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Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________________________________________________
FORM  10-Q
________________________________________________________________________________________________________________________________
 
☑       QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended September 30, 2025
 
or
 
☐        TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
Commission File Number: 1-14569
________________________________________________________________

PLAINS ALL AMERICAN PIPELINE, L.P.
(Exact name of registrant as specified in its charter)
Delaware   76-0582150
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)

333 Clay Street , Suite 1600
Houston , Texas 77002
(Address of principal executive offices) (Zip code)
( 713 ) 646-4100
(Registrant’s telephone number, including area code)
________________________________________________________________
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading Symbol(s) Name of each exchange on which registered
Common Units PAA Nasdaq

 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  ☑   Yes    ☐  No
 Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  ☑   Yes    ☐  No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☑   Accelerated filer ☐
Non-accelerated filer ☐   Smaller reporting company ☐
  Emerging growth company ☐

  If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐  
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   ☐  Yes   ☑  No
As of October 31, 2025, there were 705,497,770 Common Units outstanding.

Table of Contents

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
TABLE OF CONTENTS
  Page
PART I. FINANCIAL INFORMATION
 
Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
 
Condensed Consolidated Balance Sheets: As of September 30, 2025 and December 31, 2024
3

Condensed Consolidated Statements of Operations: For the three and nine months ended September 30, 2025 and 2024
4

Condensed Consolidated Statements of Comprehensive Income: For the three and nine months ended September 30, 2025 and 2024
5

Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss): For the nine months ended September 30, 2025 and 2024
5

Condensed Consolidated Statements of Cash Flows: For the nine months ended September 30, 2025 and 2024
6

Condensed Consolidated Statements of Changes in Partners’ Capital: For the three and nine months ended September 30, 2025 and 2024
7

Notes to the Condensed Consolidated Financial Statements:
 
1. Organization and Basis of Consolidation and Presentation
9

2. Discontinued Operations
12

3. Revenues and Accounts Receivable
13

4. Net Income Per Common Unit
17

5. Inventory, Linefill and Long-term Inventory
19

6. Debt
20

7. Partners’ Capital and Distributions
21

8. Derivatives and Risk Management Activities
23

9. Related Party Transactions
27

10. Commitments and Contingencies
28

11. Segment Information
31

12. Acquisitions
38

   
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
41

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
62

Item 4. CONTROLS AND PROCEDURES
63

   
PART II. OTHER INFORMATION
 
Item 1. LEGAL PROCEEDINGS
65

Item 1A. RISK FACTORS
65

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
65

Item 3. DEFAULTS UPON SENIOR SECURITIES
65

Item 4. MINE SAFETY DISCLOSURES
65

Item 5. OTHER INFORMATION
65

Item 6. EXHIBITS
66

SIGNATURES
70

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PART I. FINANCIAL INFORMATION  

Item 1.    UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except unit data)
September 30,
2025 December 31,
2024
  (unaudited)
ASSETS    

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

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

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

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

LIABILITIES AND PARTNERS’ CAPITAL    

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

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

COMMITMENTS AND CONTINGENCIES (NOTE 10)

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

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

Other income, net
14   26   70   45  

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

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

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

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

Basic and diluted net income per common unit:

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

The accompanying notes are an integral part of these condensed consolidated financial statements.
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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,
  2025 2024 2025 2024
  (unaudited) (unaudited)
Net income $ 529   $ 312   $ 1,342   $ 993  
Other comprehensive income/(loss)
( 51 ) 36   142   ( 68 )
Comprehensive income 478   348   1,484   925  
Comprehensive income attributable to noncontrolling interests
( 88 ) ( 92 ) ( 249 ) ( 257 )
Comprehensive income attributable to PAA $ 390   $ 256   $ 1,235   $ 668  

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)
(in millions)

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

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

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

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

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)

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

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

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

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

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

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

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

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

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

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

Other financing activities ( 64 ) ( 48 )

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

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

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

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

The accompanying notes are an integral part of these condensed consolidated financial statements.
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
(in millions)

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

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

Contributions from noncontrolling interests —  —  —  —  5   5  

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

The accompanying notes are an integral part of these condensed consolidated financial statements.
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
(continued)
(in millions)

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

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

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

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

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

Note 1— Organization and Basis of Consolidation and Presentation
 
Organization
 
Plains All American Pipeline, L.P. (“PAA”) is a Delaware limited partnership formed in 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in this Form 10-Q and unless the context indicates otherwise, the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAA and its subsidiaries.
 
Our business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals. As one of the largest crude oil midstream service providers in North America, we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. Our assets and the services we provide are primarily focused on and conducted through two operating segments: Crude Oil and Natural Gas Liquids (“NGL”). See Note 11 for further discussion of our operating segments.
 
