayments of senior notes (Note 6)	(750)		—
Proceeds from the issuance of related party notes	—		330

Repurchase of common units	—		(8)
Repurchase of Series A preferred units (Note 7)	(1,687)		(333)
Distributions paid to Series A preferred unitholders (Note 7)	(137)		(118)
Distributions paid to Series B preferred unitholders (Note 7)	(49)		(53)
Distributions paid to common unitholders (Note 7)	(884)		(802)
Distributions paid to noncontrolling interests (Note 7)	(317)		(339)
Contributions from noncontrolling interests	—		34


Other financing activities	(83)		(64)


Net cash provided by/(used in) financing activities	(4,477)		500


Effect of translation adjustment - continuing operations	(17)		13
Effect of translation adjustment - discontinued operations	—		—


Net increase in cash and cash equivalents and restricted cash	551		832
Cash and cash equivalents and restricted cash, beginning of period	328		348
Cash and cash equivalents and restricted cash, end of period	$	879	$	1,180


Cash paid for:
Interest, net of amounts capitalized	$	461	$	382
Income taxes, net of amounts refunded	$	55	$	80

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	101		49		2,195		2,345		264		2,609
Distributions (Note 7)	(101)		(49)		(884)		(1,034)		(317)		(1,351)
Other comprehensive loss	—		—		(61)		(61)		—		(61)
Repurchase of Series A preferred units (Note 7)	(1,251)		—		(358)		(1,609)		—		(1,609)


Other	3		—		(18)		(15)		(1)		(16)
Balance at September 30, 2026	$	—	$	787	$	8,675	$	9,462	$	3,190	$	12,652

	Limited Partners						Partners’ Capital Excluding Noncontrolling Interests		Noncontrolling Interests		Total Partners’ Capital
	Preferred Unitholders				Common Unitholders
	Series A		Series B
	(unaudited)
Balance at June 30, 2026	$	1,250	$	787	$	9,042	$	11,079	$	3,212	$	14,291
Net income	29		17		317		363		90		453
Distributions (Note 7)	(29)		(17)		(295)		(341)		(112)		(453)
Other comprehensive income	—		—		1		1		—		1
Repurchase of Series A preferred units (Note 7)	(1,251)		—		(358)		(1,609)		—		(1,609)



Other	1		—		(32)		(31)		—		(31)
Balance at September 30, 2026	$	—	$	787	$	8,675	$	9,462	$	3,190	$	12,652

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

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

Contributions from noncontrolling interests	—		—		—		—		5		5
Other	1		—		(13)		(12)		—		(12)
Balance at September 30, 2025	$	1,247	$	787	$	7,729	$	9,763	$	3,226	$	12,989

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

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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 non-economic general partner interest is held by PAA GP LLC (“PAA GP”), a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP, as of September 30, 2026, AAP also owned a limited partner interest in us through its ownership of approximately 233.0 million of our common units (approximately 33% of our total outstanding common units). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole and managing member of GP LLC, and, at September 30, 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 Canada Liquid Pipelines ULC (“PCLP”).

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.

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 and nine months ended September 30, 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.

On May 12, 2026, we completed the sale of the Canadian NGL Business (as defined and discussed in further detail in Note 2). The operations of the Canadian NGL Business met the criteria for classification as held for sale and for discontinued operations reporting. Accordingly, 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. 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. Through the date of the sale, all significant intercompany balances and transactions between the Canadian NGL Business and our continuing operations have been eliminated.

Subsequent to the sale of the Canadian NGL Business, during the third quarter of 2026, we effected changes in the primary financial information provided to and reviewed by our CODM for assessing performance and allocating resources. As a result, we now present one single, consolidated operating and reportable segment. Prior to the third quarter of 2026, we had defined our operating and reportable segments as Crude Oil and NGL. See Note 11 for further discussion of segment information. All segment data and related disclosures for earlier periods presented herein have been recast to reflect the new segment reporting structure.

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 nine months ended September 30, 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—Canadian NGL Business Divestiture and Discontinued Operations

On June 17, 2025, we entered into a definitive Share Purchase Agreement (as amended to date, the “SPA”) with Keyera Corp. (“Keyera”), an Alberta corporation, pursuant to which Keyera agreed to acquire all of the issued and outstanding shares of Plains Midstream Canada ULC (“PMC ULC”), our wholly-owned subsidiary that owned our NGL business in Canada (the “Canadian NGL Business”). The transaction closed on May 12, 2026, and, pursuant to the SPA, we have received cash consideration of approximately CAD$5.390 billion (approximately $3.927 billion), including working capital and other certain post-closing adjustments as defined in the SPA. As part of the sale, we divested the Canadian NGL Business, which included substantially all of our NGL assets; the NGL assets that we retained are located in the United States. The divestiture aligns with management’s strategy to focus on its crude oil operations. Prior to its classification as held for sale and presentation as discontinued operations, the Canadian NGL Business was part of our previous NGL reportable segment.

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

In connection with the closing of the Canadian NGL Business divestiture, we and Keyera entered into certain agreements, including:

•a tax matters agreement that governs our and Keyera’s tax rights and obligations after closing. At the closing of the divestiture, we recognized a liability of approximately $60 million related to our obligation to indemnify Keyera against any exposure to certain tax assessments by the Canadian tax authorities against PMC ULC. During the third quarter of 2026, we submitted a payment of approximately $12 million to Keyera. As of September 30, 2026, we have recognized a liability of approximately $48 million, which is reflected within “Current liabilities of discontinued operations” on our Condensed Consolidated Balance Sheet; and

•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. This agreement was settled and terminated for $15 million in July 2026.

Additionally, we completed certain planning and restructuring activities within our organizational structure in connection with the Canadian NGL Business divestiture. In the first quarter of 2026, PMC ULC contributed its crude oil assets to a newly formed, wholly-owned subsidiary, PCLP. While this transaction was 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 the date of the contribution by PMC ULC. These activities created current tax expense of approximately $311 million as a result of basis recapture and capital gains taxed at the applicable rates and withholding taxes on distributions. This also created a partially offsetting $217 million deferred tax benefit primarily resulting from the new tax basis in the assets received by PCLP for the nine months ended September 30, 2026. Since the transaction relates to our crude oil business, the tax impacts are presented in “Current income tax (expense)/benefit from continuing operations” and “Deferred income tax (expense)/benefit from continuing operations,” respectively, on our Condensed Consolidated Statements of Operations. Further, we recorded current income tax expense from discontinued operations of $82 million during the nine months ended September 30, 2026. As of September 30, 2026, a related liability of $77 million was included in “Current liabilities of discontinued operations” on our Condensed Consolidated Balance Sheet. Management also determined, based on analysis provided by external tax advisors, that there were no liabilities for uncertain tax positions resulting from the restructuring activities.

We determined that in conjunction with entering into the SPA, the operations of the Canadian NGL Business met the criteria for classification as held for sale and for discontinued operations reporting, as the sale represented a strategic shift that had a major effect on our operations and financial results. 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. The Canadian NGL Business disposal group was recorded at its historical carrying value, as the fair value of the disposal group, less estimated costs to sell, was greater than the carrying value of the Canadian NGL Business disposal group. Upon the completion of the divestiture on May 12, 2026, we derecognized all assets and liabilities of the Canadian NGL Business. We recognized a gain on sale of approximately $40 million and $1,645 million for the three and nine months ended September 30, 2026, respectively, which is reflected within income from discontinued operations. The gain recognized during the three months ended September 30, 2026 was primarily related to a post-closing adjustment during the period.

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Additionally, we accelerated certain general and administrative expenses of approximately $33 million for the nine months ended September 30, 2026, associated with exit activities related to the Canadian NGL Business divestiture in May 2026, which is reflected within income from continuing operations.

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


	September 30, 2026		December 31, 2025
Assets:
Current assets:

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

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

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

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

Other current liabilities	125		87
Total current liabilities of discontinued operations	$	125	$	382

Long-term liabilities:

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

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

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Revenues:
Product sales	$	—	$	139	$	292	$	818
Services	—		37		58		102
Total revenues	—		176		350		920
Cost and Expenses:
Purchases and related costs	—		(7)		205		245
Field operating costs	—		68		108		190
General and administrative expenses	—		10		17		36
Depreciation and amortization	—		—		—		57
(Gains)/losses on asset sales and other, net	(40)		2		(1,645)		15
Total costs and expenses	(40)		73		(1,315)		543

Income from discontinued operations before tax	40		103		1,665		377
Current income tax expense	—		(7)		(115)		(61)
Deferred income tax (expense)/benefit	—		(20)		38		(35)
Income from discontinued operations, net of tax	$	40	$	76	$	1,588	$	281

Note 3—Revenues and Accounts Receivable

Revenue Recognition

We disaggregate our revenues by type of activity. These categories depict how the nature, amount, timing and uncertainty of revenues and cash flows are affected by economic factors. The following disclosures only include information regarding revenues associated with consolidated entities; revenues from entities accounted for by the equity method are not included.

Revenues from Contracts with Customers. The following tables present our revenues from contracts with customers disaggregated by type of activity (as described below) and the reconciliation of our revenues from contracts with customers to total revenues as disclosed in our Condensed Consolidated Statements of Operations (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Revenues from contracts with customers:
Sales	$	14,656	$	11,134	$	43,785	$	32,428
Transportation	366		336		1,063		987
Terminalling, Storage and Other	101		86		300		262
Total revenues from contracts with customers	$	15,123	$	11,556	$	45,148	$	33,677
Other revenues	50		22		186		21
Total revenues	$	15,173	$	11,578	$	45,334	$	33,698

Sales Revenues. Revenues from product sales 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.

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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.

Minimum Volume Commitments. We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. The following table presents counterparty deficiencies associated with contracts with customers and buy/sell arrangements that include minimum volume commitments for which we had remaining performance obligations and the customers still had the ability to meet their obligations (in millions):


Counterparty Deficiencies	Financial Statement Classification	September 30, 2026		December 31, 2025
Billed and collected	Other current liabilities	$	18	$	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	(27)

Additions	32
Other (1)	(26)
Balance at September 30, 2026	$	66

(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.

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Remaining Performance Obligations. The information below includes the amount of consideration allocated to partially and wholly unsatisfied remaining performance obligations under contracts that existed as of the end of the periods and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These contracts include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of September 30, 2026 (in millions):


	Remainder of 2026		2027		2028		2029		2030		2031 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	104	$	394	$	342	$	237	$	154	$	848
Terminalling, storage and other agreement revenues	62		221		161		115		78		430
Total	$	166	$	615	$	503	$	352	$	232	$	1,278

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

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

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

•Acreage dedications;

•Buy/sell arrangements with future committed volumes;

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

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

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

Trade Accounts Receivable and Other Receivables, Net

At September 30, 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):


	September 30, 2026		December 31, 2025
Trade accounts receivable arising from revenues from contracts with customers	$	5,493	$	3,639
Other trade accounts receivable and other receivables (1)	11,884		7,357
Impact due to contractual rights of offset with counterparties	(11,785)		(7,398)
Trade accounts receivable and other receivables, net	$	5,592	$	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.

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Note 4—Net Income/(Loss) Per Common Unit

We calculate basic and diluted net income/(loss) per common unit by dividing income or loss 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.

