PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except unit data)
| | | | | | | | | | | |
| June 30,
2026 | | December 31,
2025 |
| (unaudited) |
| ASSETS | | | |
| | | |
| CURRENT ASSETS | | | |
| Cash and cash equivalents | $ | 1,059 | | | $ | 328 | |
| | | |
| Trade accounts receivable and other receivables, net | 5,267 | | | 3,598 | |
| Inventory | 84 | | | 211 | |
Current assets of discontinued operations (Note 2) | — | | | 479 | |
| Other current assets | 127 | | | 117 | |
| Total current assets | 6,537 | | | 4,733 | |
| | | |
| PROPERTY AND EQUIPMENT | 22,702 | | | 22,536 | |
| Accumulated depreciation | (5,921) | | | (5,676) | |
| Property and equipment, net | 16,781 | | | 16,860 | |
| | | |
| OTHER ASSETS | | | |
| Investments in unconsolidated entities | 2,817 | | | 2,846 | |
| Intangible assets, net | 1,610 | | | 1,754 | |
| Linefill | 892 | | | 900 | |
| Long-term operating lease right-of-use assets, net | 172 | | | 198 | |
| Long-term inventory | 257 | | | 214 | |
Long-term assets of discontinued operations (Note 2) | — | | | 2,557 | |
| Other long-term assets, net | 152 | | | 107 | |
| Total assets | $ | 29,218 | | | $ | 30,169 | |
| | | |
| LIABILITIES AND PARTNERS’ CAPITAL | | | |
| | | |
| CURRENT LIABILITIES | | | |
| Trade accounts payable | $ | 4,942 | | | $ | 3,457 | |
| Short-term debt | 9 | | | 563 | |
Current liabilities of discontinued operations (Note 2) | 154 | | | 382 | |
| Other current liabilities | 754 | | | 529 | |
| Total current liabilities | 5,859 | | | 4,931 | |
| | | |
| LONG-TERM LIABILITIES | | | |
| Senior notes, net | 8,373 | | | 9,118 | |
| Other long-term debt, net | 59 | | | 1,578 | |
| Long-term operating lease liabilities | 194 | | | 202 | |
Long-term liabilities of discontinued operations (Note 2) | — | | | 606 | |
| Other long-term liabilities and deferred credits | 442 | | | 654 | |
| Total long-term liabilities | 9,068 | | | 12,158 | |
| | | |
COMMITMENTS AND CONTINGENCIES (NOTE 10) | | | |
| | | |
| PARTNERS’ CAPITAL | | | |
Series A preferred unitholders (58,411,908 and 58,411,908 units outstanding, respectively) | 1,250 | | | 1,248 | |
Series B preferred unitholders (800,000 and 800,000 units outstanding, respectively) | 787 | | | 787 | |
Common unitholders (705,566,460 and 705,520,697 units outstanding, respectively) | 9,042 | | | 7,801 | |
| Total partners’ capital excluding noncontrolling interests | 11,079 | | | 9,836 | |
| Noncontrolling interests | 3,212 | | | 3,244 | |
| Total partners’ capital | 14,291 | | | 13,080 | |
| Total liabilities and partners’ capital | $ | 29,218 | | | $ | 30,169 | |
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 OPERATIONS
(in millions, except per unit data)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
June 30, | | Six Months Ended
June 30, |
| 2026 | | 2025 | | 2026 | | 2025 |
| (unaudited) | | (unaudited) |
| REVENUES | | | | | | | |
| Product sales revenues | $ | 17,221 | | | $ | 10,197 | | | $ | 29,246 | | | $ | 21,243 | |
| Services revenues | 472 | | | 445 | | | 916 | | | 876 | |
| Total revenues | 17,693 | | | 10,642 | | | 30,162 | | | 22,119 | |
| COSTS AND EXPENSES | | | | | | | |
| Purchases and related costs | 16,556 | | | 9,758 | | | 28,049 | | | 20,277 | |
| Field operating costs | 328 | | | 286 | | | 628 | | | 585 | |
| General and administrative expenses | 110 | | | 82 | | | 192 | | | 168 | |
| Depreciation and amortization | 242 | | | 235 | | | 486 | | | 466 | |
| Losses on asset sales, asset impairments and other, net | 59 | | | 42 | | | 6 | | | 29 | |
| Total costs and expenses | 17,295 | | | 10,403 | | | 29,361 | | | 21,525 | |
| OPERATING INCOME | 398 | | | 239 | | | 801 | | | 594 | |
| OTHER INCOME/(EXPENSE) | | | | | | | |
| Equity earnings in unconsolidated entities | 89 | | | 94 | | | 178 | | | 196 | |
| Gain on investments in unconsolidated entities, net | — | | | — | | | — | | | 31 | |
Interest expense (net of capitalized interest of $2, $3, $3 and $5, respectively) | (153) | | | (133) | | | (320) | | | (260) | |
| Other income, net | 42 | | | 31 | | | 49 | | | 57 | |
| | | | | | | |
| INCOME FROM CONTINUING OPERATIONS BEFORE TAX | 376 | | | 231 | | | 708 | | | 618 | |
| Current income tax expense from continuing operations | (107) | | | (1) | | | (322) | | | (6) | |
| Deferred income tax (expense)/benefit from continuing operations | 7 | | | (3) | | | 222 | | | (5) | |
| INCOME FROM CONTINUING OPERATIONS, NET OF TAX | 276 | | | 227 | | | 608 | | | 607 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX (NOTE 2) | 1,649 | | | 70 | | | 1,548 | | | 206 | |
| NET INCOME | 1,925 | | | 297 | | | 2,156 | | | 813 | |
| Net income attributable to noncontrolling interests | (95) | | | (87) | | | (173) | | | (160) | |
| NET INCOME ATTRIBUTABLE TO PAA | $ | 1,830 | | | $ | 210 | | | $ | 1,983 | | | $ | 653 | |
| | | | | | | |
NET INCOME PER COMMON UNIT (NOTE 4): | | | | | | | |
| Net income allocated to common unitholders — Basic and Diluted: | | | | | | | |
| Continuing operations | $ | 121 | | | $ | 80 | | | $ | 322 | | | $ | 287 | |
| Discontinued operations | 1,649 | | | 70 | | | 1,548 | | | 206 | |
| Net income allocated to common unitholders — Basic and Diluted | $ | 1,770 | | | $ | 150 | | | $ | 1,870 | | | $ | 493 | |
| | | | | | | |
| Basic and diluted weighted average common units outstanding | 706 | | | 703 | | | 706 | | | 704 | |
| | | | | | | |
| Basic and diluted net income per common unit: | | | | | | | |
| Continuing operations | $ | 0.17 | | | $ | 0.11 | | | $ | 0.46 | | | $ | 0.41 | |
| Discontinued operations | 2.34 | | | 0.10 | | | $ | 2.19 | | | $ | 0.29 | |
| Basic and diluted net income per common unit | $ | 2.51 | | | $ | 0.21 | | | $ | 2.65 | | | $ | 0.70 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
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 COMPREHENSIVE INCOME
(in millions)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
June 30, | | Six Months Ended
June 30, |
| 2026 | | 2025 | | 2026 | | 2025 |
| (unaudited) | | (unaudited) |
| Net income | $ | 1,925 | | | $ | 297 | | | $ | 2,156 | | | $ | 813 | |
| Other comprehensive income/(loss) | (13) | | | 187 | | | (63) | | | 192 | |
| Comprehensive income | 1,912 | | | 484 | | | 2,093 | | | 1,005 | |
Comprehensive income attributable to noncontrolling interests | (95) | | | (87) | | | (173) | | | (160) | |
| Comprehensive income attributable to PAA | $ | 1,817 | | | $ | 397 | | | $ | 1,920 | | | $ | 845 | |
The accompanying notes are an integral part of these condensed consolidated financial statements.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)
(in millions)
| | | | | | | | | | | | | | | | | | | | | | | |
| Derivative
Instruments | | Translation
Adjustments | | Other | | Total |
| (unaudited) |
| Balance at December 31, 2025 | $ | (29) | | | $ | (872) | | | $ | 5 | | | $ | (896) | |
| | | | | | | |
| Reclassification adjustments | 2 | | | — | | | — | | | 2 | |
| | | | | | | |
| Currency translation adjustments | — | | | (60) | | | — | | | (60) | |
| Other | — | | | — | | | (5) | | | (5) | |
| Total period activity | 2 | | | (60) | | | (5) | | | (63) | |
| Balance at June 30, 2026 | $ | (27) | | | $ | (932) | | | $ | — | | | $ | (959) | |
| | | | | | | | | | | | | | | | | | | | | | | |
| 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) | |
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 CASH FLOWS
(in millions)
| | | | | | | | | | | |
| Six Months Ended
June 30, |
| 2026 | | 2025 |
| (unaudited) |
| CASH FLOWS FROM OPERATING ACTIVITIES | | | |
| Net income | $ | 2,156 | | | $ | 813 | |
| Reconciliation of net income to net cash provided by operating activities: | | | |
| Income from discontinued operations, net of tax | (1,548) | | | (206) | |
| Depreciation and amortization | 486 | | | 466 | |
| Losses on asset sales, asset impairments and other, net | 6 | | | 29 | |
| | | |
| | | |
| Deferred income tax expense/(benefit) | (222) | | | 5 | |
| | | |
| (Gain)/loss on foreign currency revaluation | (16) | | | 4 | |
| | | |
| | | |
| Equity earnings in unconsolidated entities | (178) | | | (196) | |
| Distributions on earnings from unconsolidated entities | 204 | | | 256 | |
| Gain on investments in unconsolidated entities, net | — | | | (31) | |