Our non-economic general partner interest is held by PAA GP LLC (“PAA GP”), a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP, as of September 30, 2025, AAP also owned a limited partner interest in us through its ownership of approximately 233.0 million of our common units (approximately 31 % of our total outstanding common units and Series A preferred units combined). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole and managing member of GP LLC, and, at September 30, 2025, owned an approximate 85 % limited partner interest in AAP. PAA GP Holdings LLC (“PAGP GP”) is the general partner of PAGP.
 
As the sole member of GP LLC, PAGP has responsibility for conducting our business and managing our operations; however, the board of directors of PAGP GP has ultimate responsibility for managing the business and affairs of PAGP, AAP and us. GP LLC employs our domestic officers and personnel; our Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC.

References to our “general partner,” as the context requires, include any or all of PAGP GP, PAGP, GP LLC, AAP and PAA GP. References to “Plains entities,” as the context requires, include any or all of PAA and its subsidiaries and our general partner.
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Definitions
 
Additional defined terms may be used in this Form 10-Q and shall have the meanings indicated below:

AOCI = Accumulated other comprehensive income/(loss)
ASC = Accounting Standards Codification
ASU = Accounting Standards Update
Bcf = Billion cubic feet
Btu = British thermal unit
CAD = Canadian dollar
CODM = Chief Operating Decision Maker
EBITDA = Earnings before interest, taxes, depreciation and amortization
EPA = United States Environmental Protection Agency
FASB = Financial Accounting Standards Board
GAAP = Generally accepted accounting principles in the United States
ICE = Intercontinental Exchange
ISDA = International Swaps and Derivatives Association

LTIP = Long-term incentive plan
Mcf = Thousand cubic feet
MMbls = Million barrels
NGL = Natural gas liquids, including ethane, propane and butane
NYMEX = New York Mercantile Exchange
OECD
= Organisation for Economic Co-operation and Development

SEC = United States Securities and Exchange Commission
SOFR = Secured Overnight Financing Rate
TWh = Terawatt hour
USD = United States dollar
WTI = West Texas Intermediate

Basis of Consolidation and Presentation
 
The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our 2024 Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of PAA and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. The condensed consolidated balance sheet data as of December 31, 2024 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three and nine months ended September 30, 2025 should not be taken as indicative of results to be expected for the entire year. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany balances and transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications had no impact on net income or total partners’ capital.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Pending Sale of Canadian NGL Business

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

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

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

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

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

Subsequent Events

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

Recent Accounting Pronouncements, Disclosure Rules and Other Legislation

Except as discussed in our 2024 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the nine months ended September 30, 2025 that are of significance or potential significance to us.
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 2 — Discontinued Operations

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

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

September 30,
2025 December 31,
2024
Assets:

Current assets:

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

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

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

Liabilities:

Current liabilities:
Trade accounts payable
$ 193   $ 234  

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

Long-term liabilities:

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

(1) Amounts are net of accumulated depreciation of $ 866  million and $ 794  million as of September 30, 2025 and December 31, 2024, respectively.
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2025 2024 2025 2024
Revenues:

Product sales
$ 139   $ 261   $ 818   $ 715  
Services
37   26   102   102  
Total revenues
176   287   920   817  
Cost and Expenses:

Purchases and related costs
( 7 ) 17   245   247  
Field operating costs 68   75   190   229  
General and administrative expenses 10   12   36   41  
Depreciation and amortization
—   31   57   94  
(Gains)/losses on asset sales, net
2   1   15   ( 1 )
Total costs and expenses
73   136   543   610  

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

Note 3— Revenues and Accounts Receivable

Revenue Recognition

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

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

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

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

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

Reconciliation to Total Revenues of Reportable Segments. The following disclosures only include information regarding revenues associated with consolidated entities; revenues from entities accounted for by the equity method are not included. The following tables present the reconciliation of our revenues from contracts with customers to total revenues of reportable segments and total revenues as disclosed in our Condensed Consolidated Statements of Operations (in millions):
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Three Months Ended September 30, 2025 Crude Oil NGL Total
Revenues from contracts with customers $ 11,537   $ 24   $ 11,561  
Other revenues 22   —   22  
Total revenues of reportable segments $ 11,559   $ 24   $ 11,583  
Intersegment revenues elimination ( 5 )
Total revenues $ 11,578  

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

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

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

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

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

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

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

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

Additions 19  

Balance at September 30, 2025 $ 66  

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Remaining Performance Obligations . The information below includes the amount of consideration allocated to partially and wholly unsatisfied remaining performance obligations under contracts that existed as of the end of the periods and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These contracts include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of September 30, 2025 (in millions):

Remainder of 2025
2026
2027
2028
2029
2030 and Thereafter

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

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

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

• Minimum volume commitments on certain of our joint venture pipeline systems;
• Acreage dedications;
• Buy/sell arrangements with future committed volumes;
• Short-term contracts and those with variable consideration, due to the election of practical expedients;
• Contracts within the scope of ASC Topic 842, Leases ; and
• Contracts within the scope of ASC Topic 815, Derivatives and Hedging .

