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Item 7. Management’s Discussion and Analysis

2026-02-27 compared with 2025-02-28 · 256 added, 210 removed, 530 unchanged (47% of the section changed)

13 unchanged sentences

Our business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals.

As one of the largest crude oil midstream service providers in North America, we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada.

Our assets and the services we provide are primarily focused on crude oil and NGL.

As one of the largest crude oil midstream service providers in North America, we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada.

Our assets and the services we provide are primarily focused on crude oil and, to a lesser extent, NGL.

Pending Sale of Canadian NGL Business

On June 17, 2025, we entered into a definitive SPA with Keyera, pursuant to which Keyera agreed to acquire all of the issued and outstanding shares of PMC ULC, our wholly-owned subsidiary that owns substantially all of the Canadian NGL Business.

This transaction supports our strategic objective to focus on our core midstream crude oil operations and to reduce exposure to commodity price fluctuations and seasonality.

We will divest the Canadian NGL Business as part of the sale, which includes substantially all of our NGL assets;

the assets that we will retain are located in the United States.

This transaction is expected to close around the end of the first quarter of 2026, subject to the satisfaction or waiver of customary closing conditions, including receipt of regulatory approvals.

We determined that in conjunction with entering into the SPA, the operations of the Canadian NGL Business meet the criteria for classification as held for sale and for discontinued operations reporting, as the sale will represent a strategic shift that will have a major effect on our operations and financial results.

We have applied these changes retrospectively to all periods presented.

See Note 1 and Note 3 to our Consolidated Financial Statements for additional information.

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

Index to Financial Statements

Market Overview and Outlook

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We believe reliable, affordable, and responsible energy resources are all critical components to maintain energy security and global stability, requiring all sources of energy including both hydrocarbons and renewables.

Index to Financial Statements

Consistent with the forecast from the EIA’s Short-Term Energy Outlook (as depicted in the chart above), we expect crude oil demand to continue to increase, driven largely by our view that hydrocarbon-based fuels are the most efficient fuels for the transportation of people and goods, and hydrocarbon-based products provide the building blocks for modern civilization such as fertilizers, plastics and cement.

As depicted in EIA’s Short-Term Energy Outlook (chart above), we expect crude oil demand to continue increasing, driven largely by our view that hydrocarbon-based fuels are the most efficient fuels for the transportation of people and goods, and hydrocarbon-based products provide the building blocks for modern civilization such as fertilizers, plastics and cement.

While the market is well supplied near-term, we believe geopolitical risk and uncertainty around OPEC’s ability to continue increasing production may present a more constructive outlook for global supply/demand compared to the current EIA forecast into 2027.

North America has proven to be an essential and reliable source of crude oil and NGL production growth for the global market.

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We expect the Permian Basin to be a key contributor to global supply for years to come, based on strong economics and the recent wave of consolidation leading to more stable activity levels over a wide range of commodity price environments.

Index to Financial Statements

It is against this macro energy market backdrop that we expect to generate significant positive free cash flow on a multi-year basis, supported by our existing asset base and integrated business model.

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Overview of Operating Results

We recognized net income attributable to PAA of $772 million for the year ended December 31, 2024 compared to net income attributable to PAA of $1.230 billion for the year ended December 31, 2023.

The decrease in net income attributable to PAA was largely driven by higher costs in the 2024 period associated with the Line 901 incident that occurred in May 2015 (including $225 million related to the write-off of a receivable for insurance proceeds in the fourth quarter of 2024 and $120 million related to settlements in the third quarter of 2024), losses on asset sales, asset impairments and other related items (as compared to gains from such items in the 2023 period), and higher income tax expense largely associated with Canadian withholding tax.

In addition, net income attributable to PAA for the 2023 period included the favorable impact of gains from the mark-to-market adjustment of the Preferred Distribution Rate Reset Option.

However, our Segment Adjusted EBITDA increased in 2024 compared to 2023 due to more favorable results from our Crude Oil segment, partially offset by lower contributions from our NGL segment.

See the “—Results of Operations” section below for further discussion.

Index to Financial Statements

We recognized net income attributable to PAA of $1.435 billion for the year ended December 31, 2025 compared to net income attributable to PAA of $772 million for the year ended December 31, 2024.

See the “—Results of Operations” section below for discussion of significant drivers of our results from continuing operations.

Results of Operations

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Gains/(losses) on asset sales, asset impairments and other, net 54 (159) 213 134 %

(160) 152 (312) (205) %

Equity earnings in unconsolidated entities 382 452 (70) (15) %

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108 64 44 69 %

Income tax expense (167) (121) (46) (38) %

Net income 1,113 1,502 (389) (26) %

Income tax expense from continuing operations

(15) (87) 72 83 %

Income from continuing operations, net of tax

1,386 882 504 57 %

Income from discontinued operations, net of tax (2)

383 231 152 66 %

$ 1,769 $ 1,113 $ 656 59 %

Net income attributable to noncontrolling interests (334) (341) 7 2 %

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Basic and diluted net income per common unit:

Continuing operations

$ 1.12 $ 0.40 $ 0.72 180 %

Discontinued operations

0.54 0.33 0.21 64 %

Basic and diluted net income per common unit $ 1.66 $ 0.73 $ 0.93 127 %

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

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

(1) “Interest expense, net” and “Other income, net” each include $48 million for the year ended December 31, 2024 related to interest on promissory notes by and among PAA and certain Plains entities.

