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Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________________________________________________
FORM 10-Q
________________________________________________________________________________________________________________________________
☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 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 May 1, 2025, there were 703,299,255 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 March 3 1, 202 5 and December 31, 20 24 | 3
Condensed Consolidated Statements of Operations: For the three months ended March 3 1, 202 5 and 20 24 | 4
Condensed Consolidated Statements of Comprehensive Income: For the three months ended March 3 1, 202 5 and 20 24 | 5
Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss): For the three months ended March 3 1, 202 5 and 20 24 | 5
Condensed Consolidated Statements of Cash Flows: For the three months ended March 3 1, 202 5 and 20 24 | 6
Condensed Consolidated Statements of Changes in Partners’ Capital: For the three months ended March 3 1, 202 5 and 20 24 | 7
Notes to the Condensed Consolidated Financial Statements: |
1. Organization and Basis of Consolidation and Presentation | 8
2. Revenues and Accounts Receivable | 10
3. Net Income Per Common Unit | 13
4. Inventory, Linefill and Long-term Inventory | 14
5. Debt | 15
6. Partners’ Capital and Distributions | 16
7. Derivatives and Risk Management Activities | 18
8. Related Party Transactions | 21
9. Commitments and Contingencies | 22
10. Segment Information | 25
11. Acquisitions | 30
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 32
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 51
Item 4. CONTROLS AND PROCEDURES | 52
PART II. OTHER INFORMATION |
Item 1. LEGAL PROCEEDINGS | 53
Item 1A. RISK FACTORS | 53
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS | 53
Item 3. DEFAULTS UPON SENIOR SECURITIES | 53
Item 4. MINE SAFETY DISCLOSURES | 53
Item 5. OTHER INFORMATION | 53
Item 6. EXHIBITS | 54
SIGNATURES | 58

2

Table of Contents
PART I. FINANCIAL INFORMATION
Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except unit data)

| March 31, 2025 |  | December 31, 2024
| (unaudited)
ASSETS |  |  |
CURRENT ASSETS |  |  |
Cash and cash equivalents | $ | 427 |  |  | $ | 348 |
Trade accounts receivable and other receivables, net | 3,820 |  |  | 3,901 |
Inventory | 335 |  |  | 439 |
Other current assets | 153 |  |  | 114 |
Total current assets | 4,735 |  |  | 4,802 |
PROPERTY AND EQUIPMENT | 22,125 |  |  | 21,300 |
Accumulated depreciation | (6,063) |  |  | (5,876) |
Property and equipment, net | 16,062 |  |  | 15,424 |
OTHER ASSETS |  |  |
Investments in unconsolidated entities | 2,745 |  |  | 2,811 |
Intangible assets, net | 1,675 |  |  | 1,677 |
Linefill | 988 |  |  | 968 |
Long-term operating lease right-of-use assets, net | 321 |  |  | 332 |
Long-term inventory | 289 |  |  | 280 |
Other long-term assets, net | 244 |  |  | 268 |
Total assets | $ | 27,059 |  |  | $ | 26,562 |
LIABILITIES AND PARTNERS’ CAPITAL |  |  |
CURRENT LIABILITIES |  |  |
Trade accounts payable | $ | 3,725 |  |  | $ | 3,881 |
Short-term debt | 478 |  |  | 408 |
Other current liabilities | 488 |  |  | 661 |
Total current liabilities | 4,691 |  |  | 4,950 |
LONG-TERM LIABILITIES |  |  |
Senior notes, net | 8,131 |  |  | 7,141 |
Other long-term debt, net | 73 |  |  | 72 |
Long-term operating lease liabilities | 301 |  |  | 313 |
Other long-term liabilities and deferred credits | 1,003 |  |  | 990 |
Total long-term liabilities | 9,508 |  |  | 8,516 |
COMMITMENTS AND CONTINGENCIES (NOTE 9) |  |  |
PARTNERS’ CAPITAL |  |  |
Series A preferred unitholders (58,411,908 and 71,090,468 units outstanding, respectively) | 1,245 |  |  | 1,514 |
Series B preferred unitholders (800,000 and 800,000 units outstanding, respectively) | 787 |  |  | 787 |
Common unitholders (703,775,950 and 703,770,300 units outstanding, respectively) | 7,600 |  |  | 7,512 |
Total partners’ capital excluding noncontrolling interests | 9,632 |  |  | 9,813 |
Noncontrolling interests | 3,228 |  |  | 3,283 |
Total partners’ capital | 12,860 |  |  | 13,096 |
Total liabilities and partners’ capital | $ | 27,059 |  |  | $ | 26,562 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
3

Table of Contents
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per unit data)

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
|  |  | (unaudited)
REVENUES |  |  |  |  |  |  |
Product sales revenues |  |  |  |  | $ | 11,544 |  |  | $ | 11,546 |
Services revenues |  |  |  |  | 467 |  |  | 449 |
Total revenues |  |  |  |  | 12,011 |  |  | 11,995 |
COSTS AND EXPENSES |  |  |  |  |  |  |
Purchases and related costs |  |  |  |  | 10,761 |  |  | 10,917 |
Field operating costs |  |  |  |  | 368 |  |  | 358 |
General and administrative expenses |  |  |  |  | 100 |  |  | 96 |
Depreciation and amortization |  |  |  |  | 262 |  |  | 254 |
Gain on asset sales, net |  |  |  |  | (13) |  |  | — |
Total costs and expenses |  |  |  |  | 11,478 |  |  | 11,625 |
OPERATING INCOME |  |  |  |  | 533 |  |  | 370 |
OTHER INCOME/(EXPENSE) |  |  |  |  |  |  |
Equity earnings in unconsolidated entities |  |  |  |  | 103 |  |  | 95 |
Gain on investments in unconsolidated entities, net |  |  |  |  | 31 |  |  | — |
Interest expense (net of capitalized interest of $2 and $2, respectively) |  |  |  |  | (127) |  |  | (95) |
Other income/(expense), net |  |  |  |  | 26 |  |  | (5) |
INCOME BEFORE TAX |  |  |  |  | 566 |  |  | 365 |
Current income tax expense |  |  |  |  | (46) |  |  | (53) |
Deferred income tax (expense)/benefit |  |  |  |  | (4) |  |  | 39 |
NET INCOME |  |  |  |  | 516 |  |  | 351 |
Net income attributable to noncontrolling interests |  |  |  |  | (73) |  |  | (85) |
NET INCOME ATTRIBUTABLE TO PAA |  |  |  |  | $ | 443 |  |  | $ | 266 |
NET INCOME PER COMMON UNIT (NOTE 3): |  |  |  |  |  |  |
Net income allocated to common unitholders — Basic and Diluted |  |  |  |  | $ | 343 |  |  | $ | 203 |
Basic and diluted weighted average common units outstanding |  |  |  |  | 704 |  |  | 701 |
Basic and diluted net income per common unit |  |  |  |  | $ | 0.49 |  |  | $ | 0.29 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
4

Table of Contents
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions)

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
|  |  | (unaudited)
Net income |  |  |  |  | $ | 516 |  |  | $ | 351 |
Other comprehensive income/(loss) |  |  |  |  | 5 |  |  | (71) |
Comprehensive income |  |  |  |  | 521 |  |  | 280 |
Comprehensive income attributable to noncontrolling interests |  |  |  |  | (73) |  |  | (85) |
Comprehensive income attributable to PAA |  |  |  |  | $ | 448 |  |  | $ | 195 |

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 |  |  |  | Total
| (unaudited)
Balance at December 31, 2024 | $ | (44) |  |  | $ | (1,039) |  |  |  |  | $ | (1,083) |
Reclassification adjustments | 1 |  |  | — |  |  |  |  | 1 |
Unrealized loss on hedges | (1) |  |  | — |  |  |  |  | (1) |
Currency translation adjustments | — |  |  | 5 |  |  |  |  | 5 |
Total period activity | — |  |  | 5 |  |  |  |  | 5 |
Balance at March 31, 2025 | $ | (44) |  |  | $ | (1,034) |  |  |  |  | $ | (1,078) |

| Derivative Instruments |  | Translation Adjustments |  |  |  | Total
| (unaudited)
Balance at December 31, 2023 | $ | (81) |  |  | $ | (755) |  |  |  |  | $ | (836) |
Reclassification adjustments | 2 |  |  | — |  |  |  |  | 2 |
Unrealized gain on hedges | 13 |  |  | — |  |  |  |  | 13 |
Currency translation adjustments | — |  |  | (86) |  |  |  |  | (86) |
Total period activity | 15 |  |  | (86) |  |  |  |  | (71) |
Balance at March 31, 2024 | $ | (66) |  |  | $ | (841) |  |  |  |  | $ | (907) |

The accompanying notes are an integral part of these condensed consolidated financial statements.
5

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

| Three Months Ended March 31,
| 2025 |  | 2024
| (unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES |  |  |
Net income | $ | 516 |  |  | $ | 351 |
Reconciliation of net income to net cash provided by operating activities: |  |  |
Depreciation and amortization | 262 |  |  | 254 |
Gain on asset sales, net | (13) |  |  | — |
Deferred income tax expense/(benefit) | 4 |  |  | (39) |
Equity earnings in unconsolidated entities | (103) |  |  | (95) |
Distributions on earnings from unconsolidated entities | 125 |  |  | 132 |
Gain on investments in unconsolidated entities, net (Note 11) | (31) |  |  | — |
Other | 18 |  |  | 8 |
Changes in assets and liabilities, net of acquisitions | (139) |  |  | (192) |
Net cash provided by operating activities | 639 |  |  | 419 |
CASH FLOWS FROM INVESTING ACTIVITIES |  |  |
Cash paid in connection with acquisitions, net of cash acquired | (624) |  |  | (91) |
Investments in unconsolidated entities | — |  |  | (3) |
Additions to property, equipment and other | (191) |  |  | (157) |
Cash paid for purchases of linefill | (7) |  |  | (13) |
Proceeds from sales of assets | 3 |  |  | 3 |
Investments in related party notes (Note 8) | (330) |  |  | — |
Net cash used in investing activities | (1,149) |  |  | (261) |
CASH FLOWS FROM FINANCING ACTIVITIES |  |  |
Net borrowings under commercial paper program (Note 5) | 71 |  |  | 107 |
Proceeds from the issuance of senior notes (Note 5) | 998 |  |  | — |
Proceeds from the issuance of related party notes (Note 8) | 330 |  |  | — |
Repurchase of Series A preferred units (Note 6) | (333) |  |  | — |
Distributions paid to Series A preferred unitholders (Note 6) | (46) |  |  | (44) |
Distributions paid to Series B preferred unitholders (Note 6) | (18) |  |  | (20) |
Distributions paid to common unitholders (Note 6) | (267) |  |  | (223) |
Distributions paid to noncontrolling interests (Note 6) | (132) |  |  | (100) |
Contributions from noncontrolling interests | 4 |  |  | 12 |
Other financing activities | (17) |  |  | (5) |
Net cash provided by/(used in) financing activities | 590 |  |  | (273) |
Effect of translation adjustment | (1) |  |  | (4) |
Net increase/(decrease) in cash and cash equivalents and restricted cash | 79 |  |  | (119) |
Cash and cash equivalents and restricted cash, beginning of period | 348 |  |  | 450 |
Cash and cash equivalents and restricted cash, end of period | $ | 427 |  |  | $ | 331 |
Cash paid for: |  |  |
Interest, net of amounts capitalized | $ | 128 |  |  | $ | 64 |
Income taxes, net of amounts refunded | $ | 27 |  |  | $ | 86 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
6

Table of Contents
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 | 39 |  |  | 18 |  |  | 386 |  |  | 443 |  |  | 73 |  |  | 516 |
Distributions (Note 6) | (39) |  |  | (18) |  |  | (267) |  |  | (324) |  |  | (132) |  |  | (456) |
Other comprehensive income | — |  |  | — |  |  | 5 |  |  | 5 |  |  | — |  |  | 5 |
Repurchase of Series A preferred units (Note 6) | (270) |  |  | — |  |  | (43) |  |  | (313) |  |  | — |  |  | (313) |
Contributions from noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | 4 |  |  | 4 |
Other | 1 |  |  | — |  |  | 7 |  |  | 8 |  |  | — |  |  | 8 |
Balance at March 31, 2025 | $ | 1,245 |  |  | $ | 787 |  |  | $ | 7,600 |  |  | $ | 9,632 |  |  | $ | 3,228 |  |  | $ | 12,860 |

| 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 | 44 |  |  | 19 |  |  | 203 |  |  | 266 |  |  | 85 |  |  | 351 |
Distributions | (44) |  |  | (19) |  |  | (223) |  |  | (286) |  |  | (100) |  |  | (386) |
Other comprehensive loss | — |  |  | — |  |  | (71) |  |  | (71) |  |  | — |  |  | (71) |
Contributions from noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | 12 |  |  | 12 |
Other | 1 |  |  | — |  |  | 7 |  |  | 8 |  |  | — |  |  | 8 |
Balance at March 31, 2024 | $ | 1,510 |  |  | $ | 787 |  |  | $ | 8,042 |  |  | $ | 10,339 |  |  | $ | 3,307 |  |  | $ | 13,646 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
7