Trade Accounts Receivable and Other Receivables, Net

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

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

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

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

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Note 4— Net Income Per Common Unit
 
We calculate basic and diluted net income per common unit by dividing income from continuing operations attributable to PAA (after deducting amounts allocated to the preferred unitholders and participating securities) and income from discontinued operations by the basic and diluted weighted average number of common units outstanding during the period.

The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units and (ii) our equity-indexed compensation plan awards. See Note 11 and Note 17 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for a discussion of our Series A preferred units and equity-indexed compensation plan awards. When applying the if-converted method prescribed by FASB guidance, on a weighted-average basis, for the three and nine months ended September 30, 2025, the possible conversion of approximately 58  million and 60  million Series A preferred units, respectively, and for each of the three and nine months ended September 30, 2024, the possible conversion of approximately 71 million Series A preferred units were excluded from the calculation of diluted net income per common unit as the effect was antidilutive. Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that are deemed to be dilutive during the period are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.

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

  Three Months Ended
September 30, Nine Months Ended
September 30,
  2025 2024 2025 2024
Basic and Diluted Net Income per Common Unit        
Continuing Operations:

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

Discontinued Operations:

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

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

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

Basic and diluted net income per common unit:

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

(1) We repurchased approximately 12.7  million Series A preferred units on January 31, 2025. See Note 7 for additional information. The difference between the cash we paid for the repurchase of such units and their carrying value on our balance sheet is considered a return to Series A preferred unitholders for the calculation of net income allocated to common unitholders.
(2) We calculate net income from continuing operations allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (i.e., undistributed loss), if any, are allocated to the common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method.
(3) Net income from discontinued operations allocated to common unitholders is Income from discontinued operations, net of tax as presented on our Condensed Consolidated Statements of Operations.

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Note 5— Inventory, Linefill and Long-term Inventory
 
Inventory, linefill and long-term inventory consisted of the following (barrels in thousands and carrying value in millions):

  September 30, 2025 December 31, 2024
  Volumes Unit of
Measure Carrying
Value Price/
Unit  (1)
Volumes Unit of
Measure Carrying
Value Price/
Unit  (1)

Inventory                
Crude oil 2,021   barrels $ 122   $ 60.37   3,321   barrels $ 221   $ 66.55  
NGL 1,035   barrels 51   $ 49.28   603   barrels 26   $ 43.12  

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

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

Linefill subtotal     933         904    

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

Total     $ 1,344         $ 1,407    

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

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Note 6— Debt
 
Debt consisted of the following (in millions):

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

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

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

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

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

(1) We classified these commercial paper notes as short-term as of December 31, 2024, as these notes were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged inventory and NYMEX and ICE margin deposits.
(2) As of December 31, 2024, we classified our $ 1.0  billion, 4.65 % senior notes due October 2025 as long-term based on our ability and intent to refinance the notes on a long-term basis at that time. We redeemed these senior notes on October 3, 2025.
(3) Our fixed-rate senior notes had a face value of approximately $ 9.4  billion and $ 7.2  billion as of September 30, 2025 and December 31, 2024, respectively. We estimated the aggregate fair value of these notes as of September 30, 2025 and December 31, 2024 to be approximately $ 9.2 billion and $ 6.7 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under our commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

Senior Notes

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

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

Borrowings and Repayments
 
Total borrowings under our commercial paper program for the nine months ended September 30, 2025 and 2024 were approximately $ 38.7 billion and $ 20.7  billion, respectively. Total repayments under our commercial paper program were approximately $ 39.1 billion and $ 21.1 billion for the nine months ended September 30, 2025 and 2024, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.

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Letters of Credit
 
In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil and NGL. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At September 30, 2025 and December 31, 2024, we had outstanding letters of credit of $ 70 million and $ 90 million, respectively.

Note 7— Partners’ Capital and Distributions
 
Units Outstanding
 
The following tables present the activity for our preferred and common units:

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

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

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

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

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

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

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

Repurchase of Series A Preferred Units

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

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Distributions

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

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

(1) Payable to unitholders of record at the close of business on the applicable Record Date.
(2) At September 30, 2025, such amount was accrued as distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

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

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

(1) Payable to unitholders of record at the close of business on the applicable Record Date.
(2) At September 30, 2025, approximately $ 9  million of accrued distributions payable to our Series B preferred unitholders was included in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

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

Distributions Distribution per Common Unit

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

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

Noncontrolling Interests in Subsidiaries

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

Distributions to Noncontrolling Interests

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

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

Note 8— Derivatives and Risk Management Activities
 
We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. We use various derivative instruments to manage our exposure to commodity price risk, interest rate risk, and currency exchange rate risk. Our commodity price risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate risk and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on changes in commodity prices or interest rates. When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. At the inception of the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions. Throughout the hedging relationship, retrospective and prospective hedge effectiveness is assessed on a qualitative basis.
 