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, on a weighted average basis, for the three and nine months ended September 30, 2026, the possible conversion of approximately 48 million and 55 million Series A preferred units, respectively, and for the three and nine months ended September 30, 2025, the possible conversion of approximately 58 million and 60 million Series A Preferred Units, respectively, were excluded from the calculation of diluted net income/(loss) per common unit as the effect was antidilutive. Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that are deemed to be dilutive during the period are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Basic and Diluted Net Income/(Loss) per Common Unit
Continuing Operations:
Income from continuing operations, net of tax	$	413	$	453	$	1,021	$	1,061
Net income attributable to noncontrolling interests	(90)		(88)		(264)		(249)
Net income from continuing operations attributable to PAA	323		365		757		812
Distributions to Series A preferred unitholders	(29)		(36)		(101)		(110)
Distributions to Series B preferred unitholders	(17)		(18)		(49)		(53)
Amounts allocated to participating securities	(1)		(1)		(13)		(10)
Impact from repurchase of Series A preferred units (1)	(358)		—		(358)		(43)
Other	1		1		3		3
Net income/(loss) from continuing operations allocated to common unitholders - Basic and Diluted (2)	$	(81)	$	311	$	239	$	599

Discontinued Operations:
Net income from discontinued operations allocated to common unitholders - Basic and Diluted (3)	$	40	$	76	$	1,588	$	281

Net income/(loss) allocated to common unitholders — Basic and Diluted	$	(41)	$	387	$	1,827	$	880

Basic and diluted weighted average common units outstanding	707		704		706		704

Basic and diluted net income/(loss) per common unit:
Continuing operations	$	(0.12)	$	0.44	$	0.34	$	0.85
Discontinued operations	0.06		0.11		2.25		0.40
Basic and diluted net income/(loss) per common unit	$	(0.06)	$	0.55	$	2.59	$	1.25

(1)We repurchased approximately 12.7 million Series A preferred units on January 31, 2025, and we repurchased all remaining outstanding 58.4 million Series A preferred units on September 14, 2026. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2025 Annual Report on Form 10-K and Note 7 for additional information regarding the repurchase on January 31, 2025 and September 14, 2026, respectively. 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/(loss) from continuing operations allocated to common unitholders.

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

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

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Note 5—Inventory, Linefill and Long-term Inventory

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


	September 30, 2026						December 31, 2025
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory (2)	3,791	barrels	$	343	$	87.58	3,510	barrels	$	211	$	54.99


Linefill	14,952	barrels	888		$	59.39	15,145	barrels	900		$	59.43






Long-term inventory	3,643	barrels	323		$	88.66	3,750	barrels	214		$	57.07



Total			$	1,554					$	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.

(2)Includes parts inventory of $11 million and $18 million as of September 30, 2026 and December 31, 2025, respectively, that does not impact volumes or the price per unit calculation.

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Note 6—Debt

Debt consisted of the following (in millions):


	September 30, 2026		December 31, 2025
SHORT-TERM DEBT
Commercial paper notes, bearing a weighted-average interest rate of 3.9% (1)	$	—	$	554



Other	9		9
Total short-term debt	9		563

LONG-TERM DEBT
Senior notes, net of unamortized net discounts and debt issuance costs of $58 and $65, respectively (2)	8,375		9,118
Junior subordinated notes, net of unamortized debt issuance costs of $21	1,479		—
Commercial paper notes, bearing a weighted-average interest rate of 3.9% (3)	—		416
Term loan, net of debt issuance costs of $1, and bearing a weighted-average interest rate of 5.0%	—		1,099
Other	57		63
Total long-term debt	9,911		10,696
Total debt (4)	$	9,920	$	11,259

(1)We classified these commercial paper notes as short-term as of 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 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 at that time. We redeemed these senior notes on June 25, 2026.

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

(4)The fair value estimates for our senior notes, junior subordinated notes, commercial paper program and term loan are based upon observable market data and are classified in Level 2 of the fair value hierarchy. 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. Our fixed-rate senior notes and junior subordinated 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. The face value and estimated aggregate fair value of our fixed-rate senior notes and our junior subordinated notes are (in billions):


	September 30, 2026		December 31, 2025
Face value:
Senior notes	$	8.4	$	9.2
Junior subordinated notes	$	1.5	$	—

Estimated aggregate fair value:
Senior notes	$	7.8	$	9.0
Junior subordinated notes	$	1.5	$	—

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Credit Agreements

In June 2026, we entered into a new credit agreement that provides for a senior unsecured revolving credit facility with a committed borrowing capacity of $2.7 billion, of which $800 million is available for the issuance of letters of credit and $225 million is available for swing line loans. The new credit agreement replaced our previous credit agreements that provided for a $1.35 billion senior secured hedged inventory facility and a $1.35 billion senior unsecured revolving credit facility, which were scheduled to mature in August 2027 and August 2029, respectively. Subject to obtaining additional or increased lender commitments and other terms and conditions, the committed capacity may be increased to $4.0 billion. Borrowings accrue interest based, at our selection, on certain floating rate indices, in each case, plus an applicable margin. The new credit agreement has an initial maturity date of June 2031 and provides for one or more one-year extensions, subject to applicable approval and other terms and conditions. The covenants and events of default under this new credit agreement remain substantially unchanged from the previous agreements.

In conjunction with the closing of the new credit agreement in June 2026, we repaid in full and terminated all outstanding obligations under our $1.35 billion senior secured hedged inventory facility and $1.35 billion senior unsecured revolving credit facility. See Note 11 to our Consolidated Financial Statements included in Part IV of our 2025 Annual Report on Form 10-K for additional information regarding these agreements.

Term Loan Agreement

On November 26, 2025, we entered into a term loan agreement that provided for a $1.1 billion senior unsecured term loan. The closing of the Canadian NGL Business divestiture triggered mandatory prepayment of all amounts outstanding under the term loan agreement. See Note 2 for additional information about the Canadian NGL Business divestiture. Effective May 14, 2026, we terminated the term loan agreement and repaid all amounts outstanding thereunder.

Senior Notes

On June 25, 2026, we redeemed our $750 million, 4.50% senior notes that were due December 2026. We repaid these senior notes with proceeds from the sale of the Canadian NGL Business.

Junior Subordinated Notes

On September 14, 2026, we completed the offering of $700 million, 6.75% Series A junior subordinated notes (the “Series A Junior Subordinated Notes”) and $800 million, 7.00% Series B junior subordinated notes (the “Series B Junior Subordinated Notes”, and together with the Series A Notes, the “Junior Subordinated Notes”). The Junior Subordinated Notes were issued at a public offering price of 100% and are due on December 15, 2056. Interest on the Junior Subordinated Notes are payable semi-annually in arrears on June 15 and December 15 of each year, commencing on June 15, 2027, subject to our right to defer interest payments for up to 10 consecutive years. The Series A Junior Subordinated Notes bear interest at an initial rate of 6.75%, which will be reset on December 15, 2031 (the “Series A First Reset Date”) and each subsequent five-year anniversary of the Series A First Reset Date at a rate per annum equal to the then applicable Five-Year U.S. Treasury Rate plus a spread of 2.141%, provided that the interest rate will not reset below the initial interest rate of 6.75%. The Series B Junior Subordinated Notes bear interest at an initial rate of 7.00%, which will be reset on December 15, 2036 (the “Series B First Reset Date”, and together with the Series A First Reset Date, the “First Reset Date”) and each subsequent five-year anniversary of the Series B First Reset Date at a rate per annum equal to the then applicable Five-Year U.S. Treasury Rate plus a spread of 2.167%, provided that the interest rate will not reset below the initial interest rate of 7.00%. We may redeem all or any portion of the Junior Subordinated Notes at the redemption price in cash equal to 100% of the principal amount of each of the Junior Subordinated Notes to be redeemed, plus accrued and unpaid interest, at any time during the 90-day period prior to the applicable First Reset Date and on any applicable interest payment date thereafter. We may also redeem the Junior Subordinated Notes at other times as specified in the indenture governing the Junior Subordinated Notes. The Junior Subordinated Notes are not redeemable at the option of the holders. The Junior Subordinated Notes are unsecured obligations and rank junior and subordinate in right of payment to our existing and future senior indebtedness.

We used a portion of the net proceeds from this offering to repurchase all of our outstanding Series A and Series B preferred units. See Note 7 for additional information regarding the repurchase of Series A and Series B preferred units.

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Borrowings and Repayments

Total borrowings under our credit facilities and commercial paper program for the nine months ended September 30, 2026 and 2025 were approximately $37.1 billion and $38.7 billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately $38.1 billion and $39.1 billion for the nine months ended September 30, 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.

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. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At September 30, 2026 and December 31, 2025, we had outstanding letters of credit of $126 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

Issuances of common units under equity-indexed compensation plans	—	—	34,777
Outstanding at June 30, 2026	58,411,908	800,000	705,566,460

Repurchase of Series A preferred units	(58,411,908)	—	—
Issuances of common units under equity-indexed compensation plans	—	—	2,370,940

Outstanding at September 30, 2026	—	800,000	707,937,400


	Limited Partners
	Series A Preferred Units	Series B Preferred Units	Common Units
Outstanding at December 31, 2024	71,090,468	800,000	703,770,300
Repurchase of Series A preferred units	(12,678,560)	—	—

Issuances of common units under equity-indexed compensation plans	—	—	5,650
Outstanding at March 31, 2025	58,411,908	800,000	703,775,950
Repurchase and cancellation of common units under the Common Equity Repurchase Program	—	—	(476,695)
Issuances of common units under equity-indexed compensation plans	—	—	5,197
Outstanding at June 30, 2025	58,411,908	800,000	703,304,452

Issuances of common units under equity-indexed compensation plans	—	—	2,193,318
Outstanding at September 30, 2025	58,411,908	800,000	705,497,770

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Repurchase of Series A and Series B Preferred Units

On September 14, 2026, we repurchased all 58.4 million Series A preferred units outstanding at a redemption price of $28.88 per unit for a purchase price of approximately $1.687 billion, plus accrued and unpaid distributions through September 13, 2026 of approximately $29 million. The repurchase also resulted in the reduction of the remaining related Preferred Distribution Rate Reset Option liability of approximately $78 million. See Note 13 to our Consolidated Financial Statements included in Part IV of our 2025 Annual Report on Form 10-K for additional information regarding the Preferred Distribution Rate Reset Option. The difference between the cash we paid for the repurchase of such units and their carrying value on our balance sheet was $358 million. Such amount was considered a return to Series A preferred unitholders and thus reduced amounts attributable to our common unitholders in our Condensed Consolidated Statement of Changes in Partners’ Capital and the calculation of net income/(loss) per common unit. Certain of our Series A preferred units were held by funds affiliated with The Energy & Minerals Group (“EMG”), which is associated with a member of the board of directors of PAGP GP.

On October 9, 2026, we also repurchased all 0.8 million Series B preferred units outstanding at a redemption price of $1,000 per unit for a purchase price of approximately $800 million, plus accrued and unpaid distributions through October 8, 2026 of approximately $10 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 A and Series B preferred units.

Distributions to Our Unitholders

Series A Preferred Unit Distributions. Prior to our repurchase of all outstanding Series A preferred units in September 2026, distributions on the Series A preferred units accumulated and were 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 nine months of 2026, including distributions paid in connection with the redemption of Series A preferred units as discussed above (in millions, except per unit data):


			Series A Preferred Unitholders
Distribution Payment Date	Record Date (1)	Distribution Period	Cash Distribution		Distribution per Unit
September 14, 2026 (2)	N/A	July 1, 2026 through September 13, 2026	$	29	$	0.502
August 14, 2026	July 31, 2026	April 1, 2026 through June 30, 2026	$	36	$	0.615
May 15, 2026	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)Represents pro-rated distribution paid in connection with the redemption of all outstanding Series A preferred units on September 14, 2026.

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Series B Preferred Unit Distributions. Prior to our repurchase of all outstanding Series B preferred units on October 9, 2026, distributions on the Series B preferred units accumulated and were 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, including distributions paid in connection with the redemption of Series B preferred units as discussed above (in millions, except per unit data):


			Series B Preferred Unitholders
Distribution Payment Date	Record Date (1)	Distribution Period	Cash Distribution		Distribution per Unit
October 9, 2026 (2) (3)	N/A	August 15, 2026 through October 8, 2026	$	10	$	12.39
August 17, 2026	August 3, 2026	May 15, 2026 through August 14, 2026	$	16	$	20.50
May 15, 2026	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)Represents pro-rated distribution paid in connection with the redemption of all outstanding Series B preferred units on October 9, 2026.