Table of Contents
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 and natural gas liquids (“NGL”) producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. Our assets and the services we provide are primarily focused on and conducted through two operating segments: Crude Oil and NGL. See Note 10 for further discussion of our operating segments.
Our non-economic general partner interest is held by PAA GP LLC (“PAA GP”), a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP, as of March 31, 2025, AAP also owned a limited partner interest in us through its ownership of approximately 232.9 million of our common units (approximately 31% of our total outstanding common units and Series A preferred units combined). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole and managing member of GP LLC, and, at March 31, 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.
8

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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 months ended March 31, 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.
Subsequent Events
Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable.
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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 three months ended March 31, 2025 that are of significance or potential significance to us.
Note 2—Revenues and Accounts Receivable
Revenue Recognition
We disaggregate our revenues by segment and type of activity. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for additional information regarding our types of revenues and policies for revenue recognition.
Revenues from Contracts with Customers. The following tables present our revenues from contracts with customers disaggregated by segment and type of activity (in millions):

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
Crude Oil segment revenues from contracts with customers |  |  |  |  |  |  |
Sales |  |  |  |  | $ | 11,008 |  |  | $ | 11,185 |
Transportation |  |  |  |  | 312 |  |  | 300 |
Terminalling, Storage and Other |  |  |  |  | 88 |  |  | 92 |
Total Crude Oil segment revenues from contracts with customers |  |  |  |  | $ | 11,408 |  |  | $ | 11,577 |

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
NGL segment revenues from contracts with customers |  |  |  |  |  |  |
Sales |  |  |  |  | $ | 629 |  |  | $ | 600 |
Transportation |  |  |  |  | 9 |  |  | 10 |
Terminalling, Storage and Other |  |  |  |  | 20 |  |  | 21 |
Total NGL segment revenues from contracts with customers |  |  |  |  | $ | 658 |  |  | $ | 631 |

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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):

Three Months Ended March 31, 2025 |  | Crude Oil |  | NGL |  | Total
Revenues from contracts with customers |  | $ | 11,408 |  |  | $ | 658 |  |  | $ | 12,066 |
Other revenues |  | 31 |  |  | (20) |  |  | 11 |
Total revenues of reportable segments |  | $ | 11,439 |  |  | $ | 638 |  |  | $ | 12,077 |
Intersegment revenues elimination |  |  |  |  |  | (66) |
Total revenues |  |  |  |  |  | $ | 12,011 |
Three Months Ended March 31, 2024 |  | Crude Oil |  | NGL |  | Total
Revenues from contracts with customers |  | $ | 11,577 |  |  | $ | 631 |  |  | $ | 12,208 |
Other revenues |  | 5 |  |  | (124) |  |  | (119) |
Total revenues of reportable segments |  | $ | 11,582 |  |  | $ | 507 |  |  | $ | 12,089 |
Intersegment revenues elimination |  |  |  |  |  | (94) |
Total revenues |  |  |  |  |  | $ | 11,995 |

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

Counterparty Deficiencies |  | Financial Statement Classification |  | March 31, 2025 |  | December 31, 2024
Billed and collected |  | Other current liabilities |  | $ | 72 |  |  | $ | 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 |  | $ | 208 |
Amounts recognized as revenue |  | (20) |
Additions |  | 10 |
Other |  | (6) |
Balance at March 31, 2025 |  | $ | 192 |

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Remaining Performance Obligations. The information below includes the amount of consideration allocated to partially and wholly unsatisfied remaining performance obligations under contracts that existed as of the end of the periods and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These contracts include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of March 31, 2025 (in millions):

| Remainder of 2025 |  | 2026 |  | 2027 |  | 2028 |  | 2029 |  | 2030 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1) | $ | 276 |  |  | $ | 258 |  |  | $ | 219 |  |  | $ | 174 |  |  | $ | 99 |  |  | $ | 487 |
Terminalling, storage and other agreement revenues | 196 |  |  | 231 |  |  | 198 |  |  | 157 |  |  | 122 |  |  | 751 |
Total | $ | 472 |  |  | $ | 489 |  |  | $ | 417 |  |  | $ | 331 |  |  | $ | 221 |  |  | $ | 1,238 |

(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 March 31, 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):

| March 31, 2025 |  | December 31, 2024
Trade accounts receivable arising from revenues from contracts with customers | $ | 3,905 |  |  | $ | 4,090 |
Other trade accounts receivables and other receivables (1) | 8,336 |  |  | 7,413 |
Impact due to contractual rights of offset with counterparties | (8,421) |  |  | (7,602) |
Trade accounts receivable and other receivables, net | $ | 3,820 |  |  | $ | 3,901 |

(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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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 3—Net Income Per Common Unit
We calculate basic and diluted net income per common unit by dividing net income attributable to PAA (after deducting amounts allocated to the preferred unitholders and participating securities) by the basic and diluted weighted average number of common units outstanding during the period.
The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units and (ii) our equity-indexed compensation plan awards. See Note 11 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, the possible conversion of approximately 63 million and 71 million Series A preferred units, on a weighted-average basis, were excluded from the calculation of diluted net income per common unit for each of the three months ended March 31, 2025 and 2024, respectively, as the effect was antidilutive. Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that are deemed to be dilutive during the period are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.
The following table sets forth the computation of basic and diluted net income per common unit (in millions, except per unit data):

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
Basic and Diluted Net Income per Common Unit |  |  |  |  |  |  |
Net income attributable to PAA |  |  |  |  | $ | 443 |  |  | $ | 266 |
Distributions to Series A preferred unitholders |  |  |  |  | (39) |  |  | (44) |
Distributions to Series B preferred unitholders |  |  |  |  | (18) |  |  | (19) |
Amounts allocated to participating securities |  |  |  |  | (1) |  |  | (1) |
Impact from repurchase of Series A preferred units (1) |  |  |  |  | (43) |  |  | — |
Other |  |  |  |  | 1 |  |  | 1 |
Net income allocated to common unitholders (2) |  |  |  |  | $ | 343 |  |  | $ | 203 |
Basic and diluted weighted average common units outstanding |  |  |  |  | 704 |  |  | 701 |
Basic and diluted net income per common unit |  |  |  |  | $ | 0.49 |  |  | $ | 0.29 |

(1)We repurchased approximately 12.7 million Series A preferred units on January 31, 2025. See Note 6 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 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.
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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 4—Inventory, Linefill and Long-term Inventory
Inventory, linefill and long-term inventory consisted of the following (barrels in thousands and carrying value in millions):

| March 31, 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 | 3,399 |  |  | barrels |  | $ | 221 |  |  | $ | 65.02 |  |  |  | 3,911 |  |  | barrels |  | $ | 259 |  |  | $ | 66.22 |
NGL | 3,410 |  |  | barrels |  | 102 |  |  | $ | 29.91 |  |  |  | 6,985 |  |  | barrels |  | 166 |  |  | $ | 23.77 |
Other | N/A |  |  |  | 12 |  |  | N/A |  |  | N/A |  |  |  | 14 |  |  | N/A
Inventory subtotal |  |  |  |  | 335 |  |  |  |  |  |  |  |  |  | 439 |  |  |
Linefill |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Crude oil | 15,754 |  |  | barrels |  | 924 |  |  | $ | 58.65 |  |  |  | 15,521 |  |  | barrels |  | 906 |  |  | $ | 58.37 |
NGL | 2,269 |  |  | barrels |  | 64 |  |  | $ | 28.21 |  |  |  | 2,259 |  |  | barrels |  | 62 |  |  | $ | 27.45 |
Linefill subtotal |  |  |  |  | 988 |  |  |  |  |  |  |  |  |  | 968 |  |  |
Long-term inventory |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Crude oil | 3,501 |  |  | barrels |  | 244 |  |  | $ | 69.69 |  |  |  | 3,424 |  |  | barrels |  | 239 |  |  | $ | 69.80 |
NGL | 1,355 |  |  | barrels |  | 45 |  |  | $ | 33.21 |  |  |  | 1,355 |  |  | barrels |  | 41 |  |  | $ | 30.26 |
Long-term inventory subtotal |  |  |  |  | 289 |  |  |  |  |  |  |  |  |  | 280 |  |  |
Total |  |  |  |  | $ | 1,612 |  |  |  |  |  |  |  |  |  | $ | 1,687 |  |  |

(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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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 5—Debt
Debt consisted of the following (in millions):

| March 31, 2025 |  | December 31, 2024
SHORT-TERM DEBT |  |  |
Commercial paper notes, bearing a weighted-average interest rate of 4.6% and 4.6%, respectively (1) | $ | 464 |  |  | $ | 393 |
Other | 14 |  |  | 15 |
Total short-term debt | 478 |  |  | 408 |
LONG-TERM DEBT |  |  |
Senior notes, net of unamortized discounts and debt issuance costs of $52 and $42, respectively (2) | 8,131 |  |  | 7,141 |
Other | 73 |  |  | 72 |
Total long-term debt | 8,204 |  |  | 7,213 |
Total debt (3) | $ | 8,682 |  |  | $ | 7,621 |

(1)We classified these commercial paper notes as short-term as of March 31, 2025 and 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 NGL and crude oil inventory and NYMEX and ICE margin deposits.
(2)As of March 31, 2025 and 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.
(3)Our fixed-rate senior notes had a face value of approximately $8.2 billion and $7.2 billion as of March 31, 2025 and December 31, 2024, respectively. We estimated the aggregate fair value of these notes as of March 31, 2025 and December 31, 2024 to be approximately $7.8 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.
Borrowings and Repayments
Total borrowings under our commercial paper program for the three months ended March 31, 2025 and 2024 were approximately $12.9 billion and $9.1 billion, respectively. Total repayments under our commercial paper program were approximately $12.8 billion and $9.0 billion for the three months ended March 31, 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.
Letters of Credit
In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil and NGL. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At March 31, 2025 and December 31, 2024, we had outstanding letters of credit of $78 million and $90 million, respectively.
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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 6—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 |

| 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 |

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.
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 three months of 2025 (in millions, except per unit data):

|  |  |  |  |  | Series A Preferred Unitholders
Distribution Payment Date |  | Record Date (1) |  | Quarter Ended |  | Cash Distribution |  |  | Distribution per Unit
May 15, 2025 (2) |  | May 1, 2025 |  | March 31, 2025 |  | $ | 36 |  |  |  | $ | 0.615 |
February 14, 2025 |  | January 31, 2025 |  | December 31, 2024 |  | $ | 36 |  |  |  | $ | 0.615 |

(1)Payable to unitholders of record at the close of business on the applicable Record Date.
(2)At March 31, 2025, such amount was accrued as distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet.
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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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
May 15, 2025 (2) |  | 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 March 31, 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.
Common Unit Distributions. The following table details distributions to our common unitholders paid during or pertaining to the first three months of 2025 (in millions, except per unit data):

|  |  |  |  |  | Distributions |  |  | Distribution per Common Unit
Distribution Payment Date |  | Record Date (1) |  | Quarter Ended |  | Common Unitholders |  | Total Cash Distribution |  |
|  |  | Public |  | AAP |  |  |
May 15, 2025 |  | May 1, 2025 |  | March 31, 2025 |  | $ | 179 |  |  | $ | 88 |  |  | $ | 267 |  |  |  | $ | 0.38 |
February 14, 2025 |  | January 31, 2025 |  | 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 March 31, 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 March 31, |  |
|  |  |  |  | 2025 |  | 2024 |  |
Permian JV |  |  |  |  | $ | 105 |  |  | $ | 74 |  |  |
Cactus II |  |  |  |  | 22 |  |  | 20 |  |  |
Red River |  |  |  |  | 5 |  |  | 6 |  |  |
|  |  |  |  | $ | 132 |  |  | $ | 100 |  |  |