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We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives designated as cash flow hedges, changes in fair value are deferred in AOCI and recognized in earnings in the periods during which the underlying hedged transactions are recognized in earnings. Derivatives that are not designated in a hedging relationship for accounting purposes are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Condensed Consolidated Statements of Cash Flows.

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

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

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

In the normal course of our operations, we purchase and sell commodities. We use derivatives to manage the associated risks and, in certain circumstances, to optimize profits. As of September 30, 2025, net derivative positions related to these activities included:
 
• A net long position of 9.4 million barrels associated with our crude oil purchases, which will be unwound ratably through December 2025 to match monthly average pricing.
• A net short time spread position of 2.1 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through April 2026.
• A net crude oil basis spread position of 2.5 million barrels at multiple locations through December 2026. These derivatives allow us to lock in grade and location basis differentials.
• A net short position of 5.7 million barrels through December 2029 related to anticipated net sales of crude oil inventory.
• A net long position of 0.5 TWh through December 2030 related to anticipated power supply requirements.

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

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

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

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

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

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

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

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

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

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The following table summarizes the terms of our outstanding interest rate derivatives as of September 30, 2025 (notional amounts in millions):

Hedged Transaction Number and Types of
Derivatives Employed Notional
Amount Expected
Termination Date Average Rate
Locked Accounting
Treatment
Anticipated interest payments 8 forward starting swaps
( 30 -year)
$ 200   6/15/2026 3.09 % Cash flow hedge

 
During the three months ended September 30, 2025, we terminated $ 200  million of notional hedging instruments for proceeds of $ 7  million, which was recorded in AOCI. As of September 30, 2025, there was a net loss of $ 31  million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with interest expense accruals associated with underlying debt instruments. We estimate that substantially all of the remaining deferred loss will be reclassified to earnings through 2056 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of September 30, 2025; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

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

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

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

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

Recurring Fair Value Measurements
 
Derivative Financial Assets and Liabilities
 
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions):

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

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

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

Level 1
 
Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives and over-the-counter commodity contracts such as futures and swaps. The fair value of exchange-traded commodity derivatives and over-the-counter commodity contracts is based on unadjusted quoted prices in active markets.
 
Level 2
 
Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives, over-the-counter commodity, foreign exchange and interest rate derivatives that are traded in observable markets with less volume and transaction frequency than active markets. In addition, it includes certain physical commodity contracts. The fair values of these derivatives are corroborated with market observable inputs.

Note 9— Related Party Transactions
 
See Note 16 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for a complete discussion of related parties, including the determination of our related parties and nature of involvement with such related parties.

Promissory Notes with our General Partner

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

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

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

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

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

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Transactions with Other Related Parties

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

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

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

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

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

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

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

(1) Includes amounts related to transportation and storage services and amounts owed to us or advanced to us related to investment capital projects of equity method investees where we serve as construction manager.
(2) We have agreements to store crude oil at facilities and transport crude oil or utilize capacity on pipelines that are owned by equity method investees. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities.

Note 10— Commitments and Contingencies

Loss Contingencies — General
 
To the extent we are able to assess the likelihood of a negative outcome for a contingency, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred.
 
We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss.

Legal Proceedings — General
 
In the ordinary course of business, we are involved in various legal proceedings including those arising from regulatory and environmental matters. In connection with determining the probability of loss associated with such legal proceedings and whether any potential losses associated therewith are estimable, we take into account what we believe to be all relevant known facts and circumstances, and what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing agreements, laws and regulations. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully protect us from losses arising from current or future legal proceedings.
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Accordingly, we can provide no assurance that the outcome of the various legal proceedings that we are currently involved in, or will become involved with in the future, will not, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
 
Environmental — General

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

Although we have made significant investments in our maintenance and integrity programs, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail, storage and other facility operations. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. We also may discover environmental impacts from past releases that were previously unidentified. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
 
We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated. Generally, our recording of these liabilities coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. We record receivables for amounts we believe are recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery.

Environmental expenditures that pertain to current operations or to future revenues are expensed or capitalized consistent with our capitalization policy for property and equipment. Expenditures that result from the remediation of an existing condition caused by past operations and that do not contribute to current or future profitability are expensed.
 