(1) “Interest expense, net” and “Other income, net” each include $87 million and $48 million for the years ended December 31, 2025 and 2024, respectively, related to interest on promissory notes by and among us and certain Plains entities.

(2) See Note 3 to our Consolidated Financial Statements for a reconciliation of the line items comprising income from discontinued operations, net of tax.

Index to Financial Statements

Continuing Operations

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

Revenues and Purchases

Fluctuations in our consolidated revenues and purchases and related costs are primarily associated with our merchant activities and are generally explained by changes in commodity prices and the impact of gains and losses related to derivative instruments used to manage our commodity price exposure.

Fluctuations in our revenues and purchases and related costs are primarily associated with our merchant activities and are generally explained by changes in commodity prices and the impact of gains and losses related to derivative instruments used to manage our commodity price exposure.

Because both product sales revenues and purchases and related costs are generally based off of the same pricing indices, the market price of the commodities will not necessarily have an impact on the absolute margins related to those sales and purchases.

A majority of our crude oil sales and purchases are indexed to the prompt month price of the NYMEX Light, Sweet crude oil futures contract (“NYMEX Price”) and our NGL sales are indexed to Mont Belvieu prices.

A majority of our crude oil sales and purchases are indexed to the prompt month price of the NYMEX Light, Sweet crude oil futures contract (“NYMEX Price”).

The following table presents the range of the NYMEX Price over the last two years (in dollars per barrel):

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2024 $ 66 $ 87 $ 76

Product sales revenues and purchases increased for the year ended December 31, 2024 compared to the year ended December 31, 2023 primarily due to higher crude oil sales volumes.

Index to Financial Statements

Revenues from services increased for the year ended December 31, 2024 compared to the year ended December 31, 2023 primarily due to higher pipeline volumes and tariff escalations, as well as the impact of acquisitions.

Product sales revenues (including the impact of derivative mark-to-market valuations) and purchases decreased for the year ended December 31, 2025 compared to the year ended December 31, 2024 primarily due to lower commodity prices in 2025, partially offset by higher crude oil sales volumes in 2025.

Revenues from services increased for the year ended December 31, 2025 compared to the year ended December 31, 2024 primarily due to higher pipeline volumes and tariff escalations, as well as the impact of recently completed acquisitions, partially offset by the impact from lower commodity prices in 2025 and the impact from certain Permian long-haul pipeline contract rates resetting to market in 2025.

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

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General and Administrative Expenses

The increase in general and administrative expenses for the year ended December 31, 2024 compared to the year ended December 31, 2023 was primarily due to (i) higher employee-related costs, (ii) higher information systems costs due to ongoing systems integration work and (iii) higher office rent due to an operating cost abatement in the prior year.

The increase in general and administrative expenses for the year ended December 31, 2025 compared to the year ended December 31, 2024 was primarily due to transaction costs associated with our recent acquisitions, partially offset by lower information systems costs due to the completion of certain systems conversion and integration work.

Depreciation and Amortization

The increase in depreciation and amortization expense for the year ended December 31, 2025 compared to the year ended December 31, 2024 was largely driven by recently completed acquisitions.

See Note 8 to our Consolidated Financial Statements for additional information regarding our acquisitions.

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

The net loss on asset sales and asset impairments for the year ended December 31, 2024 was primarily due to non-cash charges related to the write-down of certain of our long-lived U.S.

The net gain on asset sales, asset impairments and other, net for the year ended December 31, 2025 was primarily due to gains recognized during the year on various asset divestitures.

In addition, in connection with the pending sale of the Canadian NGL Business, we entered into a deal-contingent forward currency instrument to hedge the currency exchange risk associated with the sale in CAD.

The year ended December 31, 2025 was impacted by the mark-to-market of this instrument.

See Note 13 to our Consolidated Financial Statements for additional information regarding this instrument and our derivatives and hedging activities.

See Note 1 to our Consolidated Financial Statements for additional information regarding the pending sale of the Canadian NGL Business.

Index to Financial Statements

The net loss on asset sales, asset impairments and other, net for the year ended December 31, 2024 was primarily due to non-cash charges related to the write-down of certain of our long-lived U.S.

terminal assets included in our NGL segment due to asset impairments and accelerated depreciation in the fourth quarter of 2024.

The net gain on asset sales and asset impairments for the year ended December 31, 2023 was primarily related to the sale of our ownership interest in the Keyera Fort Saskatchewan facility in the first quarter of 2023.

See Note 6 and Note 7 to our Consolidated Financial Statements for additional information regarding these asset sales and asset impairments.

See Note 7 and Note 8 to our Consolidated Financial Statements for additional information regarding our asset sales and asset impairments.

Equity Earnings in Unconsolidated Entities

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Gain on Investments in Unconsolidated Entities, Net

In the first quarter of 2025, we recognized a gain of $31 million related to our acquisition of the remaining 50% interest in Cheyenne Pipeline LLC through a non-monetary transaction.

