SEC EDGAR · 10-Q
10-Q – 2025-08-08 – paa-20250630.htm
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Omsättning
- Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS | 61
- REVENUES | Product sales revenues $ 10,197 $ 12,351 $ 21,243 $ 23,584 | Services revenues 445 406 876 812
- Depreciation and amortization 235 226 466 449 | Losses on asset sales, net | 42 2 29 3
- Depreciation and amortization 466 449 | Losses on asset sales, net 29 3
- Cash paid for purchases of linefill ( 17 ) ( 16 ) | Proceeds from sales of assets 21 4
- Product sales | $ 181 $ 142 $ 679 $ 455
- 27 31 57 62 | (Gains)/losses on asset sales, net | 13 ( 1 ) 13 ( 2 )
- Revenue Recognition
EBITDA
- CODM = Chief Operating Decision Maker | EBITDA = Earnings before interest, taxes, depreciation and amortization | EPA = United States Environmental Protection Agency
- 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) signi
- 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 i
- Segment Adjusted EBITDA $ 580 $ ( 10 )
- Segment Adjusted EBITDA $ 1,140 $ ( 15 )
- Segment Adjusted EBITDA $ 576 $ ( 11 )
- Segment Adjusted EBITDA $ 1,130 $ ( 9 )
Rörelseresultat
- Total costs and expenses 10,403 12,425 21,525 23,708 | OPERATING INCOME 239 332 594 688 | OTHER INCOME/(EXPENSE)
- 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 commodi
Periodens resultat
- 4. Net Income Per Common Unit | 17
- 70 32 206 42 | NET INCOME 297 330 813 681 | Net income attributable to noncontrolling interests ( 87 ) ( 80 ) ( 160 ) ( 166 )
- NET INCOME 297 330 813 681 | Net income attributable to noncontrolling interests ( 87 ) ( 80 ) ( 160 ) ( 166 ) | NET INCOME ATTRIBUTABLE TO PAA $ 210 $ 250 $ 653 $ 515
- Net income attributable to noncontrolling interests ( 87 ) ( 80 ) ( 160 ) ( 166 ) | NET INCOME ATTRIBUTABLE TO PAA $ 210 $ 250 $ 653 $ 515
- NET INCOME PER COMMON UNIT (NOTE 4):
- Net income allocated to common unitholders — Basic and Diluted: | Continuing operations $ 80 $ 148 $ 287 $ 340
- Discontinued operations 70 32 206 42 | Net income allocated to common unitholders — Basic and Diluted $ 150 $ 180 $ 493 $ 382
- Basic and diluted net income per common unit:
Kassaflöde
- 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 relat
- 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.
- ( 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 | Anticipated interest payments 4 Treasury Locks
- ( 10 -year) | $ 100 10/15/2025 4.00 % Cash flow hedge
- 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 ap
- 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
- 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
Fritt kassaflöde
- 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
- 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
- Discontinued Operations. Management believes that the presentation of certain Non-GAAP financial measures, such as Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied DCF, and certain Non-GAAP liquidity measures, such as Adjusted Free Cash Flow and Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities), on a consolidated basis (e.g., the aggregate of continuing operations and discontinued operations) provides more relevant and useful information regarding our performance a
- 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 expenditu
- 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):
- $ 1,333 $ 1,072 | Adjustments to reconcile net cash provided by operating activities to adjusted free cash flow:
- Adjusted Free Cash Flow (1) (4) | $ 40 $ 480
- (652) (572) | Adjusted Free Cash Flow after Distributions (1) (5) | $ (612) $ (92)
Likvida medel
- CURRENT ASSETS | Cash and cash equivalents $ 459 $ 348
- Net increase in cash and cash equivalents and restricted cash 111 103 | Cash and cash equivalents and restricted cash, beginning of period 348 450
- Net increase in cash and cash equivalents and restricted cash 111 103 | Cash and cash equivalents and restricted cash, beginning of period 348 450 | Cash and cash equivalents and restricted cash, end of period $ 459 $ 553
- Cash and cash equivalents and restricted cash, beginning of period 348 450 | Cash and cash equivalents and restricted cash, end of period $ 459 $ 553
- Subtotal 2,200 | Cash and cash equivalents | 459
Nettoskuld
- Net income $ 813 $ 681 | Reconciliation of net income to net cash provided by operating activities: | Income from discontinued operations, net of tax ( 206 ) ( 42 )
- Cash provided by operating activities - discontinued operations 301 80 | Net cash provided by operating activities 1,333 1,072
- Cash used in investing activities - discontinued operations ( 106 ) ( 61 ) | Net cash used in investing activities ( 1,423 ) ( 418 )
- Net cash provided by/(used in) financing activities 182 ( 545 )
- 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
- 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 expenditu
- 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):
- 2025 2024 | Net cash provided by operating activities (1) | $ 1,333 $ 1,072
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paa:PlainsOryxPermianBasinLLCMember 2025-01-01 2025-01-31 0001070423 paa:EMGMedallion2HoldingsLLCMember 2025-01-01 2025-01-31 0001070423 paa:PlainsOryxPermianBasinLLCMember 2025-01-01 2025-01-31 0001070423 paa:EMGMedallion2HoldingsLLCMember 2024-12-01 2024-12-31 0001070423 paa:CheyennePipelineLLCMember 2025-02-28 0001070423 paa:CheyennePipelineLLCMember 2025-02-01 2025-02-28 0001070423 paa:CheyennePipelineLLCMember 2025-02-28 0001070423 paa:BlackKnightMidstreamLLCMember 2025-04-01 2025-06-30 0001070423 paa:PlainsOryxPermianBasinLLCMember 2025-01-01 2025-06-30 0001070423 paa:BridgeTexPipelineCompanyLLCMember us-gaap:SubsequentEventMember 2025-07-31 0001070423 paa:BridgeTexPipelineCompanyLLCMember us-gaap:SubsequentEventMember 2025-07-01 2025-07-31 0001070423 paa:BridgeTexPipelineCompanyLLCMember us-gaap:SubsequentEventMember 2025-07-31 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 June 30, 2025 or ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number: 1-14569 ________________________________________________________________ PLAINS ALL AMERICAN PIPELINE, L.P. (Exact name of registrant as specified in its charter) Delaware 76-0582150 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) 333 Clay Street , Suite 1600 Houston , Texas 77002 (Address of principal executive offices) (Zip code) ( 713 ) 646-4100 (Registrant’s telephone number, including area code) ________________________________________________________________ Securities registered pursuant to Section 12(b) of the Act: Title of each class Trading Symbol(s) Name of each exchange on which registered Common Units PAA Nasdaq Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☑ Yes ☐ No Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☑ Yes ☐ No Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer ☑ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☑ No As of July 31, 2025, there were 703,304,452 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 June 3 0 , 2025 and December 31, 2024 3 Condensed Consolidated Statements of Operations: For the three and six months ended June 30 , 2025 and 2024 4 Condensed Consolidated Statements of Comprehensive Income: For the three and six months ended June 30 , 2025 and 2024 5 Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss): For the six months ended June 30 , 2025 and 2024 5 Condensed Consolidated Statements of Cash Flows: For the six months ended June 30 , 2025 and 2024 6 Condensed Consolidated Statements of Changes in Partners’ Capital: For the three and six months ended June 3 0 , 2025 and 2024 7 Notes to the Condensed Consolidated Financial Statements: 1. Organization and Basis of Consolidation and Presentation 9 2. Discontinued Operations 12 3. Revenues and Accounts Receivable 13 4. Net Income Per Common Unit 17 5. Inventory, Linefill and Long-term Inventory 19 6. Debt 20 7. Partners’ Capital and Distributions 21 8. Derivatives and Risk Management Activities 23 9. Related Party Transactions 26 10. Commitments and Contingencies 28 11. Segment Information 30 12. Acquisitions 37 Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 39 Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 59 Item 4. CONTROLS AND PROCEDURES 60 PART II. OTHER INFORMATION Item 1. LEGAL PROCEEDINGS 61 Item 1A. RISK FACTORS 61 Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS 61 Item 3. DEFAULTS UPON SENIOR SECURITIES 61 Item 4. MINE SAFETY DISCLOSURES 61 Item 5. OTHER INFORMATION 61 Item 6. EXHIBITS 62 SIGNATURES 66 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) June 30, 2025 December 31, 2024 (unaudited) ASSETS CURRENT ASSETS Cash and cash equivalents $ 459 $ 348 Trade accounts receivable and other receivables, net 3,562 3,679 Inventory 151 261 Current assets of discontinued operations (Note 2) 385 415 Other current assets 131 99 Total current assets 4,688 4,802 PROPERTY AND EQUIPMENT 19,589 18,528 Accumulated depreciation ( 5,412 ) ( 5,082 ) Property and equipment, net 14,177 13,446 OTHER ASSETS Investments in unconsolidated entities 2,709 2,811 Intangible assets, net 1,636 1,677 Linefill 940 904 Long-term operating lease right-of-use assets, net 182 189 Long-term inventory 234 242 Long-term assets of discontinued operations (Note 2) 2,482 2,349 Other long-term assets, net 107 142 Total assets $ 27,155 $ 26,562 LIABILITIES AND PARTNERS’ CAPITAL CURRENT LIABILITIES Trade accounts payable $ 3,364 $ 3,647 Short-term debt 475 407 Current liabilities of discontinued operations (Note 2) 313 350 Other current liabilities 527 546 Total current liabilities 4,679 4,950 LONG-TERM LIABILITIES Senior notes, net 8,133 7,141 Other long-term debt, net 71 70 Long-term operating lease liabilities 190 192 Long-term liabilities of discontinued operations (Note 2) 598 576 Other long-term liabilities and deferred credits 535 537 Total long-term liabilities 9,527 8,516 COMMITMENTS AND CONTINGENCIES (NOTE 10) PARTNERS’ CAPITAL Series A preferred unitholders ( 58,411,908 and 71,090,468 units outstanding, respectively) 1,246 1,514 Series B preferred unitholders ( 800,000 and 800,000 units outstanding, respectively) 787 787 Common unitholders ( 703,304,452 and 703,770,300 units outstanding, respectively) 7,673 7,512 Total partners’ capital excluding noncontrolling interests 9,706 9,813 Noncontrolling interests 3,243 3,283 Total partners’ capital 12,949 13,096 Total liabilities and partners’ capital $ 27,155 $ 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 June 30, Six Months Ended June 30, 2025 2024 2025 2024 (unaudited) (unaudited) REVENUES Product sales revenues $ 10,197 $ 12,351 $ 21,243 $ 23,584 Services revenues 445 406 876 812 Total revenues 10,642 12,757 22,119 24,396 COSTS AND EXPENSES Purchases and related costs 9,758 11,838 20,277 22,543 Field operating costs 286 280 585 553 General and administrative expenses 82 79 168 160 Depreciation and amortization 235 226 466 449 Losses on asset sales, net 42 2 29 3 Total costs and expenses 10,403 12,425 21,525 23,708 OPERATING INCOME 239 332 594 688 OTHER INCOME/(EXPENSE) Equity earnings in unconsolidated entities 94 106 196 201 Gain on investments in unconsolidated entities, net — — 31 — Interest expense (net of capitalized interest of $ 3 , $ 2 , $ 5 and $ 4 , respectively) ( 133 ) ( 111 ) ( 260 ) ( 205 ) Other income, net 31 23 57 18 INCOME FROM CONTINUING OPERATIONS BEFORE TAX 231 350 618 702 Current income tax expense from continuing operations ( 1 ) ( 52 ) ( 6 ) ( 68 ) Deferred income tax (expense)/benefit from continuing operations ( 3 ) — ( 5 ) 5 INCOME FROM CONTINUING OPERATIONS, NET OF TAX 227 298 607 639 INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX (NOTE 2) 70 32 206 42 NET INCOME 297 330 813 681 Net income attributable to noncontrolling interests ( 87 ) ( 80 ) ( 160 ) ( 166 ) NET INCOME ATTRIBUTABLE TO PAA $ 210 $ 250 $ 653 $ 515 NET INCOME PER COMMON UNIT (NOTE 4): Net income allocated to common unitholders — Basic and Diluted: Continuing operations $ 80 $ 148 $ 287 $ 340 Discontinued operations 70 32 206 42 Net income allocated to common unitholders — Basic and Diluted $ 150 $ 180 $ 493 $ 382 Basic and diluted weighted average common units outstanding 703 701 704 701 Basic and diluted net income per common unit: Continuing operations $ 0.11 $ 0.21 $ 0.41 $ 0.49 Discontinued operations $ 0.10 $ 0.05 $ 0.29 $ 0.06 Basic and diluted net income per common unit $ 0.21 $ 0.26 $ 0.70 $ 0.55 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 June 30, Six Months Ended June 30, 2025 2024 2025 2024 (unaudited) (unaudited) Net income $ 297 $ 330 $ 813 $ 681 Other comprehensive income/(loss) 187 ( 33 ) 192 ( 104 ) Comprehensive income 484 297 1,005 577 Comprehensive income attributable to noncontrolling interests ( 87 ) ( 80 ) ( 160 ) ( 166 ) Comprehensive income attributable to PAA $ 397 $ 217 $ 845 $ 411 The accompanying notes are an integral part of these condensed consolidated financial statements. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (in millions) Derivative Instruments Translation Adjustments Other Total (unaudited) Balance at December 31, 2024 $ ( 44 ) $ ( 1,039 ) $ — $ ( 1,083 ) Reclassification adjustments 2 — — 2 Unrealized gain on hedges 6 — — 6 Currency translation adjustments — 183 — 183 Other — — 1 1 Total period activity 8 183 1 192 Balance at June 30, 2025 $ ( 36 ) $ ( 856 ) $ 1 $ ( 891 ) Derivative Instruments Translation Adjustments Total (unaudited) Balance at December 31, 2023 $ ( 81 ) $ ( 755 ) $ ( 836 ) Reclassification adjustments 5 — 5 Unrealized gain on hedges 18 — 18 Currency translation adjustments — ( 127 ) ( 127 ) Total period activity 23 ( 127 ) ( 104 ) Balance at June 30, 2024 $ ( 58 ) $ ( 882 ) $ ( 940 ) 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) Six Months Ended June 30, 2025 2024 (unaudited) CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 813 $ 681 Reconciliation of net income to net cash provided by operating activities: Income from discontinued operations, net of tax ( 206 ) ( 42 ) Depreciation and amortization 466 449 Losses on asset sales, net 29 3 Deferred income tax expense/(benefit) 5 ( 5 ) (Gain)/loss on foreign currency revaluation 4 ( 15 ) Settlement of terminated interest rate hedging instruments — 57 Equity earnings in unconsolidated entities ( 196 ) ( 201 ) Distributions on earnings from unconsolidated entities 256 250 Gain on investments in unconsolidated entities, net (Note 12) ( 31 ) — Other 32 37 Changes in assets and liabilities, net of acquisitions ( 140 ) ( 222 ) Cash provided by operating activities - continuing operations 1,032 992 Cash provided by operating activities - discontinued operations 301 80 Net cash provided by operating activities 1,333 1,072 CASH FLOWS FROM INVESTING ACTIVITIES Cash paid in connection with acquisitions, net of cash acquired ( 681 ) ( 111 ) Investments in unconsolidated entities — ( 3 ) Additions to property, equipment and other ( 310 ) ( 233 ) Cash paid for purchases of linefill ( 17 ) ( 16 ) Proceeds from sales of assets 21 4 Investments in related party notes (Note 9) ( 330 ) — Other investing activities — 2 Cash used in investing activities - continuing operations ( 1,317 ) ( 357 ) Cash used in investing activities - discontinued operations ( 106 ) ( 61 ) Net cash used in investing activities ( 1,423 ) ( 418 ) CASH FLOWS FROM FINANCING ACTIVITIES Net borrowings/(repayments) under commercial paper program (Note 6) 69 ( 433 ) Proceeds from the issuance of senior notes (Note 6) 998 650 Proceeds from the issuance of related party notes (Note 9) 330 — Repurchase of common units ( 8 ) — Repurchase of Series A preferred units (Note 7) ( 333 ) — Distributions paid to Series A preferred unitholders (Note 7) ( 82 ) ( 88 ) Distributions paid to Series B preferred unitholders (Note 7) ( 35 ) ( 39 ) Distributions paid to common unitholders (Note 7) ( 535 ) ( 445 ) Distributions paid to noncontrolling interests (Note 7) ( 229 ) ( 198 ) Contributions from noncontrolling interests 29 24 Other financing activities ( 22 ) ( 16 ) Net cash provided by/(used in) financing activities 182 ( 545 ) Effect of translation adjustment - continuing operations 8 ( 5 ) Effect of translation adjustment - discontinued operations 11 ( 1 ) Net increase in cash and cash equivalents and restricted cash 111 103 Cash and cash equivalents and restricted cash, beginning of period 348 450 Cash and cash equivalents and restricted cash, end of period $ 459 $ 553 Cash paid for: Interest, net of amounts capitalized $ 254 $ 195 Income taxes, net of amounts refunded $ 48 $ 193 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 75 35 543 653 160 813 Distributions (Note 7) ( 75 ) ( 35 ) ( 535 ) ( 645 ) ( 229 ) ( 874 ) Other comprehensive income — — 192 192 — 192 Repurchase of Series A preferred units (Note 7) ( 270 ) — ( 43 ) ( 313 ) — ( 313 ) Repurchase of common units — — ( 8 ) ( 8 ) — ( 8 ) Contributions from noncontrolling interests — — — — 29 29 Other 2 — 12 14 — 14 Balance at June 30, 2025 $ 1,246 $ 787 $ 7,673 $ 9,706 $ 3,243 $ 12,949 Limited Partners Partners’ Capital Excluding Noncontrolling Interests Noncontrolling Interests Total Partners’ Capital Preferred Unitholders Common Unitholders Series A Series B (unaudited) Balance at March 31, 2025 $ 1,245 $ 787 $ 7,600 $ 9,632 $ 3,228 $ 12,860 Net income 36 18 156 210 87 297 Distributions (Note 7) ( 36 ) ( 18 ) ( 267 ) ( 321 ) ( 97 ) ( 418 ) Other comprehensive income — — 187 187 — 187 Repurchase of common units — — ( 8 ) ( 8 ) — ( 8 ) Contributions from noncontrolling interests — — — — 25 25 Other 1 — 5 6 — 6 Balance at June 30, 2025 $ 1,246 $ 787 $ 7,673 $ 9,706 $ 3,243 $ 12,949 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 CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (continued) (in millions) Limited Partners Partners’ Capital Excluding Noncontrolling Interests Noncontrolling Interests Total Partners’ Capital Preferred Unitholders Common Unitholders Series A Series B (unaudited) Balance at December 31, 2023 $ 1,509 $ 787 $ 8,126 $ 10,422 $ 3,310 $ 13,732 Net income 88 39 388 515 166 681 Distributions ( 88 ) ( 39 ) ( 445 ) ( 572 ) ( 198 ) ( 770 ) Other comprehensive loss — — ( 104 ) ( 104 ) — ( 104 ) Contributions from noncontrolling interests — — — — 24 24 Other 3 — 12 15 — 15 Balance at June 30, 2024 $ 1,512 $ 787 $ 7,977 $ 10,276 $ 3,302 $ 13,578 Limited Partners Partners’ Capital Excluding Noncontrolling Interests Noncontrolling Interests Total Partners’ Capital Preferred Unitholders Common Unitholders Series A Series B (unaudited) Balance at March 31, 2024 $ 1,510 $ 787 $ 8,042 $ 10,339 $ 3,307 $ 13,646 Net income 44 19 187 250 80 330 Distributions ( 44 ) ( 19 ) ( 223 ) ( 286 ) ( 97 ) ( 383 ) Other comprehensive loss — — ( 33 ) ( 33 ) — ( 33 ) Contributions from noncontrolling interests — — — — 12 12 Other 2 — 4 6 — 6 Balance at June 30, 2024 $ 1,512 $ 787 $ 7,977 $ 10,276 $ 3,302 $ 13,578 The accompanying notes are an integral part of these condensed consolidated financial statements. 8 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 producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. Our assets and the services we provide are primarily focused on and conducted through two operating segments: Crude Oil and Natural Gas Liquids (“NGL”). See Note 11 for further discussion of our operating segments. Our non-economic general partner interest is held by PAA GP LLC (“PAA GP”), a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP, as of June 30, 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 June 30, 2025, owned an approximate 85 % limited partner interest in AAP. PAA GP Holdings LLC (“PAGP GP”) is the general partner of PAGP. As the sole member of GP LLC, PAGP has responsibility for conducting our business and managing our operations; however, the board of directors of PAGP GP has ultimate responsibility for managing the business and affairs of PAGP, AAP and us. GP LLC employs our domestic officers and personnel; our Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC. References to our “general partner,” as the context requires, include any or all of PAGP GP, PAGP, GP LLC, AAP and PAA GP. References to “Plains entities,” as the context requires, include any or all of PAA and its subsidiaries and our general partner. 9 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Definitions Additional defined terms may be used in this Form 10-Q and shall have the meanings indicated below: AOCI = Accumulated other comprehensive income/(loss) ASC = Accounting Standards Codification ASU = Accounting Standards Update Bcf = Billion cubic feet Btu = British thermal unit CAD = Canadian dollar CODM = Chief Operating Decision Maker EBITDA = Earnings before interest, taxes, depreciation and amortization EPA = United States Environmental Protection Agency FASB = Financial Accounting Standards Board GAAP = Generally accepted accounting principles in the United States ICE = Intercontinental Exchange ISDA = International Swaps and Derivatives Association LTIP = Long-term incentive plan Mcf = Thousand cubic feet MMbls = Million barrels NGL = Natural gas liquids, including ethane, propane and butane NYMEX = New York Mercantile Exchange OECD = Organisation for Economic Co-operation and Development SEC = United States Securities and Exchange Commission SOFR = Secured Overnight Financing Rate TWh = Terawatt hour USD = United States dollar WTI = West Texas Intermediate Basis of Consolidation and Presentation The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our 2024 Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of PAA and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. The condensed consolidated balance sheet data as of December 31, 2024 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three and six months ended June 30, 2025 should not be taken as indicative of results to be expected for the entire year. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany balances and transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications had no impact on net income or total partners’ capital. 10 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Pending Sale of Canadian NGL Business On June 17, 2025, we entered into a definitive Share Purchase Agreement (“SPA”) with Keyera Corp. (“Keyera”), an Alberta corporation, pursuant to which Keyera agreed to acquire all of the issued and outstanding shares of Plains Midstream Canada ULC, our wholly-owned subsidiary that owns substantially all of our NGL business in Canada (the “Canadian NGL Business”), for cash consideration of approximately CAD$ 5.15 billion (approximately $ 3.75 billion), subject to certain post-closing adjustments, as defined in the SPA. This transaction is expected to close in the first quarter of 2026, subject to the satisfaction or waiver of customary closing conditions, including receipt of regulatory approvals. We determined that in conjunction with entering into the SPA, the operations of the Canadian NGL Business meet the criteria for classification as held for sale and presentation as discontinued operations, as the sale will represent a strategic shift that will have a major effect on our operations and financial results. Accordingly, the assets and liabilities of the Canadian NGL Business have been classified as held for sale, and the balance sheet, results of operations and cash flows of the Canadian NGL Business have been presented as discontinued operations in our condensed consolidated financial statements. Unless otherwise indicated, the disclosures included within the accompanying notes to the condensed consolidated financial statements relate to our continuing operations and exclude amounts related to discontinued operations. These changes have been applied retrospectively to all periods presented. Discontinued operations are not presented separately within our Condensed Consolidated Statements of Comprehensive Income, Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss) or the Condensed Consolidated Statements of Changes in Partners’ Capital. See Note 2 for additional information regarding discontinued operations. All significant intercompany balances and transactions between the Canadian NGL Business and our continuing operations have been eliminated. While we will divest the Canadian NGL Business as part of the sale, we will retain substantially all NGL assets in the United States and will also retain all crude oil assets in Canada. Prior to its classification as held for sale and presentation as discontinued operations, the Canadian NGL Business was part of our NGL reportable segment. In June 2025, we entered into a forward currency instrument to hedge currency exchange risk associated with anticipated proceeds from the pending sale of our Canadian NGL Business. See Note 8 for additional information. In connection with and contingent upon closing of the pending sale of the Canadian NGL Business, we and Keyera entered into an agreement for certain hedging arrangements and payments relating to the differential between the price of natural gas and the extracted NGL commodities (“Frac Spread”) for a twelve-month period commencing the first month after the closing date. As a result of this arrangement, we will guarantee a minimum Frac Spread margin on certain volumes. The recognition of an asset or liability will be dependent upon the terms of the specific contracts transferred as part of the sale of the Canadian NGL business and the market conditions at that time the sale closes. We do not expect any liability we might recognize as a result of this agreement to have a material adverse effect on our consolidated financial condition, results of operations or cash flows; for example, if the sale closed during the first quarter of 2026, based on existing contracts to be transferred and current market conditions as of June 30, 2025, we would recognize a liability of approximately $ 45 million. Subsequent Events Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable. Recent Accounting Pronouncements, Disclosure Rules and Other Legislation