Our estimated undiscounted reserves for environmental liabilities (excluding liabilities related to the Line 901 incident, as discussed further below) were reflected on our Condensed Consolidated Balance Sheets as follows (in millions):

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

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

Line 901 Incident . In May 2015 we experienced a release of crude oil from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. Effective as of September 30, 2025, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $ 870 million, which includes actual emergency response and clean-up costs, natural resource damage assessments, fines and penalties incurred, certain third-party claims settlements, and estimated costs associated with our remaining Line 901 lawsuits and claims as described below, as well as estimates for certain legal fees and statutory interest where applicable. We accrue such estimates of aggregate total costs to “Field operating costs” in our Condensed Consolidated Statements of Operations. This estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the resolution of certain third-party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and (ii) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. Our estimate does not include any lost revenue associated with the shutdown of Line 901 or 903 and does not include any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, with respect to potential losses that we regard as only reasonably possible or remote, we have made assumptions regarding the strength of our legal position based on our assessment of the relevant facts and applicable law and precedent; if our assumptions regarding such matters turn out to be inaccurate (i.e., we are found to be liable under circumstances where we regard the likelihood of loss as being only reasonably possible or remote), we could be responsible for significant costs and expenses that are not currently included in our estimates and accruals. In addition, for any potential losses that we regard as probable and for which we have accrued an estimate of the potential losses, our estimates regarding damages, legal fees, court costs and interest could turn out to be inaccurate and the actual losses we incur could be significantly higher than the amounts included in our estimates and accruals. Also, the amount of time it takes for us to resolve all of the current and future lawsuits and claims that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated. Accordingly, our assumptions and estimates may turn out to be inaccurate and our total costs could turn out to be materially higher; therefore, we can provide no assurance that we will not have to accrue significant additional costs in the future with respect to the Line 901 incident.

During the nine months ended September 30, 2025, we did not recognize any costs related to the Line 901 incident. During the nine months ended September 30, 2024, we recognized costs, net of amounts probable of recovery from insurance (as applicable) of $ 120  million. As of September 30, 2025 and December 31, 2024, we had a remaining undiscounted gross liability of approximately $ 3  million and $ 5 million, respectively, related to the Line 901 incident, which aggregate amounts are reflected in “Current liabilities” on our Condensed Consolidated Balance Sheet.

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

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

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

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

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

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Note 11— Segment Information

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

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

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

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

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

Crude Oil NGL Intersegment
Elimination
Total
Three Months Ended September 30, 2025
Revenues (1) :

Product sales $ 11,132   $ 22   $ ( 4 ) $ 11,150  
Services 427   2   ( 1 ) 428  
Total revenues 11,559   24   ( 5 ) 11,578  

Significant segment expenses:

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

Equity earnings in unconsolidated entities 96   — 

Other segment items (2) :

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

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

Segment Adjusted EBITDA $ 593   $ ( 10 )

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

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

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Crude Oil NGL Intersegment
Elimination
Total
Nine Months Ended September 30, 2025
Revenues (1) :

Product sales $ 32,313   $ 88   $ ( 12 ) $ 32,389  
Services 1,307   4   ( 2 ) 1,309  
Total revenues 33,620   92   ( 14 ) 33,698  

Significant segment expenses:

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

Equity earnings in unconsolidated entities 292   — 

Other segment items (2) :

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

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

Segment Adjusted EBITDA $ 1,733   $ ( 24 )

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

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

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Crude Oil NGL Intersegment
Elimination
Total
Three Months Ended September 30, 2024
Revenues (1) :

Product sales $ 12,009   $ 19   $ ( 7 ) $ 12,021  
Services 435   1   ( 1 ) 435  
Total revenues 12,444   20   ( 8 ) 12,456  

Significant segment expenses:

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

Equity earnings in unconsolidated entities 97   — 

Other segment items (2) :

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

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

Segment Adjusted EBITDA $ 577   $ ( 15 )

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

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

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Crude Oil NGL Intersegment
Elimination
Total
Nine Months Ended September 30, 2024
Revenues (1) :

Product sales $ 35,515   $ 103   $ ( 12 ) $ 35,606  
Services 1,246   3   ( 1 ) 1,248  
Total revenues 36,761   106   ( 13 ) 36,854  

Significant segment expenses:

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

Equity earnings in unconsolidated entities 298   — 

Other segment items (2) :

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

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

Segment Adjusted EBITDA $ 1,707   $ ( 26 )

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

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

(1) Segment revenues include intersegment amounts that are eliminated in purchases and related costs. Intersegment activities are conducted at posted tariff rates where applicable, or otherwise at rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated.
(2) Represents adjustments utilized by our CODM in the evaluation of segment results.
(3) Includes our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities.
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(4) We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify differences in the timing of earnings from the derivative instruments and the underlying transactions and exclude the related gains and losses in determining Segment Adjusted EBITDA such that the earnings from the derivative instruments and the underlying transactions impact Segment Adjusted EBITDA in the same period. In addition, we exclude gains and losses on derivatives that are related to (i) investing activities, such as the purchase of linefill, and (ii) purchases of long-term inventory. We also exclude the impact of corresponding inventory valuation adjustments, as applicable.
(5) We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We exclude the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and write-downs of such inventory that result from price declines from Segment Adjusted EBITDA.
(6) We, and certain of our equity method investees, have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue or equity earnings, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to Segment Adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.
(7) Our total equity-indexed compensation expense includes expense associated with awards that will be settled in units and awards that will be settled in cash. The awards that will be settled in units are included in our diluted net income per unit calculation when the applicable performance criteria have been met. We exclude compensation expense associated with these awards in determining Segment Adjusted EBITDA as the dilutive impact of the outstanding awards is included in our diluted net income per unit calculation, as applicable. The portion of compensation expense associated with awards that will be settled in cash is not excluded in determining Segment Adjusted EBITDA. See Note 17 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for a discussion regarding our equity-indexed compensation plans.
(8) During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. These gains and losses are not integral to our core operating performance and were therefore excluded in determining Segment Adjusted EBITDA.
(9) Primarily related to acquisitions completed during the first nine months of 2025. See Note 12 for information regarding these transactions.
(10) Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River.
(11) Investment capital and acquisition capital expenditures, including investments in unconsolidated entities.
(12) These amounts combined represent total capital expenditures.
(13) Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. See Note 10 for additional information regarding the Line 901 incident.