| Other | 27 | | | 32 | |
| Changes in assets and liabilities, net of acquisitions | 299 | | | (140) | |
| Cash provided by operating activities - continuing operations | 1,214 | | | 1,032 | |
| Cash provided by operating activities - discontinued operations | 159 | | | 301 | |
| Net cash provided by operating activities | 1,373 | | | 1,333 | |
| | | |
| CASH FLOWS FROM INVESTING ACTIVITIES | | | |
| Cash paid in connection with acquisitions, net of cash acquired | (130) | | | (681) | |
| | | |
| Additions to property, equipment and other | (268) | | | (310) | |
| Cash paid for purchases of linefill | (12) | | | (17) | |
| | | |
| Proceeds from sales of assets | 4 | | | 21 | |
| | | |
| Cash received from sales of linefill | 37 | | | — | |
| Investments in related party notes | — | | | (330) | |
| Other investing activities | 20 | | | — | |
| Cash used in investing activities - continuing operations | (349) | | | (1,317) | |
| Cash provided by/(used in) investing activities - discontinued operations | 3,451 | | | (106) | |
| Net cash provided by/(used in) investing activities | 3,102 | | | (1,423) | |
| | | |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | |
Net borrowings/(repayments) under commercial paper program (Note 6) | (970) | | | 69 | |
| | | |
| | | |
| | | |
Repayment under term loan (Note 6) | (1,100) | | | — | |
Proceeds from the issuance of senior notes (Note 6) | — | | | 998 | |
| Repayments of senior notes (Note 6) | (750) | | | — | |
| Proceeds from the issuance of related party notes | — | | | 330 | |
| | | |
| Repurchase of common units | — | | | (8) | |
| Repurchase of Series A preferred units | — | | | (333) | |
Distributions paid to Series A preferred unitholders (Note 7) | (72) | | | (82) | |
Distributions paid to Series B preferred unitholders (Note 7) | (33) | | | (35) | |
Distributions paid to common unitholders (Note 7) | (589) | | | (535) | |
Distributions paid to noncontrolling interests (Note 7) | (205) | | | (229) | |
| Contributions from noncontrolling interests | — | | | 29 | |
| | | |
| | | |
| Other financing activities | (9) | | | (22) | |
| | | |
| | | |
| Net cash provided by/(used in) financing activities | (3,728) | | | 182 | |
| | | |
| | | |
| Effect of translation adjustment - continuing operations | (16) | | | 8 | |
| Effect of translation adjustment - discontinued operations | — | | | 11 | |
| | | |
| | | |
| Net increase in cash and cash equivalents and restricted cash | 731 | | | 111 | |
| Cash and cash equivalents and restricted cash, beginning of period | 328 | | | 348 | |
| Cash and cash equivalents and restricted cash, end of period | $ | 1,059 | | | $ | 459 | |
| | | |
| | | |
| Cash paid for: | | | |
| Interest, net of amounts capitalized | $ | 314 | | | $ | 254 | |
| Income taxes, net of amounts refunded | $ | 53 | | | $ | 48 | |
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 PARTNERS’ CAPITAL
(in millions)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Limited Partners | | Partners’
Capital Excluding Noncontrolling Interests | | Noncontrolling Interests | | Total
Partners’
Capital |
| Preferred Unitholders | | Common
Unitholders | | | |
| Series A | | Series B | | | | |
| (unaudited) |
| Balance at December 31, 2025 | $ | 1,248 | | | $ | 787 | | | $ | 7,801 | | | $ | 9,836 | | | $ | 3,244 | | | $ | 13,080 | |
| Net income | 72 | | | 32 | | | 1,879 | | | 1,983 | | | 173 | | | 2,156 | |
| Distributions (Note 7) | (72) | | | (32) | | | (589) | | | (693) | | | (205) | | | (898) | |
| Other comprehensive loss | — | | | — | | | (63) | | | (63) | | | — | | | (63) | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Other | 2 | | | — | | | 14 | | | 16 | | | — | | | 16 | |
| Balance at June 30, 2026 | $ | 1,250 | | | $ | 787 | | | $ | 9,042 | | | $ | 11,079 | | | $ | 3,212 | | | $ | 14,291 | |
| | | | | | | | | | | |
| 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, 2026 | $ | 1,249 | | | $ | 787 | | | $ | 7,565 | | | $ | 9,601 | | | $ | 3,219 | | | $ | 12,820 | |
| Net income | 36 | | | 16 | | | 1,778 | | | 1,830 | | | 95 | | | 1,925 | |
| Distributions (Note 7) | (36) | | | (16) | | | (295) | | | (347) | | | (102) | | | (449) | |
| Other comprehensive loss | — | | | — | | | (13) | | | (13) | | | — | | | (13) | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Other | 1 | | | — | | | 7 | | | 8 | | | — | | | 8 | |
| Balance at June 30, 2026 | $ | 1,250 | | | $ | 787 | | | $ | 9,042 | | | $ | 11,079 | | | $ | 3,212 | | | $ | 14,291 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | (75) | | | (35) | | | (535) | | | (645) | | | (229) | | | (874) | |
| Other comprehensive income | — | | | — | | | 192 | | | 192 | | | — | | | 192 | |
| Repurchase of Series A preferred units | (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 | (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.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 1—Organization and Basis of Consolidation and Presentation
Organization
Plains All American Pipeline, L.P. (“PAA”) is a publicly-traded Delaware limited partnership formed in 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in this Form 10-Q and unless the context indicates otherwise, the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAA and its subsidiaries.
Our business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals. As one of the largest crude oil midstream service providers in North America, we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. Our assets and the services we provide are primarily focused on and conducted through two operating segments: Crude Oil and Natural Gas Liquids (“NGL”). See Note 11 for further discussion of our operating segments.
Our non-economic general partner interest is held by PAA GP LLC (“PAA GP”), a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP, as of June 30, 2026, AAP also owned a limited partner interest in us through its ownership of approximately 233.0 million of our common units (approximately 31% of our total outstanding common units and Series A preferred units combined). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole and managing member of GP LLC, and, at June 30, 2026, owned an approximate 85% limited partner interest in AAP. PAA GP Holdings LLC (“PAGP GP”) is the general partner of PAGP.
As the sole member of GP LLC, PAGP has responsibility for conducting our business and managing our operations; however, the board of directors of PAGP GP has ultimate responsibility for managing the business and affairs of PAGP, AAP and us. GP LLC employs our domestic officers and personnel; our Canadian officers and personnel are employed by our subsidiary, Plains Canada Liquid Pipelines ULC (“PCLP”).
References to our “general partner,” as the context requires, include any or all of PAGP GP, PAGP, GP LLC, AAP and PAA GP. References to “Plains entities,” as the context requires, include us, our subsidiaries and our general partner.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Definitions
Additional defined terms may be used in this Form 10-Q and shall have the meanings indicated below:
| | | | | | | | |
| AOCI | = | Accumulated other comprehensive income/(loss) |
| ASC | = | Accounting Standards Codification |
| ASU | = | Accounting Standards Update |
| | |
| | |
| CAD | = | Canadian dollar |
| CODM | = | Chief Operating Decision Maker |
| EBITDA | = | Earnings before interest, taxes, depreciation and amortization |
| | |
| FASB | = | Financial Accounting Standards Board |
| GAAP | = | Generally accepted accounting principles in the United States |
| ICE | = | Intercontinental Exchange |
| ISDA | = | International Swaps and Derivatives Association |
| | |
| | |
| | |
| | |
| NGL | = | Natural gas liquids, including ethane, propane and butane |
| NYMEX | = | New York Mercantile Exchange |
| | |
| SEC | = | United States Securities and Exchange Commission |
| SOFR | = | Secured Overnight Financing Rate |
| TWh | = | Terawatt hour |
U.S. | = | United States |
USD | = | U.S. dollar |
| | |
Basis of Consolidation and Presentation
The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our 2025 Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of PAA and all of its wholly-owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise.