Except as discussed in our 2024 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the six months ended June 30, 2025 that are of significance or potential significance to us. 11 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 2 — Discontinued Operations The operations of the Canadian NGL Business meet the criteria for classification as held for sale and presentation as discontinued operations. The Canadian NGL Business disposal group is recorded at its historical carrying value, as the fair value of the disposal group, less estimated costs to sell, is greater than the carrying value of the Canadian NGL Business disposal group. Depreciation and amortization on the long-lived assets of the Canadian NGL Business disposal group ceased upon meeting the criteria to be classified as assets held for sale. See Note 1 for information regarding the pending sale of the Canadian NGL Business. The following table summarizes the carrying amounts of major classes of assets and liabilities of discontinued operations (in millions): June 30, 2025 December 31, 2024 Assets: Current assets: Trade accounts receivable and other receivables, net $ 193 $ 222 Inventory 168 178 Other current assets 24 15 Total current assets of discontinued operations $ 385 $ 415 Long-term assets: Property and equipment, net (1) $ 2,118 $ 1,978 Linefill 71 64 Long-term operating lease right-of-use assets, net 137 143 Long-term inventory 41 38 Other long-term assets, net 115 126 Total long-term assets of discontinued operations $ 2,482 $ 2,349 Liabilities: Current liabilities: Trade accounts payable $ 222 $ 234 Short-term debt 1 1 Other current liabilities 90 115 Total current liabilities of discontinued operations $ 313 $ 350 Long-term liabilities: Long-term operating lease liabilities $ 107 $ 121 Other long-term liabilities and deferred credits 491 455 Total long-term liabilities of discontinued operations $ 598 $ 576 (1) Amounts are net of accumulated depreciation of $ 887 million and $ 794 million as of June 30, 2025 and December 31, 2024, respectively. 12 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following table provides a reconciliation of the line items comprising pretax income from discontinued operations to income from discontinued operations, net of tax (in millions): Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 Revenues: Product sales $ 181 $ 142 $ 679 $ 455 Services 30 34 66 77 Total revenues 211 176 745 532 Cost and Expenses: Purchases and related costs 10 20 252 232 Field operating costs 53 70 122 155 General and administrative expenses 12 14 26 29 Depreciation and amortization 27 31 57 62 (Gains)/losses on asset sales, net 13 ( 1 ) 13 ( 2 ) Total costs and expenses 115 134 470 476 Income from discontinued operations before tax 96 42 275 56 Current income tax expense ( 14 ) ( 17 ) ( 54 ) ( 55 ) Deferred income tax (expense)/benefit ( 12 ) 7 ( 15 ) 41 Income from discontinued operations, net of tax $ 70 $ 32 $ 206 $ 42 Note 3— Revenues and Accounts Receivable Revenue Recognition We disaggregate our revenues by segment and type of activity. These categories depict how the nature, amount, timing and uncertainty of revenues and cash flows are affected by economic factors. Revenues from Contracts with Customers. The following tables present our revenues from contracts with customers disaggregated by segment and type of activity (in millions): Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 Crude Oil segment revenues from contracts with customers Sales $ 10,228 $ 12,327 $ 21,236 $ 23,513 Transportation 340 295 652 595 Terminalling, Storage and Other 87 95 175 187 Total Crude Oil segment revenues from contracts with customers $ 10,655 $ 12,717 $ 22,063 $ 24,295 Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 NGL segment revenues from contracts with customers Sales $ 24 $ 23 $ 66 $ 84 Terminalling, Storage and Other 2 2 1 2 Total NGL segment revenues from contracts with customers $ 26 $ 25 $ 67 $ 86 13 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Sales Revenues. Revenues from sales of crude oil and NGL are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. The consideration received under these contracts is variable based on commodity prices. Inventory exchanges under buy/sell transactions are excluded from sales revenues in our Condensed Consolidated Statements of Operations. Transportation Revenues. Transportation revenues include revenues from transporting crude oil on pipelines and trucks. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil at a published tariff. We primarily recognize pipeline tariff and fee revenues over time as services are rendered, based on the volumes transported. As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor. We recognize the allowance volumes collected as part of the transaction price and record this non-cash consideration at fair value, measured as of the contract inception date. Terminalling, Storage and Other Revenues. Revenues in this category include (i) fees that are generated when we receive liquids from one connecting source and deliver the applicable product to another connecting carrier, (ii) fees from storage capacity agreements, (iii) fees from loading and unloading services at our terminals and (iv) fees from natural gas and condensate processing services. We generate revenue through a combination of month-to-month and multi-year agreements and processing arrangements. Storage fees are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized as our performance obligation is to make available storage capacity for a period of time. Terminal fees (including throughput and loading/unloading fees) are recognized as the liquids enter or exit the terminal and are received from or delivered to the connecting carrier or third-party terminal, as applicable. We recognize loading and unloading fees when the volumes are delivered or received. Reconciliation to Total Revenues of Reportable Segments. The following disclosures only include information regarding revenues associated with consolidated entities; revenues from entities accounted for by the equity method are not included. The following tables present the reconciliation of our revenues from contracts with customers to total revenues of reportable segments and total revenues as disclosed in our Condensed Consolidated Statements of Operations (in millions): 14 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Three Months Ended June 30, 2025 Crude Oil NGL Total Revenues from contracts with customers $ 10,655 $ 26 $ 10,681 Other revenues ( 33 ) — ( 33 ) Total revenues of reportable segments $ 10,622 $ 26 $ 10,648 Intersegment revenues elimination ( 6 ) Total revenues $ 10,642 Three Months Ended June 30, 2024 Crude Oil NGL Total Revenues from contracts with customers $ 12,717 $ 25 $ 12,742 Other revenues 18 — 18 Total revenues of reportable segments $ 12,735 $ 25 $ 12,760 Intersegment revenues elimination ( 3 ) Total revenues $ 12,757 Six Months Ended June 30, 2025 Crude Oil NGL Total Revenues from contracts with customers $ 22,063 $ 67 $ 22,130 Other revenues ( 2 ) — ( 2 ) Total revenues of reportable segments $ 22,061 $ 67 $ 22,128 Intersegment revenues elimination ( 9 ) Total revenues $ 22,119 Six Months Ended June 30, 2024 Crude Oil NGL Total Revenues from contracts with customers $ 24,295 $ 86 $ 24,381 Other revenues 22 — 22 Total revenues of reportable segments $ 24,317 $ 86 $ 24,403 Intersegment revenues elimination ( 7 ) Total revenues $ 24,396 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 June 30, 2025 December 31, 2024 Billed and collected Other current liabilities $ 68 $ 83 Contract Balances . Our contract balances consist of amounts received associated with services or sales for which we have not yet completed the related performance obligation. The following table presents the changes in the liability balance associated with contracts with customers (in millions): Contract Liabilities Balance at December 31, 2024 $ 87 Amounts recognized as revenue ( 24 ) Additions 14 Balance at June 30, 2025 $ 77 15 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 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 June 30, 2025 (in millions): Remainder of 2025 2026 2027 2028 2029 2030 and Thereafter Pipeline revenues supported by minimum volume commitments and capacity agreements (1) $ 174 $ 254 $ 213 $ 171 $ 96 $ 414 Terminalling, storage and other agreement revenues 115 222 194 143 101 488 Total $ 289 $ 476 $ 407 $ 314 $ 197 $ 902 (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 June 30, 2025 and December 31, 2024, substantially all of our trade accounts receivable were less than 30 days past their invoice date. Our expected credit losses are immaterial. Although we consider our credit procedures to be adequate to mitigate any significant credit losses, the actual amount of current and future credit losses could vary significantly from estimated amounts. The following is a reconciliation of trade accounts receivable from revenues from contracts with customers to total trade accounts receivable and other receivables, net as presented on our Condensed Consolidated Balance Sheets (in millions): June 30, 2025 December 31, 2024 Trade accounts receivable arising from revenues from contracts with customers $ 3,792 $ 3,922 Other trade accounts receivable and other receivables (1) 8,221 7,339 Impact due to contractual rights of offset with counterparties ( 8,451 ) ( 7,582 ) Trade accounts receivable and other receivables, net $ 3,562 $ 3,679 (1) The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of ASC 606. 16 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 4— Net Income Per Common Unit We calculate basic and diluted net income per common unit by dividing income from continuing operations attributable to PAA (after deducting amounts allocated to the preferred unitholders and participating securities) and income from discontinued operations by the basic and diluted weighted average number of common units outstanding during the period. The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units and (ii) our equity-indexed compensation plan awards. See Note 11 and Note 17 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for a discussion of our Series A preferred units and equity-indexed compensation plan awards. When applying the if-converted method prescribed by FASB guidance, on a weighted-average basis, for the three and six months ended June 30, 2025, the possible conversion of approximately 58 million and 61 million Series A preferred units, respectively, and for each of the three and six months ended June 30, 2024, the possible conversion of approximately 71 million Series A preferred units were excluded from the calculation of diluted net income per common unit as the effect was antidilutive. Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that are deemed to be dilutive during the period are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. 17 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 June 30, Six Months Ended June 30, 2025 2024 2025 2024 Basic and Diluted Net Income per Common Unit Continuing Operations: Income from continuing operations, net of tax $ 227 $ 298 $ 607 $ 639 Net income attributable to noncontrolling interests ( 87 ) ( 80 ) ( 160 ) ( 166 ) Net income from continuing operations attributable to PAA 140 218 447 473 Distributions to Series A preferred unitholders ( 36 ) ( 44 ) ( 75 ) ( 88 ) Distributions to Series B preferred unitholders ( 18 ) ( 19 ) ( 35 ) ( 39 ) Amounts allocated to participating securities ( 7 ) ( 8 ) ( 9 ) ( 9 ) Impact from repurchase of Series A preferred units (1) — — ( 43 ) — Other 1 1 2 3 Net income from continuing operations allocated to common unitholders - Basic and Diluted (2) $ 80 $ 148 $ 287 $ 340 Discontinued Operations: Net income from discontinued operations allocated to common unitholders - Basic and Diluted (3) $ 70 $ 32 $ 206 $ 42 Net income allocated to common unitholders — Basic and Diluted $ 150 $ 180 $ 493 $ 382 Basic and diluted weighted average common units outstanding 703 701 704 701 Basic and diluted net income per common unit: Continuing operations $ 0.11 $ 0.21 $ 0.41 $ 0.49 Discontinued operations 0.10 0.05 0.29 0.06 Basic and diluted net income per common unit $ 0.21 $ 0.26 $ 0.70 $ 0.55 (1) We repurchased approximately 12.7 million Series A preferred units on January 31, 2025. See Note 7 for additional information. The difference between the cash we paid for the repurchase of such units and their carrying value on our balance sheet is considered a return to Series A preferred unitholders for the calculation of net income allocated to common unitholders. (2) We calculate net income from continuing operations allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (i.e., undistributed loss), if any, are allocated to the common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method. (3) Net income from discontinued operations allocated to common unitholders is Income from discontinued operations, net of tax as presented on our Condensed Consolidated Statements of Operations. 