(3)At September 30, 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 nine 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
November 13, 2026	October 30, 2026	July 1, 2026 through September 30, 2026	$	199	$	97	$	296	$	0.4175
August 14, 2026	July 31, 2026	April 1, 2026 through June 30, 2026	$	198	$	97	$	295	$	0.4175
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 September 30, 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”).

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Distributions to Noncontrolling Interests

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Permian JV	$	88	$	85	$	253	$	268
Cactus II	20		21		52		59
Red River	4		4		12		12
	$	112	$	110	$	317	$	339

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 September 30, 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.

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In the normal course of our operations, we purchase and sell commodities. We use derivatives to manage the associated risks and, in certain circumstances, to optimize profits. As of September 30, 2026, net derivative positions related to these activities included:

•A net long position of 9.2 million barrels associated with our crude oil purchases, which will be unwound ratably through December 2026 to match monthly average pricing.

•A net short time spread position of 2.1 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through January 2027.

•A net crude oil basis spread position of 1.7 million barrels at multiple locations through December 2027. These derivatives allow us to lock in grade and location basis differentials.

•A net short position of 11.5 million barrels through December 2028 related to anticipated net sales of crude oil inventory.

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 September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Product sales revenues	$	45	$	13	$	150	$	(29)
Field operating costs	—		—		2		3

Net income/(loss) from commodity derivative activity	$	45	$	13	$	152	$	(26)

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


	September 30, 2026		December 31, 2025
Initial margin	$	43	$	16
Variation margin posted	31		4
Letters of credit	(32)		(1)
Net broker receivable	$	42	$	19

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


	September 30, 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	$	17	$	(30)	$	30	$	17	$	18	$	(24)	$	19	$	13
Other long-term assets, net	—		—		—		—		1		—		—		1
Derivative Liabilities
Other current liabilities	61		(90)		12		(17)		(1)		—		—		(1)
Other long-term liabilities and deferred credits	13		(13)		—		—		10		(8)		—		2
Total	$	91	$	(133)	$	42	$	—	$	28	$	(32)	$	19	$	15

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 September 30, 2026, there was a net loss of $26 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 gain recognized in AOCI for derivatives (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Interest rate derivatives, net	$	—	$	4	$	—	$	9

At September 30, 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 Canadian NGL Business divestiture, we entered into a forward currency instrument (CAD$4.5 billion notional amount) to hedge currency exchange risk. The instrument was contingent upon the sale of the Canadian NGL Business occurring and settled at closing. The cost of the deal-contingent structure was embedded in the hedge rate. We settled this instrument and received net cash proceeds of $20 million at the closing of the Canadian NGL Business divestiture. As of December 31, 2025, the fair value of the instrument was an asset of $8 million, presented in “Other current assets” on our Condensed Consolidated Balance Sheet. For the nine months ended September 30, 2026, we recognized a gain of $12 million, which was included in “(Gains)/losses on asset sales, asset impairments and other, net” on our Condensed Consolidated Statements of Operations. For the three and nine months ended September 30, 2025, we recognized gains of $90 million and $41 million, respectively. See Note 2 for additional information regarding the Canadian NGL Business divestiture.

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Recurring Fair Value Measurements

Derivative Financial Assets and Liabilities

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


	Fair Value as of September 30, 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	$	(50)	$	8	$	(42)		$	(2)	$	(2)	$	(4)

Foreign currency derivatives	—		—		—			—		8		8

Total net derivative asset/(liability)	$	(50)	$	8	$	(42)		$	(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.

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. During the second quarter of 2026, we and certain Plains entities effectively settled promissory notes with a total face value of CAD$500 million (approximately $366 million) through a non-cash transaction upon the close of the Canadian NGL Business divestiture. See Note 2 for additional information about the Canadian NGL Business divestiture. Our outstanding related party notes receivable and related party notes payable balances were as follows (in millions):


	September 30, 2026		December 31, 2025
Related party notes receivable (1)	$	943	$	1,339
Related party notes payable (1)	$	943	$	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 $5 million and $30 million as of September 30, 2026 and December 31, 2025, respectively. Interest income/expense on the related party notes totaled $15 million, and $56 million for the three and nine months ended September 30, 2026, respectively, and $23 million and $65 million for the three and nine months ended September 30, 2025, respectively.

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Transactions with Other Related Parties

During the three and nine months ended September 30, 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 September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Revenues from related parties	$	12	$	12	$	38	$	35

Purchases and related costs from related parties	$	71	$	89	$	225	$	285

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


	September 30, 2026		December 31, 2025
Trade accounts receivable and other receivables, net from related parties (1)	$	32	$	49

Trade accounts payable to related parties (1) (2)	$	47	$	64

(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.

EMG. Certain funds affiliated with EMG and subsidiaries of EMG, which is associated with a member of the board of directors of PAGP GP, were associated with activity involving our Series A preferred units and recent acquisitions, respectively. See Note 7 and Note 12 for additional information.

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.

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Legal Proceedings — General

In the ordinary course of business, we are involved in various legal proceedings including those arising from regulatory and environmental matters. In connection with determining the probability of loss associated with such legal proceedings and whether any potential losses associated therewith are estimable, we take into account what we believe to be all relevant known facts and circumstances, and what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing agreements, laws and regulations. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully protect us from losses arising from current or future legal proceedings.

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

Environmental — General

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

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

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

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

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


	September 30, 2026		December 31, 2025
Other current liabilities	$	23	$	13
Other long-term liabilities and deferred credits	73		70
Total	$	96	$	83

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

Specific Legal, Environmental or Regulatory Matters

Line 901 Incident. In May 2015 we experienced a release of crude oil from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. Effective as of September 30, 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 amount is unchanged from our estimate as of June 30, 2026 and 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.

We believe we have accrued adequate amounts for all probable and reasonably estimable costs, and during the nine months ended September 30, 2026 and 2025, we did not recognize any costs related to the Line 901 incident. As of September 30, 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.

L48 Pipeline Release. In March 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 was initiated. 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 are subject to a $10 million self-insured retention. Through September 30, 2026, we incurred $13 million in connection with clean-up and remediation activities. We do not currently anticipate any additional costs associated with the site.

Line 63 Pipeline Strike. In May 2026, our subsidiary, Pacific Pipeline System LLC, experienced a crude oil release of approximately 587 barrels on a segment of the Line 63 pipeline in Los Angeles, California, resulting from a strike by a construction crew drilling for a fiber-optic line. Clean-up and remediation activities were conducted in cooperation with applicable state and federal regulatory agencies. Investigations were initiated by the California Office of the State Fire Marshall and the California Underground Safety Board. 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 are subject to a $10 million self-insured retention. We estimate that the aggregate cost we have or will incur with respect to the line strike incident will be approximately $40 million.

Canadian Competition Bureau Lawsuit. In connection with the closing of the sale of our Canadian NGL Business to Keyera, on May 5, 2026, the Canadian Commissioner of Competition (“Commissioner”) filed a lawsuit against Keyera, PMC ULC and Plains challenging the transaction on the basis that it allegedly harms competition in the NGL fractionation and storage market at Fort Saskatchewan. Because the lawsuit did not prevent the parties from closing, Keyera and Plains closed the transaction on May 12, 2026. In its lawsuit, the Commissioner seeks remedies that it believes would restore competition at Fort Saskatchewan to pre-transaction levels. As the owner of PMC ULC and the Canadian NGL Business, Keyera is primarily responsible for the lawsuit and we do not believe the ultimate resolution of the lawsuit will have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

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Note 11—Segment Information

During the third quarter of 2026, we effected changes in the primary financial information provided to and reviewed by our CODM (our Chief Executive Officer) for assessing performance and allocating resources. As a result, we now present one single, consolidated operating and reportable segment. Prior to the third quarter of 2026, we had defined our operating and reportable segments as Crude Oil and NGL. The change in our operating and reportable segment reflects changes in our business structure and the manner in which our CODM views and evaluates the business. These changes were driven by several factors, including (i) the completion of initiatives to (a) divest NGL assets (including the sale of the Canadian NGL Business in May of 2026), (b) enhance the connectivity of our core asset base, and (c) streamline operations and management with a focused emphasis on our consolidated crude oil business, and (ii) management of commercial opportunities and operations across North America with a focus on optimization of profit, without regard to market or geographic location. Our business is generally impacted by similar market fundamentals and requires the use of similar business strategies and assets, which includes crude oil pipelines, crude oil storage and marine terminals and related crude oil merchant activities. See Note 3 for a summary of the types of products and services from which we derive our revenues. All segment data and related disclosures for earlier periods presented herein have been recast to reflect the new reporting structure.

The measure of segment profit or loss used by our CODM that is most consistent with GAAP is Net income. Our CODM also uses Adjusted EBITDA attributable to PAA as an additional performance measure. Our CODM uses such measures to evaluate consolidated performance, including analyzing actual results compared to budget and guidance, to assess investment opportunities and to optimize and align assets to maximize returns to stakeholders.

Significant expenses regularly provided to the CODM, and which are included in Net income, are Purchases and related costs, Field operating costs, and General and administrative expenses, which are the same as the amounts presented on our Condensed Consolidated Statements of Operations. The measure of segment assets is total assets as reported on our Condensed Consolidated Balance Sheet. Additional consolidated segment information is presented in the table below (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Interest income (1)	$	24	$	28	$	75	$	81
Investment and acquisition capital expenditures (2) (3)	$	151	$	305	$	476	$	1,308
Maintenance capital expenditures (3)	$	32	$	36	$	105	$	112

(1)Included in “Other income, net” on our Condensed Consolidated Statements of Operations. Includes interest income associated with promissory notes by and among us and certain Plains entities. See Note 9 for additional information.

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

(3)These amounts combined represent total capital expenditures.

Note 12—Other Transactions

Acquisition. In September 2026, we entered into a definitive agreement to acquire SCM PR II, LLC and its subsidiaries (collectively, “Silver Creek”), which own an integrated crude oil gathering and transmission business in the Powder River Basin in Wyoming, including a 49% non-operated interest in the Powder River Gateway JV, for approximately $585 million. A cash deposit of approximately $20 million was paid upon signing in September 2026. Silver Creek was owned by subsidiaries of EMG, which is associated with a member of the board of directors of PAGP GP, and Tailwater Capital LLC. The transaction closed on October 1, 2026.

Investments in Unconsolidated Entities. During the third quarter of 2026, we determined that there was an other-than-temporary decline in the value of one of our equity method investments due to changes in market conditions and expectations regarding future cash flows and value. We recognized an impairment loss of $68 million related to the write-down of the portion of the carrying amount of our investment that exceeded its fair value. The estimated fair value (which we consider a Level 3 measurement in the fair value hierarchy) was determined using a combination of market and income approaches, including market-based information such as comparable transactions and other market evidence for similar midstream infrastructure assets, as well as estimates of future cash flows and other assumptions that market participants would use in pricing the investment.

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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

Sale of Canadian NGL Business

On May 12, 2026, we completed the sale of our Canadian NGL Business, pursuant to a definitive SPA with Keyera entered into on June 17, 2025. We determined that in conjunction with entering into the SPA, the operations of the Canadian NGL Business met the criteria for classification as held for sale and for discontinued operations reporting, as the sale represented a strategic shift that had a major effect on our operations and financial results. 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.

Segment Change

During the third quarter of 2026, we effected changes in the primary financial information provided to our CODM (our Chief Executive Officer) for assessing performance and allocating resources. As a result, we now present one single, consolidated operating and reportable segment. Prior to the third quarter of 2026, we had defined our operating and reportable segments as Crude Oil and NGL. See Note 11 to our Condensed Consolidated Financial Statements for further discussion of segment information.

In connection with this change, during the third quarter of 2026, the primary measures used by our CODM to evaluate segment performance were also updated to Net income and Adjusted EBITDA attributable to PAA. See the “—Non-GAAP Financial Measures” section below for our definition of Adjusted EBITDA attributable to PAA. All segment data and related disclosures for earlier periods presented herein have been recast to reflect the new segment reporting structure.

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Overview of Operating Results

Our 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.

We generate 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.