The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. The condensed consolidated balance sheet data as of December 31, 2025 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three and six months ended June 30, 2026 should not be taken as indicative of results to be expected for the entire year. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany balances and transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications had no impact on net income or total partners’ capital.
On May 12, 2026, we completed the sale of the Canadian NGL Business (as defined and discussed in further detail in Note 2). The operations of the Canadian NGL Business met the criteria for classification as held for sale and for discontinued operations reporting. Accordingly, the balance sheet, results of operations and cash flows of the Canadian NGL Business have been presented as discontinued operations in our condensed consolidated financial statements. Unless otherwise indicated, the disclosures included within the accompanying notes to the condensed consolidated financial statements relate to our continuing operations and exclude amounts related to discontinued operations. Discontinued operations are not presented separately within our Condensed Consolidated Statements of Comprehensive Income, Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss) or the Condensed Consolidated Statements of Changes in Partners’ Capital. Through the date of the sale, all significant intercompany balances and transactions between the Canadian NGL Business and our continuing operations have been eliminated.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Subsequent Events
Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable.
Recent Accounting Pronouncements, Disclosure Rules and Other Legislation
Except as discussed in our 2025 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the six months ended June 30, 2026 that are of significance or potential significance to us.
Note 2—Canadian NGL Business Divestiture and Discontinued Operations
On June 17, 2025, we entered into a definitive Share Purchase Agreement (as amended to date, the “SPA”) with Keyera Corp. (“Keyera”), an Alberta corporation, pursuant to which Keyera agreed to acquire all of the issued and outstanding shares of Plains Midstream Canada ULC (“PMC ULC”), our wholly-owned subsidiary that owned substantially all of our NGL business in Canada (the “Canadian NGL Business”). The transaction closed on May 12, 2026, and, pursuant to the SPA, we received cash consideration of approximately CAD$5.328 billion (approximately $3.883 billion), including estimated working capital and other adjustments, subject to certain post-closing adjustments as defined in the SPA. As part of the sale, we divested the Canadian NGL Business, which included substantially all of our NGL assets; the NGL assets that we retained are located in the United States. The divestiture aligns with management’s strategy to focus on its crude oil operations. Prior to its classification as held for sale and presentation as discontinued operations, the Canadian NGL Business was part of our NGL reportable segment.
In June 2025, we entered into a forward currency instrument to hedge currency exchange risk associated with proceeds from the sale of our Canadian NGL Business. See Note 8 for additional information.
In connection with the closing of the Canadian NGL Business divestiture, we and Keyera entered into certain agreements, including:
•a tax matters agreement that governs our and Keyera’s tax rights and obligations after closing. We have recognized a liability of approximately $62 million related to our obligation to indemnify Keyera against any exposure to certain tax assessments by the Canadian tax authorities against PMC ULC, which is reflected within “Current liabilities of discontinued operations” on our Condensed Consolidated Balance Sheet; and
•an agreement for certain hedging arrangements and payments relating to the differential between the price of natural gas and the extracted NGL commodities (“Frac Spread”) for a twelve-month period commencing the first month after the closing date. As a result of this arrangement, we will guarantee a minimum Frac Spread margin on certain volumes. We have recognized a liability of approximately $15 million for the value of the agreement, based on contracts transferred and market conditions at closing, which is reflected within “Current liabilities of discontinued operations” on our Condensed Consolidated Balance Sheet. This agreement was settled and terminated for $15 million in July 2026.
Additionally, we completed certain planning and restructuring activities within our organizational structure in connection with the Canadian NGL Business divestiture. In the first quarter of 2026, PMC ULC contributed its crude oil assets to a newly formed, wholly-owned subsidiary, PCLP. While this transaction was among entities under common control and recorded at a carry-over basis under GAAP, the applicable Canadian tax law recognizes the transaction at fair value, resulting in a new tax basis to PCLP as of the date of the contribution by PMC ULC. These activities created current tax expense of approximately $311 million as a result of basis recapture and capital gains taxed at the applicable rates and withholding taxes on distributions. This also created a partially offsetting $217 million deferred tax benefit primarily resulting from the new tax basis in the assets received by PCLP for the six months ended June 30, 2026. Since the transaction relates to our crude oil business, the tax impacts are presented in “Current income tax expense from continuing operations” and “Deferred income tax (expense)/benefit from continuing operations,” respectively, on our Condensed Consolidated Statements of Operations. Further, we recorded current income tax expense from discontinued operations of $82 million during the six months ended June 30, 2026. As of June 30, 2026, a related liability of $77 million was included in “Current liabilities of discontinued operations” on our Condensed Consolidated Balance Sheet. Management also determined, based on analysis provided by external tax advisors, that there were no liabilities for uncertain tax positions resulting from the restructuring activities.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
We determined that in conjunction with entering into the SPA, the operations of the Canadian NGL Business met the criteria for classification as held for sale and for discontinued operations reporting, as the sale represented a strategic shift that had a major effect on our operations and financial results. Depreciation and amortization on the long-lived assets of the Canadian NGL Business disposal group ceased upon meeting the criteria to be classified as assets held for sale. The Canadian NGL Business disposal group was recorded at its historical carrying value, as the fair value of the disposal group, less estimated costs to sell, was greater than the carrying value of the Canadian NGL Business disposal group. Upon the completion of the divestiture on May 12, 2026, we derecognized all assets and liabilities of the Canadian NGL Business. We recognized a gain on sale of approximately $1.637 billion and $1.605 billion for the three and six months ended June 30, 2026, respectively, which is reflected within income from discontinued operations.
The following table summarizes the carrying amounts of major classes of assets and liabilities of discontinued operations (in millions):
| | | | | | | | | | | |
| June 30,
2026 | | December 31,
2025 |
Assets: | | | |
| Current assets: | | | |
| | | |
Trade accounts receivable and other receivables, net | $ | — | | | $ | 285 | |
| Inventory | — | | | 176 | |
| Other current assets | — | | | 18 | |
Total current assets of discontinued operations | $ | — | | | $ | 479 | |
| | | |
| Long-term assets: | | | |
Property and equipment, net (1) | $ | — | | | $ | 2,191 | |
| | | |
| Linefill | — | | | 70 | |
| Long-term operating lease right-of-use assets, net | — | | | 138 | |
| Long-term inventory | — | | | 38 | |
| Other long-term assets, net | — | | | 120 | |
Total long-term assets of discontinued operations | $ | — | | | $ | 2,557 | |
| | | |
Liabilities: | | | |
| Current liabilities: | | | |
Trade accounts payable | $ | — | | | $ | 295 | |
| | | |
| Other current liabilities | 154 | | | 87 | |
Total current liabilities of discontinued operations | $ | 154 | | | $ | 382 | |
| | | |
| Long-term liabilities: | | | |
| | | |
| Long-term operating lease liabilities | $ | — | | | $ | 96 | |
| Other long-term liabilities and deferred credits | — | | | 510 | |
Total long-term liabilities of discontinued operations | $ | — | | | $ | 606 | |
(1)Amounts are net of accumulated depreciation of $876 million as of December 31, 2025.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table provides a reconciliation of the line items comprising income from discontinued operations before tax to income from discontinued operations, net of tax (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
June 30, | | Six Months Ended
June 30, |
| 2026 | | 2025 | | 2026 | | 2025 |
Revenues: | | | | | | | |
Product sales | $ | 35 | | | $ | 181 | | | $ | 292 | | | $ | 679 | |
Services | 19 | | | 30 | | | 58 | | | 66 | |
Total revenues | 54 | | | 211 | | | 350 | | | 745 | |
Cost and Expenses: | | | | | | | |
Purchases and related costs | — | | | 10 | | | 205 | | | 252 | |
| Field operating costs | 37 | | | 53 | | | 108 | | | 122 | |