18 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 5— Inventory, Linefill and Long-term Inventory Inventory, linefill and long-term inventory consisted of the following (barrels in thousands and carrying value in millions): June 30, 2025 December 31, 2024 Volumes Unit of Measure Carrying Value Price/ Unit (1) Volumes Unit of Measure Carrying Value Price/ Unit (1) Inventory Crude oil 1,640 barrels $ 102 $ 62.20 3,321 barrels $ 221 $ 66.55 NGL 746 barrels 39 $ 52.28 603 barrels 26 $ 43.12 Other N/A 10 N/A N/A 14 N/A Inventory subtotal 151 261 Linefill Crude oil 15,830 barrels 939 $ 59.32 15,463 barrels 903 $ 58.40 NGL 33 barrels 1 $ 30.30 32 barrels 1 $ 31.25 Linefill subtotal 940 904 Long-term inventory Crude oil 3,529 barrels 230 $ 65.17 3,413 barrels 238 $ 69.73 NGL 90 barrels 4 $ 44.44 90 barrels 4 $ 44.44 Long-term inventory subtotal 234 242 Total $ 1,325 $ 1,407 (1) Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products. 19 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 6— Debt Debt consisted of the following (in millions): June 30, 2025 December 31, 2024 SHORT-TERM DEBT Commercial paper notes, bearing a weighted-average interest rate of 4.6 % and 4.6 %, respectively (1) $ 462 $ 393 Other 13 14 Total short-term debt 475 407 LONG-TERM DEBT Senior notes, net of unamortized discounts and debt issuance costs of $ 50 and $ 42 , respectively (2) 8,133 7,141 Other 71 70 Total long-term debt 8,204 7,211 Total debt (3) $ 8,679 $ 7,618 (1) We classified these commercial paper notes as short-term as of June 30, 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 inventory and NYMEX and ICE margin deposits. (2) As of June 30, 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 June 30, 2025 and December 31, 2024, respectively. We estimated the aggregate fair value of these notes as of June 30, 2025 and December 31, 2024 to be approximately $ 7.9 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 six months ended June 30, 2025 and 2024 were approximately $ 27.6 billion and $ 20.6 billion, respectively. Total repayments under our commercial paper program were approximately $ 27.5 billion and $ 21.0 billion for the six months ended June 30, 2025 and 2024, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities. 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 June 30, 2025 and December 31, 2024, we had outstanding letters of credit of $ 81 million and $ 90 million, respectively. 20 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 7— Partners’ Capital and Distributions Units Outstanding The following tables present the activity for our preferred and common units: Limited Partners Series A Preferred Units Series B Preferred Units Common Units Outstanding at December 31, 2024 71,090,468 800,000 703,770,300 Repurchase of Series A preferred units ( 12,678,560 ) — — Issuances of common units under equity-indexed compensation plans — — 5,650 Outstanding at March 31, 2025 58,411,908 800,000 703,775,950 Repurchase and cancellation of common units under the Common Equity Repurchase Program — — ( 476,695 ) Issuances of common units under equity-indexed compensation plans — — 5,197 Outstanding at June 30, 2025 58,411,908 800,000 703,304,452 Limited Partners Series A Preferred Units Series B Preferred Units Common Units Outstanding at December 31, 2023 71,090,468 800,000 701,008,749 Issuances of common units under equity-indexed compensation plans — — 62,282 Outstanding at March 31, 2024 71,090,468 800,000 701,071,031 Issuances of common units under equity-indexed compensation plans — — 10,268 Outstanding at June 30, 2024 71,090,468 800,000 701,081,299 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. 21 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 six 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 August 14, 2025 (2) July 31, 2025 June 30, 2025 $ 36 $ 0.615 May 15, 2025 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 June 30, 2025, such amount was accrued as distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet. Series B Preferred Unit Distributions . Distributions on the Series B preferred units accumulate and are payable quarterly in arrears on the 15th day of February, May, August and November. See Note 11 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for additional information regarding Series B preferred unit distributions. The following table details distributions paid or to be paid to our Series B preferred unitholders (in millions, except per unit data): Series B Preferred Unitholders Distribution Payment Date Record Date (1) Distribution Period Cash Distribution Distribution per Unit August 15, 2025 (2) August 1, 2025 May 15, 2025 through August 14, 2025 $ 18 $ 22.23 May 15, 2025 May 1, 2025 February 15, 2025 through May 14, 2025 $ 17 $ 21.49 February 18, 2025 February 3, 2025 November 15, 2024 through February 14, 2025 $ 18 $ 22.73 (1) Payable to unitholders of record at the close of business on the applicable Record Date. (2) At June 30, 2025, approximately $ 9 million of accrued distributions payable to our Series B preferred unitholders was included in “Other current liabilities” on our Condensed Consolidated Balance Sheet. Common Unit Distributions . The following table details distributions to our common unitholders paid during or pertaining to the first six 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 August 14, 2025 July 31, 2025 June 30, 2025 $ 179 $ 88 $ 267 $ 0.38 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. 22 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Noncontrolling Interests in Subsidiaries As of June 30, 2025, noncontrolling interests in our subsidiaries consisted of (i) a 35 % interest in Plains Oryx Permian Basin LLC (the “Permian JV”), (ii) a 30 % interest in Cactus II Pipeline LLC (“Cactus II”) and (iii) a 33 % interest in Red River Pipeline Company LLC (“Red River”). Distributions to Noncontrolling Interests The following table details distributions paid to noncontrolling interests during the periods presented (in millions): Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 Permian JV $ 78 $ 74 $ 183 $ 148 Cactus II 16 16 38 37 Red River 3 7 8 13 $ 97 $ 97 $ 229 $ 198 Note 8— Derivatives and Risk Management Activities We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. We use various derivative instruments to manage our exposure to commodity price risk, interest rate risk, and currency exchange rate risk. Our commodity price risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate risk and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on changes in commodity prices or interest rates. When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. At the inception of the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions. Throughout the hedging relationship, retrospective and prospective hedge effectiveness is assessed on a qualitative basis. We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives designated as cash flow hedges, changes in fair value are deferred in AOCI and recognized in earnings in the periods during which the underlying hedged transactions are recognized in earnings. Derivatives that are not designated in a hedging relationship for accounting purposes are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Condensed Consolidated Statements of Cash Flows. Our financial derivatives, used for hedging risk, are governed through ISDA master agreements and clearing brokerage agreements. These agreements include stipulations regarding the right of set off in the event that we or our counterparty default on performance obligations. If a default were to occur, both parties have the right to net amounts payable and receivable into a single net settlement between parties. At June 30, 2025 and December 31, 2024, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our exchange-traded derivatives transacted through a clearing brokerage account, as described below, we do not require our non-cleared derivative counterparties to post collateral with us. 23 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 June 30, 2025, net derivative positions related to these activities included: • A net long position of 5.1 million barrels associated with our crude oil purchases, which will be unwound ratably through September 2025 to match monthly average pricing. • A net short time spread position of 3.2 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through April 2026. • A net crude oil basis spread position of 2.6 million barrels at multiple locations through December 2026. These derivatives allow us to lock in grade and location basis differentials. • A net short position of 5.1 million barrels through December 2029 related to anticipated net sales of crude oil inventory. • A net long position of 0.5 TWh through December 2030 related to anticipated power supply requirements. Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchases and normal sales scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings. We have determined that substantially all of our physical commodity contracts qualify for the normal purchases and normal sales scope exception. 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 June 30, Six Months Ended June 30, 2025 2024 2025 2024 Product sales revenues $ ( 40 ) $ — $ ( 41 ) $ ( 28 ) Field operating costs 5 ( 5 ) 3 ( 6 ) Net loss from commodity derivative activity $ ( 35 ) $ ( 5 ) $ ( 38 ) $ ( 34 ) 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): June 30, 2025 December 31, 2024 Initial margin $ 9 $ 16 Variation margin posted/(returned) ( 6 ) 15 Letters of credit — ( 9 ) Net broker receivable $ 3 $ 22 24 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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. June 30, 2025 December 31, 2024 Effect of Collateral Netting Net Carrying Value Presented on the Balance Sheet Effect of Collateral Netting Net Carrying Value Presented on the Balance Sheet Commodity Derivatives Commodity Derivatives Assets Liabilities Assets Liabilities Derivative Assets Other current assets $ 27 $ ( 16 ) $ 3 $ 14 $ 25 $ ( 24 ) $ 22 $ 23 Other long-term assets, net 1 — — 1 — — — — Derivative Liabilities Other current liabilities — — — — ( 5 ) 5 — — Other long-term liabilities and deferred credits 3 ( 6 ) — ( 3 ) 2 ( 6 ) — ( 4 ) Total $ 31 $ ( 22 ) $ 3 $ 12 $ 22 $ ( 25 ) $ 22 $ 19 Interest Rate Risk Hedging We use interest rate derivatives to hedge the benchmark interest rate associated with interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist of forward starting interest rate swaps and treasury locks. These derivatives are designated as cash flow hedges. As such, changes in fair value are deferred in AOCI and are reclassified to interest expense as we incur the interest expense associated with the underlying debt. The following table summarizes the terms of our outstanding interest rate derivatives as of June 30, 2025 (notional amounts in millions): Hedged Transaction Number and Types of Derivatives Employed Notional Amount Expected Termination Date Average Rate Locked Accounting Treatment Anticipated interest payments 8 forward starting swaps ( 30 -year) $ 200 6/15/2026 3.09 % Cash flow hedge Anticipated interest payments 4 forward starting swaps ( 30 -year) $ 100 10/15/2025 3.76 % Cash flow hedge Anticipated interest payments 4 Treasury Locks ( 10 -year) $ 100 10/15/2025 4.00 % Cash flow hedge As of June 30, 2025, there was a net loss of $ 36 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 June 30, 2025; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions. The following table summarizes the net unrealized gain/(loss) recognized in AOCI for derivatives (in millions): Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 Interest rate derivatives, net $ 7 $ 5 $ 6 $ 18 25 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS At June 30, 2025, the net fair value of our interest rate hedges, which was included in “Other current assets” on our Condensed Consolidated Balance Sheet, totaled $ 33 million. At December 31, 2024, the net fair value of our interest rate hedges, which was included in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet, totaled $ 27 million. Currency Exchange Rate Risk Hedging In connection with the pending sale of the Canadian NGL Business, we entered into a forward currency instrument (CAD$ 4.5 billion notional amount) to hedge currency exchange risk. The instrument is contingent upon the sale occurring and will settle at closing. The cost of the deal-contingent structure is embedded in the hedge rate. As of June 30, 2025, the sale of the Canadian NGL Business is probable and the fair value of the instrument is a $ 49 million liability, presented in “Other current liabilities” on our Condensed Consolidated Balance Sheet. For the three months ended June 30, 2025, we recognized the $ 49 million loss, presented in “Losses on asset sales, net” on our Condensed Consolidated Statements of