We recognized net income attributable to PAA of $2.345 billion for the nine months ended September 30, 2026 compared to net income attributable to PAA of $1.093 billion for the first nine 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 September 30,				Variance				Nine Months Ended September 30,				Variance
	2026		2025		$		%		2026		2025		$		%
Product sales revenues	$	14,700	$	11,150	$	3,550	32	%	$	43,946	$	32,389	$	11,557	36	%
Services revenues	473		428		45		11	%	1,388		1,309		79		6	%
Purchases and related costs	(14,030)		(10,585)		(3,445)		(33)	%	(42,078)		(30,862)		(11,216)		(36)	%
Field operating costs	(306)		(288)		(18)		(6)	%	(934)		(873)		(61)		(7)	%
General and administrative expenses	(78)		(83)		5		6	%	(270)		(251)		(19)		(8)	%
Depreciation and amortization	(235)		(230)		(5)		(2)	%	(721)		(696)		(25)		(4)	%
Gains/(losses) on asset sales, asset impairments and other, net	(8)		92		(100)		(109)	%	(14)		64		(78)		(122)	%
Equity earnings in unconsolidated entities	85		96		(11)		(11)	%	263		292		(29)		(10)	%
Gain on/(impairment of) investments in unconsolidated entities, net	(68)		—		(68)		N/A		(68)		31		(99)		**
Interest expense, net (1)	(131)		(135)		4		3	%	(451)		(395)		(56)		(14)	%
Other income, net (1)	19		14		5		36	%	69		70		(1)		(1)	%
Income tax expense from continuing operations	(8)		(6)		(2)		(33)	%	(109)		(17)		(92)		**
Income from continuing operations, net of tax	413		453		(40)		(9)	%	1,021		1,061		(40)		(4)	%


Income from discontinued operations, net of tax (2)	40		76		(36)		(47)	%	1,588		281		1,307		**
Net income	453		529		(76)		(14)	%	2,609		1,342		1,267		94	%
Net income attributable to noncontrolling interests	(90)		(88)		(2)		(2)	%	(264)		(249)		(15)		(6)	%
Net income attributable to PAA	$	363	$	441	$	(78)	(18)	%	$	2,345	$	1,093	$	1,252	115	%

Basic and diluted net income/(loss) per common unit:
Continuing operations	$	(0.12)	$	0.44	$	(0.56)	(127)	%	$	0.34	$	0.85	$	(0.51)	(60)	%
Discontinued operations	0.06		0.11		(0.05)		(45)	%	2.25		0.40		1.85		**
Basic and diluted net income/(loss) per common unit	$	(0.06)	$	0.55	$	(0.61)	(111)	%	$	2.59	$	1.25	$	1.34	107	%

Basic and diluted weighted average common units outstanding	707		704		3		—	%	706		704		2		—	%

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

(1)“Interest expense, net” and “Other income, net” include $15 million and $56 million for the three and nine months ended September 30, 2026, respectively, and $23 million and $65 million for the three and nine months ended September 30, 2025, respectively, 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 from discontinued operations, net of tax.

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Operating Data


	Three Months Ended September 30,		Variance			Nine Months Ended September 30,		Variance
Average Volumes	2026	2025	Volumes	%		2026	2025	Volumes	%

Crude oil pipeline tariff (by region) (1) (2)
Permian Basin	8,071	7,490	581	8	%	7,965	7,196	769	11	%
South Texas / Eagle Ford	505	538	(33)	(6)	%	515	524	(9)	(2)	%
Mid-Continent	578	564	14	2	%	543	506	37	7	%
Gulf Coast	187	227	(40)	(18)	%	212	220	(8)	(4)	%
Rocky Mountain	470	449	21	5	%	474	484	(10)	(2)	%
Western	353	283	70	25	%	325	273	52	19	%
Canada	343	332	11	3	%	348	342	6	2	%

Total crude oil pipeline tariff	10,507	9,883	624	6	%	10,382	9,545	837	9	%

(1)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.

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

Continuing Operations

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

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 September 30, 2026	$	67	$	107	$	86
Three Months Ended September 30, 2025	$	62	$	70	$	65

Nine Months Ended September 30, 2026	$	56	$	119	$	84
Nine Months Ended September 30, 2025	$	57	$	80	$	67

Product sales revenues (including the impact of derivative mark-to-market valuations) and purchases increased for the three and nine months ended September 30, 2026 compared to the same periods in 2025 primarily due to higher commodity prices and crude oil sales volumes in the 2026 periods.

Services revenues for the three and nine months ended September 30, 2026 increased compared to the same periods in 2025 primarily due to the impact of 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.

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Field Operating Costs

Field operating costs increased for the three and nine months ended September 30, 2026 compared to the same periods in 2025. The 2026 periods were primarily impacted by recently completed acquisitions, with recurring period-over-period cost increases being driven by (i) higher volumes, (ii) higher property taxes and (iii) higher environmental remediation costs, all partially offset by (iv) lower employee-related costs associated with the divestiture of certain trucking operations.

General and Administrative Expenses

The increase in general and administrative expenses for the nine months ended September 30, 2026 compared to the same period in 2025 was primarily due to the acceleration of certain expenses during the second quarter of 2026 resulting from exit costs associated with the Canadian NGL Business. This increase was partially offset by the impact of (i) lower information systems costs in the 2026 periods primarily due to the completion of certain systems conversion and integration work in the second quarter of 2025 and (ii) the recognition in the 2025 period of acquisition-related transaction costs. The exit costs associated with the Canadian NGL Business are excluded from our Non-GAAP, adjusted results. See “Non-GAAP Financial Measures” below for additional information.

Depreciation and Amortization

The increase in depreciation and amortization for the nine months ended September 30, 2026 compared to the same period in 2025 was largely driven by recently completed acquisitions.

Gains/Losses on Asset Sales, Asset Impairments and Other, Net

In anticipation of the closing of the sale of the Canadian NGL Business, which was completed on May 12, 2026, we entered into a deal-contingent forward currency instrument to hedge the currency exchange risk associated with the sale in CAD. The 2026 and 2025 periods presented were 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 2 to our Condensed Consolidated Financial Statements for additional information regarding the sale of the Canadian NGL Business. In addition, the 2026 periods were impacted by net losses on certain other asset divestitures.

Equity Earnings

Equity earnings in unconsolidated entities decreased for the three and nine months ended September 30, 2026 primarily due to the impact of long-haul contract rates on certain of our investments resetting to market in 2025.

Gain on/Impairment of Investments in Unconsolidated Entities, Net

In the third quarter of 2026, we recognized an impairment loss of $68 million due to changes in market conditions and expectations regarding future cash flows and value for one of our equity method investments. See Note 12 to our Condensed Consolidated Financial Statements for additional information.

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 and nine months ended September 30, 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.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Interest expense on third-party borrowings (1)	$	118	$	116	$	400	$	339
Interest expense on related party promissory notes (2)	15		23		56		65
Capitalized interest	(2)		(4)		(5)		(9)
	$	131	$	135	$	451	$	395

(1)The increase in interest expense for the nine-month 2026 period compared to the same period in 2025 was primarily driven by higher weighted-average third-party debt outstanding in the 2026 period, partially offset by lower weighted-average related party promissory notes in the 2026 period due to settlement of certain notes upon the close of the Canadian NGL Business divestiture. See Note 6 to our Condensed Consolidated Financial Statements for additional information regarding our outstanding debt. See Note 9 to our Condensed Consolidated Financial Statements for additional information regarding our related party promissory notes.

(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 September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Interest income on related party promissory notes (1)	$	15	$	23	$	56	$	65

Net gain/(loss) on foreign currency revaluation (2)	—		(15)		3		(13)



Contingent consideration fair value adjustment (3)	(5)		—		(11)		—
Other	9		6		21		18
	$	19	$	14	$	69	$	70

(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.

Income Tax Expense from Continuing Operations

The net unfavorable income tax variance from continuing operations for the nine months ended September 30, 2026 compared to the same period in 2025 was primarily due to tax impacts from certain planning and restructuring activities within our organizational structure in connection with the Canadian NGL Business divestiture. These included (i) current income tax expense of $311 million as a result of basis recapture and capital gains taxed at the applicable rates and withholding taxes on distributions, (ii) a partially offsetting $217 million deferred tax benefit primarily resulting from the transfer of the crude oil assets from PMC ULC to PCLP and (iii) current income tax expense of approximately $95 million primarily related to withholding taxes on distributions. These unfavorable impacts were partially offset by lower income within our Canadian operations as impacted by fluctuations of derivative mark-to-market valuations. See Note 2 to our Condensed Consolidated Financial Statements for additional information regarding the Canadian NGL Business divestiture.

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Noncontrolling Interests

The increase in amounts attributable to noncontrolling interests for the nine months ended September 30, 2026 compared to the same period in 2025 was primarily due to higher net income recognized by the Permian JV, largely due to higher volumes, as well as contributions from acquisitions completed by the Permian JV during 2025.

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

From June 17, 2025, the date we entered into the SPA with Keyera to sell the Canadian NGL Business, through the closing of the divestiture on May 12, 2026, management reviewed such business as a component of our overall company performance and ability to fund distributions to our unitholders in the near term. As such, 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), are presented on a consolidated basis (i.e., the aggregate of continuing operations and discontinued operations) to provide relevant and useful information regarding our historical performance and results of operations and to assist in reconciling results presented in historical periods.

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, (a) 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, (b) long-term inventory costing adjustments, (c) charges for obligations that are expected to be settled with the issuance of equity instruments, (d) 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 “—Overview of Operating Results.”

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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 September 30,				Variance				Nine Months Ended September 30,				Variance
	2026		2025		$		%		2026		2025		$		%
Net income	$	453	$	529	$	(76)	(14)	%	$	2,609	$	1,342	$	1,267	94	%
Less: Income from discontinued operations, net of tax	(40)		(76)		36		47	%	(1,588)		(281)		(1,307)		(465)	%
Income from continuing operations, net of tax	413		453		(40)		(9)	%	1,021		1,061		(40)		(4)	%
Interest expense, net (1)	116		112		4		4	%	395		330		65		20	%
Income tax expense	8		6		2		33	%	109		17		92		**
Depreciation and amortization	235		230		5		2	%	721		696		25		4	%
(Gains)/losses on asset sales, asset impairments and other, net	8		(92)		100		109	%	14		(64)		78		122	%
(Gain on)/impairment of investments in unconsolidated entities, net	68		—		68		N/A		68		(31)		99		319	%
Depreciation and amortization of unconsolidated entities (2)	22		21		1		5	%	63		62		1		2	%
Selected Items Impacting Comparability:
Derivative activities and inventory valuation adjustments (3)	25		(30)		55		**		81		(2)		83		**
Long-term inventory costing adjustments (4)	(72)		10		(82)		**		(118)		27		(145)		**
Deficiencies under minimum volume commitments, net (5)	9		(6)		15		**		(27)		(21)		(6)		**
Equity-indexed compensation expense (6)	11		10		1		**		30		28		2		**
Foreign currency revaluation (7)	1		12		(11)		**		(15)		19		(34)		**

Contingent consideration fair value adjustment (8)	5		—		5		**		11		—		11		**
Impact from exit of Canadian NGL Business (9)	(2)		—		(2)		**		33		—		33		**
Transaction-related expenses (10)	—		—		—		**		—		7		(7)		**
Selected Items Impacting Comparability - Adjusted EBITDA	(23)		(4)		(19)		**		(5)		58		(63)		**
Adjusted EBITDA attributable to discontinued operations (11)	—		80		(80)		(100)	%	191		370		(179)		(48)	%
Adjusted EBITDA	$	847	$	806	$	41	5	%	$	2,577	$	2,499	$	78	3	%
Adjusted EBITDA attributable to noncontrolling interests (12)	(136)		(137)		1		1	%	(398)		(404)		6		1	%
Adjusted EBITDA attributable to PAA	$	711	$	669	$	42	6	%	$	2,179	$	2,095	$	84	4	%

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	Three Months Ended September 30,				Variance				Nine Months Ended September 30,				Variance
	2026		2025		$		%		2026		2025		$		%
Adjusted EBITDA (13)	$	847	$	806	$	41	5	%	$	2,577	$	2,499	$	78	3	%
Interest expense, net of certain non-cash and other items (14)	(112)		(109)		(3)		(3)	%	(381)		(320)		(61)		(19)	%
Maintenance capital from continuing operations (15)	(32)		(36)		4		11	%	(105)		(112)		7		6	%
Maintenance capital from discontinued operations (15)	—		(20)		20		100	%	(20)		(49)		29		59	%
Investment capital of noncontrolling interests (16)	(34)		(25)		(9)		(36)	%	(83)		(89)		6		7	%
Current income tax benefit/(expense), net of certain tax effects related to the Canadian NGL Business divestiture (17)	4		(12)		16		133	%	(66)		(72)		6		8	%
Distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings (18)	(3)		(9)		6		**		(14)		10		(24)		**
Distributions to noncontrolling interests (19)	(112)		(110)		(2)		(2)	%	(317)		(339)		22		6	%
Implied DCF	$	558	$	485	$	73	15	%	$	1,591	$	1,528	$	63	4	%
Preferred unit distributions (19)	(82)		(54)		(28)		(52)	%	(186)		(171)		(15)		(9)	%
Implied DCF Available to Common Unitholders	$	476	$	431	$	45	10	%	$	1,405	$	1,357	$	48	4	%
Common unit cash distributions (19)	(295)		(267)						(884)		(802)
Implied DCF Excess (20)	$	181	$	164					$	521	$	555

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

(1)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.