| General and administrative expenses | 3 | | | 12 | | | 17 | | | 26 | |
Depreciation and amortization | — | | | 27 | | | — | | | 57 | |
| (Gains)/losses on asset sales and other, net | (1,637) | | | 13 | | | (1,605) | | | 13 | |
Total costs and expenses | (1,597) | | | 115 | | | (1,275) | | | 470 | |
| | | | | | | |
| Income from discontinued operations before tax | 1,651 | | | 96 | | | 1,625 | | | 275 | |
| Current income tax expense | (71) | | | (14) | | | (115) | | | (54) | |
| Deferred income tax (expense)/benefit | 69 | | | (12) | | | 38 | | | (15) | |
| Income from discontinued operations, net of tax | $ | 1,649 | | | $ | 70 | | | $ | 1,548 | | | $ | 206 | |
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, |
| 2026 | | 2025 | | 2026 | | 2025 |
| Crude Oil segment revenues from contracts with customers | | | | | | | |
| Sales | $ | 17,267 | | | $ | 10,228 | | | $ | 29,278 | | | $ | 21,236 | |
| Transportation | 358 | | | 340 | | | 696 | | | 652 | |
| Terminalling, Storage and Other | 102 | | | 87 | | | 197 | | | 175 | |
| Total Crude Oil segment revenues from contracts with customers | $ | 17,727 | | | $ | 10,655 | | | $ | 30,171 | | | $ | 22,063 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
June 30, | | Six Months Ended
June 30, |
| 2026 | | 2025 | | 2026 | | 2025 |
| NGL segment revenues from contracts with customers | | | | | | | |
| Sales | $ | 22 | | | $ | 24 | | | $ | 59 | | | $ | 66 | |
| | | | | | | |
Terminalling, Storage and Other | — | | | 2 | | | 2 | | | 1 | |
| Total NGL segment revenues from contracts with customers | $ | 22 | | | $ | 26 | | | $ | 61 | | | $ | 67 | |
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 (as described above for each segment) to total revenues of reportable segments and total revenues as disclosed in our Condensed Consolidated Statements of Operations (in millions):
| | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, 2026 | | Crude Oil | | NGL | | Total |
| Revenues from contracts with customers | | $ | 17,727 | | | $ | 22 | | | $ | 17,749 | |
| Other revenues | | 33 | | | — | | | 33 | |
| Total revenues of reportable segments | | $ | 17,760 | | | $ | 22 | | | $ | 17,782 | |
| Intersegment revenues elimination | | | | | | (89) | |
| Total revenues | | | | | | $ | 17,693 | |
| | | | | | |
| 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 | |
| | | | | | |
| Six Months Ended June 30, 2026 | | Crude Oil | | NGL | | Total |
| Revenues from contracts with customers | | $ | 30,171 | | | $ | 61 | | | $ | 30,232 | |
Other revenues | | 138 | | | — | | | 138 | |
| Total revenues of reportable segments | | $ | 30,309 | | | $ | 61 | | | $ | 30,370 | |
Intersegment revenues elimination | | | | | | (208) | |
| Total revenues | | | | | | $ | 30,162 | |
| | | | | | |
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | |
| 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 | |
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,
2026 | | December 31,
2025 |
| Billed and collected | | Other current liabilities | | $ | 16 | | | $ | 47 | |
| | | | | | |
| | | | | | |
Contract Balances. Our contract balances consist of amounts received associated with services or sales for which we have not yet completed the related performance obligation. The following table presents the changes in the liability balance associated with contracts with customers (in millions):
| | | | | | | | |
| | Contract Liabilities |
| Balance at December 31, 2025 | | $ | 87 | |
| Amounts recognized as revenue | | (22) | |
| | |
| Additions | | 4 | |
Other (1) | | (24) | |
| Balance at June 30, 2026 | | $ | 45 | |
(1)Amount represents a contract liability that was originally recognized under ASC 606. The underlying contract was subsequently renegotiated and ceased to meet the criteria in ASC 606 for a contract with a customer.
Remaining Performance Obligations. The information below includes the amount of consideration allocated to partially and wholly unsatisfied remaining performance obligations under contracts that existed as of the end of the periods and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These contracts include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of June 30, 2026 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Remainder of 2026 | | 2027 | | 2028 | | 2029 | | 2030 | | 2031 and Thereafter |
Pipeline revenues supported by minimum volume commitments and capacity agreements (1) | $ | 208 | | | $ | 392 | | | $ | 342 | | | $ | 237 | | | $ | 154 | | | $ | 848 | |
| Terminalling, storage and other agreement revenues | 124 | | | 218 | | | 158 | | | 113 | | | 75 | | | 426 | |
| Total | $ | 332 | | | $ | 610 | | | $ | 500 | | | $ | 350 | | | $ | 229 | | | $ | 1,274 | |
(1)Calculated as volumes committed under contracts multiplied by the current applicable tariff rate.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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, 2026 and December 31, 2025, substantially all of our trade accounts receivable were less than 30 days past their invoice date. Our expected credit losses are immaterial. Although we consider our credit procedures to be adequate to mitigate any significant credit losses, the actual amount of current and future credit losses could vary significantly from estimated amounts.
The following is a reconciliation of trade accounts receivable from revenues from contracts with customers to total “Trade accounts receivable and other receivables, net” as presented on our Condensed Consolidated Balance Sheets (in millions):
| | | | | | | | | | | |
| June 30,
2026 | | December 31,
2025 |
Trade accounts receivable arising from revenues from contracts with customers | $ | 5,135 | | | $ | 3,639 | |
Other trade accounts receivable and other receivables (1) | 11,077 | | | 7,357 | |
| Impact due to contractual rights of offset with counterparties | (10,945) | | | (7,398) | |
| Trade accounts receivable and other receivables, net | $ | 5,267 | | | $ | 3,598 | |
(1)The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of ASC 606.
Note 4—Net Income Per Common Unit
We calculate basic and diluted net income per common unit by dividing income from continuing operations attributable to PAA (after deducting amounts allocated to the preferred unitholders and participating securities) and income or loss from discontinued operations by the basic and diluted weighted average number of common units outstanding during the period.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units and (ii) our equity-indexed compensation plan awards. See Note 12 and Note 18 to our Consolidated Financial Statements included in Part IV of our 2025 Annual Report on Form 10-K for a discussion of our Series A preferred units and equity-indexed compensation plan awards. When applying the if-converted method prescribed by FASB guidance, on a weighted average basis, for each of the three and six months ended June 30, 2026, the possible conversion of approximately 58 million Series A preferred units and 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, 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.
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, |
| 2026 | | 2025 | | 2026 | | 2025 |
| Basic and Diluted Net Income per Common Unit | | | | | | | |
Continuing Operations: | | | | | | | |
Income from continuing operations, net of tax | $ | 276 | | | $ | 227 | | | $ | 608 | | | $ | 607 | |
Net income attributable to noncontrolling interests | (95) | | | (87) | | | (173) | | | (160) | |
Net income from continuing operations attributable to PAA | 181 | | | 140 | | | 435 | | | 447 | |
Distributions to Series A preferred unitholders | (36) | | | (36) | | | (72) | | | (75) | |
Distributions to Series B preferred unitholders | (16) | | | (18) | | | (32) | | | (35) | |
| Amounts allocated to participating securities | (9) | | | (7) | | | (11) | | | (9) | |
Impact from repurchase of Series A preferred units (1) | — | | | — | | | — | | | (43) | |
Other | 1 | | | 1 | | | 2 | | | 2 | |
Net income from continuing operations allocated to common unitholders - Basic and Diluted (2) | $ | 121 | | | $ | 80 | | | $ | 322 | | | $ | 287 | |
| | | | | | | |
Discontinued Operations: | | | | | | | |
Net income from discontinued operations allocated to common unitholders - Basic and Diluted (3) | $ | 1,649 | | | $ | 70 | | | $ | 1,548 | | | $ | 206 | |
| | | | | | | |
Net income allocated to common unitholders — Basic and Diluted | $ | 1,770 | | | $ | 150 | | | $ | 1,870 | | | $ | 493 | |
| | | | | | | |
| Basic and diluted weighted average common units outstanding | 706 | | | 703 | | | 706 | | | 704 | |
| | | | | | | |
| Basic and diluted net income per common unit: | | | | | | | |
| Continuing operations | $ | 0.17 | | | $ | 0.11 | | | $ | 0.46 | | | $ | 0.41 | |
| Discontinued operations | 2.34 | | | 0.10 | | | 2.19 | | | 0.29 | |
| Basic and diluted net income per common unit | $ | 2.51 | | | $ | 0.21 | | | $ | 2.65 | | | $ | 0.70 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(1)We repurchased approximately 12.7 million Series A preferred units on January 31, 2025. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2025 Annual Report on Form 10-K for additional information. The difference between the cash we paid for the repurchase of such units and their carrying value on our balance sheet is considered a return to Series A preferred unitholders for the calculation of net income from continuing operations allocated to common unitholders.
(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.