Operations. As of June 30, 2025, for the periods covered by the instrument, the average fixed USD to CAD rate of the instrument is $ 1.37 and the average forward USD to CAD rate is $ 1.35 . See Note 1 for additional information regarding the pending sale of the Canadian NGL Business. Recurring Fair Value Measurements Derivative Financial Assets and Liabilities The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions): Fair Value as of June 30, 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 $ 12 $ ( 3 ) $ 9 $ 11 $ ( 14 ) $ ( 3 ) Interest rate derivatives — 33 33 — 27 27 Foreign currency derivatives — ( 49 ) ( 49 ) — — — Total net derivative asset/(liability) $ 12 $ ( 19 ) $ ( 7 ) $ 11 $ 13 $ 24 (1) Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits. Level 1 Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives and over-the-counter commodity contracts such as futures and swaps. The fair value of exchange-traded commodity derivatives and over-the-counter commodity contracts is based on unadjusted quoted prices in active markets. Level 2 Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives, over-the-counter commodity, foreign exchange and interest rate derivatives that are traded in observable markets with less volume and transaction frequency than active markets. In addition, it includes certain physical commodity contracts. The fair values of these derivatives are corroborated with market observable inputs. Note 9— Related Party Transactions See Note 16 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for a complete discussion of related parties, including the determination of our related parties and nature of involvement with such related parties. Promissory Notes with our General Partner In February 2025, a consolidated subsidiary issued an additional unsecured promissory note to PAGP with a face value of CAD$ 473 million (approximately $ 330 million). Concurrently, PAGP issued an unsecured promissory note to us for the 26 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 $ 32 million and $ 27 million as of June 30, 2025 and December 31, 2024, respectively. Interest income/expense on the related party notes totaled $ 23 million and $ 43 million for the three and six months ended June 30, 2025, respectively, and $ 7 million and $ 15 million for the three and six months ended June 30, 2024, respectively. As of June 30, 2025 and December 31, 2024, our outstanding related party notes receivable and related party notes payable balances were as follows (in millions): June 30, 2025 December 31, 2024 Related party notes receivable (1) $ 1,349 $ 948 Related party notes payable (1) $ 1,349 $ 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 and six months ended June 30, 2025 and 2024, we recognized sales and transportation revenues, purchased petroleum products and utilized transportation and storage services from related parties. These transactions were conducted at posted tariff rates or prices that we believe approximate market. The impact to our Condensed Consolidated Statements of Operations from these transactions is included below (in millions): Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 Revenues from related parties $ 12 $ 11 $ 23 $ 22 Purchases and related costs from related parties $ 98 $ 96 $ 196 $ 193 Our receivable and payable amounts with these related parties as reflected on our Condensed Consolidated Balance Sheets were as follows (in millions): June 30, 2025 December 31, 2024 Trade accounts receivable and other receivables, net from related parties (1) $ 42 $ 40 Trade accounts payable to related parties (1) (2) $ 64 $ 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. 27 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 10— Commitments and Contingencies Loss Contingencies — General To the extent we are able to assess the likelihood of a negative outcome for a contingency, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Legal Proceedings — General In the ordinary course of business, we are involved in various legal proceedings including those arising from regulatory and environmental matters. In connection with determining the probability of loss associated with such legal proceedings and whether any potential losses associated therewith are estimable, we take into account what we believe to be all relevant known facts and circumstances, and what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing agreements, laws and regulations. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully protect us from losses arising from current or future legal proceedings. Accordingly, we can provide no assurance that the outcome of the various legal proceedings that we are currently involved in, or will become involved with in the future, will not, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Environmental — General We currently own or lease, and in the past have owned and leased, properties where hazardous liquids, including hydrocarbons, are or have been handled. These properties and the hazardous liquids or associated wastes disposed thereon may be subject to the U.S. federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, and the U.S. federal Resource Conservation and Recovery Act, as amended, as well as state and Canadian federal and provincial laws and regulations. Under such laws and regulations, we could be required to remove or remediate hazardous liquids or associated wastes (including wastes disposed of or released by prior owners or operators) and to clean up contaminated property (including contaminated groundwater). Assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified or insured. Although we have made significant investments in our maintenance and integrity programs, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail, storage and other facility operations. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. We also may discover environmental impacts from past releases that were previously unidentified. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows. 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. 28 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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): June 30, 2025 December 31, 2024 Other current liabilities $ 7 $ 11 Other long-term liabilities and deferred credits 74 69 Total $ 81 $ 80 In some cases, the actual cash expenditures associated with these liabilities may not occur for several years. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing or future legal claims giving rise to additional liabilities. Therefore, although we believe that our reserves are adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of such reserves and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows. 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 June 30, 2025, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $ 870 million, which includes actual emergency response and clean-up costs, natural resource damage assessments, fines and penalties incurred, certain third-party claims settlements, and estimated costs associated with our remaining Line 901 lawsuits and claims as described below, as well as estimates for certain legal fees and statutory interest where applicable. We accrue such estimates of aggregate total costs to “Field operating costs” in our Condensed Consolidated Statements of Operations. This estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the resolution of certain third-party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and (ii) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. Our estimate does not include any lost revenue associated with the shutdown of Line 901 or 903 and does not include any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, with respect to potential losses that we regard as only reasonably possible or remote, we have made assumptions regarding the strength of our legal position based on our assessment of the relevant facts and applicable law and precedent; if our assumptions regarding such matters turn out to be inaccurate (i.e., we are found to be liable under circumstances where we regard the likelihood of loss as being only reasonably possible or remote), we could be responsible for significant costs and expenses that are not currently included in our estimates and accruals. In addition, for any potential losses that we regard as probable and for which we have accrued an estimate of the potential losses, our estimates regarding damages, legal fees, court costs and interest could turn out to be inaccurate and the actual losses we incur could be significantly higher than the amounts included in our estimates and accruals. Also, the amount of time it takes for us to resolve all of the current and future lawsuits and claims that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated. Accordingly, our assumptions and estimates may turn out to be inaccurate and our total costs could turn out to be materially higher; therefore, we can provide no assurance that we will not have to accrue significant additional costs in the future with respect to the Line 901 incident. 29 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS We did not recognize any costs, net of amounts probable of recovery from insurance (as applicable), during the three and six months ended June 30, 2025 and 2024. As of June 30, 2025 and December 31, 2024, we had a remaining undiscounted gross liability of approximately $ 20 million and $ 5 million, respectively, related to the Line 901 incident, which aggregate amounts are reflected in “Current liabilities” on our Condensed Consolidated Balance Sheet. We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such liabilities. To date, we have collected $ 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 June 30, 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 and professional costs during future periods. During the second quarter of 2025, we agreed to confidential settlement terms for various lawsuits filed in California Superior Court in Santa Barbara County by companies and individuals who provided labor, goods, or services associated with oil production activities they claim were disrupted following the Line 901 incident, the agreed aggregate settlement amount has been factored into our Line 901 total cost estimate. The only other remaining Line 901 lawsuit is pending in California Superior Court in Santa Barbara County, in which a landowner on an adjacent pipeline is alleging property damage from the “stigma” of the Line 901 incident. We are vigorously defending this remaining lawsuit, which has not yet been set for trial, and believe we have strong defenses. Taking into account the costs that we have included in our total estimate of costs for the Line 901 incident and considering what we regard as very strong defenses to the claims made in our remaining Line 901 lawsuits, we do not believe the ultimate resolution of such remaining lawsuit will have a material adverse effect on our consolidated financial condition, results of operations or cash flows. L48 Pipeline Release. In March of 2025, our subsidiary, Pacific Pipeline System LLC, experienced a crude oil release of approximately 125 barrels on a segment of the Line 48 pipeline in Carson, California. Clean-up and remediation activities were conducted in cooperation with applicable state and federal regulatory agencies. An investigation by the California Office of the State Fire Marshall is not complete. To date no charges, fines or penalties have been assessed against us with respect to this release; however, it is possible that charges, fines or penalties may be assessed against us in the future. We provided notification to our applicable insurance carriers and intend to pursue reimbursement of any costs incurred in excess of our $ 10 million self-insured retention. We estimate that the aggregate cost to clean-up and remediate the site will be approximately $ 20 million. Through June 30, 2025, we incurred $ 12 million in connection with clean-up and remediation activities. Other Litigation Matters: Hartree. On July 19, 2022, Hartree Natural Gas Storage, LLC (“Hartree”) filed a lawsuit under seal in the Superior Court for the State of Delaware asserting claims against PAA Natural Gas Storage, L.P. and PAA arising out of a Membership Interest Purchase Agreement relating to the 2021 sale of the Pine Prairie Energy Center natural gas storage facility to Hartree. In early 2025, we entered into a settlement agreement with Hartree; the terms of the settlement are confidential and the amount paid is not material to our operations. All of Hartree’s claims were dismissed with prejudice and without any admission of wrongdoing by Plains. Louisiana Coastal Erosion Lawsuit. Various coastal parishes, the State of Louisiana and some of its departments have filed lawsuits in Louisiana against a number of energy companies seeking damages for coastal erosion in connection with oil and gas operations in Louisiana. One of our subsidiaries has been named in such a lawsuit filed by The Louisiana Department of Wildlife and Fisheries (“LADWF”). LADWF filed a lawsuit in the 24th Judicial District Court of Jefferson Parish, Louisiana on October 30, 2023 against our subsidiary, Plains Pipeline, L.P., Chevron Pipe Line Company, BP Oil Pipeline Company and Arrowhead Gulf Coast Pipeline, LLC (collectively, “Defendants”), as the former and current parties to certain pipeline right of way agreements (“ROWs”) in the vicinity of the Elmer Island Wildlife Refuge. LADWF alleges that the Defendants breached the terms of the ROWs by failing to prevent erosion and seeks restoration of the Wildlife Refuge or alternatively monetary compensatory damages including restoration costs, legal fees and disgorgement of profits derived from the alleged trespass. Our subsidiary owned and operated a pipeline in the vicinity of the refuge from 2006 through 2016. We believe the claims in the lawsuit lack merit and intend to vigorously defend this lawsuit in coordination with the other Defendants. 