(2)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 attributable to PAA, similar to our consolidated assets.

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

(4)We carry 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 Adjusted EBITDA attributable to PAA.

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

(6)Our total equity-indexed compensation expense includes expense associated with awards that will be settled in units and awards that will be settled in cash. The awards that will be settled in units are included in our diluted net income per unit calculation when the applicable performance criteria have been met. We exclude compensation expense associated with these awards in determining Adjusted EBITDA attributable to PAA 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 Adjusted EBITDA attributable to PAA. 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.

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

(8)We agreed to potential earnout payments associated with recently completed acquisitions, primarily our Cactus III acquisition. We do not consider the non-cash change in the estimated fair value of such earnout payments as integral to our core operating performance, and we therefore exclude the change in determining Adjusted EBITDA attributable to PAA.

(9)Represents the acceleration of certain general and administrative expenses associated with exit activities related to the Canadian NGL Business divestiture in May 2026. Such costs are not integral to our core operating performance and were therefore excluded in determining Adjusted EBITDA attributable to PAA. See Note 2 to our Condensed Consolidated Financial Statements for additional information regarding the Canadian NGL Business divestiture.

(10)Primarily related to deal-specific costs incurred during the periods presented. Such costs are not integral to our core operating performance and were therefore excluded in determining Adjusted EBITDA attributable to PAA.

(11)Reflects amounts attributable to discontinued operations in the calculation of Adjusted EBITDA attributable to PAA. See the table below for a reconciliation to the most directly comparable measure as reported in accordance with GAAP.

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

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

(14)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.

(15)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.

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

(17)Includes current income tax expense from continuing operations and discontinued operations, adjusted for current income tax expense associated with certain planning and restructuring activities within our organizational structure in connection with the Canadian NGL Business divestiture that had income tax consequences that required recognition

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during the first and second quarters of 2026. See Note 2 to our Condensed Consolidated Financial Statements for additional information regarding the Canadian NGL Business divestiture.

(18)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).

(19)Cash distributions paid during the period presented.

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

The following tables set forth the reconciliation of the non-GAAP financial performance measures Adjusted EBITDA attributable to Discontinued Operations to Income from Discontinued Operations, Net of Tax (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Income from discontinued operations, net of tax	$	40	$	76	$	1,588	$	281
Income tax expense from discontinued operations	—		27		77		96
Depreciation and amortization from discontinued operations	—		—		—		57
(Gains)/losses on asset sales, net from discontinued operations	(40)		2		(1,645)		15
Adjustments attributable to discontinued operations:
Derivative activities and inventory valuation adjustments	—		(18)		186		(73)
Long-term inventory costing adjustments	—		4		(4)		3
Rail fleet amortization expense related to discontinued operations (1)	—		(10)		(11)		(10)
Foreign currency revaluation	—		(1)		—		1
Adjusted EBITDA attributable to discontinued operations	$	—	$	80	$	191	$	370

(1)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. We include an adjustment for the impact of amortization of the rail fleet associated with the Canadian NGL Business in our calculation of Adjusted EBITDA attributable to PAA. See Note 2 for additional information regarding the sale of the Canadian NGL Business.

Analysis of Adjusted EBITDA attributable to PAA

Adjusted EBITDA attributable to PAA for the three and nine months ended September 30, 2026 increased versus comparable results for the three and nine months ended September 30, 2025. The benefit to the 2026 period results from (i) contributions from the Cactus III acquisition completed in the fourth quarter of 2025, (ii) volume growth across our pipeline systems largely driven by increased production in the Permian Basin region and (iii) market opportunities and optimization initiatives. These favorable impacts were partially offset by (iv) the impact from certain Permian long-haul contract rates resetting to market in 2025, (v) higher operating costs driven by environmental remediation expenses and property tax expense and (vi) contributions in the 2025 periods from the Canadian NGL Business, which was sold in May 2026.

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Liquidity and Capital Resources

General

Our primary sources of liquidity are (i) cash flow from operating activities and (ii) borrowings under our credit facility 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 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 and preferred equity. We generally expect to fund our short-term cash requirements through cash flow generated from operating activities and/or borrowings under our credit facility 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 September 30, 2026, we had a working capital surplus of $597 million and approximately $3.6 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 September 30, 2026
Availability under senior unsecured revolving credit facility (1) (2)	$	2,671

Amounts outstanding under commercial paper program (3)	—
Subtotal	2,671
Cash and cash equivalents	879
Total	$	3,550

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

(2)Available capacity under our credit facility was reduced by outstanding letters of credit issued under the facility of $29 million.

(3)We borrowed approximately $650 million under our commercial paper program subsequent to September 30, 2026 to fund a portion of our acquisition activity and Series B preferred unit repurchase in October 2026.

In June 2026, we entered into a new credit agreement to facilitate the renewal and extension of our credit facilities. Our $1.35 billion senior secured hedged inventory facility with maturity date of August 2027 and $1.35 billion senior unsecured revolving credit facility with maturity date of August 2029 were replaced with a $2.7 billion senior unsecured revolving credit facility with an initial maturity in June 2031. The new credit agreement provides for one or more one-year extensions and have accordion features which, subject to receipt of incremental lender approval and other terms and conditions, permit us to increase borrowing capacity to $4.0 billion. The covenants and events of default under the new credit agreement remain substantially unchanged from the previous agreements. See Note 6 to our Condensed Consolidated Financial Statements for additional information.

Usage of our credit facility, and, in turn, our commercial paper program, is subject to ongoing compliance with covenants. The credit agreement for our revolving credit facility (which impacts our ability to access our commercial paper program because it provides the financial backstop that supports our short-term credit ratings) and the indentures governing our senior notes contain cross-default provisions. A default under our credit agreement 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 agreement, our ability to make distributions of available cash is not restricted. We were in compliance with the covenants contained in our credit agreement and indentures as of September 30, 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 facility, 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 (in millions):


	Nine Months Ended September 30,
		2026		2025
Net cash provided by operating activities		$	2,042	$	2,150
Adjustments to reconcile net cash provided by operating activities to adjusted free cash flow:
Net cash provided by/(used in) investing activities (1)		3,003		(1,831)
Cash contributions from noncontrolling interests		—		34
Cash distributions paid to noncontrolling interests (2)		(317)		(339)
Proceeds from the issuance of related party notes (1)		—		330

Adjusted Free Cash Flow		$	4,728	$	344
Cash distributions (3)		(1,070)		(973)
Adjusted Free Cash Flow after Distributions (4)		$	3,658	$	(629)

(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 provided by/(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 facility 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. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—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 nine months of 2026 and 2025 was $1.883 billion and $1.836 billion, 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
	Nine Months Ended September 30,				Nine Months Ended September 30,				Nine Months Ended September 30,
Capital Expenditures (3) (4)	2026		2025		2026		2025		2026		2025













Investment capital	$	253	$	401	$	336	$	493	$	326	$	404
Maintenance capital	110		149		125		161		105		112
Acquisition capital	149		832		150		904		150		904
	$	512	$	1,382	$	611	$	1,558	$	581	$	1,420

(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 $10 million and $20 million for investment and maintenance capital for the nine months ended September 30, 2026, respectively. Capital expenditures for investment and maintenance capital related to discontinued operations were $89 million and $49 million for the nine months ended September 30, 2025, respectively. There was no 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.”

(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.”

In September 2026, we entered into a definitive agreement to acquire SCM PR II, LLC, which owns an integrated crude oil gathering and transmission business in the Powder River Basin, including a 49% non-operated interest in the Powder River Gateway JV, for approximately $585 million. The transaction closed on October 1, 2026. We used cash on hand and commercial paper borrowings to fund this acquisition. See Note 12 to our Condensed Consolidated Financial Statements for additional information regarding this transaction.

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Projected 2026 Capital Expenditures. Total investment capital for the year ending December 31, 2026 is currently projected to be approximately $535 million ($425 million net to our interest), which includes approximately $10 million related to discontinued operations of the Canadian NGL Business prior to the completion of the divestiture in May 2026. 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 $195 million ($175 million net to our interest), which includes approximately $20 million related to discontinued operations of the Canadian NGL Business prior to the completion of the divestiture in May 2026. Note that potential variation to current capital cost estimates may result from (i) changes to project design, (ii) final cost of materials and labor and (iii) timing of incurrence of costs due to uncontrollable factors such as receipt of permits or regulatory approvals and weather.

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 owned the Canadian NGL Business. The transaction closed on May 12, 2026, and, pursuant to the SPA, we received cash consideration of approximately CAD$5.390 billion (approximately $3.927 billion, or approximately $3.527 billion, net of cash divested), including working capital and other certain post-closing adjustments as defined in the SPA. We used the net proceeds to reduce leverage, which included the repayment of outstanding borrowings under our commercial paper program and term loan, as well as the repayment of $750 million, 4.50% senior notes that were due December 2026 and the repurchase of a portion of our Series A and Series B preferred units in September and October 2026, respectively. See Note 2 to our Condensed Consolidated Financial Statements for additional information regarding the 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 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 contango market activities, and the payment of distributions to our unitholders and noncontrolling interests.

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Borrowings and Repayments Under Credit Agreements and Term Loan

During the nine months ended September 30, 2026, we had net repayments under our credit facilities and commercial paper program of $970 million. The net repayments resulted primarily from cash flow from operating activities and proceeds from the sale of the Canadian NGL Business, which offset borrowings during the period related to funding needs for the repurchase of all outstanding Series A preferred units in September 2026, capital investments, inventory purchases and other general partnership purposes. See Note 7 to our Condensed Consolidated Financial Statements for more information regarding the repurchase of Series A preferred units.

During the nine months ended September 30, 2025, we had net repayments under our commercial paper program of $393 million. The net repayments resulted primarily from cash flow from operating activities and proceeds from the issuance of $1.25 billion aggregate principal amount of senior notes in September 2025, which offset borrowings during the period related to funding needs for capital investments, inventory purchases and other general partnership purposes.

On May 14, 2026, in connection with the closing of the Canadian NGL Business divestiture, we terminated the senior unsecured term loan agreement and repaid the outstanding borrowings of $1.1 billion. We used a portion of the proceeds from the sale of the Canadian NGL Business to fund the repayment. See Note 2 and Note 6 to our Condensed Consolidated Financial Statements for additional information regarding the Canadian NGL Business divestiture and the term loan agreement, respectively.