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, 2026 | | | December 31, 2025 |
| Volumes | | Unit of
Measure | | Carrying
Value | | Price/ Unit (1) | | | Volumes | | Unit of
Measure | | Carrying
Value | | Price/ Unit (1) |
| Inventory | | | | | | | | | | | | | | | | |
| Crude oil | 722 | | | barrels | | $ | 52 | | | $ | 72.02 | | | | 2,948 | | | barrels | | $ | 166 | | | $ | 56.31 | |
| NGL | 333 | | | barrels | | 17 | | | $ | 51.05 | | | | 562 | | | barrels | | 27 | | | $ | 48.04 | |
| | | | | | | | | | | | | | | | |
| Other | N/A | | | | 15 | | | N/A | | | N/A | | | | 18 | | | N/A |
| Inventory subtotal | | | | | 84 | | | | | | | | | | 211 | | | |
| | | | | | | | | | | | | | | | |
| Linefill | | | | | | | | | | | | | | | | |
| Crude oil | 14,975 | | | barrels | | 891 | | | $ | 59.50 | | | | 15,112 | | | barrels | | 898 | | | $ | 59.42 | |
| NGL | 32 | | | barrels | | 1 | | | $ | 31.25 | | | | 33 | | | barrels | | 2 | | | $ | 60.61 | |
| | | | | | | | | | | | | | | | |
| Linefill subtotal | | | | | 892 | | | | | | | | | | 900 | | | |
| | | | | | | | | | | | | | | | |
| Long-term inventory | | | | | | | | | | | | | | | | |
| Crude oil | 3,647 | | | barrels | | 255 | | | $ | 69.92 | | | | 3,724 | | | barrels | | 213 | | | $ | 57.20 | |
| NGL | 51 | | | barrels | | 2 | | | $ | 39.22 | | | | 26 | | | barrels | | 1 | | | $ | 38.46 | |
| Long-term inventory subtotal | | | | | 257 | | | | | | | | | | 214 | | | |
| | | | | | | | | | | | | | | | |
| Total | | | | | $ | 1,233 | | | | | | | | | | $ | 1,325 | | | |
(1)Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products.
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,
2026 | | December 31,
2025 |
| SHORT-TERM DEBT | | | |
Commercial paper notes, bearing a weighted-average interest rate of 3.9% (1) | $ | — | | | $ | 554 | |
| | | |
| | | |
| | | |
| Other | 9 | | | 9 | |
| Total short-term debt | 9 | | | 563 | |
| | | |
| LONG-TERM DEBT | | | |
Senior notes, net of unamortized discounts and debt issuance costs of $60 and $65, respectively (2) | 8,373 | | | 9,118 | |
Commercial paper notes, bearing a weighted-average interest rate of 3.9% (3) | — | | | 416 | |
Term loan, net of debt issuance costs of $1, and bearing a weighted-average interest rate of 5.0% | — | | | 1,099 | |
| Other | 59 | | | 63 | |
| Total long-term debt | 8,432 | | | 10,696 | |
Total debt (4) | $ | 8,441 | | | $ | 11,259 | |
(1)We classified these commercial paper notes as short-term as of December 31, 2025, as these notes were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged inventory and NYMEX and ICE margin deposits.
(2)As of December 31, 2025, we classified our $750 million, 4.50% senior notes due December 2026 as long-term based on our ability and intent to refinance the notes on a long-term basis at that time. We redeemed these senior notes on June 25, 2026.
(3)As of December 31, 2025, we classified a portion of our commercial paper notes as long-term based on our ability and intent to refinance such amounts on a long-term basis.
(4)Our fixed-rate senior notes had a face value of approximately $8.4 billion and $9.2 billion at June 30, 2026 and December 31, 2025, respectively. We estimated the aggregate fair value of these notes as of June 30, 2026 and December 31, 2025 to be approximately $8.2 billion and $9.0 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under our commercial paper program and our term loan approximate fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, commercial paper program and term loan are based upon observable market data and are classified in Level 2 of the fair value hierarchy.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Credit Agreements
In June 2026, we entered into a new credit agreement that provides for a senior unsecured revolving credit facility with a committed borrowing capacity of $2.7 billion, of which $800 million is available for the issuance of letters of credit and $225 million is available for the swing line loans. The new credit agreement replaced our previous credit agreements that provided for a $1.35 billion senior secured hedged inventory facility and a $1.35 billion senior unsecured revolving credit facility, which were scheduled to mature in August 2027 and August 2029, respectively. Subject to obtaining additional or increased lender commitments and other terms and conditions, the committed capacity may be increased to $4.0 billion. Borrowings accrue interest based, at our selection, on certain floating rate indices, in each case, plus an applicable margin. The new credit agreement has an initial maturity date of June 2031 and provides for one or more one-year extensions, subject to applicable approval and other terms and conditions. The covenants and events of default under this new credit agreement remain substantially unchanged from the previous agreements.
In conjunction with the closing of the new credit agreement in June 2026, we repaid in full and terminated all outstanding obligations under our $1.35 billion senior secured hedged inventory facility and $1.35 billion senior unsecured revolving credit facility. See Note 11 to our Consolidated Financial Statements included in Part IV of our 2025 Annual Report on Form 10-K for additional information regarding these agreements.
Term Loan Agreement
On November 26, 2025, we entered into a term loan agreement that provided for a $1.1 billion senior unsecured term loan. The closing of the Canadian NGL Business divestiture triggered mandatory prepayment of all amounts outstanding under the term loan agreement. See Note 2 for additional information about the Canadian NGL Business divestiture. Effective May 14, 2026, we terminated the term loan agreement and repaid all amounts outstanding thereunder.
Senior Notes
On June 25, 2026, we redeemed our $750 million, 4.50% senior notes that were due December 2026. We repaid these senior notes with proceeds from the sale of the Canadian NGL Business.
Borrowings and Repayments
Total borrowings under our credit facilities and commercial paper program for the six months ended June 30, 2026 and 2025 were approximately $37.1 billion and $27.6 billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately $38.1 billion and $27.5 billion for the six months ended June 30, 2026 and 2025, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.
Letters of Credit
In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At June 30, 2026 and December 31, 2025, we had outstanding letters of credit of $63 million and $95 million, respectively.
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, 2025 | 58,411,908 | | | 800,000 | | | 705,520,697 | |
| | | | | |
| Issuances of common units under equity-indexed compensation plans | — | | | — | | | 10,986 | |
Outstanding at March 31, 2026 | 58,411,908 | | | 800,000 | | | 705,531,683 | |
| | | | | |
| Issuances of common units under equity-indexed compensation plans | — | | | — | | | 34,777 | |
| Outstanding at June 30, 2026 | 58,411,908 | | | 800,000 | | | 705,566,460 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | | | | | | | | | | | | | |
| 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 | |
| | | | | |
| | | | | |
| | | | | |
Distributions to Our Unitholders
Series A Preferred Unit Distributions. Distributions on the Series A preferred units accumulate and are payable quarterly within 45 days following the end of each quarter. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2025 Annual Report on Form 10-K for additional information regarding Series A preferred unit distributions. The following table details distributions to our Series A preferred unitholders paid during or pertaining to the first six months of 2026 (in millions, except per unit data):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Series A Preferred Unitholders |
| Distribution Payment Date | | Record Date (1) | | Distribution Period | | Cash Distribution | | | Distribution per Unit |
| | | | | | | | | |
August 14, 2026 (2) | | July 31, 2026 | | April 1, 2026 through June 30, 2026 | | $ | 36 | | | | $ | 0.615 | |
| May 15, 2026 | | May 1, 2026 | | January 1, 2026 through March 31, 2026 | | $ | 36 | | | | $ | 0.615 | |
| February 13, 2026 | | January 30, 2026 | | October 1, 2025 through December 31, 2025 | | $ | 36 | | | | $ | 0.615 | |
(1)Payable to unitholders of record at the close of business on the applicable Record Date.
(2)At June 30, 2026, such amount was accrued as distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Series B Preferred Unit Distributions. Distributions on the Series B preferred units accumulate and are payable quarterly in arrears on the 15th day of February, May, August and November (or the immediately succeeding Business Day). See Note 12 to our Consolidated Financial Statements included in Part IV of our 2025 Annual Report on Form 10-K for additional information regarding Series B preferred unit distributions. The following table details distributions paid or to be paid to our Series B preferred unitholders (in millions, except per unit data):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Series B Preferred Unitholders |
| Distribution Payment Date | | Record Date (1) | | Distribution Period | | Cash Distribution | | | Distribution per Unit |
| | | | | | | | | |
August 17, 2026 (2) | | August 3, 2026 | | May 15, 2026 through August 14, 2026 | | $ | 16 | | | | $ | 20.50 | |
| May 15, 2026 | | May 1, 2026 | | February 15, 2026 through May 14, 2026 | | $ | 16 | | | | $ | 19.84 | |
| February 17, 2026 | | February 2, 2026 | | November 15, 2025 through February 14, 2026 | | $ | 17 | | | | $ | 21.02 | |
(1)Payable to unitholders of record at the close of business on the applicable Record Date.
(2)At June 30, 2026, approximately $8 million of accrued distributions payable to our Series B preferred unitholders was included in “Other current liabilities” on our Condensed Consolidated Balance Sheet.