30 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 11— Segment Information Our operating segments, Crude Oil and NGL, which are also our reportable segments, are organized by product as our Crude Oil and NGL businesses are generally impacted by different market fundamentals and require the use of different assets and business strategies. The Crude Oil segment includes our crude oil pipelines, crude oil storage and marine terminals and related crude oil marketing activities. Our crude oil marketing activities are included in our Crude Oil reporting segment as its primary purpose is to support the utilization of our assets by entering into transactions that facilitate increased volumes handled by our assets, resulting in additional earnings for the segment. The NGL segment includes our four NGL assets located in the United States. Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below). The measure of Segment Adjusted EBITDA forms the basis of our internal financial reporting and is the primary performance measure of segment profit/(loss) used by our CODM in assessing performance and allocating resources among our operating segments. We define Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) significant segment expenses including: (i) purchases and related costs, (ii) field operating costs and (iii) segment general and administrative expenses, plus (b) our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities, further adjusted (c) for certain selected items including (i) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance and (d) to exclude the portion of all preceding items that is attributable to noncontrolling interests (“Segment amounts attributable to noncontrolling interests”). Our CODM uses Segment Adjusted EBITDA to evaluate the performance of each segment, including analyzing actual results compared to budget and guidance, to assess investment opportunities and to optimize and align assets to maximize returns to stakeholders. Segment Adjusted EBITDA excludes depreciation and amortization. As an MLP, we make quarterly distributions of our “available cash” (as defined in our partnership agreement) to our unitholders. We look at each period’s earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of Segment Adjusted EBITDA as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as pipelines and facilities, caused by age-related decline and wear and tear. We compensate for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance investments, which act to partially offset the aging and wear and tear in the value of our principal fixed assets. These maintenance investments are a component of field operating costs included in Segment Adjusted EBITDA or in maintenance capital, depending on the nature of the cost. Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as investment capital. Capital expenditures made to replace and/or refurbish partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as maintenance capital, which is deducted in determining “available cash.” Maintenance capital is reviewed by our CODM on a segment basis. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are charged to expense as incurred. Assets are not reviewed by our CODM on a segmented basis; therefore, such information is not presented. 31 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following tables reflect certain financial data from continuing operations for each segment (in millions): Crude Oil NGL Intersegment Elimination Total Three Months Ended June 30, 2025 Revenues (1) : Product sales $ 10,178 $ 24 $ ( 5 ) $ 10,197 Services 444 2 ( 1 ) 445 Total revenues 10,622 26 ( 6 ) 10,642 Significant segment expenses: Purchases and related costs (1) ( 9,742 ) ( 22 ) 6 ( 9,758 ) Field operating costs ( 279 ) ( 7 ) — ( 286 ) Segment general and administrative expenses ( 75 ) ( 7 ) — ( 82 ) Total significant segment expenses ( 10,096 ) ( 36 ) 6 ( 10,126 ) Equity earnings in unconsolidated entities 94 — Other segment items (2) : Depreciation and amortization of unconsolidated entities (3) 20 — Derivative activities and inventory valuation adjustments (4) 52 — Long-term inventory costing adjustments (5) 17 — Deficiencies under minimum volume commitments, net (6) ( 9 ) — Equity-indexed compensation expense (7) 8 — Foreign currency revaluation (8) 9 — Transaction-related expenses (9) 3 — Segment amounts attributable to noncontrolling interests (10) ( 140 ) — Total other segment items ( 40 ) — Segment Adjusted EBITDA $ 580 $ ( 10 ) Investment and acquisition capital expenditures (11) (12) $ 218 $ — $ 218 Maintenance capital expenditures (12) $ 43 $ 1 $ 44 As of June 30, 2025 Investments in unconsolidated entities $ 2,709 $ — $ 2,709 32 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Crude Oil NGL Intersegment Elimination Total Six Months Ended June 30, 2025 Revenues (1) : Product sales $ 21,185 $ 66 $ ( 8 ) $ 21,243 Services 876 1 ( 1 ) 876 Total revenues 22,061 67 ( 9 ) 22,119 Significant segment expenses: Purchases and related costs (1) ( 20,231 ) ( 55 ) 9 ( 20,277 ) Field operating costs ( 571 ) ( 14 ) — ( 585 ) Segment general and administrative expenses ( 155 ) ( 13 ) — ( 168 ) Total significant segment expenses ( 20,957 ) ( 82 ) 9 ( 21,030 ) Equity earnings in unconsolidated entities 196 — Other segment items (2) : Depreciation and amortization of unconsolidated entities (3) 40 — Derivative activities and inventory valuation adjustments (4) 28 — Long-term inventory costing adjustments (5) 18 — Deficiencies under minimum volume commitments, net (6) ( 16 ) — Equity-indexed compensation expense (7) 18 — Foreign currency revaluation (8) 9 — Transaction-related expenses (9) 8 — Segment amounts attributable to noncontrolling interests (10) ( 265 ) — Total other segment items ( 160 ) — Segment Adjusted EBITDA $ 1,140 $ ( 15 ) Investment and acquisition capital expenditures (11) (12) $ 1,002 $ — $ 1,002 Maintenance capital expenditures (12) $ 74 $ 3 $ 77 As of June 30, 2025 Investments in unconsolidated entities $ 2,709 $ — $ 2,709 33 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Crude Oil NGL Intersegment Elimination Total Three Months Ended June 30, 2024 Revenues (1) : Product sales $ 12,330 $ 23 $ ( 2 ) $ 12,351 Services 405 2 ( 1 ) 406 Total revenues 12,735 25 ( 3 ) 12,757 Significant segment expenses: Purchases and related costs (1) ( 11,820 ) ( 21 ) 3 ( 11,838 ) Field operating costs ( 272 ) ( 8 ) — ( 280 ) Segment general and administrative expenses ( 72 ) ( 7 ) — ( 79 ) Total significant segment expenses ( 12,164 ) ( 36 ) 3 ( 12,197 ) Equity earnings in unconsolidated entities 106 — Other segment items (2) : Depreciation and amortization of unconsolidated entities (3) 17 — Derivative activities and inventory valuation adjustments (4) ( 4 ) — Long-term inventory costing adjustments (5) 4 — Deficiencies under minimum volume commitments, net (6) 7 — Equity-indexed compensation expense (7) 10 — Foreign currency revaluation (8) ( 2 ) — Segment amounts attributable to noncontrolling interests (10) ( 133 ) — Total other segment items ( 101 ) — Segment Adjusted EBITDA $ 576 $ ( 11 ) Investment and acquisition capital expenditures (11) (12) $ 79 $ — $ 79 Maintenance capital expenditures (12) $ 41 $ 2 $ 43 As of December 31, 2024 Investments in unconsolidated entities $ 2,811 $ — $ 2,811 34 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Crude Oil NGL Intersegment Elimination Total Six Months Ended June 30, 2024 Revenues (1) : Product sales $ 23,505 $ 84 $ ( 5 ) $ 23,584 Services 812 2 ( 2 ) 812 Total revenues 24,317 86 ( 7 ) 24,396 Significant segment expenses: Purchases and related costs (1) ( 22,484 ) ( 66 ) 7 ( 22,543 ) Field operating costs ( 538 ) ( 15 ) — ( 553 ) Segment general and administrative expenses ( 146 ) ( 14 ) — ( 160 ) Total significant segment expenses ( 23,168 ) ( 95 ) 7 ( 23,256 ) Equity earnings in unconsolidated entities 201 — Other segment items (2) : Depreciation and amortization of unconsolidated entities (3) 37 — Derivative activities and inventory valuation adjustments (4) 34 — Long-term inventory costing adjustments (5) ( 25 ) — Deficiencies under minimum volume commitments, net (6) ( 5 ) — Equity-indexed compensation expense (7) 19 — Foreign currency revaluation (8) ( 19 ) — Segment amounts attributable to noncontrolling interests (10) ( 261 ) — Total other segment items ( 220 ) — Segment Adjusted EBITDA $ 1,130 $ ( 9 ) Investment and acquisition capital expenditures (11) (12) $ 261 $ — $ 261 Maintenance capital expenditures (12) $ 87 $ 3 $ 90 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. 35 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 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) During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. These gains and losses are not integral to our core operating performance and were therefore excluded in determining Segment Adjusted EBITDA. (9) Primarily related to acquisitions completed during the first half of 2025. See Note 12 for information regarding these transactions. (10) Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River. (11) Investment capital and acquisition capital expenditures, including investments in unconsolidated entities. (12) These amounts combined represent total capital expenditures. 36 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Segment Adjusted EBITDA Reconciliation The following table reconciles Segment Adjusted EBITDA to Income from continuing operations, net of tax (in millions): Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 Segment Adjusted EBITDA $ 570 $ 565 $ 1,125 $ 1,121 Total other segment items (1) 40 101 160 220 Depreciation and amortization ( 235 ) ( 226 ) ( 466 ) ( 449 ) Losses on asset sales, net ( 42 ) ( 2 ) ( 29 ) ( 3 ) Gain on investments in unconsolidated entities, net — — 31 — Interest expense, net ( 133 ) ( 111 ) ( 260 ) ( 205 ) Other income, net 31 23 57 18 Income from continuing operations before tax 231 350 618 702 Income tax expense from continuing operations ( 4 ) ( 52 ) ( 11 ) ( 63 ) Income from continuing operations, net of tax $ 227 $ 298 $ 607 $ 639 (1) See footnotes to the segment financial data tables above for a more detailed discussion of Other segment items. Note 12 — Acquisitions Ironwood Midstream Ironwood Midstream . On January 31, 2025, we acquired Ironwood Midstream Energy Partners II, LLC (“Ironwood Midstream”), which owns a gathering system in the Eagle Ford Basin, for approximately $ 481 million in cash from EnCap Flatrock Midstream. The Ironwood Midstream acquisition is accounted for in our Crude Oil segment. In January 2025, in a separate transaction, we also repurchased from EnCap Flatrock Midstream, a portion of our outstanding Series A preferred units. EnCap Flatrock Midstream is affiliated with EnCap Investments, L.P., an entity that is associated with a member of the board of directors of PAGP GP. See Note 7 for additional information. The Ironwood Midstream acquisition was accounted for as a business combination using the acquisition method of accounting. In accordance with applicable accounting guidance, the fair value of the assets acquired and liabilities assumed following the acquisition was utilized as the consideration transferred for the purchase price allocation. The determination of the fair value of the assets and liabilities assumed was estimated in accordance with applicable accounting guidance. The analysis was performed based on estimates that are reflective of market participant assumptions. The following table reflects our preliminary determination of the fair value of the Ironwood Midstream acquisition assets and liabilities (in millions): Identifiable Assets Acquired and Liabilities Assumed: Estimated Useful Lives (in years) Recognized Amount Property and equipment 3 - 30 $ 435 Intangible assets 16 27 Working capital and other assets and liabilities N/A 19 $ 481 37 Table of Contents PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 