Senior Notes

On June 25, 2026, we redeemed our $750 million, 4.50% senior notes that were due December 2026. We repaid these senior notes with proceeds from the sale of the Canadian NGL Business.

Junior Subordinated Notes

In September 2026, we completed the offering of $700 million, 6.75% Series A junior subordinated notes and $800 million, 7.00% Series B junior subordinated notes. These notes were issued at a public offering price of 100% and are due on December 15, 2056. Interest payments on these notes are due on June 15 and December 15 of each year, commencing on June 15, 2027, subject to our right to defer interest payments for up to 10 consecutive years. We used the net proceeds from this offering of approximately $1.479 billion, after deducting the underwriting discount and offering expenses, together with cash on hand and commercial paper borrowings, to fund the repurchase on September 14, 2026 of all outstanding Series A preferred units and the repurchase on October 9, 2026 of all outstanding Series B preferred units. See Note 7 to our Condensed Consolidated Financial Statements for more information regarding the repurchase of our Series A and Series B preferred units.

Common Equity Repurchase Program

There were no repurchases under the Common Equity Repurchase Program (the “Program”) during the nine months ended September 30, 2026. We repurchased approximately 0.5 million common units under the Program through open market purchases that settled during the nine months ended September 30, 2025 for a total purchase price of $8 million, including commissions and fees. The repurchased common units were canceled immediately upon acquisition, as were the PAGP Class C shares held by us associated with the repurchased common units. At September 30, 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.

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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 September 30, 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 nine months ended September 30, 2026.

Series A and Series B Preferred Unit Repurchase

See Note 7 to our Condensed Consolidated Financial Statements for more information regarding these repurchases.

Distributions to Our Unitholders

Series A preferred unitholders. On September 14, 2026, we paid a final quarterly cash distribution of approximately $0.502 per unit to Series A preferred unitholders for the period from July 1, 2026 through September 13, 2026 and repurchased all 58.4 million Series A preferred units outstanding.

Series B preferred unitholders. On October 9, 2026, we paid a final quarterly cash distribution of approximately $12.39 per unit to Series B preferred unitholders for the period from August 15, 2026 through October 8, 2026 and repurchased all 0.8 million Series B preferred units outstanding.

Common Unitholders. On November 13, 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 October 30, 2026 for the period from July 1, 2026 through September 30, 2026.

See Note 7 to our Condensed Consolidated Financial Statements for details of distributions paid during or pertaining to the first nine 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 September 30, 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 nine months ended September 30, 2026.

Contingencies

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

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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.

The following table includes our best estimate of the amount and timing of these payments as of September 30, 2026 (in millions):


	Remainder of 2026		2027		2028		2029		2030		2031 and Thereafter		Total
Crude oil and other purchases (1)	$	10,508	$	34,375	$	31,403	$	29,647	$	25,436	$	64,026	$	195,395

(1)Amounts are primarily based on estimated volumes and market prices based on average activity during September 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. 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 September 30, 2026 and December 31, 2025, we had outstanding letters of credit of approximately $126 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:

•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 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 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;

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•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 resulting changes in pricing conditions or transportation throughput requirements;

•unanticipated changes in crude oil 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;

•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 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;

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•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;

•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 and other petroleum products.

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 and interest 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 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 September 30, 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	$	(42)	$	(9)	$	9


Total fair value	$	(42)

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 September 30, 2026. All of our senior notes are fixed rate notes and thus are not subject to interest rate risk. Our junior subordinated notes bear interest at fixed rates for initial periods generally ranging from five to ten years, after which the interest rates reset every five years. We did not have any variable rate debt outstanding at September 30, 2026. The average interest rate on variable rate debt that was outstanding during the nine months ended September 30, 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.

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 September 30, 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. On October 9, 2026, we repurchased all outstanding Series B preferred units. See Note 7 to our Condensed Consolidated Financial Statements for additional information regarding the repurchase and 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.

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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 September 30, 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 third 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

The Omnibus Agreement, entered into as part of the Simplification Transactions, which closed on November 15, 2016, provides for the mechanics by which (i) the total number of PAGP’s outstanding Class A shares will equal the number of AAP units held by PAGP, and (ii) the total number of our common units held by AAP will equal the sum of the number of outstanding Class A units of AAP (“AAP units”) and the number of AAP units that are issuable to the holders of vested and earned Class B units of AAP (“AAP Management Units”). As such, we are obligated to issue common units to AAP in connection with PAGP’s issuance of Class A shares upon PAGP LTIP award vestings. During the three months ended September 30, 2026, we issued 59,200 common units to AAP in connection with PAGP LTIP award vestings. This issuance was exempt from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof.

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 September 30, 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

2.1 *	—	Share Purchase Agreement, dated as of June 17, 2025, by and between Plains Midstream Luxembourg S.A.R.L. and Keyera Corp. (portions of this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (incorporated by reference to Exhibit 2.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2025).

2.2 *	—	First Amendment to Share Purchase Agreement, dated as of May 11, 2026, by and between Plains Midstream Luxembourg S.A.R.L. and Keyera Corp. (portions of this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (incorporated by reference to Exhibit 2.2 to our Current Report on Form 8-K filed May 12, 2026).

2.3 *	—	Second Amendment to Share Purchase Agreement, dated as of May 12, 2026, by and between Plains Midstream Luxembourg S.A.R.L. and Keyera Corp. (portions of this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (incorporated by reference to Exhibit 2.3 to our Current Report on Form 8-K filed May 12, 2026).

2.4 *	—	Third Amendment to Share Purchase Agreement, dated as of May 12, 2026, by and between Plains Midstream Luxembourg S.A.R.L. and Keyera Corp. (portions of this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (incorporated by reference to Exhibit 2.4 to our Current Report on Form 8-K filed May 12, 2026).

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).

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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).

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).

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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	—	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).

4.9	—	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).

4.10	—	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).

4.11	—	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).

4.12	—	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).

4.13	—	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).

4.14	—	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).

4.15	—	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).

4.16	—	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).

4.17	—	Subordinated Indenture, dated September 14, 2026, by and between Plains All American Pipeline, L.P. 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 14, 2026 ).

4.18	—	Fi rst Supplemental Indenture, dated September 14, 2026, by and between Plains All American Pipeline, L.P. and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed September 14, 2026 ).

4.19	—	S econd Supplemental Indenture, dated September 14, 2026, by and between Plains All American Pipeline, L.P. and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.4 to our Current Report on Form 8-K filed September 14, 2026 ).

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10.1	—	Credit Agreement dated as of June 12, 2026, among Plains All American Pipeline, L.P., Plains Marketing, L.P. and Plains Canada Liquid Pipelines ULC, as Borrowers; certain subsidiaries of Plains All American Pipeline, L.P. from time to time party thereto, as Designated Borrowers; Bank of America, N.A., as Administrative Agent and Swing Line Lender; Bank of America, N.A., PNC Bank, National Association and Wells Fargo Bank, National Association, as L/C Issuers; and the other Lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed June 17, 2026).

10.2 **†	—	F orm of LTIP Grant Letter dated August 13, 2026 (Named Executive Officers).

10.3 **†	—	Form of LTIP Grant Letter dated August 13, 2026 (Directors ).

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.

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)

* Certain information has been omitted from this exhibit as such omitted information is both (i) not material and (ii) the

type of information that the registrant treats as private or confidential.

** Management compensatory plan or arrangement.

† 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)

November 6, 2026

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

November 6, 2026

	By:	/s/ Russ Montgomery
		Russ Montgomery,
		Vice President, Accounting and Chief Accounting Officer of Plains All American GP LLC
		(Principal Accounting Officer)

November 6, 2026

Document

EXHIBIT 10.2

https://cdn.kscope.io/9e89342ec6fc47d8c828ea80c0a8df8f-plainsofficerlogo.jpg

2026 Regular Annual LTIP Grant

Section 16 Officers

August 13, 2026

«Section 16 Officer»

«Address»

Re: Grant of Phantom Units

Dear «Salutation»:

I am pleased to inform you that, subject to the terms hereof, you have been granted a target number of Phantom Units equal to «LTIP_Grant» as of the above date pursuant to the Company’s «LTIP_Plan» Long-Term Incentive Plan (the “Plan”). In addition, in tandem with each Phantom Unit you have been granted a distribution equivalent right (a “DER”). A DER represents the right to receive a cash payment equivalent to the amount, if any, paid in cash distributions on one Common Unit of Plains All American Pipeline, L.P. (“PAA” or the “Partnership”) to the holder of such Common Unit. The terms and conditions of this grant are as set forth below.

1.Subject to the further provisions hereof, your Phantom Units shall vest (become payable in the form of one Common Unit of PAA for each Phantom Unit that vests) as set forth below. With respect to Tranche 2 and Tranche 3 below, the actual number of Phantom Units that vest may be lower or higher than the percentage of target Phantom Units associated with such Tranche.

a.50% of your Phantom Units (“Tranche 1”) will vest on the August 2029 Distribution Date.

b.25% of your Phantom Units (“Tranche 2”) will vest pursuant to the terms and conditions described in Exhibit A attached hereto.

c.25% of your Phantom Units (“Tranche 3”) will vest pursuant to the terms and conditions described in Exhibit B attached hereto.

d.Any Tranche 2 or Tranche 3 Phantom Units that are determined not to have vested as of the August 2029 Distribution Date shall expire effective as of such date.

2.Subject to the further provisions hereof, your DERs shall vest (become payable in cash) as follows:

a.The DERs associated with Tranche 1 will begin accruing on the November 2026 Distribution Date and will continue to accrue until the August 2027 Distribution Date, on which date such accrued but unpaid DERs will vest and be paid in a lump sum. Beginning on the November 2027 Distribution Date, such

333 Clay Street, Suite 1600 (77002) ■ P.O. Box 4648 ■ Houston, Texas 77210-4648 ■ 713-646-4100

«Section 16 Officer»

August 13, 2026

Page 2

vested DERs will be paid quarterly until the associated Phantom Units vest or are forfeited pursuant to the terms hereof.

b.The DERs associated with Tranches 2 and 3 will begin accruing on the November 2026 Distribution Date and will continue to accrue until the associated Phantom Units vest or are forfeited pursuant to the terms hereof. Until such time as a final determination has been made regarding the number of Phantom Units that have vested for Tranche 2 and Tranche 3, such accruals will be based on the assumption that the final “Payout Percentage” as determined pursuant to Exhibit A or Exhibit B, as applicable, equals 100%. Once the final Payout Percentages and the final number of Phantom Units vesting for Tranche 2 and Tranche 3 have been determined, such accrued amounts shall be adjusted upward or downward, as applicable, so that they equal the total amount that would have been accrued in respect of the DERs associated with such vested Phantom Units had the accrual been based on such number of vested Phantom Units commencing on the November 2026 Distribution Date. Unless the Phantom Units subject to this award are forfeited or vest prior to the August 2029 Distribution Date pursuant to paragraphs 5, 6, 7 or 8 below, all accrued and unpaid DERs associated with Tranche 2 and Tranche 3 shall be paid on the August 2029 Distribution Date or as soon thereafter as is administratively practicable.

3.The number of Phantom Units and DERs subject to this award, and with respect to the Phantom Units comprising Tranche 3, the distributable cash flow level required for vesting of such Phantom Units, shall be proportionately reduced or increased for any split or reverse split, respectively, of PAA Common Units, or any event or transaction having a similar effect.

4.Upon vesting of any Phantom Units, an equivalent number of DERs will expire. Any such DERs that are payable on the Distribution Date on which the Phantom Units vest, shall be payable on such Distribution Date prior to their expiration.