Common Unit Distributions. The following table details distributions to our common unitholders paid during or pertaining to the first six months of 2026 (in millions, except per unit data):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Distributions | | | Distribution per Common Unit |
| Distribution Payment Date | | Record Date (1) | | Distribution Period | | Common Unitholders | | Total Cash Distribution | | |
| | | Public | | AAP | | | |
| | | | | | | | | | | | | |
| August 14, 2026 | | July 31, 2026 | | April 1, 2026 through June 30, 2026 | | $ | 198 | | | $ | 97 | | | $ | 295 | | | | $ | 0.4175 | |
| May 15, 2026 | | May 1, 2026 | | January 1, 2026 through March 31, 2026 | | $ | 198 | | | $ | 97 | | | $ | 295 | | | | $ | 0.4175 | |
| February 13, 2026 | | January 30, 2026 | | October 1, 2025 through December 31, 2025 | | $ | 198 | | | $ | 97 | | | $ | 295 | | | | $ | 0.4175 | |
(1)Payable to unitholders of record at the close of business on the applicable Record Date.
Noncontrolling Interests in Subsidiaries
As of June 30, 2026, noncontrolling interests in our subsidiaries consisted of (i) a 35% interest in Plains Oryx Permian Basin LLC (the “Permian JV”), (ii) a 30% interest in Cactus II Pipeline LLC (“Cactus II”) and (iii) a 33% interest in Red River Pipeline Company LLC (“Red River”).
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, |
| 2026 | | 2025 | | 2026 | | 2025 |
| Permian JV | $ | 81 | | | $ | 78 | | | $ | 165 | | | $ | 183 | |
Cactus II | 17 | | | 16 | | | 32 | | | 38 | |
| Red River | 4 | | | 3 | | | 8 | | | 8 | |
| $ | 102 | | | $ | 97 | | | $ | 205 | | | $ | 229 | |
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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, 2026 and December 31, 2025, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our exchange-traded derivatives transacted through a clearing brokerage account, as described below, we do not require our non-cleared derivative counterparties to post collateral with us.
Commodity Price Risk Hedging
Our core business activities involve certain commodity price-related risks that we manage in various ways, including through the use of derivative instruments. Our policy is to (i) only purchase inventory for which we have a sales market, (ii) structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold material physical inventory or derivatives for the purpose of speculating on commodity price changes. The material commodity-related risks inherent in our business activities are described below.
In the normal course of our operations, we purchase and sell commodities. We use derivatives to manage the associated risks and, in certain circumstances, to optimize profits. As of June 30, 2026, net derivative positions related to these activities included:
•A net long position of 8.1 million barrels associated with our crude oil purchases, which will be unwound ratably through September 2026 to match monthly average pricing.
•A net short time spread position of 2.1 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through October 2026.
•A net crude oil basis spread position of 2.6 million barrels at multiple locations through March 2027. These derivatives allow us to lock in grade and location basis differentials.
•A net short position of 7.8 million barrels through December 2027 related to anticipated net sales of crude oil inventory.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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, |
| 2026 | | 2025 | | 2026 | | 2025 |
| Product sales revenues | $ | 17 | | | $ | (40) | | | $ | 105 | | | $ | (41) | |
| Field operating costs | — | | | 5 | | | 2 | | | 3 | |
| | | | | | | |
| Net income/(loss) from commodity derivative activity | $ | 17 | | | $ | (35) | | | $ | 107 | | | $ | (38) | |
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,
2026 | | December 31,
2025 |
| Initial margin | $ | 31 | | | $ | 16 | |
Variation margin posted | 31 | | | 4 | |
Letters of credit | (29) | | | (1) | |
| Net broker receivable | $ | 33 | | | $ | 19 | |
The following table reflects the Condensed Consolidated Balance Sheet line items that include the fair values of our commodity derivative assets and liabilities and the effect of the collateral netting. Such amounts are presented on a gross basis, before the effects of counterparty netting. However, we have elected to present our commodity derivative assets and liabilities with the same counterparty on a net basis on our Condensed Consolidated Balance Sheet when the legal right of offset exists. Amounts in the table below are presented in millions.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2026 | | | December 31, 2025 |
| | | | | | Effect of Collateral Netting | | Net Carrying Value Presented on the Balance Sheet | | | | | | | Effect of Collateral Netting | | Net Carrying Value Presented on the Balance Sheet |
| | Commodity Derivatives | | | | | Commodity Derivatives | | |
| | Assets | | Liabilities | | | | | Assets | | Liabilities | | |
| Derivative Assets | | | | | | | | | | | | | | | | | |
| Other current assets | | $ | 20 | | | $ | (12) | | | $ | (7) | | | $ | 1 | | | | $ | 18 | | | $ | (24) | | | $ | 19 | | | $ | 13 | |
| Other long-term assets, net | | 11 | | | (3) | | | — | | | 8 | | | | 1 | | | — | | | — | | | 1 | |
| Derivative Liabilities | | | | | | | | | | | | | | | | | |
| Other current liabilities | | 28 | | | (87) | | | 40 | | | (19) | | | | (1) | | | — | | | — | | | (1) | |
| Other long-term liabilities and deferred credits | | — | | | — | | | — | | | — | | | | 10 | | | (8) | | | — | | | 2 | |
| Total | | $ | 59 | | | $ | (102) | | | $ | 33 | | | $ | (10) | | | | $ | 28 | | | $ | (32) | | | $ | 19 | | | $ | 15 | |
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Interest Rate Risk Hedging
We use interest rate derivatives to hedge the benchmark interest rate associated with interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist of forward starting interest rate swaps and treasury locks. These derivatives are designated as cash flow hedges. As such, changes in fair value are deferred in AOCI and are reclassified to interest expense as we incur the interest expense associated with the underlying debt.
As of June 30, 2026, there was a net loss of $27 million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with interest expense accruals associated with underlying debt instruments. We estimate that substantially all of the remaining deferred loss will be reclassified to earnings through 2056 as the underlying hedged transactions impact earnings.
The following table summarizes the net unrealized gain recognized in AOCI for derivatives (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
June 30, | | Six Months Ended
June 30, |
| 2026 | | 2025 | | 2026 | | 2025 |
| Interest rate derivatives, net | $ | — | | | $ | 7 | | | $ | — | | | $ | 6 | |
At June 30, 2026 and December 31, 2025, we did not have any interest rate hedges recorded on our Condensed Consolidated Balance Sheets.
Currency Exchange Rate Risk Hedging
In connection with the Canadian NGL Business divestiture, we entered into a forward currency instrument (CAD$4.5 billion notional amount) to hedge currency exchange risk. The instrument was contingent upon the sale of the Canadian NGL Business occurring and settled at closing. The cost of the deal-contingent structure was embedded in the hedge rate. We settled this instrument and received net cash proceeds of $20 million at the closing of the Canadian NGL Business divestiture. As of December 31, 2025, the fair value of the instrument was an asset of $8 million, presented in “Other current assets” on our Condensed Consolidated Balance Sheet. For the three and six months ended June 30, 2026, we recognized a loss of $41 million and a gain of $12 million, respectively, which were included in “Losses on asset sales, asset impairments and other, net” on our Condensed Consolidated Statements of Operations. For each of the three and six months ended June 30, 2025, we recognized a loss of $49 million. See Note 2 for additional information regarding the Canadian NGL Business divestiture.
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, 2026 | | | Fair Value as of December 31, 2025 |
Recurring Fair Value Measures (1) | | Level 1 | | Level 2 | | | | Total | | | Level 1 | | Level 2 | | | | Total |
| Commodity derivatives | | $ | (50) | | | $ | 7 | | | | | $ | (43) | | | | $ | (2) | | | $ | (2) | | | | | $ | (4) | |
| | | | | | | | | | | | | | | | | |
| Foreign currency derivatives | | — | | | — | | | | | — | | | | — | | | 8 | | | | | 8 | |
| | | | | | | | | | | | | | | | | |
| Total net derivative asset/(liability) | | $ | (50) | | | $ | 7 | | | | | $ | (43) | | | | $ | (2) | | | $ | 6 | | | | | $ | 4 | |
(1)Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.
Level 1
Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives and over-the-counter commodity contracts such as futures and swaps. The fair value of exchange-traded commodity derivatives and over-the-counter commodity contracts is based on unadjusted quoted prices in active markets.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Level 2
Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives, over-the-counter commodity, foreign exchange and interest rate derivatives that are traded in observable markets with less volume and transaction frequency than active markets. In addition, it includes certain physical commodity contracts. The fair values of these derivatives are corroborated with market observable inputs.
Note 9—Related Party Transactions
See Note 17 to our Consolidated Financial Statements included in Part IV of our 2025 Annual Report on Form 10-K for a complete discussion of related parties, including the determination of our related parties and nature of involvement with such related parties.