In the fourth quarter of 2024, we recognized a gain of $15 million related to our acquisition of the remaining 50% interest in Midway Pipeline LLC.

In the third quarter of 2023, we recognized a gain of $29 million related to the Permian JV’s acquisition of the remaining 43% interest in OMOG JV Holdings LLC.

See Note 8 to our Consolidated Financial Statements for additional information regarding these transactions.

Interest Expense, Net and Other Income/(Expense), Net

For the year ended December 31, 2024, “Interest expense, net” and “Other income, net” each include interest expense and interest income associated with promissory notes payable and receivable by and among PAA and certain Plains entities, which is the primary driver of the increase in interest expense compared to 2023 and is a component of the variance in other income year-over-year.

For the years ended December 31, 2025 and 2024, “Interest expense, net” and “Other income, net” each include interest expense and interest income associated with promissory notes payable and receivable by and among us and certain Plains entities.

These amounts are excluded from our non-GAAP performance measures Adjusted EBITDA and Implied DCF.

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See the “—Non-GAAP Financial Measures” section below.

See Note 17 to our Consolidated Financial Statements for additional information on our related party notes.

See Note 11 to our Consolidated Financial Statements for additional information regarding our debt and related activities during the periods presented.

Index to Financial Statements

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

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Capitalized interest

(1) Represents interest expense associated with promissory notes by and among PAA and certain Plains entities, as described above.

The following table summarizes the components impacting Other income/(expense), net (in millions):

(1) The increase in interest expense for the year ended December 31, 2025 compared to 2024 was primarily driven by (i) the issuance of an aggregate of $3.0 billion of senior notes during 2025 and (ii) higher commercial paper and term loan borrowings in 2025, primarily related to the funding of the EPIC acquisition, partially offset by (iii) the repayment of $1.0 billion of senior notes in October 2025.

See Note 11 to our Consolidated Financial Statements for additional information regarding our debt and related activities during the periods presented.

See Note 8 to our Consolidated Financial Statements for additional information regarding the EPIC acquisition.

(2) Represents interest expense associated with promissory notes by and among us and certain Plains entities, as described above.

Index to Financial Statements

The following table summarizes the components impacting Other income, net (in millions):

Year Ended December 31,

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Interest income from other sources

Net gain/(loss) on foreign currency revaluation (2)

Gain on mark-to-market adjustment of Preferred Distribution Rate Reset Option embedded derivative (3)

(1) Represents interest income associated with promissory notes by and among PAA and certain Plains entities, as described above.

(2) The activity during the periods presented was primarily related to the impact from the change in the United States Dollar to Canadian dollar exchange rate on the portion of our intercompany net investment that is not long-term in nature.

(3) See Note 12 to our Consolidated Financial Statements for additional information.

Income Tax (Expense)/Benefit

The net unfavorable income tax variance for the year ended December 31, 2024 compared to the year ended December 31, 2023 was primarily due to higher income tax expense in 2024 associated with Canadian withholding tax on dividends from our Canadian entities to other Plains entities driven by timing of dividend payments, including proceeds from asset divestitures.

Noncontrolling Interests

The increase in amounts attributable to noncontrolling interests for the year ended December 31, 2024 compared to the year ended December 31, 2023 was due to higher net income recognized by the Permian JV and Cactus II related to higher volumes, as well as contributions from acquisitions completed by the Permian JV.

See Note 7 to our Consolidated Financial Statements for additional information.

Index to Financial Statements

Net loss on foreign currency revaluation (2)

(1) Represents interest income associated with promissory notes by and among us and certain Plains entities, as described above.

(2) The activity during the periods presented was primarily related to the impact from the change in the CAD to USD exchange rate on the portion of our intercompany net investment that is not long-term in nature.

Income Tax Expense from Continuing Operations

The net favorable income tax expense from continuing operations variance for the year ended December 31, 2025 compared to the year ended December 31, 2024 was primarily due to higher income tax expense in 2024 associated with Canadian withholding tax on intercompany dividends from our Canadian entity driven by timing of dividend payments, including proceeds from asset divestitures.

Non-GAAP Financial Measures

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See “—Liquidity and Capital Resources—Non-GAAP Financial Liquidity Measures” for additional information regarding Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions.

Index to Financial Statements

Non-GAAP Financial Performance Measures

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

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

Adjusted EBITDA attributable to PAA excludes the portion of Adjusted EBITDA that is attributable to noncontrolling interests.

Management believes that the presentation of Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF provides useful information to investors regarding our performance and results of operations because these measures, when used to supplement related GAAP financial measures, (i) provide additional information about our core operating performance and ability to fund distributions to our unitholders through cash generated by our operations, (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions and (iii) present measures that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations.

These non-GAAP financial performance measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (iii) long-term inventory costing adjustments, (iv) items that are not indicative of our core operating results and/or (v) other items that we believe should be excluded in understanding our core operating performance.

Management believes that the presentation of Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF provides useful information to investors regarding our performance and results of operations because these measures, when used to supplement related GAAP financial measures, (i) provide additional information about our operating performance and ability to fund distributions to our unitholders through cash generated by our operations, (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions and (iii) present measures that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations.