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 and $ 2 million during the three and six months ended June 30, 2025, respectively, and the future amortization expense for the remainder of 2025 through 2029 is estimated as follows (in millions): Remainder of 2025 $ 2 2026 $ 5 2027 $ 4 2028 $ 3 2029 $ 3 Pro forma financial information assuming the acquisition had occurred as of the beginning of the calendar year prior to the year of the acquisition, as well as the revenues and earnings generated during the period since the acquisition date, were not material for disclosure purposes. Other Acquisitions Medallion Midstream . In January 2025, we acquired EMG Medallion 2 Holdings, LLC and its subsidiaries, which own a crude oil gathering and transportation business in the Delaware Basin, for $ 163 million (approximately $ 106 million net to our 65 % interest in the Permian JV), subject to certain adjustments. A cash deposit of approximately $ 16 million was paid upon signing in December 2024. The Medallion Midstream acquisition is accounted for in our Crude Oil segment. EMG Medallion 2 Holdings, LLC was a portfolio company of The Energy & Minerals Group (“EMG”), which is associated with a member of the board of directors of PAGP GP. Cheyenne Pipeline . In February 2025, through a non-monetary transaction, we acquired the remaining 50 % interest in Cheyenne Pipeline LLC (“Cheyenne”) in exchange for the termination of certain obligations. The transaction resulted in a net gain of approximately $ 31 million, which represents the difference between the fair value of the entity and the historical book value of our investment. This gain is reflected in “Gain on investments in unconsolidated entities, net” on our Condensed Consolidated Statement of Operations. Prior to this transaction, our 50 % interest in Cheyenne was accounted for as an equity method investment, reported in our Crude Oil segment. Black Knight Midstream. During the second quarter of 2025, we acquired Black Knight Midstream, LLC (“Black Knight Midstream”), which owns a crude oil gathering business in the Permian Basin, for $ 59 million (approximately $ 38 million net to our 65 % interest in the Permian JV), subject to certain adjustments. The Black Knight Midstream assets are accounted for in our Crude Oil segment. BridgeTex Pipeline . In July 2025, we acquired an additional 20 % interest in BridgeTex Pipeline Company, LLC (“BridgeTex”) for approximately $ 180 million. As a result of this transaction, we now own a 40 % interest in BridgeTex and continue to account for our interest in BridgeTex, which is reported in our Crude Oil segment, as an equity method investment. 38 Table of Contents Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Introduction The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical Consolidated Financial Statements and accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations as presented in our 2024 Annual Report on Form 10-K. For more detailed information regarding the basis of presentation for the following financial information, see the Condensed Consolidated Financial Statements and related notes that are contained in Part I, Item 1 of this Quarterly Report on Form 10-Q. Our discussion and analysis includes the following: • Executive Summary • Results of Operations • Liquidity and Capital Resources • Recent Accounting Pronouncements • Forward-Looking Statements Executive Summary Company Overview Our business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals. As one of the largest crude oil midstream service providers in North America, we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. Our assets and the services we provide are primarily focused on crude oil and, to a lesser extent, NGL. Pending Sale of Canadian NGL Business On June 17, 2025, we entered into a definitive SPA with Keyera, pursuant to which Keyera agreed to acquire all of the issued and outstanding shares of Plains Midstream Canada ULC, our wholly-owned subsidiary that owns substantially all of the Canadian NGL Business. This transaction supports our strategic objective to focus on our core midstream crude oil operations and to reduce exposure to commodity price fluctuations and seasonality. While we will divest the Canadian NGL Business as part of the sale, we will retain substantially all NGL assets in the United States and will also retain all crude oil assets in Canada. This transaction is expected to close in the first quarter of 2026, subject to the satisfaction or waiver of customary closing conditions, including receipt of regulatory approvals. We determined that in conjunction with entering into the SPA, the operations of the Canadian NGL Business meet the criteria for classification as held for sale and presentation as discontinued operations, as the sale will represent a strategic shift that will have a major effect on our operations and financial results. We have applied these changes retrospectively to all periods presented. See Note 1 and Note 2 to our Condensed Consolidated Financial Statements for additional information. Unless otherwise indicated, the discussion below relates to our continuing operations and excludes amounts related to discontinued operations. Overview of Operating Results We recognized net income attributable to PAA of $653 million for the six months ended June 30, 2025 compared to net income attributable to PAA of $515 million for the first six months of 2024. See the “Results of Operations” section below for discussion of significant drivers of our results from continuing operations. 39 Table of Contents 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 June 30, Variance Six Months Ended June 30, Variance 2025 2024 $ % 2025 2024 $ % Product sales revenues $ 10,197 $ 12,351 $ (2,154) (17) % $ 21,243 $ 23,584 $ (2,341) (10) % Services revenues 445 406 39 10 % 876 812 64 8 % Purchases and related costs (9,758) (11,838) 2,080 18 % (20,277) (22,543) 2,266 10 % Field operating costs (286) (280) (6) (2) % (585) (553) (32) (6) % General and administrative expenses (82) (79) (3) (4) % (168) (160) (8) (5) % Depreciation and amortization (235) (226) (9) (4) % (466) (449) (17) (4) % Losses on asset sales, net (42) (2) (40) ** (29) (3) (26) (867) % Equity earnings in unconsolidated entities 94 106 (12) (11) % 196 201 (5) (2) % Gain on investments in unconsolidated entities, net — — — N/A 31 — 31 N/A Interest expense, net (1) (133) (111) (22) (20) % (260) (205) (55) (27) % Other income, net (1) 31 23 8 35 % 57 18 39 ** Income tax expense from continuing operations (4) (52) 48 92 % (11) (63) 52 83 % Income from continuing operations, net of tax 227 298 (71) (24) % 607 639 (32) (5) % Income from discontinued operations, net of tax (2) 70 32 38 119 % 206 42 164 ** Net income 297 330 (33) (10) % 813 681 132 19 % Net income attributable to noncontrolling interests (87) (80) (7) (9) % (160) (166) 6 4 % Net income attributable to PAA $ 210 $ 250 $ (40) (16) % $ 653 $ 515 $ 138 27 % Basic and diluted net income per common unit: Continuing operations $ 0.11 $ 0.21 $ (0.10) (48) % $ 0.41 $ 0.49 $ (0.08) (16) % Discontinued operations 0.10 0.05 0.05 100 % 0.29 0.06 0.23 ** Basic and diluted net income per common unit $ 0.21 $ 0.26 $ (0.05) (19) % $ 0.70 $ 0.55 $ 0.15 27 % Basic and diluted weighted average common units outstanding 703 701 2 — % 704 701 3 — % ** Indicates that variance as a percentage is not meaningful. (1) “Interest expense, net” and “Other income, net” each include $23 million and $43 million for the three and six months ended June 30, 2025, respectively, and $15 million for the three and six months ended June 30, 2024 related to interest on promissory notes by and among us and certain Plains entities. (2) See Note 2 to our Condensed Consolidated Financial Statements for a reconciliation of the line items comprising income from discontinued operations, net of tax. 40 Table of Contents Continuing Operations The following discussion of our results of operations focuses on our continuing operations. Revenues and Purchases Fluctuations in our revenues and purchases and related costs are primarily associated with our merchant activities and are generally explained by changes in commodity prices and the impact of gains and losses related to derivative instruments used to manage our commodity price exposure. Because both product sales revenues and purchases and related costs are generally based off of the same pricing indices, the market price of the commodities will not necessarily have an impact on the absolute margins related to those sales and purchases. A majority of our crude oil sales and purchases are indexed to the prompt month price of the NYMEX Light, Sweet crude oil futures contract (“NYMEX Price”). The following table presents the range of the NYMEX Price over the last two years (in dollars per barrel): NYMEX Price Low High Average Three Months Ended June 30, 2025 $ 57 $ 75 $ 64 Three Months Ended June 30, 2024 $ 73 $ 87 $ 81 Six Months Ended June 30, 2025 $ 57 $ 80 $ 68 Six Months Ended June 30, 2024 $ 70 $ 87 $ 79 Product sales revenues (including the impact of derivative mark-to-market valuations) and purchases decreased for the three and six months ended June 30, 2025 compared to the same periods in 2024 primarily due to lower commodity prices in the 2025 periods, partially offset by higher crude oil sales volumes in the 2025 periods. Services revenues for the three and six months ended June 30, 2025 increased compared to the same periods in 2024 primarily due to higher pipeline volumes and tariff escalations, as well as the impact of recently completed acquisitions. 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 six months ended June 30, 2025 compared to the same periods in 2024 was primarily due to transaction costs associated with our recent acquisitions. Depreciation and Amortization The increase in depreciation and amortization for the three and six months ended June 30, 2025 compared to the same periods in 2024 was largely driven by acquisitions. Loss on Asset Sales, Net In connection with the pending sale of the Canadian NGL Business, we entered into a deal-contingent forward currency instrument to hedge the currency exchange risk associated with the sale in CAD. The 2025 periods were impacted by the mark-to-market of this instrument. See Note 8 to our Condensed Consolidated Financial Statements for additional information regarding this instrument and our derivatives and hedging activities. See Note 1 to our Condensed Consolidated Financial Statements for additional information regarding the pending sale of the Canadian NGL Business. 41 Table of Contents Equity Earnings See discussion of Equity earnings in unconsolidated entities in the “—Analysis of Operating Segments” section below. Gain on Investments in Unconsolidated Entities, Net We recognized a net gain of $31 million related to our acquisition of the remaining 50% interest in Cheyenne in the first quarter of 2025. See Note 12 to our Condensed Consolidated Financial Statements for additional information regarding this transaction. Interest Expense, Net and Other Income, Net For the three and six months ended June 30, 2025 and 2024, “Interest expense, net” and “Other income, net” each include interest expense and interest income associated with promissory notes payable and receivable by and among us and certain Plains entities. These amounts are excluded from our non-GAAP performance measures Adjusted EBITDA and Implied DCF. As such, the interest expense and interest income associated with these notes are presented on a net basis in the reconciliation of these metrics to Net Income. See the “—Non-GAAP Financial Measures” section below. The following table summarizes the components impacting Interest expense, net (in millions): Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 Interest expense on third-party borrowings (1) $ 113 $ 98 $ 222 $ 194 Interest expense on related party promissory notes (2) 23 15 43 15 Capitalized interest (3) (2) (5) (4) $ 133 $ 111 $ 260 $ 205 (1) The increase in interest expense for the 2025 periods compared to the same periods in 2024 was primarily driven by the issuance of $1.0 billion, 5.95% senior notes in January 2025 and $650 million, 5.70% senior notes in June 2024, partially offset by the repayment of $750 million, 3.60% senior notes in November 2024. See Note 6 to our Condensed Consolidated Financial Statements for additional information regarding our senior notes. (2) Represents interest expense associated with promissory notes by and among us and certain Plains entities, as described above. The following table summarizes the components impacting Other income, net (in millions): Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 Interest income on related party promissory notes (1) $ 23 $ 15 $ 43 $ 15 Other (2) 8 8 14 3 $ 31 $ 23 $ 57 $ 18 (1) Represents interest income associated with promissory notes by and among us and certain Plains entities, as described above. (2) Primarily includes interest income from other sources and gains and losses on foreign revaluation related to the impact from the change in the CAD to USD exchange rate on the portion of our intercompany net investment that is not long-term in nature. 