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 7—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 and interest rate risk. Our commodity price risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on changes in commodity prices or interest rates. When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. At the inception of the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions. Throughout the hedging relationship, retrospective and prospective hedge effectiveness is assessed on a qualitative basis.
We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives designated as cash flow hedges, changes in fair value are deferred in AOCI and recognized in earnings in the periods during which the underlying hedged transactions are recognized in earnings. Derivatives that are not designated in a hedging relationship for accounting purposes are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Condensed Consolidated Statements of Cash Flows.
Our financial derivatives, used for hedging risk, are governed through ISDA master agreements and clearing brokerage agreements. These agreements include stipulations regarding the right of set off in the event that we or our counterparty default on performance obligations. If a default were to occur, both parties have the right to net amounts payable and receivable into a single net settlement between parties.
At March 31, 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 March 31, 2025, net derivative positions related to these activities included:
•A net long position of 8.5 million barrels associated with our crude oil purchases, which was unwound ratably during April 2025 to match monthly average pricing.
•A net short time spread position of 2.2 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through February 2026.
•A net crude oil basis spread position of 0.2 million barrels at multiple locations through December 2025. These derivatives allow us to lock in grade and location basis differentials.
•A net short position of 8.2 million barrels through December 2029 related to anticipated net sales of crude oil and NGL inventory.
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We purchase natural gas for processing and operational needs. Additionally, we purchase NGL mix for fractionation and sell the resulting individual specification products (including ethane, propane, butane and condensate). In conjunction with these activities, we hedge the price risk associated with the purchase of the natural gas and the subsequent sale of the individual specification products. The following table summarizes our open derivative positions utilized to hedge the price risk associated with anticipated purchases and sales related to our natural gas processing and NGL fractionation activities as of March 31, 2025:

|  | Notional Volume |  |
|  | (Short)/Long |  | Remaining Tenor
Natural gas purchases |  | 41.6 Bcf |  | March 2026
Propane sales |  | (7.8) MMbls |  | March 2026
Butane sales |  | (0.9) MMbls |  | December 2025
Condensate sales |  | (1.8) MMbls |  | December 2025
Fuel gas requirements (1) |  | 1.6 Bcf |  | December 2025
Power supply requirements (1) |  | 1.9 TWh |  | December 2030

(1)Positions to hedge a portion of our power supply and fuel gas requirements at our Canadian natural gas processing and fractionation plants.
Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchases and normal sales scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings. We have determined that substantially all of our physical commodity contracts qualify for the normal purchases and normal sales scope exception.
Our commodity derivatives are not designated in a hedging relationship for accounting purposes; as such, changes in the fair value are reported in earnings. The following table summarizes the impact of our commodity derivatives recognized in earnings (in millions):

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
Product sales revenues |  |  |  |  | $ | (34) |  |  | $ | (173) |
Field operating costs |  |  |  |  | (12) |  |  | (16) |
Net loss from commodity derivative activity |  |  |  |  | $ | (46) |  |  | $ | (189) |

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

| March 31, 2025 |  | December 31, 2024
Initial margin | $ | 66 |  |  | $ | 53 |
Variation margin posted | 59 |  |  | 49 |
Letters of credit | (29) |  |  | (30) |
Net broker receivable | $ | 96 |  |  | $ | 72 |

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

|  | March 31, 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 |  | $ | 38 |  |  | $ | (25) |  |  | $ | 66 |  |  | $ | 79 |  |  |  | $ | 36 |  |  | $ | (74) |  |  | $ | 72 |  |  | $ | 34 |
Other long-term assets, net |  | 1 |  |  | — |  |  | — |  |  | 1 |  |  |  | — |  |  | — |  |  | — |  |  | — |
Derivative Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other current liabilities |  | 10 |  |  | (44) |  |  | 30 |  |  | (4) |  |  |  | 4 |  |  | (28) |  |  | — |  |  | (24) |
Other long-term liabilities and deferred credits |  | 3 |  |  | (26) |  |  | — |  |  | (23) |  |  |  | 2 |  |  | (16) |  |  | — |  |  | (14) |
Total |  | $ | 52 |  |  | $ | (95) |  |  | $ | 96 |  |  | $ | 53 |  |  |  | $ | 42 |  |  | $ | (118) |  |  | $ | 72 |  |  | $ | (4) |

Interest Rate Risk Hedging
We use interest rate derivatives to hedge the benchmark interest rate associated with interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist of forward starting interest rate swaps and treasury locks. These derivatives are designated as cash flow hedges. As such, changes in fair value are deferred in AOCI and are reclassified to interest expense as we incur the interest expense associated with the underlying debt.
The following table summarizes the terms of our outstanding interest rate derivatives as of March 31, 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
Anticipated interest payments |  | 4 forward starting swaps (30-year) |  | $ | 100 |  |  | 10/15/2025 |  | 3.76% |  | Cash flow hedge

As of March 31, 2025, there was a net loss of $44 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 March 31, 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 March 31,
|  |  |  |  | 2025 |  | 2024
Interest rate derivatives, net |  |  |  |  | $ | (1) |  |  | $ | 13 |

At March 31, 2025, the net fair value of our interest rate hedges, which was included in “Other current assets” and “Other long-term assets, net” on our Condensed Consolidated Balance Sheet, totaled $1 million and $24 million, respectively. 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.
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Recurring Fair Value Measurements
Derivative Financial Assets and Liabilities
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions):

|  | Fair Value as of March 31, 2025 |  |  | Fair Value as of December 31, 2024
Recurring Fair Value Measures (1) |  | Level 1 |  | Level 2 |  |  |  | Total |  |  | Level 1 |  | Level 2 |  |  |  | Total
Commodity derivatives |  | $ | 21 |  |  | $ | (64) |  |  |  |  | $ | (43) |  |  |  | $ | 14 |  |  | $ | (90) |  |  |  |  | $ | (76) |
Interest rate derivatives |  | — |  |  | 25 |  |  |  |  | 25 |  |  |  | — |  |  | 27 |  |  |  |  | 27 |
Total net derivative asset/(liability) |  | $ | 21 |  |  | $ | (39) |  |  |  |  | $ | (18) |  |  |  | $ | 14 |  |  | $ | (63) |  |  |  |  | $ | (49) |

(1)Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.
Level 1
Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives and over-the-counter commodity contracts such as futures and swaps. The fair value of exchange-traded commodity derivatives and over-the-counter commodity contracts is based on unadjusted quoted prices in active markets.
Level 2
Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives and over-the-counter commodity and interest rate derivatives that are traded in observable markets with less volume and transaction frequency than active markets. In addition, it includes certain physical commodity contracts. The fair values of these derivatives are corroborated with market observable inputs.
Note 8—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 $8 million and $27 million as of March 31, 2025 and December 31, 2024, respectively. Interest income/expense on the related party notes totaled $20 million and $8 million for the three months ended March 31, 2025 and 2024, respectively.
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As of March 31, 2025 and December 31, 2024, our outstanding related party notes receivable and related party notes payable balances were as follows (in millions):

| March 31, 2025 |  | December 31, 2024
Related party notes receivable (1) | $ | 1,278 |  |  | $ | 948 |
Related party notes payable (1) | $ | 1,278 |  |  | $ | 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.
Transactions with Other Related Parties
During the three months ended March 31, 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 March 31,
|  |  |  |  | 2025 |  | 2024
Revenues from related parties |  |  |  |  | $ | 11 |  |  | $ | 11 |
Purchases and related costs from related parties |  |  |  |  | $ | 97 |  |  | $ | 97 |

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

| March 31, 2025 |  | December 31, 2024
Trade accounts receivable and other receivables, net from related parties (1) | $ | 39 |  |  | $ | 40 |
Trade accounts payable to related parties (1) (2) | $ | 68 |  |  | $ | 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 9—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.
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We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss.
Legal Proceedings — General
In the ordinary course of business, we are involved in various legal proceedings including those arising from regulatory and environmental matters. In connection with determining the probability of loss associated with such legal proceedings and whether any potential losses associated therewith are estimable, we take into account what we believe to be all relevant known facts and circumstances, and what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing agreements, laws and regulations. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully protect us from losses arising from current or future legal proceedings.
Accordingly, we can provide no assurance that the outcome of the various legal proceedings that we are currently involved in, or will become involved with in the future, will not, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
Environmental — General
We currently own or lease, and in the past have owned and leased, properties where hazardous liquids, including hydrocarbons, are or have been handled. These properties and the hazardous liquids or associated wastes disposed thereon may be subject to the U.S. federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, and the U.S. federal Resource Conservation and Recovery Act, as amended, as well as state and Canadian federal and provincial laws and regulations. Under such laws and regulations, we could be required to remove or remediate hazardous liquids or associated wastes (including wastes disposed of or released by prior owners or operators) and to clean up contaminated property (including contaminated groundwater). Assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified or insured.
Although we have made significant investments in our maintenance and integrity programs, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail, storage and other facility operations. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. We also may discover environmental impacts from past releases that were previously unidentified. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated. Generally, our recording of these 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):
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| March 31, 2025 |  | December 31, 2024
Other current liabilities | $ | 29 |  |  | $ | 15 |
Other long-term liabilities and deferred credits | 87 |  |  | 81 |
Total | $ | 116 |  |  | $ | 96 |

In some cases, the actual cash expenditures associated with these liabilities may not occur for several years. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing or future legal claims giving rise to additional liabilities. Therefore, although we believe that our reserves are adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of such reserves and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
Specific Legal, Environmental or Regulatory Matters
Line 901 Incident. In May 2015 we experienced a release of crude oil from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. Effective as of March 31, 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 and projected 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.
We did not recognize any costs, net of amounts probable of recovery from insurance (as applicable), during the three months ended March 31, 2025 and 2024. As of March 31, 2025 and December 31, 2024, we had a remaining undiscounted gross liability of approximately $4 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.
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We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such liabilities. To date, we have collected $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 $225 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 March 31, 2025 and December 31, 2024.
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, professional and regulatory costs during future periods. The remaining Line 901 lawsuits include various lawsuits filed in California Superior Court in Santa Barbara County by (i) companies and individuals who provided labor, goods, or services associated with oil production activities they claim were disrupted following the Line 901 incident, and (ii) a landowner on an adjacent pipeline alleging property damage from the “stigma” of the Line 901 incident. We are vigorously defending these remaining lawsuits, which have 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 lawsuits 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 March 31, 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. 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 10—Segment Information
Our operating segments, Crude Oil and NGL, which are also our reportable segments, are organized by product as our Crude Oil and NGL businesses are generally impacted by different market fundamentals and require the use of different assets and business strategies. The Crude Oil segment includes our crude oil pipelines, crude oil storage and marine terminals and related crude oil marketing activities. The NGL segment includes our NGL pipelines, NGL storage, natural gas processing and NGL fractionation facilities and related NGL marketing activities. Our crude oil and NGL marketing activities are included in the respective reporting segments as their primary purpose is to support the utilization of our assets by entering into transactions that facilitate increased volumes handled by our assets, resulting in additional earnings for each of our segments.
Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below). 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 for each segment (in millions):

| Crude Oil |  | NGL |  | Intersegment Elimination |  | Total |
Three Months Ended March 31, 2025 |  |  |  |  |  |  |  |
Revenues (1): |  |  |  |  |  |  |  |
Product sales | $ | 11,008 |  |  | $ | 596 |  |  | $ | (60) |  |  | $ | 11,544 |  |
Services | 431 |  |  | 42 |  |  | (6) |  |  | 467 |  |
Total revenues | 11,439 |  |  | 638 |  |  | (66) |  |  | 12,011 |  |
Significant segment expenses: |  |  |  |  |  |  |  |
Purchases and related costs (1) | (10,488) |  |  | (339) |  |  | 66 |  |  | (10,761) |  |
Field operating costs | (292) |  |  | (76) |  |  | — |  |  | (368) |  |
Segment general and administrative expenses | (79) |  |  | (21) |  |  | — |  |  | (100) |  |
Total significant segment expenses | (10,859) |  |  | (436) |  |  | 66 |  |  | (11,229) |  |
Equity earnings in unconsolidated entities | 103 |  |  | — |  |  |  |  |  |
Other segment items (2): |  |  |  |  |  |  |  |
Depreciation and amortization of unconsolidated entities (3) | 20 |  |  | — |  |  |  |  |  |
Derivative activities and inventory valuation adjustments (4) | (24) |  |  | (10) |  |  |  |  |  |
Long-term inventory costing adjustments (5) | — |  |  | (3) |  |  |  |  |  |
Deficiencies under minimum volume commitments, net (6) | (7) |  |  | — |  |  |  |  |  |
Equity-indexed compensation expense (7) | 9 |  |  | — |  |  |  |  |  |
Transaction-related expenses (8) | 5 |  |  | — |  |  |  |  |  |
Segment amounts attributable to noncontrolling interests (9) | (127) |  |  | — |  |  |  |  |  |
Total other segment items | (124) |  |  | (13) |  |  |  |  |  |
Segment Adjusted EBITDA | $ | 559 |  |  | $ | 189 |  |  |  |  |  |
Investment and acquisition capital expenditures (10) (11) | $ | 785 |  |  | $ | 41 |  |  |  |  | $ | 826 |  |
Maintenance capital expenditures (11) | $ | 31 |  |  | $ | 10 |  |  |  |  | $ | 41 |  |
As of March 31, 2025 |  |  |  |  |  |  |  |
Investments in unconsolidated entities | $ | 2,745 |  |  | $ | — |  |  |  |  | $ | 2,745 |  |