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Segment Adjusted EBITDA Reconciliation

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

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

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

Note 12 — Acquisitions

Ironwood Midstream

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

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

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

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

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

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

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

Other Acquisitions

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

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

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

BridgeTex Pipeline . In July 2025, we acquired an additional 20 % interest in BridgeTex Pipeline Company, LLC (“BridgeTex”) for approximately $ 180  million. As a result of this transaction, we now own a 40 % interest in BridgeTex and continue to account for our interest in BridgeTex, which is reported in our Crude Oil segment, as an equity method investment.
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EPIC Pipeline . On October 31, 2025, we purchased an aggregate 55 % equity interest in EPIC Crude Holdings, LP (“EPIC Crude Holdings”), which owns the EPIC Crude Oil Pipeline (“EPIC Pipeline”), from subsidiaries of Diamondback Energy, Inc. and Kinetik Holdings Inc., for approximately $ 1.57  billion, subject to certain adjustments and inclusive of approximately $ 600  million of debt assumed. We also agreed to a potential earnout payment of $ 193  million contingent upon the formal sanctioning before the end of 2027 of one or more expansions of EPIC Pipeline that in the aggregate will increase the capacity of the pipeline to at least 900,000 barrels per day. In a separate transaction, effective November 1, 2025, we acquired the remaining 45 % equity interest in EPIC Crude Holdings from a portfolio company of Ares Private Equity funds for approximately $ 1.33  billion, subject to certain adjustments and inclusive of approximately $ 500  million of debt assumed. We also agreed to a potential earnout payment to the seller of up to $ 157  million depending on the timing and amount of incremental expansion capacity up to 300,000 barrels per day in excess of 650,000 barrels per day that is formally sanctioned before the end of 2028.

Subsequent to these two transactions (collectively, the “EPIC acquisition”), we now own 100 % of EPIC Crude Holdings and are the operator of record for the EPIC Pipeline, which provides long-haul crude oil takeaway from the Permian and Eagle Ford basins to the Gulf Coast market at Corpus Christi. We believe this acquisition is highly synergistic and strategic to our existing footprint. The EPIC acquisition will be accounted for in our Crude Oil segment.
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Item 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 

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

Executive Summary
 
Company Overview
 
Our business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals. As one of the largest crude oil midstream service providers in North America, we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. Our assets and the services we provide are primarily focused on crude oil and, to a lesser extent, NGL.

Pending Sale of Canadian NGL Business

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

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

Overview of Operating Results

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

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Results of Operations
 
Consolidated Results

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

Three Months Ended
September 30, Variance Nine Months Ended
September 30, Variance
  2025 2024 $ % 2025 2024 $ %
Product sales revenues $ 11,150  $ 12,021  $ (871) (7) % $ 32,389  $ 35,606  $ (3,217) (9) %
Services revenues 428  435  (7) (2) % 1,309  1,248  61  5  %
Purchases and related costs (10,585) (11,540) 955  8  % (30,862) (34,086) 3,224  9  %
Field operating costs (288) (408) 120  29  % (873) (962) 89  9  %
General and administrative expenses (83) (86) 3  3  % (251) (246) (5) (2) %
Depreciation and amortization (230) (226) (4) (2) % (696) (675) (21) (3) %
Gains/(losses) on asset sales, net
92  —  92  N/A 64  (2) 66  **
Equity earnings in unconsolidated entities 96  97  (1) (1) % 292  298  (6) (2) %
Gain on investments in unconsolidated entities, net
—  —  —  N/A 31  —  31  N/A
Interest expense, net (1)
(135) (113) (22) (19) % (395) (318) (77) (24) %

Other income, net (1)
14  26  (12) (46) % 70  45  25  56  %
Income tax expense from continuing operations
(6) (8) 2  25  % (17) (71) 54  76  %
Income from continuing operations, net of tax
453  198  255  129  % 1,061  837  224  27  %