These non-GAAP financial performance measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (iii) long-term inventory costing adjustments, (iv) items that are not indicative of our operating results and/or (v) other items that we believe should be excluded in understanding our operating performance.

These measures may further be adjusted to include amounts related to deficiencies associated with minimum volume commitments whereby we have billed the counterparties for their deficiency obligation and such amounts are recognized as deferred revenue in “Other current liabilities” in our Consolidated Financial Statements.

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Index to Financial Statements

Discontinued Operations.

Management believes that the presentation of certain Non-GAAP financial performance measures, such as Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied DCF, and certain Non-GAAP financial liquidity measures, such as Adjusted Free Cash Flow and Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities), on a consolidated basis (e.g., the aggregate of continuing operations and discontinued operations) provides more relevant and useful information regarding our performance and results of operations than presenting such metrics only on a continuing operations or discontinued operations basis.

In addition, as the potential sale of the Canadian NGL Business is not anticipated to close until around the end of the first quarter of 2026, management continues to view the Canadian NGL Business as a component of our overall company performance and ability to fund distributions to our unitholders in the near term.

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

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Net income (1)

$ 1,769 $ 1,113 $ 656 59 %

Interest expense, net of certain items (2)

467 382 85 22 %

Income tax expense 167 121 46 38 %

Depreciation and amortization 1,026 1,048 (22) (2) %

(Gains)/losses on asset sales, asset impairments and other, net

Income tax expense from continuing operations

15 87 (72) (83) %

Income tax expense from discontinued operations (3)

139 80 59 74 %

Depreciation and amortization from continuing operations

953 901 52 6 %

Depreciation and amortization from discontinued operations (3)

57 125 (68) (54) %

(Gains)/losses on asset sales, asset impairments and other, net from continuing operations

(54) 159 (213) (134) %

Losses on asset sales, asset impairments and other, net from discontinued operations (3)

Gain on investments in unconsolidated entities, net

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Depreciation and amortization of unconsolidated entities (4)

84 87 (3) (3) %

Selected Items Impacting Comparability (1) :

Derivative activities and inventory valuation adjustments

(108) 85 (193) **

Long-term inventory costing adjustments

Deficiencies under minimum volume commitments, net

(38) (31) (7) **

Rail fleet amortization expense related to discontinued operations (5)

(18) — (18) **

Equity-indexed compensation expense

Foreign currency revaluation

15 (27) 42 **

Line 901 incident

— 345 (345) **

Transaction-related expenses

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(47) 399 (446) **

Mark-to-market adjustment of Preferred Distribution Rate Reset Option embedded derivative (4)

Foreign currency revaluation (7)

10 (16) 26 **

Selected Items Impacting Comparability - Adjusted EBITDA (1) (8)

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Adjusted EBITDA attributable to PAA (1)

$ 2,833 $ 2,779 $ 54 2 %

Index to Financial Statements

Year Ended December 31, Variance

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(452) (365) (87) (24) %

Maintenance capital (10)

Maintenance capital from continuing operations (12)

(156) (187) 31 17 %

Maintenance capital from discontinued operations (12)

(70) (74) 4 5 %

Investment capital of noncontrolling interests (13)

(108) (86) (22) (26) %

Current income tax expense (195) (145) (50) (34) %

Distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings (12)

Current income tax expense from continuing operations

(1) (82) 81 99 %

Current income tax expense from discontinued operations (3)

(99) (113) 14 12

Distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings (14)

Distributions to noncontrolling interests (15)

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Implied DCF (1)

Preferred unit cash distributions (13)

$ 2,063 $ 2,005 $ 58 3 %

Preferred unit distributions (15)

Implied DCF Available to Common Unitholders (1)

$ 1,838 $ 1,751

Common unit cash distributions (15)

(1,070) (891)

Implied DCF Excess (1) (16)

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

(1) Represents “Interest expense, net” as reported on our Consolidated Statements of Operations, net of interest income associated with promissory notes by and among PAA and certain Plains entities.

Index to Financial Statements

(1) Includes results from continuing operations and discontinued operations.

(2) Represents “Interest expense, net” as reported on our Consolidated Statements of Operations, net of interest income associated with promissory notes by and among us and certain Plains entities.

(3) See Note 3 to our Consolidated Financial Statements for additional information.

(4) We exclude our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities when reviewing Adjusted EBITDA, similar to our consolidated assets.

(3) For a more detailed discussion of these selected items impacting comparability, see the footnotes to the Segment Adjusted EBITDA Reconciliation table in Note 19 to our Consolidated Financial Statements.

(4) The Preferred Distribution Rate Reset Option of our Series A preferred units was accounted for as an embedded derivative and recorded at fair value in our Consolidated Financial Statements.

The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability.

See Note 12 to our Consolidated Financial Statements for additional information regarding the Preferred Distribution Rate Reset Option.

(5) 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.

Management believes that the presentation of Adjusted EBITDA and Implied DCF on a consolidated basis (e.g., the aggregate of continuing operations and discontinued operations) provides more relevant and useful information regarding our performance and results of operations than presenting such metrics only on a continuing operations or discontinued operations basis.