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

| Crude Oil |  | NGL |  | Intersegment Elimination |  | Total |
Three Months Ended March 31, 2024 |  |  |  |  |  |  |  |
Revenues (1): |  |  |  |  |  |  |  |
Product sales | $ | 11,176 |  |  | $ | 458 |  |  | $ | (88) |  |  | $ | 11,546 |  |
Services | 406 |  |  | 49 |  |  | (6) |  |  | 449 |  |
Total revenues | 11,582 |  |  | 507 |  |  | (94) |  |  | 11,995 |  |
Significant segment expenses: |  |  |  |  |  |  |  |
Purchases and related costs (1) | (10,665) |  |  | (346) |  |  | 94 |  |  | (10,917) |  |
Field operating costs | (266) |  |  | (92) |  |  | — |  |  | (358) |  |
Segment general and administrative expenses | (73) |  |  | (23) |  |  | — |  |  | (96) |  |
Total significant segment expenses | (11,004) |  |  | (461) |  |  | 94 |  |  | (11,371) |  |
Equity earnings in unconsolidated entities | 95 |  |  | — |  |  |  |  |  |
Other segment items (2): |  |  |  |  |  |  |  |
Depreciation and amortization of unconsolidated entities (3) | 19 |  |  | — |  |  |  |  |  |
Derivative activities and inventory valuation adjustments (4) | 37 |  |  | 122 |  |  |  |  |  |
Long-term inventory costing adjustments (5) | (28) |  |  | (5) |  |  |  |  |  |
Deficiencies under minimum volume commitments, net (6) | (12) |  |  | — |  |  |  |  |  |
Equity-indexed compensation expense (7) | 9 |  |  | — |  |  |  |  |  |
Foreign currency revaluation (12) | (17) |  |  | (4) |  |  |  |  |  |
Segment amounts attributable to noncontrolling interests (9) | (128) |  |  | — |  |  |  |  |  |
Total other segment items | (120) |  |  | 113 |  |  |  |  |  |
Segment Adjusted EBITDA | $ | 553 |  |  | $ | 159 |  |  |  |  |  |
Investment and acquisition capital expenditures (10) (11) | $ | 183 |  |  | $ | 14 |  |  |  |  | $ | 197 |  |
Maintenance capital expenditures (11) | $ | 46 |  |  | $ | 11 |  |  |  |  | $ | 57 |  |
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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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(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)Primarily related to acquisitions completed during the first quarter of 2025. See Note 11 for information regarding these transactions.
(9)Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River.
(10)Investment capital and acquisition capital expenditures, including investments in unconsolidated entities.
(11)These amounts combined represent total capital expenditures.
(12)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.
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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Segment Adjusted EBITDA Reconciliation
The following table reconciles Segment Adjusted EBITDA to Net income attributable to PAA (in millions):

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
Segment Adjusted EBITDA |  |  |  |  | $ | 748 |  |  | $ | 712 |
Total other segment items (1) |  |  |  |  | 137 |  |  | 7 |
Depreciation and amortization |  |  |  |  | (262) |  |  | (254) |
Gain on asset sales, net |  |  |  |  | 13 |  |  | — |
Gain on investments in unconsolidated entities, net |  |  |  |  | 31 |  |  | — |
Interest expense, net |  |  |  |  | (127) |  |  | (95) |
Other income/(expense), net |  |  |  |  | 26 |  |  | (5) |
Income before tax |  |  |  |  | 566 |  |  | 365 |
Income tax expense |  |  |  |  | (50) |  |  | (14) |
Net income |  |  |  |  | 516 |  |  | 351 |
Net income attributable to noncontrolling interests |  |  |  |  | (73) |  |  | (85) |
Net income attributable to PAA |  |  |  |  | $ | 443 |  |  | $ | 266 |

(1)See footnotes to the segment financial data tables above for a more detailed discussion of Other segment items.
Note 11— 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 6 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 |  | $ | 442 |
Intangible assets |  | 16 |  | 27 |
Working capital and other assets and liabilities |  | N/A |  | 12 |
|  |  |  | $ | 481 |

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 during the three months ended March 31, 2025, and the future amortization expense for the remainder of 2025 through 2029 is estimated as follows (in millions):

Remainder of 2025 |  |  |  | $ | 3 |
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 LLC. 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.
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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 and NGL producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. Our assets and the services we provide are primarily focused on crude oil and NGL.
Overview of Operating Results
We recognized net income attributable to PAA of $443 million for the three months ended March 31, 2025 compared to net income attributable to PAA of $266 million for the first three months of 2024. The increase in net income attributable to PAA was largely driven by fluctuations of derivative mark-to-market valuations, as well as higher Segment Adjusted EBITDA in the 2025 period due to more favorable results from our Crude Oil and NGL segments. See the “Results of Operations” section below for further discussion.
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Results of Operations
Consolidated Results
The following table sets forth an overview of our consolidated financial results calculated in accordance with GAAP (in millions, except per unit data):

|  |  |  |  |  | Three Months Ended March 31, |  | Variance
|  |  |  |  |  |  |  |  |  | 2025 |  | 2024 |  | $ |  | %
Product sales revenues |  |  |  |  |  |  |  |  |  | $ | 11,544 |  |  | $ | 11,546 |  |  | $ | (2) |  |  | — | %
Services revenues |  |  |  |  |  |  |  |  |  | 467 |  |  | 449 |  |  | 18 |  |  | 4 | %
Purchases and related costs |  |  |  |  |  |  |  |  |  | (10,761) |  |  | (10,917) |  |  | 156 |  |  | 1 | %
Field operating costs |  |  |  |  |  |  |  |  |  | (368) |  |  | (358) |  |  | (10) |  |  | (3) | %
General and administrative expenses |  |  |  |  |  |  |  |  |  | (100) |  |  | (96) |  |  | (4) |  |  | (4) | %
Depreciation and amortization |  |  |  |  |  |  |  |  |  | (262) |  |  | (254) |  |  | (8) |  |  | (3) | %
Gain on asset sales, net |  |  |  |  |  |  |  |  |  | 13 |  |  | — |  |  | 13 |  |  | N/A
Equity earnings in unconsolidated entities |  |  |  |  |  |  |  |  |  | 103 |  |  | 95 |  |  | 8 |  |  | 8 | %
Gain on investments in unconsolidated entities, net |  |  |  |  |  |  |  |  |  | 31 |  |  | — |  |  | 31 |  |  | N/A
Interest expense, net (1) |  |  |  |  |  |  |  |  |  | (127) |  |  | (95) |  |  | (32) |  |  | (34) | %
Other income/(expense), net (1) |  |  |  |  |  |  |  |  |  | 26 |  |  | (5) |  |  | 31 |  |  | **
Income tax expense |  |  |  |  |  |  |  |  |  | (50) |  |  | (14) |  |  | (36) |  |  | **
Net income |  |  |  |  |  |  |  |  |  | 516 |  |  | 351 |  |  | 165 |  |  | 47 | %
Net income attributable to noncontrolling interests |  |  |  |  |  |  |  |  |  | (73) |  |  | (85) |  |  | 12 |  |  | 14 | %
Net income attributable to PAA |  |  |  |  |  |  |  |  |  | $ | 443 |  |  | $ | 266 |  |  | $ | 177 |  |  | 67 | %
Basic and diluted net income per common unit |  |  |  |  |  |  |  |  |  | $ | 0.49 |  |  | $ | 0.29 |  |  | $ | 0.20 |  |  | 69 | %
Basic and diluted weighted average common units outstanding |  |  |  |  |  |  |  |  |  | 704 |  |  | 701 |  |  | 3 |  |  | — | %

** Indicates that variance as a percentage is not meaningful.
(1)“Interest expense, net” and “Other income/(expense), net” each include $20 million for the three months ended March 31, 2025 related to interest on promissory notes by and among PAA and certain Plains entities.
Revenues and Purchases
Fluctuations in our consolidated 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”) and our NGL sales are indexed to Mont Belvieu prices. The following table presents the range of the NYMEX Price over the last two years (in dollars per barrel):

| NYMEX Price
| Low |  | High |  | Average
Three Months Ended March 31, 2025 | $ | 66 |  |  | $ | 80 |  |  | $ | 71 |
Three Months Ended March 31, 2024 | $ | 70 |  |  | $ | 83 |  |  | $ | 77 |

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Product sales revenues (including the impact of derivative mark-to-market valuations), services revenues and purchases for the three months ended March 31, 2025 were all relatively in line with the same metrics for the three months ended March 31, 2024.
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 three months ended March 31, 2025 compared to the same period in 2024 was primarily due to transaction costs associated with our recent acquisitions.
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 11 to our Condensed Consolidated Financial Statements for additional information regarding this transaction.
Interest Expense, Net and Other Income/(Expense), Net
For the three months ended March 31, 2025, “Interest expense, net” and “Other income/(expense), net” each include interest expense and interest income associated with promissory notes payable and receivable by and among PAA 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 is presented on a net basis in the reconciliation of these metrics to Net Income. See the “—Non-GAAP Financial Measures” section below.
The following table summarizes the components impacting Interest expense, net (in millions):

|  |  |  | Three Months Ended March 31,
|  |  |  |  |  | 2025 |  | 2024
Interest expense on third-party borrowings (1) |  |  |  |  |  | $ | 109 |  |  | $ | 97 |
Interest expense on related party promissory notes (2) |  |  |  |  |  | 20 |  |  | — |
Capitalized interest |  |  |  |  |  | (2) |  |  | (2) |
|  |  |  |  |  | $ | 127 |  |  | $ | 95 |

(1)The increase for the 2025 period compared to the same period in 2024 was primarily driven by our issuance of $1.0 billion, 5.95% senior notes in January 2025. See Note 5 to our Condensed Consolidated Financial Statements for additional information regarding our senior notes.
(2)Represents interest expense associated with promissory notes by and among PAA and certain Plains entities, as described above.
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The following table summarizes the components impacting Other income/(expense), net (in millions):

|  |  |  | Three Months Ended March 31,
|  |  |  |  |  | 2025 |  | 2024
Interest income on related party promissory notes (1) |  |  |  |  |  | $ | 20 |  |  | $ | — |
Interest income from other sources |  |  |  |  |  | 5 |  |  | 5 |
Net loss on foreign currency revaluation (2) |  |  |  |  |  | — |  |  | (12) |
Other |  |  |  |  |  | 1 |  |  | 2 |
|  |  |  |  |  | $ | 26 |  |  | $ | (5) |