Income from discontinued operations, net of tax (2)
76  114  (38) (33) % 281  156  125  80  %
Net income
529  312  217  70  % 1,342  993  349  35  %
Net income attributable to noncontrolling interests
(88) (92) 4  4  % (249) (257) 8  3  %
Net income attributable to PAA $ 441  $ 220  $ 221  100  % $ 1,093  $ 736  $ 357  49  %

Basic and diluted net income per common unit:

Continuing operations $ 0.44  $ 0.06  $ 0.38  ** $ 0.85  $ 0.55  $ 0.30  55  %
Discontinued operations 0.11  0.16  (0.05) (31) % 0.40  0.22  0.18  82  %
Basic and diluted net income per common unit $ 0.55  $ 0.22  $ 0.33  150  % $ 1.25  $ 0.77  $ 0.48  62  %

Basic and diluted weighted average common units outstanding 704  702  2  —  % 704  702  2  —  %

**     Indicates that variance as a percentage is not meaningful.
(1) “Interest expense, net” and “Other income, net” each include $23 million and $65 million for the three and nine months ended September 30, 2025, respectively, and $16 million and $31 million for the three and nine months ended September 30, 2024, respectively, 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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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, 2025 $ 62  $ 70  $ 65 
Three Months Ended September 30, 2024 $ 66  $ 84  $ 75 

Nine Months Ended September 30, 2025 $ 57  $ 80  $ 67 
Nine Months Ended September 30, 2024 $ 66  $ 87  $ 78 

Product sales revenues (including the impact of derivative mark-to-market valuations) and purchases decreased for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to lower commodity prices in the 2025 periods, partially offset by higher crude oil sales volumes in the 2025 periods.

Services revenues for the nine months ended September 30, 2025 increased compared to the same period in 2024 primarily due to higher pipeline volumes and tariff escalations, as well as the impact of recently completed acquisitions, partially offset by the impact from lower commodity prices in the 2025 period.

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

Field Operating Costs

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

General and Administrative Expenses

The increase in general and administrative expenses for the nine months ended September 30, 2025 compared to the same periods in 2024 was primarily due to transaction costs associated with our recent acquisitions, partially offset by lower information systems costs due to the completion of certain systems conversion and integration work, which was also the primarily driver of the decrease in general and administrative expenses for the comparative three-month period.

Depreciation and Amortization

The increase in depreciation and amortization for the nine months ended September 30, 2025 compared to the same periods in 2024 was largely driven by acquisitions.
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Gains/Losses on Asset Sales, Net

In connection with the pending sale of the Canadian NGL Business, we entered into a deal-contingent forward currency instrument to hedge the currency exchange risk associated with the sale in CAD. The 2025 periods 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 1 to our Condensed Consolidated Financial Statements for additional information regarding the pending sale of the Canadian NGL Business.

Equity Earnings

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

Gain on Investments in Unconsolidated Entities, Net

We recognized a net gain of $31 million related to our acquisition of the remaining 50% interest in Cheyenne in the first quarter of 2025. See Note 12 to our Condensed Consolidated Financial Statements for additional information regarding this transaction.

Interest Expense, Net and Other Income, Net

For the three and nine months ended September 30, 2025 and 2024, “Interest expense, net” and “Other income, net” each include interest expense and interest income associated with promissory notes payable and receivable by and among us and certain Plains entities. These amounts are excluded from our non-GAAP performance measures Adjusted EBITDA and Implied DCF. As such, the interest expense and interest income associated with these notes are presented on a net basis in the reconciliation of these metrics to Net Income. See the “—Non-GAAP Financial Measures” section below.

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2025 2024 2025 2024
Interest expense on third-party borrowings (1)
$ 116  $ 99  $ 339  $ 294 
Interest expense on related party promissory notes (2)
23  16  65  31 
Capitalized interest (4) (2) (9) (7)
$ 135  $ 113  $ 395  $ 318 

(1) The increase in interest expense for the three-month 2025 period compared to the same period in 2024 was primarily driven by the issuances of (i) $1.0 billion, 5.95% senior notes in January 2025 and (ii) $700 million, 4.70% senior notes and $550 million, 5.60% senior notes in September 2025, partially offset by the repayment of (iii) $750 million, 3.60% senior notes in November 2024. The increase for the nine-month comparative period was further impacted by the issuance of $650 million, 5.70% senior notes in June 2024. See Note 6 to our Condensed Consolidated Financial Statements for additional information regarding our senior notes.
(2) Represents interest expense associated with promissory notes by and among us and certain Plains entities, as described above.
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The following table summarizes the components impacting Other income, net (in millions):

Three Months Ended
September 30, Nine Months Ended
September 30,
  2025 2024 2025 2024
Interest income on related party promissory notes (1)
$ 23  $ 16  $ 65  $ 31 

Other (2)
(9) 10  5  14 
$ 14  $ 26  $ 70  $ 45 

(1) Represents interest income associated with promissory notes by and among us and certain Plains entities, as described above.
(2) Primarily includes interest income from other sources and gains and losses on foreign revaluation 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.