We therefore include an adjustment for the impact of amortization of the rail fleet associated with the Canadian NGL Business in our calculation of Adjusted EBITDA.

See Note 1 to our Consolidated Financial Statements for additional information regarding the pending sale of the Canadian NGL Business.

Also see the “—Non-GAAP Financial Measures” section above.

(6) For a more detailed discussion of these selected items impacting comparability, see the footnotes to the segment financial data tables in Note 20 to our Consolidated Financial Statements.

(7) During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency.

The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability.

(6) “Other income/(expense), net” on our Consolidated Statements of Operations, excluding interest income associated with promissory notes by and among PAA and certain Plains entities, adjusted for selected items impacting comparability (“Adjusted other income/(expense), net”) is included in Adjusted EBITDA and excluded from Segment Adjusted EBITDA.

(8) “Other income, net” on our Consolidated Statements of Operations, excluding interest income associated with promissory notes by and among us and certain Plains entities, adjusted for selected items impacting comparability (“Adjusted other income, net”) is included in Adjusted EBITDA and excluded from Segment Adjusted EBITDA.

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

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

(9) Amount excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps and is net of interest income associated with promissory notes by and among PAA and certain Plains entities.

(11) Amount excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps and is net of interest income associated with promissory notes by and among us and certain Plains entities.

Index to Financial Statements

(12) Maintenance capital expenditures are defined as capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets.

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Crude Oil and NGL.

Our Chief Operating Decision Maker (“CODM”) (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Adjusted EBITDA, segment volumes and maintenance capital investment.

Our Chief Operating Decision Maker (“CODM”) (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA.

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”).

See Note 19 to our Consolidated Financial Statements for a reconciliation of Segment Adjusted EBITDA to Net income attributable to PAA.

Index to Financial Statements

See Note 20 to our Consolidated Financial Statements for a reconciliation of Segment Adjusted EBITDA to Income from Continuing Operations, Net of Tax.

In connection with our merchant activities, our Crude Oil and NGL segments may enter into intersegment transactions for the purchase or sale of products, along with services such as the transportation, terminalling or storage of products.

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Our merchant activities are governed by our risk management policies.

Index to Financial Statements

Our Crude Oil segment generates revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees, month-to-month and multi-year storage and terminalling agreements and the sale of gathered and bulk-purchased crude oil.

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Generally, results from our merchant activities are impacted by (i) increases or decreases in our lease gathering crude oil purchases volumes and (ii) volatility in commodity price differentials, particularly grade and location differentials, as well as time spreads.

The segment results also include the direct fixed and variable field costs of operating the crude oil assets, as well as an allocation of indirect operating costs.

Index to Financial Statements

The segment results also include the direct fixed and variable field costs of operating the crude oil assets, as well as an allocation of indirect operating and general and administrative costs.

The following tables set forth our operating results from our Crude Oil segment:

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Depreciation and amortization of unconsolidated entities

84 87 (3) (3) %

Derivative activities and inventory valuation adjustments (23) 5 (28) **

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7,333 6,731 602 9 %

Rocky Mountain (6)

South Texas / Eagle Ford

521 403 118 29 %

Mid-Continent

518 506 12 2 %

Total crude oil pipeline tariff 8,934 8,460 474 6 %

Commercial crude oil storage capacity (6) (7)

Crude oil lease gathering purchases (5) (8)

1,308 1,294 14 1 %

Total crude oil pipeline tariff 9,680 8,934 746 8 %

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

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The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.

Index to Financial Statements

(4) Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results.

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Volumes associated with acquisitions represent total volumes for the number of days we actually owned the assets divided by the number of days in the period.

Index to Financial Statements

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

(7) Average monthly capacity in millions of barrels per day calculated as total volumes for the year divided by the number of months in the year.

(8) Of this amount, approximately 1,278 and 1,147 thousand barrels per day were purchased in the Permian Basin for the years ended December 31, 2024 and 2023, respectively.

Segment Adjusted EBITDA

Crude Oil Segment Adjusted EBITDA increased for the year ended December 31, 2024 compared to the year ended December 31, 2023 primarily due to higher tariff volumes on our pipelines, tariff escalations and contributions from acquisitions, partially offset by fewer market-based opportunities.

The following is a more detailed discussion of the significant factors impacting Segment Adjusted EBITDA for the year ended December 31, 2024 compared to the year ended December 31, 2023.

Crude Oil Segment Adjusted EBITDA increased for the year ended December 31, 2025 compared to the year ended December 31, 2024 primarily due to higher tariff volumes on our pipelines, contributions from acquisitions and the benefit of tariff escalations, partially offset by fewer market-based opportunities and the impact from certain contract rates resetting to market.

The following is a more detailed discussion of the significant factors impacting Segment Adjusted EBITDA for the periods indicated.

Net Revenues and Equity Earnings.

Our results were favorably impacted by (i) volume growth across our pipeline systems driven by increased production in the Permian Basin region, as well as increased movements from the Rocky Mountain region to Cushing, Oklahoma, (ii) the benefit of tariff escalations and (iii) contributions from acquisitions, including increases in ownership of certain pipeline systems.