Promissory Notes with our General Partner
We and certain Plains entities have issued promissory notes to facilitate financing. During the second quarter of 2026, we and certain Plains entities effectively settled promissory notes with a total face value of CAD$500 million (approximately $366 million) through a non-cash transaction upon the close of the Canadian NGL Business divestiture. See Note 2 for additional information about the Canadian NGL Business divestiture. Our outstanding related party notes receivable and related party notes payable balances were as follows (in millions):
| | | | | | | | | | | |
| June 30,
2026 | | December 31,
2025 |
Related party notes receivable (1) | $ | 942 | | | $ | 1,339 | |
Related party notes payable (1) | $ | 942 | | | $ | 1,339 | |
(1)We have elected to present our related party notes with the same counterparty on a net basis on our Condensed Consolidated Balance Sheets because there is a legal right to offset and we intend to offset with the counterparty.
Accrued and unpaid interest receivable/payable was $8 million and $30 million as of June 30, 2026 and December 31, 2025, respectively. Interest income/expense on the related party notes totaled $18 million, and $41 million for the three and six months ended June 30, 2026, respectively, and $23 million and $43 million for the three and six months ended June 30, 2025, respectively.
Transactions with Other Related Parties
During the three and six months ended June 30, 2026 and 2025, we recognized sales and transportation revenues, purchased petroleum products and utilized transportation and storage services from related parties. These transactions were conducted at posted tariff rates or prices that we believe approximate market.
The impact to our Condensed Consolidated Statements of Operations from these transactions is included below (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
June 30, | | Six Months Ended
June 30, |
| 2026 | | 2025 | | 2026 | | 2025 |
| Revenues from related parties | $ | 13 | | | $ | 12 | | | $ | 26 | | | $ | 23 | |
| | | | | | | |
| Purchases and related costs from related parties | $ | 80 | | | $ | 98 | | | $ | 154 | | | $ | 196 | |
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Our receivable and payable amounts with these related parties as reflected on our Condensed Consolidated Balance Sheets were as follows (in millions):
| | | | | | | | | | | |
| June 30,
2026 | | December 31,
2025 |
Trade accounts receivable and other receivables, net from related parties (1) | $ | 33 | | | $ | 49 | |
| | | |
Trade accounts payable to related parties (1) (2) | $ | 50 | | | $ | 64 | |
| | | |
| | | |
| | | |
(1)Primarily includes amounts related to transportation and storage services.
(2)We have agreements to store crude oil at facilities and transport crude oil or utilize capacity on pipelines that are owned by equity method investees. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities.
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.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Environmental — General
We currently own or lease, and in the past have owned and leased, properties where hazardous liquids, including hydrocarbons, are or have been handled. These properties and the hazardous liquids or associated wastes disposed thereon may be subject to the U.S. federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, and the U.S. federal Resource Conservation and Recovery Act, as amended, as well as state and Canadian federal and provincial laws and regulations. Under such laws and regulations, we could be required to remove or remediate hazardous liquids or associated wastes (including wastes disposed of or released by prior owners or operators) and to clean up contaminated property (including contaminated groundwater). Assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified or insured.
Although we have made significant investments in our maintenance and integrity programs, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail, storage and other facility operations. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. We also may discover environmental impacts from past releases that were previously unidentified. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated. Generally, our recording of these liabilities coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. We record receivables for amounts we believe are recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery.
Environmental expenditures that pertain to current operations or to future revenues are expensed or capitalized consistent with our capitalization policy for property and equipment. Expenditures that result from the remediation of an existing condition caused by past operations and that do not contribute to current or future profitability are expensed.
Our estimated undiscounted reserves for environmental liabilities (excluding liabilities related to the Line 901 incident, as discussed further below) were reflected on our Condensed Consolidated Balance Sheets as follows (in millions):
| | | | | | | | | | | |
| June 30,
2026 | | December 31,
2025 |
| Other current liabilities | $ | 40 | | | $ | 13 | |
| Other long-term liabilities and deferred credits | 70 | | | 70 | |
| Total | $ | 110 | | | $ | 83 | |
In some cases, the actual cash expenditures associated with these liabilities may not occur for several years. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing or future legal claims giving rise to additional liabilities. Therefore, although we believe that our reserves are adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of such reserves and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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, 2026, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $870 million, which includes actual emergency response and clean-up costs, natural resource damage assessments, fines and penalties incurred, certain third-party claims settlements, and estimated costs associated with our remaining Line 901 lawsuits and claims as described below, as well as estimates for certain legal fees and statutory interest where applicable. We accrue such estimates of aggregate total costs to “Field operating costs” in our Condensed Consolidated Statements of Operations. This estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the resolution of certain third-party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and (ii) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. Our estimate does not include any lost revenue associated with the shutdown of Line 901 or 903 and does not include any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, with respect to potential losses that we regard as only reasonably possible or remote, we have made assumptions regarding the strength of our legal position based on our assessment of the relevant facts and applicable law and precedent; if our assumptions regarding such matters turn out to be inaccurate (i.e., we are found to be liable under circumstances where we regard the likelihood of loss as being only reasonably possible or remote), we could be responsible for significant costs and expenses that are not currently included in our estimates and accruals. In addition, for any potential losses that we regard as probable and for which we have accrued an estimate of the potential losses, our estimates regarding damages, legal fees, court costs and interest could turn out to be inaccurate and the actual losses we incur could be significantly higher than the amounts included in our estimates and accruals. Also, the amount of time it takes for us to resolve all of the current and future lawsuits and claims that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated.
During the six months ended June 30, 2026 and 2025, we did not recognize any costs related to the Line 901 incident. As of June 30, 2026 and December 31, 2025, we had a remaining undiscounted gross liability of approximately $23 million and $22 million, respectively, related to the Line 901 incident, which aggregate amounts are reflected in “Current liabilities” on our Condensed Consolidated Balance Sheet.
We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such liabilities. To date, we have collected approximately $295 million of the $500 million available under our 2015 insurance program. With respect to the Line 901 incident, we do not have any amounts recorded as receivables that are recognized on our Condensed Consolidated Balance Sheets as of June 30, 2026 and December 31, 2025.
We have completed the required clean-up and remediation work with respect to the Line 901 incident; however, we expect to make payments for additional legal and professional costs during future periods. The only remaining Line 901 lawsuit is pending in California Superior Court in Santa Barbara County, in which a landowner on an adjacent pipeline is alleging property damage from the “stigma” of the Line 901 incident. We are vigorously defending this lawsuit, which has not yet been set for trial, and believe we have strong defenses. Taking into account the costs that we have included in our total estimate of costs for the Line 901 incident and considering what we regard as very strong defenses to the claims made in our remaining Line 901 lawsuits, we do not believe the ultimate resolution of such remaining lawsuit will have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
L48 Pipeline Release. In March 2025, our subsidiary, Pacific Pipeline System LLC, experienced a crude oil release of approximately 125 barrels on a segment of the Line 48 pipeline in Carson, California. Clean-up and remediation activities were conducted in cooperation with applicable state and federal regulatory agencies. An investigation by the California Office of the State Fire Marshall was initiated. To date no charges, fines or penalties have been assessed against us with respect to this release; however, it is possible that charges, fines or penalties may be assessed against us in the future. We provided notification to our applicable insurance carriers and are subject to a $10 million self-insured retention. Through June 30, 2026, we incurred $13 million in connection with clean-up and remediation activities. We do not currently anticipate any additional costs associated with the site.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Line 63 Pipeline Strike. In May 2026, our subsidiary, Pacific Pipeline System LLC, experienced a crude oil release of approximately 585 barrels on a segment of the Line 63 pipeline in Los Angeles, California, resulting from a strike by a construction crew drilling for a fiber-optic line. Clean-up and remediation activities were conducted in cooperation with applicable state and federal regulatory agencies. Investigations were initiated by the California Office of the State Fire Marshall and the California Underground Safety Board. To date no charges, fines or penalties have been assessed against us with respect to this release; however, it is possible that charges, fines or penalties may be assessed against us in the future. We provided notification to our applicable insurance carriers and are subject to a $10 million self-insured retention. We estimate that the aggregate cost to clean-up and remediate the site will be approximately $40 million.
Canadian Competition Bureau Lawsuit. In connection with the closing of the sale of our Canadian NGL Business to Keyera, on May 5, 2026, the Canadian Commissioner of Competition (“Commissioner”) filed a lawsuit against Keyera, PMC ULC and Plains challenging the transaction on the basis that it allegedly harms competition in the NGL fractionation and storage market at Fort Saskatchewan. Because the lawsuit did not prevent the parties from closing, Keyera and Plains closed the transaction on May 12, 2026. In its lawsuit, the Commissioner seeks remedies that it believes would restore competition at Fort Saskatchewan to pre-transaction levels. As the owner of PMC ULC and the Canadian NGL Business, Keyera is primarily responsible for the lawsuit and we do not believe the ultimate resolution of the lawsuit will have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
Note 11—Segment Information
Our operating segments, Crude Oil and NGL, which are also our reportable segments, are organized by product as our Crude Oil and NGL businesses are generally impacted by different market fundamentals and require the use of different assets and business strategies. The Crude Oil segment includes our crude oil pipelines, crude oil storage and marine terminals and related crude oil marketing activities. Our crude oil marketing activities are included in our Crude Oil reporting segment as its primary purpose is to support the utilization of our assets by entering into transactions that facilitate increased volumes handled by our assets, resulting in additional earnings for the segment. The NGL segment includes our NGL assets located in the United States.
Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below). The measure of Segment Adjusted EBITDA forms the basis of our internal financial reporting and is the primary performance measure of segment profit/(loss) used by our CODM in assessing performance and allocating resources among our operating segments. We define Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) significant segment expenses including: (i) purchases and related costs, (ii) field operating costs and (iii) segment general and administrative expenses, plus (b) our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities, further adjusted (c) for certain selected items including (i) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance and (d) to exclude the portion of all preceding items that is attributable to noncontrolling interests (“Segment amounts attributable to noncontrolling interests”).
Our CODM uses Segment Adjusted EBITDA to evaluate the performance of each segment, including analyzing actual results compared to budget and guidance, to assess investment opportunities and to optimize and align assets to maximize returns to stakeholders.
Segment Adjusted EBITDA excludes depreciation and amortization. As an MLP, we make quarterly distributions of our “available cash” (as defined in our partnership agreement) to our unitholders. We look at each period’s earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of Segment Adjusted EBITDA as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as pipelines and facilities, caused by age-related decline and wear and tear. We compensate for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance investments, which act to partially offset the aging and wear and tear in the value of our principal fixed assets. These maintenance investments are a component of field operating costs included in Segment Adjusted EBITDA or in maintenance capital, depending on the nature of the cost. Capital expenditures made to
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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.
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, 2026 | | | | | | | | |
Revenues (1): | | | | | | | | |
| Product sales | $ | 17,290 | | | $ | 20 | | | $ | (89) | | | $ | 17,221 | | |
| Services | 470 | | | 2 | | | — | | | 472 | | |
| Total revenues | 17,760 | | | 22 | | | (89) | | | 17,693 | | |
| | | | | | | | |
Significant segment expenses: | | | | | | | | |
Purchases and related costs (1) | (16,632) | | | (13) | | | 89 | | | (16,556) | | |
Field operating costs | (325) | | | (3) | | | — | | | (328) | | |
Segment general and administrative expenses | (108) | | | (2) | | | — | | | (110) | | |
Total significant segment expenses | (17,065) | | | (18) | | | 89 | | | (16,994) | | |
| | | | | | | | |
| Equity earnings in unconsolidated entities | 89 | | | — | | | | | | |
| | | | | | | | |
Other segment items (2): | | | | | | | | |
Depreciation and amortization of unconsolidated entities (3) | 21 | | | — | | | | | | |
Derivative activities and inventory valuation adjustments (4) | (74) | | | — | | | | | | |
Long-term inventory costing adjustments (5) | 67 | | | — | | | | | | |
Deficiencies under minimum volume commitments, net (6) | (4) | | | — | | | | | | |
Equity-indexed compensation expense (7) | 10 | | | — | | | | | | |
Foreign currency revaluation (8) | (8) | | | — | | | | | | |
| | | | | | | | |
Impact from exit of Canadian NGL Business (9) | 34 | | | — | | | | | | |
| | | | | | | | |
Segment amounts attributable to noncontrolling interests (10) | (140) | | | — | | | | | | |
Total other segment items | (94) | | | — | | | | | | |
| | | | | | | | |
| Segment Adjusted EBITDA | $ | 690 | | | $ | 4 | | | | | | |
| | | | | | | | |
Investment and acquisition capital expenditures (11) (12) | $ | 155 | | | $ | — | | | | | $ | 155 | | |
Maintenance capital expenditures (12) | $ | 38 | | | $ | — | | | | | $ | 38 | | |
| | | | | | | | |
| As of June 30, 2026 | | | | | | | | |
| Investments in unconsolidated entities | $ | 2,817 | | | $ | — | | | | | $ | 2,817 | | |
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, 2026 | | | | | | | | |
Revenues (1): | | | | | | | | |
| Product sales | $ | 29,396 | | | $ | 58 | | | $ | (208) | | | $ | 29,246 | | |
| Services | 913 | | | 3 | | | — | | | 916 | | |
| Total revenues | 30,309 | | | 61 | | | (208) | | | 30,162 | | |
| | | | | | | | |
Significant segment expenses: | | | | | | | | |
Purchases and related costs (1) | (28,211) | | | (46) | | | 208 | | | (28,049) | | |
Field operating costs | (616) | | | (12) | | | — | | | (628) | | |
Segment general and administrative expenses | (184) | | | (8) | | | — | | | (192) | | |
Total significant segment expenses | (29,011) | | | (66) | | | 208 | | | (28,869) | | |
| | | | | | | | |
| Equity earnings in unconsolidated entities | 178 | | | — | | | | | | |
| | | | | | | | |
Other segment items (2): | | | | | | | | |
Depreciation and amortization of unconsolidated entities (3) | 42 | | | — | | | | | | |
Derivative activities and inventory valuation adjustments (4) | 56 | | | — | | | | | | |
Long-term inventory costing adjustments (5) | (45) | | | — | | | | | | |
Deficiencies under minimum volume commitments, net (6) | (36) | | | — | | | | | | |
Equity-indexed compensation expense (7) | 20 | | | — | | | | | | |
Foreign currency revaluation (8) | (13) | | | — | | | | | | |
| | | | | | | | |
Impact from exit of Canadian NGL Business (9) | 34 | | | — | | | | | | |
| | | | | | | | |
Segment amounts attributable to noncontrolling interests (10) | (262) | | | — | | | | | | |
Total other segment items | (204) | | | — | | | | | | |
| | | | | | | | |
| Segment Adjusted EBITDA | $ | 1,272 | | | $ | (5) | | | | | | |
| | | | | | | | |
Investment and acquisition capital expenditures (11) (12) | $ | 326 | | | $ | — | | | | | $ | 326 | | |
Maintenance capital expenditures (12) | $ | 72 | | | $ | 1 | | | | | $ | 73 | | |
| | | | | | | | |
| As of June 30, 2026 | | | | | | | | |
Investments in unconsolidated entities | $ | 2,817 | | | $ | — | | | | | $ | 2,817 | | |
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, 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 (13) | 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 December 31, 2025 | | | | | | | | |
Investments in unconsolidated entities | $ | 2,846 | | | $ | — | | | | | $ | 2,846 | | |
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 (13) | 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 December 31, 2025 | | | | | | | | |
Investments in unconsolidated entities | $ | 2,846 | | | $ | — | | | | | $ | 2,846 | | |
(1)Segment revenues include intersegment amounts that are eliminated in Purchases and related costs. Intersegment activities are conducted at posted tariff rates where applicable, or otherwise at rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated.
(2)Represents adjustments utilized by our CODM in the evaluation of segment results.
(3)Includes our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities.
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 18 to our Consolidated Financial Statements included in Part IV of our 2025 Annual Report on Form 10-K for a discussion regarding our equity-indexed compensation plans.
(8)During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. These gains and losses are not integral to our core operating performance and were therefore excluded in determining Segment Adjusted EBITDA.
(9)Represents the acceleration of certain general and administrative expenses associated with exit activities related to the Canadian NGL Business divestiture in May 2026. Such costs are not integral to our core operating performance and were therefore excluded in determining Segment Adjusted EBITDA. See Note 2 for additional information regarding the Canadian NGL Business divestiture.
(10)Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River.
(11)Investment capital and acquisition capital expenditures, including investments in unconsolidated entities.
(12)These amounts combined represent total capital expenditures.
(13)Primarily related to deal-specific costs incurred during the periods presented.
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, |
| 2026 | | 2025 | | 2026 | | 2025 |
| Segment Adjusted EBITDA | $ | 694 | | | $ | 570 | | | $ | 1,267 | | | $ | 1,125 | |
Total other segment items (1) | 94 | | | 40 | | | 204 | | | 160 | |
| Depreciation and amortization | (242) | | | (235) | | | (486) | | | (466) | |
| Losses on asset sales, asset impairments and other, net | (59) | | | (42) | | | (6) | | | (29) | |
Gain on investments in unconsolidated entities, net | — | | | — | | | — | | | 31 | |
| Interest expense, net | (153) | | | (133) | | | (320) | | | (260) | |
Other income, net | 42 | | | 31 | | | 49 | | | 57 | |
Income from continuing operations before tax | 376 | | | 231 | | | 708 | | | 618 | |
Income tax expense from continuing operations | (100) | | | (4) | | | (100) | | | (11) | |
Income from continuing operations, net of tax | $ | 276 | | | $ | 227 | | | $ | 608 | | | $ | 607 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
(1)See footnotes to the segment financial data tables above for a more detailed discussion of Other segment items.