Income Tax Expense

The net favorable income tax variance for the nine months ended September 30, 2025 compared to the same period in 2024 was primarily due to the impact of (i) lower income tax expense in 2025 associated with Canadian withholding tax on dividends from our Canadian entities to other Plains entities, partially offset by (ii) higher year-over-year income within our Canadian operations as impacted by fluctuations of derivative mark-to-market valuations.

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

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

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Non-GAAP Financial Performance Measures

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

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

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

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

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

Three Months Ended
September 30, Variance Nine Months Ended
September 30, Variance
  2025 2024 $ % 2025 2024 $ %
Net income (1)
$ 529  $ 312  $ 217  70  % $ 1,342  $ 993  $ 349  35  %
Interest expense, net of certain items (2)
112  97  15  15  % 330  287  43  15  %

Income tax expense from continuing operations
6  8  (2) (25) % 17  71  (54) (76) %
Income tax expense from discontinued operations (3)
27  37  (10) (27) % 96  51  45  88  %
Depreciation and amortization from continuing operations
230  226  4  2  % 696  675  21  3  %
Depreciation and amortization from discontinued operations (3)
—  31  (31) (100) % 57  94  (37) (39) %
(Gains)/losses on asset sales, net from continuing operations
(92) —  (92) N/A (64) 2  (66) **
(Gains)/losses on asset sales, net from discontinued operations (3)
2  1  1  100  % 15  (1) 16  **
Gain on investments in unconsolidated entities, net
—  —  —  N/A (31) —  (31) N/A
Depreciation and amortization of unconsolidated entities (4)
21  22  (1) (5) % 62  59  3  5  %
Selected Items Impacting Comparability (1) :

Derivative activities and inventory valuation adjustments
(48) (105) 57  ** (75) 78  (153) **
Long-term inventory costing adjustments
14  31  (17) ** 30  8  22  **
Deficiencies under minimum volume commitments, net
(6) 15  (21) ** (21) 10  (31) **
Rail fleet amortization expense related to discontinued operations (5)
(10) —  (10) ** (10) —  (10) **
Equity-indexed compensation expense
10  9  1  ** 28  28  —  **
Foreign currency revaluation
(4) 2  (6) ** 7  (22) 29  **
Line 901 incident
—  120  (120) ** —  120  (120) **
Transaction-related expenses
—  —  —  ** 7  —  7  **
Selected Items Impacting Comparability - Segment Adjusted EBITDA (1) (6)
(44) 72  (116) ** (34) 222  (256) **

Foreign currency revaluation (7)
15  (1) 16  ** 13  6  7  **

Selected Items Impacting Comparability - Adjusted EBITDA (1) (8)
(29) 71  (100) ** (21) 228  (249) **
Adjusted EBITDA (1) (8)
$ 806  $ 805  $ 1  —  % $ 2,499  $ 2,459  $ 40  2  %
Adjusted EBITDA attributable to noncontrolling interests (9)
(137) (146) 9  6  % (404) (408) 4  1  %
Adjusted EBITDA attributable to PAA (1)
$ 669  $ 659  $ 10  2  % $ 2,095  $ 2,051  $ 44  2  %

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Three Months Ended
September 30, Variance Nine Months Ended
September 30, Variance
  2025 2024 $ % 2025 2024 $ %

Adjusted EBITDA (1) (8) (10)
$ 806  $ 805  $ 1  —  % $ 2,499  $ 2,459  $ 40  2  %
Interest expense, net of certain non-cash and other items (11)
(109) (94) (15) (16) % (320) (274) (46) (17) %
Maintenance capital from continuing operations (12)
(36) (50) 14  28  % (112) (140) 28  20  %
Maintenance capital from discontinued operations (12)
(20) (19) (1) (5) % (49) (48) (1) (2) %
Investment capital of noncontrolling interests (13)
(25) (21) (4) (19) % (89) (62) (27) (44) %
Current income tax expense from continuing operations
(5) (4) (1) (25) % (11) (72) 61  85  %
Current income tax expense from discontinued operations (3)
(7) (16) 9  56  % (61) (71) 10  14  %
Distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings (14)
(9) 4  (13) ** 10  11  (1) **
Distributions to noncontrolling interests (15)
(110) (113) 3  3  % (339) (310) (29) (9) %
Implied DCF (1)
$ 485  $ 492  $ (7) (1) % $ 1,528  $ 1,493  $ 35  2  %
Preferred unit distributions (15)
(54) (64) 10  16  % (171) (190) 19  10  %
Implied DCF Available to Common Unitholders (1)
$ 431  $ 428  $ 3  1  % $ 1,357  $ 1,303  $ 54  4  %
Common unit cash distributions (15)
(267) (223) (802) (668)
Implied DCF Excess (1) (16)
$ 164  $ 205  $ 555  $ 635