42 Table of Contents Income Tax Expense The net favorable income tax variance for the three and six months ended June 30, 2025 compared to the same periods in 2024 was primarily due to the impact of (i) lower income tax expense in 2025 associated with Canadian withholding tax on dividends from our Canadian entities to other Plains entities, partially offset by (ii) higher year-over-year income within our Canadian operations as impacted by fluctuations of derivative mark-to-market valuations. Non-GAAP Financial Measures To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future and to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. The primary additional measures used by management are Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied distributable cash flow (“DCF”), Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions. Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF are reconciled to Net Income, and Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions are reconciled to Net Cash Provided by Operating Activities, the most directly comparable measures as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our Condensed Consolidated Financial Statements and accompanying notes. See “—Liquidity and Capital Resources—Non-GAAP Financial Liquidity Measures” for additional information regarding Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions. Non-GAAP Financial Performance Measures Adjusted EBITDA is defined as earnings from continuing operations and discontinued operations before (i) interest expense, (ii) income tax (expense)/benefit from continuing operations and discontinued operations, (iii) depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, of unconsolidated entities) from continuing operations and discontinued operations, (iv) gains and losses on asset sales, asset impairments and other, net from continuing operations and discontinued operations, (v) gains on investments in unconsolidated entities, net and (vi) interest income on promissory notes by and among us and certain Plains entities, and (vii) adjusted for certain selected items impacting comparability. Adjusted EBITDA attributable to PAA excludes the portion of Adjusted EBITDA that is attributable to noncontrolling interests. Management believes that the presentation of Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF provides useful information to investors regarding our performance and results of operations because these measures, when used to supplement related GAAP financial measures, (i) provide additional information about our operating performance and ability to fund distributions to our unitholders through cash generated by our operations, (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions and (iii) present measures that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These non-GAAP financial performance measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (iii) long-term inventory costing adjustments, (iv) items that are not indicative of our operating results and/or (v) other items that we believe should be excluded in understanding our operating performance. These measures may further be adjusted to include amounts related to deficiencies associated with minimum volume commitments whereby we have billed the counterparties for their deficiency obligation and such amounts are recognized as deferred revenue in “Other current liabilities” in our Condensed Consolidated Financial Statements. We also adjust for amounts billed by our equity method investees related to deficiencies under minimum volume commitments. Such amounts are presented net of applicable amounts subsequently recognized into revenue. We have defined all such items as “selected items impacting comparability.” We do not necessarily consider all of our selected items impacting comparability to be non-recurring, infrequent or unusual, but we believe that an understanding of these selected items impacting comparability is material to the evaluation of our operating results and prospects. 43 Table of Contents Although we present selected items impacting comparability that management considers in evaluating our performance, you should also be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions, divestitures, investment capital projects and numerous other factors as discussed, as applicable, in “—Analysis of Operating Segments.” Discontinued Operations. Management believes that the presentation of certain Non-GAAP financial measures, such as Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied DCF, and certain Non-GAAP liquidity measures, such as Adjusted Free Cash Flow and Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities), on a consolidated basis (e.g., the aggregate of continuing operations and discontinued operations) provides more relevant and useful information regarding our performance and results of operations than presenting such metrics only on a continuing operations or discontinued operations basis. In addition, as the potential sale of the Canadian NGL Business is not anticipated to close until the first quarter of 2026, management continues to view the Canadian NGL Business as a component of our overall company performance and ability to fund distributions to our unitholders in the near term. 44 Table of Contents 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 June 30, Variance Six Months Ended June 30, Variance 2025 2024 $ % 2025 2024 $ % Net income (1) $ 297 $ 330 $ (33) (10) % $ 813 $ 681 $ 132 19 % Interest expense, net of certain items (2) 110 96 14 15 % 217 190 27 14 % Income tax expense from continuing operations 4 52 (48) (92) % 11 63 (52) (83) % Income tax expense from discontinued operations (3) 26 10 16 160 % 69 14 55 ** Depreciation and amortization from continuing operations 235 226 9 4 % 466 449 17 4 % Depreciation and amortization from discontinued operations (3) 27 31 (4) (13) % 57 62 (5) (8) % Losses on asset sales, net from continuing operations 42 2 40 ** 29 3 26 ** (Gains)/losses on asset sales, net from discontinued operations (3) 13 (1) 14 ** 13 (2) 15 ** Gain on investments in unconsolidated entities, net — — — N/A (31) — (31) N/A Depreciation and amortization of unconsolidated entities (4) 20 17 3 18 % 40 37 3 8 % Selected Items Impacting Comparability (1) : Derivative activities and inventory valuation adjustments 8 24 (16) ** (27) 184 (211) ** Long-term inventory costing adjustments 19 10 9 ** 17 (24) 41 ** Deficiencies under minimum volume commitments, net (9) 7 (16) ** (16) (5) (11) ** Equity-indexed compensation expense 8 10 (2) ** 18 19 (1) ** Foreign currency revaluation 12 (3) 15 ** 11 (24) 35 ** Transaction-related expenses 3 — 3 ** 8 — 8 ** Selected Items Impacting Comparability - Segment Adjusted EBITDA (1) (5) 41 48 (7) ** 11 150 (139) ** Foreign currency revaluation (6) (3) (4) 1 ** (2) 7 (9) ** Selected Items Impacting Comparability - Adjusted EBITDA (1) (7) 38 44 (6) ** 9 157 (148) ** Adjusted EBITDA (1) (7) $ 812 $ 807 $ 5 1 % $ 1,693 $ 1,654 $ 39 2 % Adjusted EBITDA attributable to noncontrolling interests (8) (140) (133) (7) (5) % (267) (263) (4) (2) % Adjusted EBITDA attributable to PAA (1) $ 672 $ 674 $ (2) — % $ 1,426 $ 1,391 $ 35 3 % 45 Table of Contents Three Months Ended June 30, Variance Six Months Ended June 30, Variance 2025 2024 $ % 2025 2024 $ % Adjusted EBITDA (1) (7) (9) $ 812 $ 807 $ 5 1 % $ 1,693 $ 1,654 $ 39 2 % Interest expense, net of certain non-cash and other items (10) (107) (91) (16) (18) % (211) (180) (31) (17) % Maintenance capital from continuing operations (11) (44) (43) (1) (2) % (77) (90) 13 14 % Maintenance capital from discontinued operations (11) (20) (18) (2) (11) % (28) (28) — — % Investment capital of noncontrolling interests (12) (33) (17) (16) (94) % (64) (41) (23) (56) % Current income tax expense from continuing operations (1) (52) 51 98 % (6) (68) 62 91 % Current income tax expense from discontinued operations (3) (14) (17) 3 18 % (54) (55) 1 2 % Distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings (13) 22 (5) 27 ** 19 7 12 ** Distributions to noncontrolling interests (14) (97) (97) — — % (229) (198) (31) (16) % Implied DCF (1) $ 518 $ 467 $ 51 11 % $ 1,043 $ 1,001 $ 42 4 % Preferred unit distributions (14) (53) (63) 10 16 % (117) (127) 10 8 % Implied DCF Available to Common Unitholders (1) $ 465 $ 404 $ 61 15 % $ 926 $ 874 $ 52 6 % Common unit cash distributions (14) (267) (223) (535) (445) Implied DCF Excess (1) (15) $ 198 $ 181 $ 391 $ 429 ** Indicates that variance as a percentage is not meaningful. (1) Includes results from continuing operations and discontinued operations. (2) Represents “Interest expense, net” as reported on our Condensed Consolidated Statements of Operations, net of interest income associated with promissory notes by and among us and certain Plains entities. (3) See Note 2 to our Condensed Consolidated Financial Statements for additional information. (4) We exclude our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities when reviewing Adjusted EBITDA, similar to our consolidated assets. (5) For a more detailed discussion of these selected items impacting comparability, see the footnotes to the segment financial data tables in Note 11 to our Condensed Consolidated Financial Statements. (6) 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. (7) “Other income, net” on our Condensed Consolidated Statements of Operations, excluding interest income associated with promissory notes by and among us and certain Plains entities, adjusted for selected items impacting comparability (“Adjusted other income, net”) is included in Adjusted EBITDA and excluded from Segment Adjusted EBITDA. (8) Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River. (9) See the table above for a reconciliation from Net Income to Adjusted EBITDA. 46 Table of Contents (10) Amount excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps and is net of interest income associated with promissory notes by and among us and certain Plains entities. (11) 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. (12) Investment capital expenditures attributable to noncontrolling interests that reduce Implied DCF available to PAA common unitholders. (13) 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). (14) Cash distributions paid during the period presented. (15) Excess DCF is retained to establish reserves for debt repayment, future distributions, common equity repurchases, capital expenditures and other partnership purposes. Analysis of Operating Segments We manage our operations through two operating segments: Crude Oil and NGL. Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA. See Note 11 to our Condensed Consolidated Financial Statements for our definition of Segment Adjusted EBITDA and a reconciliation of Segment Adjusted EBITDA to Income from Continuing Operations, Net of Tax. See Note 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 and general and administrative costs. 47 Table of Contents The following tables set forth our operating results from our Crude Oil segment: Operating Results (1) Three Months Ended June 30, Variance Six Months Ended June 30, Variance (in millions) 2025 2024 $ % 2025 2024 $ % Revenues $ 10,622 $ 12,735 $ (2,113) (17) % $ 22,061 $ 24,317 $ (2,256) (9) % Purchases and related costs (9,742) (11,820) 2,078 18 % (20,231) (22,484) 2,253 10 % Field operating costs (279) (272) (7) (3) % (571) (538) (33) (6) % Segment general and administrative expenses (2) (75) (72) (3) (4) % (155) (146) (9) (6) % Equity earnings in unconsolidated entities 94 106 (12) (11) % 196 201 (5) (2) % Other segment items (3) : Depreciation and amortization of unconsolidated entities 20 17 3 ** 40 37 3 ** Derivative activities and inventory valuation adjustments 52 (4) 56 ** 28 34 (6) ** Long-term inventory costing adjustments 17 4 13 ** 18 (25) 43 ** Deficiencies under minimum volume commitments, net (9) 7 (16) ** (16) (5) (11) ** Equity-indexed compensation expense 8 10 (2) ** 18 19 (1) ** Foreign currency revaluation 9 (2) 11 ** 9 (19) 28 ** Transaction-related expenses 3 — 3 ** 8 — 8 ** Segment amounts attributable to noncontrolling interests (140) (133) (7) ** (265) (261) (4) ** Segment Adjusted EBITDA $ 580 $ 576 $ 4 1 % $ 1,140 $ 1,130 $ 10 1 % Maintenance capital expenditures $ 43 $ 41 $ 2 5 % $ 74 $ 87 $ (13) (15) % Three Months Ended June 30, Variance Six Months Ended June 30, Variance Average Volumes 2025 2024 Volumes % 2025 2024 Volumes % Crude oil pipeline tariff (by region) (4) (5) Permian Basin 7,223 6,701 522 8 % 7,047 6,565 482 7 % South Texas / Eagle Ford 542 395 147 37 % 517 386 131 34 % Mid-Continent 537 530 7 1 % 477 508 (31) (6) % Other 1,357 1,312 45 3 % 1,333 1,310 23 2 % Total crude oil pipeline tariff 9,659 8,938 721 8 % 9,374 8,769 605 7 %