5.In the event of the termination of your employment with the Company and its Affiliates for any reason (other than in connection with a Change in Status, Retirement or by reason of your death or “disability,” as defined in paragraph 6 below), all of your then outstanding Phantom Units and DERs shall automatically be forfeited as of the date of termination; provided, however, that if the Company or its Affiliates terminate your employment other than as a result of a Termination for Cause, the following provisions shall apply: (i) if such termination takes place prior to the first anniversary of the date of this grant, all of your then outstanding Phantom Units and DERs shall automatically be forfeited as of the date of termination; and (ii) if such termination takes place after the first anniversary of the date of this grant, a “pro rata portion” of the target number of your then outstanding Phantom Units and DERs shall be deemed nonforfeitable on the date of termination and shall vest on the next following Distribution Date. The “pro

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rata portion” of Phantom Units vesting pursuant to clause (ii) immediately preceding shall be determined by multiplying the target number of your then outstanding Phantom Units by a fraction equal to the number of days between the grant date and the date of termination divided by the number of days between the grant date and the August 2029 Distribution Date (1,097). If the resulting amount includes a fraction, it will be rounded down to the nearest whole number.

6.In the event of the termination of your employment with the Company and its Affiliates by reason of your death or your “disability” (a physical or mental infirmity that impairs your ability substantially to perform your duties for a period of eighteen months or that the Company otherwise determines constitutes a “disability”), the following provisions shall apply: (i) if such termination takes place prior to the first anniversary of the date of this grant, all of your then outstanding Phantom Units and DERs shall automatically be forfeited as of the date of termination; and (ii) if such termination takes place on or after the first anniversary of the date of this grant, (x) all of your then outstanding Phantom Units (which shall be equal to the target number of Phantom Units specified in the first paragraph hereof) shall be deemed nonforfeitable on the date of termination and shall vest on the next following Distribution Date, and (y) any DERs associated with such unvested, nonforfeitable Phantom Units shall not be forfeited on the date of termination, but shall be payable and shall expire on the next following Distribution Date. As soon as administratively practicable after the vesting of any Phantom Units pursuant to this paragraph 6, payment will be made in cash in an amount equal to the Market Value of the number of Phantom Units vesting.

7.In the event of a Change in Status, (i) all of your then outstanding Phantom Units (which shall be equal to the target number of Phantom Units specified in the first paragraph hereof, except that the Compensation Committee shall have the discretion to adjust the payout level for any Tranche 2 or Tranche 3 Phantom Units based on the performance of the Company under the applicable performance metric taking into account such Change of Control transaction, in each case as reasonably determined by the Compensation Committee) shall be deemed nonforfeitable on such date and shall vest on the next following Distribution Date, and (ii) any DERs associated with such unvested, nonforfeitable Phantom Units shall not be forfeited on such date, but shall be payable and shall expire on the next following Distribution Date.

8.In the event of the termination of your employment with the Company and its Affiliates due to your Retirement, the following provisions shall apply: (i) if such termination takes place prior to the first anniversary of the date of this grant, all of your then outstanding Phantom Units and DERs shall automatically be forfeited as of the date of termination; and (ii) if such termination takes place on or after the first anniversary of the date of this grant, (x) all of your then outstanding Phantom Units (which shall be equal to the target number of Phantom Units specified in the first paragraph hereof) shall be deemed nonforfeitable on the date of termination and shall vest on the next

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Page 4

following Distribution Date, and (y) any DERs associated with such unvested, nonforfeitable Phantom Units shall not be forfeited on the date of termination, but shall be payable and shall expire on the next following Distribution Date.

9.Upon payment pursuant to a DER, the Company will withhold any taxes due from your compensation as required by law. Upon vesting of a Phantom Unit, the Company will withhold any taxes due from your compensation as required by law, which (in the sole discretion of the Company) may include withholding a number of Common Units otherwise payable to you.

As used herein, (i) the “Company” refers to Plains All American GP LLC; (ii) “Distribution Date” means the day in February, May, August or November in any year (as context dictates) that is 45 days after the end of the most recently completed calendar quarter (or, if not a business day, the closest previous business day); (iii) “Market Value” means the average of the closing sales prices for a Common Unit on Nasdaq for the five trading days preceding the then most recent “ex dividend” date for payment of a distribution by the Partnership; and (iv) “Retirement” means termination from full-time employment on terms and timing as approved by the CEO (or by the Board in the case of the CEO).

The phrase “Change in Status” means (A) the termination of your employment by the Company other than a Termination for Cause, within two and a half months prior to or one year following a Change of Control (the “Protected Period”), or (B) the termination of your employment by you due to the occurrence during the Protected Period, without your written consent, of (i) any material diminution in your authority, duties or responsibilities, (ii) any material reduction in your base salary, or (iii) any other action or inaction that constitutes a material breach of this Agreement by the Company. A termination by you pursuant to (B) above shall not be a Change in Status unless (1) you provide written notice to the Company of the condition in (B)(i), (ii) or (iii) that would constitute a Change in Status within 90 days of the initial existence of the condition, and (2) the Company fails to remedy the condition within the 30-day period following such notice.

The phrase “Change of Control” means, and shall be deemed to have occurred upon the occurrence of, one or more of the following events:

(i)any Person (other than Plains GP Holdings, L.P. (“PAGP”) and any affiliate of PAGP that is controlled by PAGP) becomes the beneficial owner, directly or indirectly (in one transaction or a series of related transactions and whether by merger or otherwise), of 50% or more of the membership interest in PAA GP Holdings LLC, a Delaware limited liability company (“PAGP GP”)1;

1 For the avoidance of doubt, the ownership by a Person of PAGP Class A or Class B shares (or combination thereof) that represent 50% or more of the outstanding Class A and B shares of PAGP (in the aggregate) constitutes indirect ownership of 50% or more of the membership interests in PAGP GP for so long as PAGP directly owns 50% or more of such membership interests in PAGP GP.

«Section 16 Officer»

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(ii)any Person (other than PAGP GP, PAGP or any affiliate of PAGP that is controlled by PAGP) acquires (in one transaction or a series of related transactions and whether by merger or otherwise) direct or indirect control of the general partner interest of PAGP;

(iii)PAGP ceases to retain direct or indirect control (in one transaction or a series of related transactions and whether by merger or otherwise) of the general partner of the Partnership; or

(iv)the consummation of a reorganization, merger or consolidation with, or any direct or indirect sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Partnership to, one or more Persons (other than PAGP or any affiliates of PAGP that are controlled by PAGP).

As used in this definition, “Person” shall include any “partnership, limited partnership, syndicate or other group” constituting a “person” within the meaning of such terms pursuant to Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended.

The phrase “Termination for Cause” shall mean severance of your employment with the Company or its Affiliates based on your (i) failure to perform the duties and responsibilities of your position at an acceptable level as reasonably determined in good faith by the CEO of the Company, (ii) conviction of or guilty plea to the committing of an act or acts constituting a felony under the laws of the United States or any state thereof (or Canada or any province thereof) or any misdemeanor involving moral turpitude, or (iii) violation of the Company’s Code of Business Conduct (unless waived in accordance with the terms thereof), in the case of clauses (i) and (iii), with the specific failure or violation described to you in writing.

Terms used herein that are not defined herein shall have the meanings set forth in the Plan or, if not defined in the Plan, in the Seventh Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P., as amended (the “Partnership Agreement”).

This award is intended to either (i) qualify as a “short-term deferral” under Section 409A of the Internal Revenue Code of 1986, as amended, or (ii) comply with the provisions of Section 409A. If it is determined that any payments or benefits to be made or provided under this Agreement do not comply with Section 409A, the parties agree to amend this Agreement or take such other actions as reasonably necessary or appropriate to comply with Section 409A while preserving the economic agreement of the parties.

By signing below, you agree that the Phantom Units and DERs granted hereunder are governed by the terms of the Plan. You also acknowledge and agree that (i) Tranches 2 and 3 of this award constitute Incentive-Based Compensation and Performance-Based Compensation as defined in the Amended and Restated Clawback Policy adopted by PAGP GP on November 16, 2023, as it may be amended from time to time, and (ii) this award, as well as any other performance-based or time-based compensation previously paid or awarded to you, is subject to

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recovery or cancellation pursuant to such Policy. Copies of the Plan, the Partnership Agreement and the Clawback Policy are available upon request.

«Section 16 Officer»

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Please designate in the space provided below a beneficiary to receive benefits payable under this grant in the event of your death. Unless you indicate otherwise by checking the box below, the named beneficiaries on this form will serve as your beneficiaries for all previous LTIP grants. In addition, please execute and return a copy of this grant letter to me and retain a copy for your records.

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: ______________________________

Name: Jim Tillis

Title: Vice President – Human Resources


«Section 16 Officer»


Target Number of Phantom Units:			«LTIP_Grant»


Dated:

Beneficiary Designation


Primary Beneficiary Name	Relationship	Percent (Must total 100%)



Secondary Beneficiary Name	Relationship	Percent (Must total 100%)

Check this box only if this beneficiary designation does not apply to prior grants.

Exhibit A

Tranche 2 Vesting Terms
(Total Shareholder Return)

1.General. Consistent with the Company’s pay for performance philosophy and in order to more closely align the interests of management with the interests of investors, a portion of your Phantom Units will vest based on PAA’s total shareholder return (“TSR”) compared to the TSR of a peer group as described below. TSR, which will be calculated using data from Bloomberg, is a primary long-term measure of PAA’s performance.

2.Vesting and Payout. As soon as administratively feasible following the close of the three-year period ending on June 30, 2029 (the “Performance Period”), the Compensation Committee shall determine and certify the TSR Payout Percentage (as defined below). The Compensation Committee shall make such determination based on a scaled payout range of between 0% and 200% as provided in the table below (the specific payout percentage is referred to as the “TSR Payout Percentage”) based on PAA’s TSR ranking at the end of the Performance Period compared to the TSR ranking of the various companies and/or indices included in the PAA Peer Group described below. If PAA’s absolute TSR is within 50 basis points of the TSR of one or more peer group comparators (i.e., 50 basis points higher or lower), PAA and such comparator(s) shall be deemed to have the same rank and the TSR Payout Percentage shall be equal to the average of the TSR Payout Percentages associated with the relevant rankings as set forth in the table below. If PAA’s absolute TSR at the end of the Performance Period is less than 0% and the TSR Payout Percentage is greater than 100%, (i) a TSR Payout Percentage equal to or greater than 125% will be reduced by 25 gross percentage points, and (ii) a TSR Payout Percentage between 100% and 125% will be reduced to 100%. The number of Tranche 2 Phantom Units vesting will be determined by multiplying your target number of Tranche 2 Phantom Units by the TSR Payout Percentage as certified by the Compensation Committee. If the resulting amount includes a fraction, it will be rounded down to the nearest whole number.


PAA TSR Ranking vs. PAA Peer Group			TSR Payout Percentage*
1			200%
2			186%
3			171%
4			157%
5			143%
6			129%
7			114%
8			100%
9			86%
10			71%
11			57%
12			43%
13			29%
14			14%
15			0%

*Note that these amounts are rounded. The actual TSR Payout Percentage will be determined at the end of the Performance Period.

A-1

Illustrative Examples (based on an assumed target number of Tranche 2 Phantom Units of 1,000):


PAA TSR Ranking vs. PAA Peer Group			TSR Payout Percentage / Number of Units Vesting (impact of negative absolute TSR)
#1			200% / 2,000 units
#4			157% / 1,570 units
#4, but PAA’s absolute TSR is less than 0%			132% / 1,320 units (TSR Payout Percentage reduced by 25 gross percentage points)
#7			114% / 1,140 units
#7, but PAA’s absolute TSR is less than 0%			100% / 1,000 units (TSR Payout Percentage reduced from 114% to 100%)
#8			100% / 1,000 units (performance at Target)
#12			43% / 430 units
#15			0% / 0 units

3.PAA Peer Group (2026-2029 Performance Period):


Company Name			Ticker
Enterprise Products Partners LP			EPD
Kinder Morgan Inc.			KMI
The Williams Companies Inc.			WMB
MPLX LP			MPLX
Energy Transfer LP			ET
ONEOK Inc.			OKE
Genesis Energy LP			GEL
Targa Resources Corp.			TRGP
Western Midstream Partners LP			WES
Kinetik Holdings Inc.			KNTK
Gibson Energy Inc.			GEI
South Bow Corporation			SOBO
Alerian Midstream Energy Index			AMNA
S&P 500 Index			SPX

In the event any member of the PAA Peer Group files for bankruptcy, liquidates or reorganizes under the United States Bankruptcy Code or other applicable bankruptcy law, such entity shall remain in the PAA Peer Group but shall be deemed to have a TSR of -100% for purposes of calculating the TSR Payout Percentage. In all cases involving the acquisition, merger, reorganization or other material change in ownership, legal structure or business operations of any member of the PAA Peer Group before the end of the Performance Period, the Compensation Committee shall have authority to retain, remove or replace such member, as applicable, for purposes of calculating the TSR Payout Percentage. In connection with any change to the PAA Peer Group, the Compensation Committee shall also have authority to make related adjustments to the rankings and TSR Payout Percentages.