Additionally, our results for the year ended December 31, 2024 compared to 2023 reflect fewer crude oil market-based opportunities.

Our results increased for the year ended December 31, 2025 compared to the year ended December 31, 2024.

Favorable results from (i) volume growth across our pipeline systems largely driven by increased production in the Permian Basin region, (ii) contributions from recently completed acquisitions in the Permian Basin and South Texas regions, including our Cactus III pipeline acquisition, and (iii) the benefit of tariff escalations were partially offset by (iv) fewer market-based opportunities, (v) lower commodity prices, which resulted in lower revenues from pipeline loss allowance in the 2025 periods, and (vi) the impact from certain Permian long-haul contract rates resetting to market in 2025.

In addition, equity earnings in the 2024 period includes the benefit of the recognition of deferred revenue associated with certain of our joint venture pipelines, a majority of which is excluded from Segment Adjusted EBITDA in “Other segment items” in the table above.

Field Operating Costs.

For the year ended December 31, 2024 compared to the year ended December 31, 2023, we recognized higher expenses associated with (i) an increase in costs associated with settlements related to the Line 901 incident that occurred in May 2015 (which impact field operating costs, but are excluded from Segment Adjusted EBITDA, and thus are reflected as a component of “Other segment items” in the table above), (ii) an increase in estimated costs for long-term environmental remediation obligations, (iii) property taxes due to the impact of favorable adjustments in 2023 and (iv) incremental operating costs and employee-related costs associated with acquisitions, partially offset by (v) unrealized mark-to-market gains on power hedges (which impact our field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as a component of “Other segment items” in the table above) and (vi) decreased costs resulting from lower third-party trucked volumes.

The decrease in field operating costs for the year ended December 31, 2025 compared to the year ended December 31, 2024 was primarily due to the recognition in 2024 of costs associated with settlements related to the Line 901 incident that occurred in May 2015 (which impact field operating costs, but are excluded from Segment Adjusted EBITDA, and thus are reflected in “Other segment items” in the table above).

This was partially offset by higher expenses in the 2025 period resulting from (i) acquisitions, (ii) higher volumes and (iii) property taxes.

Maintenance Capital

Maintenance capital consists of capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets.

The increase in maintenance capital spending for the year ended December 31, 2024 compared to the year ended December 31, 2023 was primarily due to (i) an increase in integrity management, maintenance and repairs and replacement projects and (ii) more trucking lease buyouts.

Our NGL segment operations involve natural gas processing and NGL fractionation, storage, transportation and terminalling.

Our NGL revenues are primarily derived from a combination of (i) providing gathering, fractionation, storage, and/or terminalling services to third-party customers for a fee, and (ii) our merchant activities of extracting NGL mix from the gas stream processed at our Empress straddle plant facility as well as acquiring NGL mix, which is then transported, stored and fractionated into finished products and sold to customers.

The commodity exposure associated with our merchant activities is governed by our risk management policies.

Generally, our segment results are impacted by (i) increases or decreases in our NGL sales volumes, (ii) volatility in commodity price differentials, primarily the differential between the price of natural gas and the extracted NGL (“frac spread”), as well as location differentials and time spreads, (iii) the quality and volume of natural gas transported on third-party assets through our Empress straddle plant and (iv) our share of the NGL received from a third-party straddle plant.

The decrease in maintenance capital spending for the year ended December 31, 2025 compared to the same period in 2024 was primarily due to lower costs resulting from timing of certain pipeline integrity activities.

Index to Financial Statements

Our NGL operations are sensitive to weather-related demand, particularly during the approximate five-month peak heating season of November through March, and temperature differences from period-to-period may have a significant effect on NGL demand, and thus our financial performance, as well as the impact of comparative performance between financial reporting periods that bisect the five-month peak heating season.

The following tables set forth our operating results from our NGL segment:

Our NGL segment operations involve NGL storage and terminalling from our NGL assets primarily located in the Southwestern United States.

Our NGL segment revenues are primarily derived from (i) providing storage and/or terminalling services at these facilities to third-party customers for a fee and (ii) the transport, storage and sale of specification NGL products.

The segment results also include the direct fixed and variable field costs of operating our four NGL facilities, as well as an allocation of indirect operating costs and general and administrative expenses.

The following table sets forth our operating results from our NGL segment:

Operating Results (1)

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(28) (30) 2 7 %

Other segment items (4) :

Derivative activities

80 142 (62) **

Long-term inventory costing adjustments

(10) 13 (23) **

Equity-indexed compensation expense

Foreign currency revaluation

(5) 5 (10) **

Segment Adjusted EBITDA

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$ 3 $ 4 $ (1) (25) %

Year Ended December 31, Variance

Average Volumes (in thousands of barrels per day) (5)

2024 2023 Volumes %

NGL fractionation

132 115 17 15 %

NGL pipeline tariff 213 180 33 18 %

Propane and butane sales

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

(1) Revenues and costs and expenses include intersegment amounts.

(2) Represents components of significant segment expenses.