(1)Represents interest income associated with promissory notes by and among PAA and certain Plains entities, as described above.
(2)The activity during the periods presented was primarily related to the impact from the change in the CAD to USD exchange rate on the portion of our intercompany net investment that is not long-term in nature.
Income Tax Expense
The net unfavorable income tax variance for the three months ended March 31, 2025 compared to the same period in 2024 was primarily due to higher year-over-year income within our Canadian operations as impacted by fluctuations of derivative mark-to-market valuations.
Noncontrolling Interests
The decrease in amounts attributable to noncontrolling interests for the three months ended March 31, 2025 compared to the same period in 2024 was primarily due to lower income recognized by the Permian JV in the 2025 period driven by additional depreciation and amortization associated with recent acquisitions.
Non-GAAP Financial Measures
To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future and to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. The primary additional measures used by management are Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied distributable cash flow (“DCF”), Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions.
Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF are reconciled to Net Income, and Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions are reconciled to Net Cash Provided by Operating Activities, the most directly comparable measures as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our Condensed Consolidated Financial Statements and accompanying notes. See “—Liquidity and Capital Resources—Non-GAAP Financial Liquidity Measures” for additional information regarding Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions.
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Non-GAAP Financial Performance Measures
Adjusted EBITDA is defined as earnings before interest expense, income tax (expense)/benefit, depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, of unconsolidated entities), gains and losses on asset sales, gains or losses on investments in unconsolidated entities and interest income on promissory notes by and among PAA and certain Plains entities, 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 core 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 core operating results and/or (v) other items that we believe should be excluded in understanding our core 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.”
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The following tables set forth the reconciliation of the non-GAAP financial performance measures Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF to Net Income (in millions):

|  |  |  |  |  |  | Three Months Ended March 31, |  | Variance
|  |  |  |  |  |  |  |  |  |  | 2025 |  | 2024 |  | $ |  | %
Net income |  |  |  |  |  |  |  |  |  |  | $ | 516 |  |  | $ | 351 |  |  | $ | 165 |  |  | 47 | %
Interest expense, net of certain items (1) |  |  |  |  |  |  |  |  |  |  | 107 |  |  | 95 |  |  | 12 |  |  | 13 | %
Income tax expense |  |  |  |  |  |  |  |  |  |  | 50 |  |  | 14 |  |  | 36 |  |  | **
Depreciation and amortization |  |  |  |  |  |  |  |  |  |  | 262 |  |  | 254 |  |  | 8 |  |  | 3 | %
Gain on asset sales, net |  |  |  |  |  |  |  |  |  |  | (13) |  |  | — |  |  | (13) |  |  | N/A
Gain on investments in unconsolidated entities, net |  |  |  |  |  |  |  |  |  |  | (31) |  |  | — |  |  | (31) |  |  | N/A
Depreciation and amortization of unconsolidated entities (2) |  |  |  |  |  |  |  |  |  |  | 20 |  |  | 19 |  |  | 1 |  |  | 5 | %
Selected Items Impacting Comparability: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivative activities and inventory valuation adjustments |  |  |  |  |  |  |  |  |  |  | (34) |  |  | 159 |  |  | (193) |  |  | **
Long-term inventory costing adjustments |  |  |  |  |  |  |  |  |  |  | (3) |  |  | (33) |  |  | 30 |  |  | **
Deficiencies under minimum volume commitments, net |  |  |  |  |  |  |  |  |  |  | (7) |  |  | (12) |  |  | 5 |  |  | **
Equity-indexed compensation expense |  |  |  |  |  |  |  |  |  |  | 9 |  |  | 9 |  |  | — |  |  | **
Foreign currency revaluation |  |  |  |  |  |  |  |  |  |  | — |  |  | (21) |  |  | 21 |  |  | **
Transaction-related expenses |  |  |  |  |  |  |  |  |  |  | 5 |  |  | — |  |  | 5 |  |  | **
Selected Items Impacting Comparability - Segment Adjusted EBITDA (3) |  |  |  |  |  |  |  |  |  |  | (30) |  |  | 102 |  |  | (132) |  |  | **
Foreign currency revaluation (4) |  |  |  |  |  |  |  |  |  |  | — |  |  | 12 |  |  | (12) |  |  | **
Selected Items Impacting Comparability - Adjusted EBITDA (5) |  |  |  |  |  |  |  |  |  |  | (30) |  |  | 114 |  |  | (144) |  |  | **
Adjusted EBITDA (5) |  |  |  |  |  |  |  |  |  |  | $ | 881 |  |  | $ | 847 |  |  | $ | 34 |  |  | 4 | %
Adjusted EBITDA attributable to noncontrolling interests (6) |  |  |  |  |  |  |  |  |  |  | (127) |  |  | (129) |  |  | 2 |  |  | 2 | %
Adjusted EBITDA attributable to PAA |  |  |  |  |  |  |  |  |  |  | $ | 754 |  |  | $ | 718 |  |  | $ | 36 |  |  | 5 | %
Adjusted EBITDA (5) (7) |  |  |  |  |  |  |  |  |  |  | $ | 881 |  |  | $ | 847 |  |  | $ | 34 |  |  | 4 | %
Interest expense, net of certain non-cash and other items (8) |  |  |  |  |  |  |  |  |  |  | (104) |  |  | (90) |  |  | (14) |  |  | (16) | %
Maintenance capital (9) |  |  |  |  |  |  |  |  |  |  | (41) |  |  | (57) |  |  | 16 |  |  | 28 | %
Investment capital of noncontrolling interests (10) |  |  |  |  |  |  |  |  |  |  | (30) |  |  | (25) |  |  | (5) |  |  | (20) | %
Current income tax expense |  |  |  |  |  |  |  |  |  |  | (46) |  |  | (53) |  |  | 7 |  |  | 13 | %
Distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings (11) |  |  |  |  |  |  |  |  |  |  | (2) |  |  | 12 |  |  | (14) |  |  | **
Distributions to noncontrolling interests (12) |  |  |  |  |  |  |  |  |  |  | (132) |  |  | (100) |  |  | (32) |  |  | (32) | %
Implied DCF |  |  |  |  |  |  |  |  |  |  | $ | 526 |  |  | $ | 534 |  |  | $ | (8) |  |  | (1) | %
Preferred unit distributions (12) |  |  |  |  |  |  |  |  |  |  | (64) |  |  | (64) |  |  | — |  |  | — | %
Implied DCF Available to Common Unitholders |  |  |  |  |  |  |  |  |  |  | $ | 462 |  |  | $ | 470 |  |  | $ | (8) |  |  | (2) | %
Common unit cash distributions (12) |  |  |  |  |  |  |  |  |  |  | (267) |  |  | (223) |  |  |  |  |
Implied DCF Excess (13) |  |  |  |  |  |  |  |  |  |  | $ | 195 |  |  | $ | 247 |  |  |  |  |

** Indicates that variance as a percentage is not meaningful.
(1)Represents “Interest expense, net” as reported on our Condensed Consolidated Statements of Operations, net of interest income associated with promissory notes by and among PAA and certain Plains entities.
(2)We exclude our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities when reviewing Adjusted EBITDA, similar to our consolidated assets.
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(3)For a more detailed discussion of these selected items impacting comparability, see the footnotes to the Segment Adjusted EBITDA Reconciliation table in Note 10 to our Condensed Consolidated Financial Statements.
(4)During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability.
(5)“Other income/(expense), net” on our Condensed Consolidated Statements of Operations, excluding interest income associated with promissory notes by and among PAA and certain Plains entities, adjusted for selected items impacting comparability (“Adjusted other income, net”) is included in Adjusted EBITDA and excluded from Segment Adjusted EBITDA.
(6)Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River.
(7)See the table above for a reconciliation from Net Income to Adjusted EBITDA.
(8)Amount excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps and is net of interest income associated with promissory notes by and among PAA and certain Plains entities.
(9)Maintenance capital expenditures are defined as capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets.
(10)Investment capital expenditures attributable to noncontrolling interests that reduce Implied DCF available to PAA common unitholders.
(11)Comprised of cash distributions received from unconsolidated entities less equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization, including write-downs related to cancelled projects, and selected items impacting comparability of unconsolidated entities).
(12)Cash distributions paid during the period presented.
(13)Excess DCF is retained to establish reserves for debt repayment, future distributions, common equity repurchases, capital expenditures and other partnership purposes.
Analysis of Operating Segments
We manage our operations through two operating segments: Crude Oil and NGL. Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA. See Note 10 to our Condensed Consolidated Financial Statements for our definition of Segment Adjusted EBITDA and a reconciliation of Segment Adjusted EBITDA to Net income attributable to PAA. See Note 19 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for our definition of maintenance capital.
Crude Oil Segment
Our Crude Oil segment operations generally consist of gathering and transporting crude oil using pipelines (including gathering systems), trucks and, at times, on barges or railcars, in addition to providing terminalling, storage and other related services utilizing our integrated assets across the United States and Canada. Our assets provide services to third parties as well as to our merchant activities. Our merchant activities include the purchase of crude oil supply and the movement of this supply on our assets or third-party assets to sales locations, including our terminals, third-party connecting carriers, regional hubs or to refineries. Our merchant activities are governed by our risk management policies.
Our Crude Oil segment generates revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees, month-to-month and multi-year storage and terminalling agreements and the sale of gathered and bulk-purchased crude oil. Tariffs and other fees on our pipeline systems are typically based on volumes transported and vary by receipt point and delivery point. Fees for our terminalling and storage services are based on capacity leases and throughput volumes. Generally, results from our merchant activities are impacted by (i) increases or decreases in our lease gathering crude oil purchases volumes and (ii) volatility in commodity price differentials, particularly grade and location differentials, as well as time spreads. The segment results also include the direct fixed and variable field costs of operating the crude oil assets, as well as an allocation of indirect operating costs.
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The following tables set forth our operating results from our Crude Oil segment:

Operating Results (1) |  |  |  |  |  |  | Three Months Ended March 31, |  | Variance
(in millions) |  |  |  |  |  |  |  |  |  |  | 2025 |  | 2024 |  | $ |  | %
Revenues |  |  |  |  |  |  |  |  |  |  | $ | 11,439 |  |  | $ | 11,582 |  |  | $ | (143) |  |  | (1) | %
Purchases and related costs |  |  |  |  |  |  |  |  |  |  | (10,488) |  |  | (10,665) |  |  | 177 |  |  | 2 | %
Field operating costs |  |  |  |  |  |  |  |  |  |  | (292) |  |  | (266) |  |  | (26) |  |  | (10) | %
Segment general and administrative expenses (2) |  |  |  |  |  |  |  |  |  |  | (79) |  |  | (73) |  |  | (6) |  |  | (8) | %
Equity earnings in unconsolidated entities |  |  |  |  |  |  |  |  |  |  | 103 |  |  | 95 |  |  | 8 |  |  | 8 | %
Other segment items (3): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Depreciation and amortization of unconsolidated entities |  |  |  |  |  |  |  |  |  |  | 20 |  |  | 19 |  |  | 1 |  |  | **
Derivative activities and inventory valuation adjustments |  |  |  |  |  |  |  |  |  |  | (24) |  |  | 37 |  |  | (61) |  |  | **
Long-term inventory costing adjustments |  |  |  |  |  |  |  |  |  |  | — |  |  | (28) |  |  | 28 |  |  | **
Deficiencies under minimum volume commitments, net |  |  |  |  |  |  |  |  |  |  | (7) |  |  | (12) |  |  | 5 |  |  | **
Equity-indexed compensation expense |  |  |  |  |  |  |  |  |  |  | 9 |  |  | 9 |  |  | — |  |  | **
Foreign currency revaluation |  |  |  |  |  |  |  |  |  |  | — |  |  | (17) |  |  | 17 |  |  | **
Transaction-related expenses |  |  |  |  |  |  |  |  |  |  | 5 |  |  | — |  |  | 5 |  |  | **
Segment amounts attributable to noncontrolling interests |  |  |  |  |  |  |  |  |  |  | (127) |  |  | (128) |  |  | 1 |  |  | **
Segment Adjusted EBITDA |  |  |  |  |  |  |  |  |  |  | $ | 559 |  |  | $ | 553 |  |  | $ | 6 |  |  | 1 | %
Maintenance capital expenditures |  |  |  |  |  |  |  |  |  |  | $ | 31 |  |  | $ | 46 |  |  | $ | (15) |  |  | (33) | %

|  |  |  |  |  |  | Three Months Ended March 31, |  | Variance
Average Volumes |  |  |  |  |  |  |  |  |  |  | 2025 |  | 2024 |  | Volumes |  | %
Crude oil pipeline tariff (by region) (4) (5) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Permian Basin |  |  |  |  |  |  |  |  |  |  | 6,869 |  |  | 6,428 |  |  | 441 |  |  | 7 | %
South Texas / Eagle Ford |  |  |  |  |  |  |  |  |  |  | 492 |  |  | 378 |  |  | 114 |  |  | 30 | %
Mid-Continent |  |  |  |  |  |  |  |  |  |  | 415 |  |  | 486 |  |  | (71) |  |  | (15) | %
Other |  |  |  |  |  |  |  |  |  |  | 1,310 |  |  | 1,308 |  |  | 2 |  |  | — | %
Total crude oil pipeline tariff |  |  |  |  |  |  |  |  |  |  | 9,086 |  |  | 8,600 |  |  | 486 |  |  | 6 | %