A-2

Exhibit B

Tranche 3 Vesting Terms
(Cumulative DCF with Leverage Modifier)

1.General. Consistent with the Company’s pay for performance philosophy and in order to more closely align the interests of management with the interests of investors, a portion of your Phantom Units will vest based on PAA’s cumulative distributable cash flow (“DCF”) per common unit equivalent (“CUE”) over a three-year period as described below. PAA’s ability to sustain and increase DCF is a primary long-term measure of PAA’s performance and is consistent with PAA’s overall financial strategy. The final payout calculation will be subject to modification based on leverage levels at the end of the Performance Period; the purpose of the potential leverage modifier is to insure that DCF performance remains tied to leverage levels assumed in PAA’s long term plan as of the grant date (the “Grant Date Plan”).

2.Vesting and Payout. As soon as administratively feasible following the close of the three-year period ending on June 30, 2029 (the “Performance Period”), the Compensation Committee shall determine and certify the DCF Payout Percentage (as defined below). The Compensation Committee shall make such determination based on a scaled payout range between 0% and 200% as provided in the table below (the specific payout percentage is referred to as the “DCF Payout Percentage”) based on PAA’s cumulative DCF per CUE over the Performance Period. If PAA’s cumulative DCF per CUE at the end of the Performance Period is between any two of the stated amounts in the table below, the DCF Payout Percentage will be interpolated between the two levels. In addition, the DCF Payout Percentage will be reduced by 25 gross percentage points (the “Leverage Modifier”) if PAA’s “Leverage Ratio” (long-term debt to adjusted EBITDA as calculated pursuant to PAA’s senior unsecured revolving credit facility, modified to include customary adjustments deemed appropriate by the Compensation Committee (for example, a “net debt” adjustment to account for certain cash balances reflected on PAA’s balance sheet as of the applicable measurement date)) as of June 30, 2029 is higher than the Leverage Ratio that equals the upper end of PAA’s then applicable target Leverage Ratio range (the “Threshold Leverage Ratio”) (such range is 2.5x to 3.0x as of the date hereof); if PAA’s Leverage Ratio as of June 30, 2029 is equal to or lower than the Threshold Leverage Ratio, there will be no adjustment to the DCF Payout Percentage.


Cumulative DCF Per CUE Over the Performance Period			DCF Payout Percentage
$10.01 (110% of target)			200%
$9.7825			175%
$9.555			150%
$9.3275			125%
$9.10 (target)			100%
$8.8725			75%
$8.645			50%
$8.4175			25%
$8.19 (90% of target)			0%

Note: Both the cumulative DCF per CUE targets set forth in the table above and the initial Threshold Leverage Ratio referenced above are based on the Grant Date Plan, excluding the earnings and leverage impacts of potential asset sales (other than asset sales under contract as of the grant date). Accordingly, when calculating the DCF Payout Percentage, the following adjustments will be made:

(a)the cumulative DCF per CUE target for the Performance Period as set forth in the table above will be adjusted downward to account for the loss of earnings assumed in the Grant Date Plan for any divested

B-1

assets, net of avoided interest expense allocable to the divested assets (calculated based on an assumption that 100% of the net sales proceeds from such divestitures are used to reduce debt); and

(b)with respect to any divested assets that were included as divestitures in the Grant Date Plan, the Threshold Leverage Ratio target will be adjusted to reflect the leverage impact of any such divested assets based on the assumptions originally set forth in the Grant Date Plan.

In addition, for the Leverage Modifier, the Leverage Ratio calculation will be adjusted up or down as appropriate to neutralize the impact on leverage of any DCF per CUE over or under performance that has already been taken into account in determining the final amount of cumulative DCF per CUE during the Performance Period (with the goal of isolating the balance sheet impact of other actions such as timing and amount of asset sales, amount of capital expenditures, etc.). In addition, the Compensation Committee shall have the ability to make adjustments to the Leverage Ratio calculation to the extent deemed appropriate in connection with leverage attributable to a transaction or project approved by the Company’s Board of Directors (including, without limitation, transactions involving changes to the Company’s capital structure). The number of Tranche 3 Phantom Units vesting will be determined by multiplying your target number of Tranche 3 Phantom Units by the DCF Payout Percentage as certified by the Compensation Committee. If the resulting amount includes a fraction, it will be rounded down to the nearest whole number.

Illustrative Examples (based on an assumed target number of Tranche 3 Phantom Units of 1,000 and based on an assumed Threshold Leverage Ratio of 3.0x, which is the Leverage Ratio that is equal to the upper end of PAA’s current target Leverage Ratio range of 2.5x to 3.0x):


PAA Cumulative DCF per CUE Over the Performance Period	Leverage Ratio as of June 30, 2029	DCF Payout Percentage / Number of Units Vesting (Impact of Leverage Modifier)
$10.01	3.0x or lower	200% / 2,000 units (no adjustment to DCF Payout Percentage)
$10.01	3.1x	175% / 1,750 units (DCF Payout Percentage reduced by 25 gross percentage points)
$9.10	3.0x or lower	100% / 1,000 units (no adjustment to DCF Payout Percentage)
$9.10	3.1x	75% / 750 units (DCF Payout Percentage reduced by 25 gross percentage points)
$8.4175	3.0x or lower	25% / 250 units (no adjustment to DCF Payout Percentage)
$8.4175	3.1x	0% / 0 units (DCF Payout Percentage reduced by 25 gross percentage points)
$8.19	3.0x or lower	0% / 0 units (DCF Payout Percentage equal to zero based on DCF performance)
$8.19	3.1x	0% / 0 units (DCF Payout Percentage equal to zero based on DCF performance)

B-2

Document

EXHIBIT 10.3

https://cdn.kscope.io/9e89342ec6fc47d8c828ea80c0a8df8f-plainsdirectorlogo.jpg

2026 ANNUAL DIRECTOR GRANT

August 13, 2026

«FirstName» «LastName»

«Company»

«Address»

«City», «State» «Zip»

Re: Grant of Phantom Class A Shares

Dear «Salutation»:

I am pleased to inform you that you have been granted 6,150 Phantom Class A Shares as of the above date pursuant to the Plains GP Holdings, L.P. Long-Term Incentive Plan (the “Plan”). In tandem with each Phantom Class A Share granted hereby you have been granted a distribution equivalent right (a “DER”). A DER represents the right to receive a cash payment equivalent to the amount, if any, paid in cash distributions on one Class A Share of Plains GP Holdings, L.P. (“PAGP” or the “Partnership”) to the holder of such Class A Share. The terms and conditions of this grant are as set forth below.

1.Subject to the further provisions of this Agreement, your Phantom Class A Shares shall vest (become payable in the form of one Class A Share of PAGP for each Phantom Class A Share that vests) on the August 2027 Distribution Date.

2.Subject to the further provisions of this Agreement, your DERs shall be payable in cash substantially contemporaneously with each Distribution Date.

3.Immediately after the vesting of any Phantom Class A Shares, an equal number of DERs shall expire.

4.Upon any forfeiture of Phantom Class A Shares, an equal number of DERs shall expire.

5.In the event that (i) you voluntarily terminate your service on the Board of Directors (other than for Retirement) or (ii) your service on the Board of Directors is terminated by the Board (by a majority vote of the remaining Directors) for Cause (as defined in the LLC Agreement), all unvested Phantom Class A Shares (and tandem DERs) shall be forfeited as of the date service terminates.

333 Clay Street, Suite 1600 (77002) | P.O. Box 4648 | Houston, Texas 77210-4648 | (713) 646-4100

«FirstName» «LastName» - 2 - August 13, 2026

6.In the event your service on the Board of Directors is terminated (i) because of your death or disability (as determined in good faith by the Board), (ii) due to your Retirement, or (iii) for any reason other than as described in clauses (i) and (ii) of paragraph 5 above, all unvested Phantom Class A Shares shall immediately become nonforfeitable and shall vest in full as of the next following Distribution Date. Upon such payment, the tandem DERs associated with the Phantom Class A Shares that are vesting shall expire.

7.For the avoidance of doubt, to the extent the expiration of a DER relates to the vesting of a Phantom Class A Share on a Distribution Date, the intent is for the DER to be paid with respect to such Distribution Date before the DER expires.

As used herein, (i) “Company” refers to PAA GP Holdings LLC, (ii) “Distribution Date” means the day in February, May, August or November in any year (as context dictates) that is 45 days after the end of a calendar quarter (or, if not a business day, the closest previous business day), (iii) “Board of Directors” or “Board” means the Board of Directors of the Company, and (iv) “Retirement” means you have provided the Chairman of the Board of the Company with written notice indicating that (a) you have retired (or will retire within the next sixty days) from full-time employment and from service as a director of the Company, and (b) excluding director positions held by you at such time, you do not intend to serve as a director of any other public company.

Terms used herein that are not defined herein shall have the meanings set forth in the Plan or, if not defined in the Plan, in the Second Amended and Restated Agreement of Limited Partnership of Plains GP Holdings, L.P., as amended (the “Partnership Agreement”) or the Fourth Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC (the “LLC Agreement”). By signing below, you agree that the Phantom Class A Shares and DERs granted hereunder are governed by the terms of the Plan. Copies of the Plan, the Partnership Agreement and the LLC Agreement are available upon request.

«FirstName» «LastName» - 3 - August 13, 2026

Please designate in the space provided below a beneficiary to receive benefits payable under this a grant in the event of your death. In addition, please execute and return a copy of this grant letter to me and retain a copy for your records.

PLAINS GP HOLDINGS, L.P.

By: PAA GP HOLDINGS LLC

By: ____________________________________

Name: Richard McGee

Title: Executive Vice President

«FirstName» «LastName»

No. of Phantom Class A Shares: 6,150

Dated:

Beneficiary Designation


Primary Beneficiary Name	Relationship	Percent (Must total 100%)



Secondary Beneficiary Name	Relationship	Percent (Must total 100%)

Document

EXHIBIT 31.1

CERTIFICATION

I, Willie Chiang, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Plains All American Pipeline, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 6, 2026


/s/ Willie Chiang
Willie Chiang
Chief Executive Officer and President

Document

EXHIBIT 31.2

CERTIFICATION

I, Al Swanson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Plains All American Pipeline, L.P. (the “registrant”);

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 6, 2026


/s/ Al Swanson
Al Swanson
Chief Financial Officer

Document

EXHIBIT 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

OF PLAINS ALL AMERICAN PIPELINE, L.P.

PURSUANT TO 18 U.S.C. 1350

I, Willie Chiang, Chief Executive Officer of Plains All American Pipeline, L.P. (the “Company”), hereby certify that:

(i) the accompanying report on Form 10-Q for the period ended September 30, 2026 and filed with the Securities and Exchange Commission on the date hereof (the “Report”) by the Company fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Willie Chiang
Name: Willie Chiang
Date: November 6, 2026

Document

EXHIBIT 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

OF PLAINS ALL AMERICAN PIPELINE, L.P.

PURSUANT TO 18 U.S.C. 1350

I, Al Swanson, Chief Financial Officer of Plains All American Pipeline, L.P. (the “Company”), hereby certify that:

(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Al Swanson
Name: Al Swanson
Date: November 6, 2026