(3) Field operating costs and segment general and administrative expenses include certain costs that are part of the overhead of continuing operations.

(4) Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments.

The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.

(4) Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results.

See Note 19 to our Consolidated Financial Statements for additional discussion of such adjustments.

(5) Average daily volumes are calculated as total volumes (attributable to our interest for assets owned through UJIs) for the year divided by the number of days in the year.

Segment Adjusted EBITDA

NGL Segment Adjusted EBITDA for the year ended December 31, 2024 decreased compared to the year ended December 31, 2023, primarily due to the impact of lower realized frac spreads, partially offset by higher propane and butane sales volumes.

Index to Financial Statements

Significant variances in the components of Segment Adjusted EBITDA are discussed in more detail below:

Net Revenues.

Net revenues include the impact of derivative activities and long-term inventory costing adjustments, which are excluded from Segment Adjusted EBITDA and thus are reflected as a component of “Other segment items” in the table above.

Excluding such impacts, net revenues decreased for the year ended December 31, 2024 compared to the year ended December 31, 2023 primarily due to (i) lower realized frac spreads and (ii) lower field operating cost recoveries at our Empress straddle plants realized through our commercial agreements, partially offset by (iii) higher propane and butane sales volumes, (iv) tariff escalations and (v) market opportunities.

Field Operating Costs.

The decrease in field operating costs for the year ended December 31, 2024 compared to the year ended December 31, 2023 was primarily due to (i) decreased utilities-related costs largely as a result of lower prices and (ii) a decrease in unrealized mark-to-market losses on power hedges (which impact our field operating costs, but are excluded from Segment Adjusted EBITDA, and thus are reflected as a component of “Other segment items” in the table above), partially offset by (iii) higher maintenance and repairs.

The decrease in utilities-related costs was partially offset by the lower benefit to net revenues of operating cost recoveries realized through commercial agreements.

Maintenance Capital

The decrease in maintenance capital spending for the year ended December 31, 2024 compared to the year ended December 31, 2023 was primarily due to timing of routine integrity activities.

NGL Segment Adjusted EBITDA loss for the years ended December 31, 2025 and 2024 was largely driven by costs that are part of the overhead of our NGL activities and are included in continuing operations as they are not related to contracts or arrangements that will be included in the sale of the Canadian NGL Business.

These costs include information technology, insurance and other shared services costs.

Liquidity and Capital Resources

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In addition, we generally expect to fund our long-term needs, such as those resulting from investment capital activities, acquisitions or refinancing our long-term debt, through a variety of sources, which may include any or a combination of the sources listed above.

Index to Financial Statements

As of December 31, 2025, although we had a working capital deficit of $198 million, we had over $2.0 billion of liquidity available to meet our ongoing operating, investing and financing needs, subject to continued covenant compliance, as noted below (in millions):

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(2) Available capacity under our senior unsecured revolving credit facility and senior secured hedged inventory facility was reduced by outstanding letters of credit issued under these facilities of less than $1 million and $52 million, respectively.

(3) Excludes restricted cash of $1 million.

Index to Financial Statements

Usage of our credit facilities, which provide the financial backstop for our commercial paper program, is subject to ongoing compliance with covenants, as discussed further below.

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“Risk Factors” for further discussion regarding risks that may impact our liquidity and capital resources.

Credit Agreements, Commercial Paper Program and Indentures

Credit Agreements, Commercial Paper Program, Term Loan and Indentures

We have three primary credit arrangements, which we use to meet our short-term cash needs.

These include our $1.35 billion senior unsecured revolving credit facility maturing in 2029 (excluding a commitment of $64 million, which matures in 2027), $1.35 billion senior secured hedged inventory facility maturing in 2027 (excluding a commitment of $64 million, which matures in 2026) and $2.7 billion unsecured commercial paper program that is backstopped by our revolving credit facility and our hedged inventory facility.

The credit agreements for our revolving credit facilities (which impact our ability to access our commercial paper program because they provide the financial backstop that supports our short-term credit ratings) and the indentures governing our senior notes contain cross-default provisions.

A default under our credit agreements or indentures would permit the lenders to accelerate the maturity of the outstanding debt.

As long as we are in compliance with the provisions in our credit agreements, our ability to make distributions of available cash is not restricted.

We were in compliance with the covenants contained in our credit agreements and indentures as of December 31, 2024.

The credit agreements for our revolving credit facilities (which impact our ability to access our commercial paper program because they provide the financial backstop that supports our short-term credit ratings), the term loan and the indentures governing our senior notes contain cross-default provisions.

A default under our credit agreements, term loan or indentures would permit the lenders to accelerate the maturity of the outstanding debt.

As long as we are in compliance with the provisions in our credit agreements and term loan agreement, our ability to make distributions of available cash is not restricted.

We were in compliance with the covenants contained in our credit agreements, term loan and indentures as of December 31, 2025.

Index to Financial Statements

Non-GAAP Financial Liquidity Measures

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Adjusted Free Cash Flow is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Adjusted Free Cash Flow after Distributions.