** Indicates that variance as a percentage is not meaningful.
(1)Revenues and costs and expenses include intersegment amounts.
(2)Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
(3)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 10 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.
(4)Average daily volumes in thousands of barrels per day calculated as the total volumes (attributable to our interest for assets owned by unconsolidated entities or through undivided joint interests) for the period divided by the number of days in the period. Volumes associated with acquisitions represent total volumes for the number of days we actually owned the assets divided by the number of days in the period.
(5)Includes volumes (attributable to our interest) from assets owned by unconsolidated entities.
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Segment Adjusted EBITDA
Crude Oil Segment Adjusted EBITDA for the three months ended March 31, 2025 was in line with comparable results for the three months ended March 31, 2024. The benefit to the 2025 period from higher tariff volumes on our pipelines, tariff escalations and contributions from recently completed acquisitions was largely offset by higher operating expenses.
The following is a more detailed discussion of the significant factors impacting Segment Adjusted EBITDA for the three months ended March 31, 2025 compared to the same period in 2024.
Net Revenues and Equity Earnings. Our results were favorably impacted by (i) volume growth across our pipeline systems driven by increased production in the Permian Basin region, (ii) the benefit of tariff escalations and (iii) contributions from recentl y completed acquisitions in the Permian Basin and South Texas regions. These favorable impacts were partially offset by lower volumes on certain of our pipelines due to refinery downtime in the 2025 period.
Field Operating Costs. For the three months ended March 31, 2025 compared to the same period in 2024, we recognized higher expenses associated with (i) environmental remediation expenses, (ii) employee-related costs primarily resulting from higher average salaries, bonuses and medical benefits, (iii) incremental operating costs associated with acquisitions and (iv) higher utilities-related costs as a result of higher volumes.
Maintenance Capital
The decrease in maintenance capital spending for the three months ended March 31, 2025 compared to the same period in 2024 was primarily due to lower costs resulting from timing of certain pipeline integrity activities.
NGL Segment
Our NGL segment operations involve natural gas processing and NGL fractionation, storage, transportation and terminalling. Our NGL revenues are primarily derived from a combination of (i) providing gathering, fractionation, storage, and/or terminalling services to third-party customers for a fee, and (ii) our merchant activities of extracting NGL mix from the gas stream processed at our Empress straddle plant facility as well as acquiring NGL mix, which is then transported, stored and fractionated into finished products and sold to customers. The commodity exposure associated with our merchant activities is governed by our risk management policies.
Generally, our segment results are impacted by (i) increases or decreases in our NGL sales volumes, (ii) volatility in commodity price differentials, primarily the differential between the price of natural gas and the extracted NGL (“frac spread”), as well as location differentials and time spreads, (iii) the quality and volume of natural gas transported on third-party assets through our Empress straddle plant and (iv) our share of the NGL received from a third-party straddle plant.
Our NGL operations are sensitive to weather-related demand, particularly during the approximate five-month peak heating season of November through March, and temperature differences from period-to-period may have a significant effect on NGL demand, and thus our financial performance, as well as the impact of comparative performance between financial reporting periods that bisect the five-month peak heating season.
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The following tables set forth our operating results from our NGL segment:

Operating Results (1) |  |  |  |  |  |  | Three Months Ended March 31, |  | Variance
(in millions) |  |  |  |  |  |  |  |  |  |  | 2025 |  | 2024 |  | $ |  | %
Revenues |  |  |  |  |  |  |  |  |  |  | $ | 638 |  |  | $ | 507 |  |  | $ | 131 |  |  | 26 | %
Purchases and related costs |  |  |  |  |  |  |  |  |  |  | (339) |  |  | (346) |  |  | 7 |  |  | 2 | %
Field operating costs |  |  |  |  |  |  |  |  |  |  | (76) |  |  | (92) |  |  | 16 |  |  | 17 | %
Segment general and administrative expenses (2) |  |  |  |  |  |  |  |  |  |  | (21) |  |  | (23) |  |  | 2 |  |  | 9 | %
Other segment items (3): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivative activities |  |  |  |  |  |  |  |  |  |  | (10) |  |  | 122 |  |  | (132) |  |  | **
Long-term inventory costing adjustments |  |  |  |  |  |  |  |  |  |  | (3) |  |  | (5) |  |  | 2 |  |  | **
Foreign currency revaluation |  |  |  |  |  |  |  |  |  |  | — |  |  | (4) |  |  | 4 |  |  | **
Segment Adjusted EBITDA |  |  |  |  |  |  |  |  |  |  | $ | 189 |  |  | $ | 159 |  |  | $ | 30 |  |  | 19 | %
Maintenance capital expenditures |  |  |  |  |  |  |  |  |  |  | $ | 10 |  |  | $ | 11 |  |  | $ | (1) |  |  | (9) | %

|  |  |  |  |  |  | Three Months Ended March 31, |  | Variance
Average Volumes (in thousands of barrels per day) (4) |  |  |  |  |  |  |  |  |  |  | 2025 |  | 2024 |  | Volumes |  | %
NGL fractionation |  |  |  |  |  |  |  |  |  |  | 157 |  |  | 128 |  |  | 29 |  |  | 23 | %
NGL pipeline tariff |  |  |  |  |  |  |  |  |  |  | 234 |  |  | 214 |  |  | 20 |  |  | 9 | %
Propane and butane sales |  |  |  |  |  |  |  |  |  |  | 147 |  |  | 128 |  |  | 19 |  |  | 15 | %

** Indicates that variance as a percentage is not meaningful.
(1)Revenues and costs and expenses include intersegment amounts.
(2)Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
(3)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 10 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.
(4)Average daily volumes are calculated as total volumes (attributable to our interest for assets owned through undivided joint interests) for the period divided by the number of days in the period.
Segment Adjusted EBITDA
NGL Segment Adjusted EBITDA increased for the three months ended March 31, 2025 compared to the same period in 2024 primarily as a result of the impact of (i) higher NGL sales volumes, (ii) higher realized frac spreads, and (iii) lower field operating costs.
Significant variances in the components of Segment Adjusted EBITDA are discussed in more detail below.
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Net Revenues. Net revenues include the impact of derivative activities and long-term inventory costing adjustments, which are excluded from Segment Adjusted EBITDA, and thus are reflected as a component of “Other segment items” in the table above. Excluding such impacts, net revenues increased for the three months ended March 31, 2025 compared to the same period in 2024. The increase in net revenues for the three months ended March 31, 2025 compared to the same period in 2024 was primarily due to (i) higher NGL sales volumes and (ii) higher realized frac spreads.
Field Operating Costs. The decrease in field operating costs for the three months ended March 31, 2025 compared to the same period in 2024 was primarily due to (i) a decrease in unrealized mark-to-market losses on power hedges (which impact our field operating costs, but are excluded from Segment Adjusted EBITDA, and thus are reflected as a component of “Other segment items” in the table above) and (ii) decreased utilities-related costs largely as a result of lower power prices.
Liquidity and Capital Resources
General
Our primary sources of liquidity are (i) cash flow from operating activities and (ii) borrowings under our credit facilities or commercial paper program. In addition, we may supplement these primary sources of liquidity with proceeds from asset sales, and in the past have utilized funds received from sales of equity and debt securities. Our primary cash requirements include, but are not limited to, (i) ordinary course of business uses, such as the payment of amounts related to the purchase of crude oil, NGL and other products, payment of other expenses and interest payments on outstanding debt, (ii) investment and maintenance capital activities, (iii) acquisitions of assets or businesses, (iv) repayment of principal on our long-term debt and (v) distributions to our unitholders and noncontrolling interests. In addition, we may use cash for repurchases of common equity. We generally expect to fund our short-term cash requirements through cash flow generated from operating activities and/or borrowings under our credit facilities or commercial paper program. In addition, we generally expect to fund our long-term needs, such as those resulting from investment capital activities, acquisitions or refinancing our long-term debt, through a variety of sources, which may include any or a combination of the sources listed above.
As of March 31, 2025, we had a working capital surplus of $44 million and approximately $2.6 billion of liquidity available to meet our ongoing operating, investing and financing needs (subject to continued covenant compliance) as noted below (in millions):

| As of March 31, 2025
Availability under senior unsecured revolving credit facility (1) (2) | $ | 1,350 |
Availability under senior secured hedged inventory facility (1) (2) | 1,315 |
Amounts outstanding under commercial paper program | (464) |
Subtotal | 2,201 |
Cash and cash equivalents (3) | 426 |
Total | $ | 2,627 |

(1)Represents availability prior to giving effect to borrowings outstanding under our commercial paper program, which reduce available capacity under our credit facilities.
(2)Available capacity under our senior unsecured revolving credit facility and senior secured hedged inventory facility was reduced by outstanding letters of credit issued under these facilities of less than $1 million and $35 million, respectively.
(3)Excludes restricted cash of $1 million.
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Usage of our credit facilities, and, in turn, our commercial paper program, is subject to ongoing compliance with covenants. The credit agreements for our revolving credit facilities (which impact our ability to access our commercial paper program because they provide the financial backstop that supports our short-term credit ratings) and the indentures governing our senior notes contain cross-default provisions. A default under our credit agreements or indentures would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with the provisions in our credit agreements, our ability to make distributions of available cash is not restricted. We were in compliance with the covenants contained in our credit agreements and indentures as of March 31, 2025.
We believe that we have, and will continue to have, the ability to access our commercial paper program and credit facilities, which we use to meet our short-term cash needs. We believe that our financial position remains strong and we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow, including extended disruptions in the financial markets and/or energy price volatility resulting from current macroeconomic and geopolitical conditions, including actions by the Organization of Petroleum Exporting Countries (OPEC). A prolonged material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity and cost of borrowing. Our borrowing capacity and borrowing costs are also impacted by our credit rating. See Item 1A. “Risk Factors” included in our 2024 Annual Report on Form 10-K for further discussion regarding risks that may impact our liquidity and capital resources.
Non-GAAP Financial Liquidity Measures
Management uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. Adjusted Free Cash Flow is defined as Net cash provided by operating activities, less Net cash provided by/(used in) investing activities, which primarily includes acquisition, investment and maintenance capital expenditures, investments in unconsolidated entities and related party notes and the impact from the purchase and sale of linefill, net of proceeds from the sales of assets and further impacted by distributions to and contributions from noncontrolling interests and proceeds from the issuance of related party notes. Adjusted Free Cash Flow is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Adjusted Free Cash Flow after Distributions. Also see “Results of Operations–Non-GAAP Financial Measures” above for more information about our non-GAAP measures.
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The following table sets forth the reconciliation of the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions from Net Cash Provided by Operating Activities (in millions):

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
Net cash provided by operating activities |  |  |  |  | $ | 639 |  |  | $ | 419 |
Adjustments to reconcile net cash provided by operating activities to adjusted free cash flow: |  |  |  |  |  |  |
Net cash used in investing activities (1) |  |  |  |  | (1,149) |  |  | (261) |
Cash contributions from noncontrolling interests |  |  |  |  | 4 |  |  | 12 |
Cash distributions paid to noncontrolling interests (2) |  |  |  |  | (132) |  |  | (100) |
Proceeds from the issuance of related party notes (1) |  |  |  |  | 330 |  |  | — |
Adjusted Free Cash Flow |  |  |  |  | $ | (308) |  |  | $ | 70 |
Cash distributions (3) |  |  |  |  | (331) |  |  | (287) |
Adjusted Free Cash Flow after Distributions (4) |  |  |  |  | $ | (639) |  |  | $ | (217) |

(1)PAA and certain Plains entities have issued promissory notes by and among such entities to facilitate financing. “Proceeds from the issuance of related party notes” has an equal and offsetting cash outflow associated with our investment in related party notes, which is included as a component of “Net cash used in investing activities.” See Note 8 to our Condensed Consolidated Financial Statements for additional information on our related party notes.
(2)Cash distributions paid during the period presented.
(3)Cash distributions paid to our preferred and common unitholders during the period presented.
(4)Excess Adjusted Free Cash Flow after Distributions is retained to establish reserves for future distributions, capital expenditures, debt reduction and other partnership purposes. Adjusted Free Cash Flow after Distributions shortages, if any, may be funded from previously established reserves, cash on hand or from borrowings under our credit facilities or commercial paper program.
Cash Flow from Operating Activities
For a comprehensive discussion of the primary drivers of cash flow from operating activities, including the impact of varying market conditions and the timing of settlement of our derivatives, see Item 7. “Liquidity and Capital Resources—Cash Flow from Operating Activities” included in our 2024 Annual Report on Form 10-K.
Net cash provided by operating activities for the first three months of 2025 and 2024 was $639 million and $419 million, respectively, and primarily resulted from earnings from our operations. Both periods were also impacted by changes in net operating working capital items. The 2024 period was impacted more unfavorably, primarily by margin requirements related to our hedging activities.
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Investing Activities
Capital Expenditures
In addition to our operating needs, we also use cash for our investment capital projects, maintenance capital activities and acquisition activities. We fund these expenditures with cash generated by operating activities, financing activities and/or proceeds from asset sales. The following table summarizes our investment, maintenance and acquisition capital expenditures (in millions):

| Three Months Ended March 31,
| 2025 |  | 2024
Investment capital (1) (2) (3) | $ | 161 |  |  | $ | 104 |
Maintenance capital (1) (3) | 41 |  |  | 57 |
Acquisition capital (2) (4) | 665 |  |  | 93 |
| $ | 867 |  |  | $ | 254 |

(1)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.”
(2)Contributions to unconsolidated entities, accounted for under the equity method of accounting, that are related to investment capital projects by such entities are recognized in “Investment capital.” Acquisitions of initial investments or additional interests in unconsolidated entities are included in “Acquisition capital.”
(3)Investment capital and maintenance capital, net to our 65% interest in the Permian JV, was approximately $130 million and $38 million, respectively, for the three months ended March 31, 2025, and approximately $79 million and $53 million, respectively, for the three months ended March 31, 2024.
(4)Acquisition capital, net to our 65% interest in the Permian JV, was approximately $613 million and $92 million for the three months ended March 31, 2025 and 2024, respectively. Acquisition capital for the 2025 period primarily included the acquisitions of (i) Ironwood Midstream, (ii) Medallion Midstream by the Permian JV and (iii) the remaining 50% interest in Cheyenne Pipeline LLC through a non-cash transaction. See Note 11 to our Condensed Consolidated Financial Statements for additional information. Acquisition capital for the 2024 period primarily included the acquisition of an additional ownership interest in an equity method investee.
2025 Investment and Maintenance Capital. Total investment capital for the year ending December 31, 2025 is projected to be approximately $500 million ($400 million net to our interest). Approximately half of our projected investment capital expenditures are expected to be invested in the Permian JV assets. Additionally, maintenance capital for 2025 is projected to be approximately $260 million ($240 million net to our interest).
Ongoing Activities Related to Strategic Transactions
We are continuously engaged in the evaluation of potential transactions that support our current business strategy. In the past, such transactions have included the acquisition of assets that complement our existing footprint, the sale of non-core assets, the sale of partial interests in assets to strategic joint venture partners, and large investment capital projects. With respect to a potential acquisition or divestiture, we may conduct an auction process or participate in an auction process conducted by a third-party or we may negotiate a transaction with one or a limited number of potential sellers (in the case of an acquisition) or buyers (in the case of a divestiture). Such transactions could have a material effect on our financial condition and results of operations.
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We typically do not announce a transaction until after we have executed a definitive agreement. In certain cases, in order to protect our business interests or for other reasons, we may defer public announcement of a transaction until closing or a later date. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future efforts with respect to any such transactions will be successful, and we can provide no assurance that our financial expectations with respect to such transactions will ultimately be realized. See Item 1A. “Risk Factors—Risks Related to Our Business—Acquisitions and divestitures involve risks that may adversely affect our business” included in our 2024 Annual Report on Form 10-K.
Related Party Promissory Notes
In February 2025, promissory notes with a face value of CAD$473 million (approximately $330 million) were issued by and among us and certain Plains entities. The cash outflow associated with our investment in promissory notes issued by PAGP to us has an equal and offsetting cash inflow associated with proceeds from the issuance by our consolidated subsidiary of promissory notes to PAGP for the same face value amount, which is included as a component of financing activities. See Note 8 to our Condensed Consolidated Financial Statements for additional information on our related party notes.
Financing Activities
Our financing activities primarily relate to funding investment capital projects, acquisitions and refinancing of our debt maturities, as well as short-term working capital (including borrowings for NYMEX and ICE margin deposits) and hedged inventory borrowings related to our NGL business and contango market activities, and the payment of distributions to our unitholders and noncontrolling interests.
Borrowings and Repayments Under Credit Agreements
During the three months ended March 31, 2025 and 2024, we had net borrowings under our commercial paper program of $71 million and $107 million, respectively. The net borrowings resulted primarily from borrowings during the period related to funding needs for capital investments, inventory purchases and other general partnership purposes.
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. We used the net proceeds from this offering of approximately $988 million, after deducting the underwriting discount and offering expenses, to (i) fund the acquisitions completed during the first quarter of 2025, (ii) fund the repurchase of approximately 12.7 million Series A preferred units in January 2025 and (iii) repay outstanding borrowings under our credit facilities and commercial paper program and for general partnership purposes.
Common Equity Repurchase Program
There were no repurchases under the Common Equity Repurchase Program (the “Program”) during the three months ended March 31, 2025 or 2024. The remaining available capacity under the Program as of March 31, 2025 was $198 million.
Registration Statements
We periodically access the capital markets for both equity and debt financing. We have filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to a specified amount of debt or equity securities (“Traditional Shelf”), under which we had approximately $1.1 billion of unsold securities available at March 31, 2025. We did not conduct any offerings under our Traditional Shelf during the three months ended March 31, 2025. We also have access to a universal shelf registration statement (“WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. The offering of $1.0 billion, 5.95% senior notes in January 2025 was conducted under our WKSI Shelf.
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Series A Preferred Unit Repurchase
On January 31, 2025, we repurchased approximately 12.7 million units, or 18%, of our outstanding Series A preferred units 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. We used a portion of the net proceeds from our January 2025 senior notes offering to fund this repurchase. See Note 6 to our Condensed Consolidated Financial Statements for more information regarding our Series A preferred units.
Distributions to Our Unitholders
Series A preferred unitholders. On May 15, 2025, we will pay a quarterly cash distribution of approximately $0.615 per unit to Series A preferred unitholders of record at the close of business on May 1, 2025 for the period from January 1, 2025 through March 31, 2025.
Series B preferred unitholders. On May 15, 2025, we will pay a quarterly cash distribution of approximately $21.49 per unit to Series B preferred unitholders of record at the close of business on May 1, 2025 for the period from February 15, 2025 through May 14, 2025.
Common Unitholders. On May 15, 2025, we will pay a quarterly cash distribution of $0.38 per common unit ($1.52 per unit on an annualized basis) to common unitholders of record at the close of business on May 1, 2025 for the period from January 1, 2025 through March 31, 2025.
See Note 6 to our Condensed Consolidated Financial Statements for details of distributions paid during or pertaining to the first three months of 2025, including distributions to our preferred unitholders.
Distributions to Noncontrolling Interests
Distributions to noncontrolling interests represent amounts paid on interests in consolidated entities that are not owned by us. As of March 31, 2025, noncontrolling interests in our subsidiaries consisted of (i) a 35% interest in the Permian JV, (ii) a 30% interest in Cactus II and (iii) a 33% interest in Red River. See Note 6 to our Condensed Consolidated Financial Statements for details of distributions paid to noncontrolling interests during the three months ended March 31, 2025.
Related Party Promissory Notes
In February 2025, promissory notes with a face value of CAD$473 million (approximately $330 million) were issued by and among us and certain Plains entities. The cash inflow associated with proceeds from the issuance by our consolidated subsidiary of promissory notes to PAGP has an equal and offsetting cash outflow associated with our investment in promissory notes issued by PAGP to us for the same face value amount, which is included as a component of investing activities. See Note 8 to our Condensed Consolidated Financial Statements for additional information on our related party notes.
Contingencies
For a discussion of contingencies that may impact us, see Note 9 to our Condensed Consolidated Financial Statements.
Commitments
Purchase Obligations. In the ordinary course of doing business, we purchase crude oil and NGL from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years, with a limited number of contracts with remaining terms extending up to 10 years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy or who have provided credit support we consider adequate.
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The following table includes our best estimate of the amount and timing of these payments as of March 31, 2025 (in millions):

| Remainder of 2025 |  | 2026 |  | 2027 |  | 2028 |  | 2029 |  | 2030 and Thereafter |  | Total
Crude oil, NGL and other purchases (1) | $ | 18,061 |  |  | $ | 19,985 |  |  | $ | 17,694 |  |  | $ | 14,881 |  |  | $ | 13,406 |  |  | $ | 27,052 |  |  | $ | 111,079 |

(1)Amounts are primarily based on estimated volumes and market prices based on average activity during March 2025. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.
Letters of Credit. In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the product is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At March 31, 2025 and December 31, 2024, we had outstanding letters of credit of approximately $78 million and $90 million, respectively.
Recent Accounting Pronouncements
See Note 1 to our Condensed Consolidated Financial Statements.
FORWARD-LOOKING STATEMENTS
All statements included in this report, other than statements of historical fact, are forward-looking statements, including but not limited to statements incorporating the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast,” as well as similar expressions and statements regarding our business strategy, plans and objectives for future operations. The absence of such words, expressions or statements, however, does not mean that the statements are not forward-looking. Any such forward-looking statements reflect our current views with respect to future events, based on what we believe to be reasonable assumptions. Certain factors could cause actual results or outcomes to differ materially from the results or outcomes anticipated in the forward-looking statements. The most important of these factors include, but are not limited to:
•general economic, market or business conditions in the United States and elsewhere (including the potential for a recession or significant slowdown in economic activity levels, the risk of persistently high inflation and supply chain issues, the impact of global public health events, such as pandemics, on demand and growth, and the timing, pace and extent of economic recovery) that impact (i) demand for crude oil, drilling and production activities and therefore the demand for the midstream services we provide and (ii) commercial opportunities available to us;
•declines in global crude oil demand and/or crude oil prices or other factors that correspondingly lead to a significant reduction of North American crude oil and natural gas liquids (“NGL”) production (whether due to reduced producer cash flow to fund drilling activities or the inability of producers to access capital, or both, the unavailability of pipeline and/or storage capacity, the shutting-in of production by producers, government-mandated pro-ration orders, or other factors), which in turn could result in significant declines in the actual or expected volume of crude oil and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets and/or the reduction of the margins we can earn or the commercial opportunities that might otherwise be available to us;
•fluctuations in refinery capacity and other factors affecting demand for various grades of crude oil and NGL and resulting changes in pricing conditions or transportation throughput requirements;
•unanticipated changes in crude oil and NGL market structure, grade differentials and volatility (or lack thereof);
•the effects of competition and capacity overbuild in areas where we operate, including downward pressure on rates, volumes and margins, contract renewal risk and the risk of loss of business to other midstream operators who are willing or under pressure to aggressively reduce transportation rates in order to capture or preserve customers;
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•the successful operation of joint ventures and joint operating arrangements we enter into from time to time, whether relating to assets operated by us or by third parties, and the successful integration and future performance of acquired assets or businesses;
•the availability of, and our ability to consummate, acquisitions, divestitures, joint ventures or other strategic opportunities and realize benefits therefrom;
•environmental liabilities, litigation or other events that are not covered by an indemnity, insurance or existing reserves;
•negative societal sentiment regarding the hydrocarbon energy industry and the continued development and consumption of hydrocarbons, which could influence consumer preferences and governmental or regulatory actions that adversely impact our business;
•the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event that materially impacts our operations, including cyber or other attacks on our or our service providers’ electronic and computer systems;
•weather interference with business operations or project construction, including the impact of extreme weather events or conditions (including hurricanes, floods, wildfires and drought);
•the impact of current and future laws, rulings, legislation, governmental regulations, executive orders, trade policies, trade tariffs, accounting standards and statements, and related interpretations that (i) prohibit, restrict or regulate the development of oil and gas resources and the related infrastructure on lands dedicated to or served by our pipelines, (ii) negatively impact our ability to develop, operate or repair midstream assets, or (iii) otherwise negatively impact our business or increase our exposure to risk;
•negative impacts on production levels in the Permian Basin or elsewhere due to issues associated with (or laws, rules or regulations relating to) hydraulic fracturing and related activities (including wastewater injection or disposal), including earthquakes, subsidence, expansion or other issues;
•the pace of development of natural gas or other infrastructure and its impact on expected crude oil production growth in the Permian Basin;
•the refusal or inability of our customers or counterparties to perform their obligations under their contracts with us (including commercial contracts, asset sale agreements and other agreements), whether justified or not and whether due to financial constraints (such as reduced creditworthiness, liquidity issues or insolvency), market constraints, legal constraints (including governmental orders or guidance), the exercise of contractual or common law rights that allegedly excuse their performance (such as force majeure or similar claims) or other factors;
•loss of key personnel and inability to attract and retain new talent;
•disruptions to futures markets for crude oil, NGL and other petroleum products, which may impair our ability to execute our commercial or hedging strategies;
•the effectiveness of our risk management activities;
•shortages or cost increases of supplies, materials or labor;
•maintenance of our credit ratings and ability to receive open credit from our suppliers and trade counterparties;
•our inability to perform our obligations under our contracts, whether due to non-performance by third parties, including our customers or counterparties, market constraints, third-party constraints, supply chain issues, legal constraints (including governmental orders or guidance), or other factors or events;
•the incurrence of costs and expenses related to unexpected or unplanned capital or maintenance expenditures, third-party claims or other factors;
•failure to implement or capitalize, or delays in implementing or capitalizing, on investment capital projects, whether due to permitting delays, permitting withdrawals or other factors;
•tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, investment capital projects, working capital requirements and the repayment or refinancing of indebtedness;
•the amplification of other risks caused by volatile or closed financial markets, capital constraints, liquidity concerns and inflation;
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•the use or availability of third-party assets upon which our operations depend and over which we have little or no control;
•the currency exchange rate of the Canadian dollar to the United States dollar;
•the deferral of current revenue recognition attributable to deficiency payments received from customers who fail to ship or move their minimum contracted volumes;
•significant under-utilization of our assets and facilities;
•increased costs, or lack of availability, of insurance;
•fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans;
•risks related to the development and operation of our assets; and
•other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, as well as in the processing, transportation, fractionation, storage and marketing of NGL.
Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read “Risk Factors” discussed in Item 1A of our 2024 Annual Report on Form 10-K. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.
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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to various market risks, including commodity price risk and interest rate risk. We use various derivative instruments to manage such risks and, in certain circumstances, to realize incremental margin during volatile market conditions. Our risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our exchange-cleared and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. We have a risk management function that has direct responsibility and authority for our risk policies, related controls around commercial activities and certain aspects of corporate risk management. Our risk management function also approves all new risk management strategies through a formal process. The following discussion addresses each category of risk.
Commodity Price Risk
We use derivative instruments to hedge price risk associated with the following commodities:
•Crude oil
We utilize crude oil derivatives to hedge commodity price risk inherent in our pipeline, terminalling and merchant activities. Our objectives for these derivatives include hedging changes in inventory positions associated with our lease gathering activities, anticipated purchases and sales, stored inventory and basis differentials. We manage these exposures with various instruments including futures, forwards, swaps and options.
•Natural gas
We utilize natural gas derivatives to hedge commodity price risk by purchasing natural gas to replace the energy content of the NGL extracted by our natural gas processing assets (natural gas purchase component of the frac spread) and, on occasion, to hedge ethane that may be purchased and stored until it is reinjected into the natural gas stream. Additionally, we utilize natural gas derivatives to hedge anticipated operational fuel gas requirements related to our natural gas processing and NGL fractionation plants. We manage these exposures with various instruments including futures, swaps and options.
•NGL and other
We utilize NGL derivatives, primarily propane and butane derivatives, to hedge commodity price risk inherent in our commercial activities, including the sale of the individual specification products extracted in our natural gas processing assets (sale of specification NGL products component of the frac spread), as well as other net sales of NGL inventory, held mainly at our owned NGL storage terminals. Our objectives for these derivatives include hedging anticipated purchases and sales and stored inventory. We manage these exposures with various instruments including futures, forwards, swaps and options.
See Note 7 to our Condensed Consolidated Financial Statements for further discussion regarding our hedging strategies and objectives.
The fair value of our commodity derivatives and the change in fair value as of March 31, 2025 that would be expected from a 10% price increase or decrease is shown in the table below (in millions):

| Fair Value |  | Effect of 10% Price Increase |  | Effect of 10% Price Decrease
Crude oil | $ | 20 |  |  | $ | 19 |  |  | $ | (17) |
Natural gas | 7 |  |  | $ | 7 |  |  | $ | (7) |
NGL and other | (70) |  |  | $ | (28) |  |  | $ | 28 |
Total fair value | $ | (43) |  |  |  |  |

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The fair values presented in the table above reflect the sensitivity of the derivative instruments only and do not include the effect of the underlying hedged commodity. Price-risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in near-term commodity prices, the fair value of our derivative portfolio would typically change less than that shown in the table as changes in near-term prices are not typically mirrored in delivery months further out.
Interest Rate Risk
Debt. Our use of variable rate debt and any forecasted issuances of fixed rate debt expose us to interest rate risk. Therefore, from time to time, we use interest rate derivatives to hedge interest rate risk associated with anticipated interest payments and, in certain cases, outstanding debt instruments. All of our senior notes are fixed rate notes and thus are not subject to interest rate risk. Our variable rate debt outstanding at March 31, 2025, approximately $464 million, was subject to interest rate resets that generally occur within one week or less. The average interest rate on variable rate debt that was outstanding during the three months ended March 31, 2025 was approximately 4.6%, based upon rates in effect during such period. The fair value of our interest rate derivatives was a net asset of $25 million as of March 31, 2025. A 10% increase in the forward SOFR curve as of March 31, 2025 would have resulted in an increase of $19 million to the fair value of our interest rate derivatives. A 10% decrease in the forward SOFR curve as of March 31, 2025 would have resulted in a decrease of $19 million to the fair value of our interest rate derivatives. See Note 7 to our Condensed Consolidated Financial Statements for a discussion of our interest rate risk hedging activities.
Series B Preferred Units. Distributions on the Series B preferred units accumulate and are payable quarterly in arrears on the 15th day of February, May, August and November. Distributions on the Series B preferred units accumulate based on the applicable three-month SOFR, plus certain adjustments. Based upon the Series B preferred units outstanding at March 31, 2025 and the liquidation preference of $1,000 per unit, a change of 100 basis points in interest rates would increase or decrease the annual distributions on the Series B preferred units by approximately $8 million. See Note 11 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for additional information regarding our Series B preferred unit distributions.
Item 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
We maintain written disclosure controls and procedures, which we refer to as our “DCP.” Our DCP is designed to ensure that information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 (the “Exchange Act”) is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.
Applicable SEC rules require an evaluation of the effectiveness of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our DCP as of March 31, 2025, the end of the period covered by this report, and, based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our DCP is effective.
Changes in Internal Control over Financial Reporting
In addition to the information concerning our DCP, we are required to disclose certain changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting during the first quarter of 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Certifications
The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a) are filed with this report as Exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350 are furnished with this report as Exhibits 32.1 and 32.2.
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PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
The information required by this item is included in Note 9 to our Condensed Consolidated Financial Statements, and is incorporated herein by reference thereto.
Item 1A. RISK FACTORS
For a discussion of our risk factors, see Item 1A. of our 2024 Annual Report on Form 10-K. Those risks and uncertainties are not the only ones facing us and there may be additional matters of which we are unaware or that we currently consider immaterial. All of those risks and uncertainties could adversely affect our business, financial condition and/or results of operations.
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Sales of Unregistered Securities
None.
Issuer Purchases of Equity Securities
None.
Item 3. DEFAULTS UPON SENIOR SECURITIES
None.
Item 4. MINE SAFETY DISCLOSURES
Not applicable.
Item 5. OTHER INFORMATION
During the quarter ended March 31, 2025, none of our directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted or terminated any Rule 10b5-1 trading arrangement or any non-Rule 10b5-1 trading arrangement (as defined in Item 408 of Regulation S-K).
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Item 6. EXHIBITS

Exhibit No. |  | Description
3.1 | — | Seventh Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P., dated as of October 10, 2017 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 12, 2017).
3.2 | — | Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
3.3 | — | Amendment No. 1 dated December 31, 2010 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.9 to our Annual Report on Form 10-K for the year ended December 31, 2010).
3.4 | — | Amendment No. 2 dated January 1, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2010).
3.5 | — | Amendment No. 3 dated June 30, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.7 to our Annual Report on Form 10-K for the year ended December 31, 2013).
3.6 | — | Amendment No. 4 dated January 1, 2013 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P (incorporated by reference to Exhibit 3.8 to our Annual Report on Form 10-K for the year ended December 31, 2013).
3.7 | — | Amendment No. 5 dated December 1, 2019 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.7 to our Annual Report on Form 10-K for the year ended December, 31, 2019).
3.8 | — | Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.3 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
3.9 | — | Amendment No. 1 dated January 1, 2013 to the Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. (incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2013).
3.10 | — | Seventh Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated November 15, 2016 (incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K filed November 21, 2016).
3.11 | — | Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. dated November 15, 2016 (incorporated by reference to Exhibit 3.4 to our Current Report on Form 8-K filed November 21, 2016).
3.12 | — | Amendment No. 1 dated September 26, 2018 to the Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 2, 2018).
3.13 | — | Amendment No. 2 dated May 23, 2019 to the Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed May 30, 2019).
3.14 | — | Amendment No. 3 dated August 17, 2023 to the Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed August 21, 2023).
3.15 | — | Certificate of Incorporation of PAA Finance Corp. (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2006).

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3.16 | — | Bylaws of PAA Finance Corp. (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.11 to our Annual Report on Form 10-K for the year ended December 31, 2006).
3.17 | — | Limited Liability Company Agreement of PAA GP LLC dated December 28, 2007 (incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K filed January 4, 2008).
3.18 | — | Certificate of Limited Partnership of Plains GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to PAGP’s Registration Statement on Form S-1 (333-190227) filed July 29, 2013).
3.19 | — | Second Amended and Restated Agreement of Limited Partnership of Plains GP Holdings, L.P. dated November 15, 2016 (incorporated by reference to Exhibit 3.2 to PAGP’s Current Report on Form 8-K filed November 21, 2016).
3.20 | — | Amendment No. 1 dated April 6, 2020 to the Second Amended and Restated Agreement of Limited Partnership of Plains GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to PAGP’s Current Report on Form 8-K filed April 9, 2020).
3.21 | — | Certificate of Formation of PAA GP Holdings LLC (incorporated by reference to Exhibit 3.3 to PAGP’s Registration Statement on Form S-1 (333-190227) filed July 29, 2013).
3.22 | — | Fourth Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC dated effective as of August 19, 2021 (incorporated by reference to Exhibit 3.21 to our Annual Report on Form 10-K for the year ended December 31, 2021).
4.1 | — | Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).
4.2 | — | Sixth Supplemental Indenture (Series A and Series B 6.70% Senior Notes due 2036) dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed May 12, 2006).
4.3 | — | Tenth Supplemental Indenture (Series A and Series B 6.650% Senior Notes due 2037) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed October 30, 2006).
4.4 | — | Twenty-First Supplemental Indenture (5.15% Senior Notes due 2042) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed March 26, 2012).
4.5 | — | Twenty-Third Supplemental Indenture (4.30% Senior Notes due 2043) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 12, 2012).
4.6 | — | Twenty-Fifth Supplemental Indenture (4.70% Senior Notes due 2044) dated April 23, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed April 29, 2014).
4.7 | — | Twenty-Eighth Supplemental Indenture (4.90% Senior Notes due 2045) dated December 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 11, 2014).
4.8 | — | Twenty-Ninth Supplemental Indenture (4.65% Senior Notes due 2025) dated August 24, 2015, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed August 26, 2015).

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4.9 | — | Thirtieth Supplemental Indenture (4.50% Senior Notes due 2026) dated November 22, 2016, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed November 29, 2016).
4.10 | — | Thirty-First Supplemental Indenture (3.55% Senior Notes due 2029) dated September 16, 2019, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed September 17, 2019).
4.11 | — | Thirty-Second Supplemental Indenture (3.80% Senior Notes due 2030) dated June 11, 2020, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed June 11, 2020).
4.12 | — | Thirty-Third Supplemental Indenture (5.70% Senior Notes due 2034) dated June 27, 2024, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed June 27, 2024).
4.13 | — | Thirty-Four th Supplemental Indenture (5.95 0% Senior Notes due 203 5) dated J anuary 15, 202 5, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed J anuary 15, 2025).
4.14 | — | Registration Rights Agreement dated September 3, 2009 by and between Plains All American Pipeline, L.P. and Vulcan Gas Storage LLC (incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-3, File No. 333-162477).
4.15 | — | Registration Rights Agreement dated as of January 28, 2016 among Plains All American Pipeline, L.P. and the Purchasers named therein (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed February 2, 2016).
4.16 | — | Registration Rights Agreement by and among Plains All American Pipeline, L.P. and the Holders defined therein, dated November 15, 2016 (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed November 21, 2016).
4.17 | — | Description of Our Securities (incorporated by reference to Exhibit 4.1 7 to our Annual Report on Form 10-K for the year ended December 31, 202 4).
31.1 † | — | Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).
31.2 † | — | Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).
32.1 †† | — | Certification of Principal Executive Officer pursuant to 18 U.S.C. 1350.
32.2 †† | — | Certification of Principal Financial Officer pursuant to 18 U.S.C. 1350.
101.INS† | — | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH† | — | Inline XBRL Taxonomy Extension Schema Document
101.CAL† | — | Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF† | — | Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB† | — | Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE† | — | Inline XBRL Taxonomy Extension Presentation Linkbase Document
104† | — | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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

| PLAINS ALL AMERICAN PIPELINE, L.P.
| By: | PAA GP LLC,
|  | its general partner
| By: | Plains AAP, L.P.,
|  | its sole member
| By: | Plains All American GP LLC,
|  | its general partner
| By: | /s/ Willie Chiang
|  | Willie Chiang,
|  | Chief Executive Officer of Plains All American GP LLC
|  | (Principal Executive Officer)
May 9, 2025 |  |
| By: | /s/ Al Swanson
|  | Al Swanson,
|  | Executive Vice President and Chief Financial Officer of Plains All American GP LLC
|  | (Principal Financial Officer)
May 9, 2025 |  |
| By: | /s/ Chris Herbold
|  | Chris Herbold,
|  | Senior Vice President, Finance and Chief Accounting Officer of Plains All American GP LLC
|  | (Principal Accounting Officer)
May 9, 2025 |

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