Index to Financial Statements

The following table sets forth the reconciliation of the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions from Net Cash Provided by Operating Activities and includes results from continuing operations and discontinued operations for all periods presented (in millions):

Year Ended December 31,

Net cash provided by operating activities

$ 2,936 $ 2,490

Adjustments to reconcile net cash provided by operating activities to adjusted free cash flow:

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Adjusted Free Cash Flow after Distributions (4)

(1) PAA and certain Plains entities have issued promissory notes by and among such entities to facilitate financing.

$ (2,170) $ 102

(1) Certain Plains entities have issued promissory notes by and among such entities to facilitate financing.

“Proceeds from the issuance of related party notes” has an equal and offsetting cash outflow associated with our investment in related party notes, which is included as a component of “Net cash used in investing activities.” See Note 17 to our Consolidated Financial Statements for additional information on our related party notes.

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Similarly, the level of NGL and other product inventory stored and held for resale at period end affects our cash flow from operating activities.

Index to Financial Statements

In periods when the market is not in contango, we typically sell our crude oil during the same month in which we purchase it and we do not rely on borrowings under our credit facilities or commercial paper program to pay for the crude oil.

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See Note 13 to our Consolidated Financial Statements for a discussion regarding our derivatives and risk management activities.

Net cash provided by operating activities for the years ended December 31, 2024 and 2023 was approximately $2.5 billion and $2.7 billion, respectively, and primarily resulted from earnings from our operations.

Index to Financial Statements

Net cash provided by operating activities from continuing operations for the years ended December 31, 2025 and 2024 was approximately $2.5 billion and $2.2 billion, respectively, and primarily resulted from earnings from our operations.

Investing Activities

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In the near term, we do not plan to issue common equity to fund such expenditures.

The following table summarizes our investment, maintenance and acquisition capital expenditures (in millions):

The following table summarizes our investment, maintenance and acquisition capital expenditures related to continuing operations and discontinued operations (in millions):

Net to PAA (1) (2)

Consolidated (2)

Continuing Operations

Year Ended December 31,

Capital Expenditures (3) (4)

2025 2024 2025 2024 2025 2024

Investment capital

$ 409 $ 214 $ 520 $ 300 $ 520 $ 300

Maintenance capital

138 164 153 183 153 183

Acquisition capital (5)

2,729 243 2,801 254 2,801 254

$ 3,276 $ 621 $ 3,474 $ 737 $ 3,474 $ 737

Investment capital

$ 99 $ 115 $ 99 $ 115 $ — $ —

Maintenance capital

73 78 73 78 3 4

$ 172 $ 193 $ 172 $ 193 $ 3 $ 4

Investment capital

$ 508 $ 329 $ 619 $ 415 $ 520 $ 300

Maintenance capital

211 242 226 261 156 187

Acquisition capital (5)

2,729 243 2,801 254 2,801 254

$ 3,448 $ 814 $ 3,646 $ 930 $ 3,477 $ 741

(1) Excludes expenditures attributable to noncontrolling interests, which primarily relate to the Permian JV.

Includes results from continuing operations and discontinued operations for all periods presented.

(2) Includes results from continuing operations and discontinued operations for all periods presented.

Capital expenditures related to discontinued operations were $99 million and $70 million for investment and maintenance capital for the year ended December 31, 2025, respectively.

Capital expenditures for investment and maintenance capital related to discontinued operations were $115 million and $74 million for the year ended December 31, 2024, respectively.

There was no acquisition capital related to discontinued operations for any period presented.

(3) Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as “Investment capital.” Capital expenditures made to replace and/or refurbish partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as “Maintenance capital.”

Index to Financial Statements

(4) Contributions to unconsolidated entities, accounted for under the equity method of accounting, that are related to investment capital projects by such entities are recognized in “Investment capital.” Acquisitions of initial investments or additional interests in unconsolidated entities are included in “Acquisition capital.”

(3) Investment capital and maintenance capital, net to our 65% interest in the Permian JV, was approximately $329 million and $242 million, respectively, for 2024, and approximately $310 million and $214 million, respectively, for 2023.

(5) Acquisition capital for 2025 primarily includes the acquisitions of (i) EPIC (Cactus III), (ii) Ironwood Midstream, (iii) EMG Medallion 2 Holdings, LLC and its subsidiaries by the Permian JV, (iv) Black Knight Midstream, LLC by the Permian JV, (v) the remaining 50% interest in Cheyenne Pipeline LLC through a non-cash transaction, and (vi) an additional 20% interest in BridgeTex Pipeline.

Acquisition capital for 2024 primarily includes the acquisitions of additional ownership interests in equity method investees.

Acquisition capital for 2023 primarily includes the acquisition by the Permian JV of (i) the remaining 43% interest in OMOG JV Holdings LLC and (ii) gathering assets in the Southern and Northern Delaware Basins.

See Note 8 and Note 9 to our Consolidated Financial Statements for additional information.

Acquisition capital, net to our 65% interest in the Permian JV, was approximately $243 million and $281 million for 2024 and 2023, respectively.

In the first quarter of 2025, we completed two additional bolt-on acquisitions for $636 million (approximately $580 million net to our interest), which included (i) a Delaware Basin crude oil gathering business and (ii) an Eagle Ford Basin gathering system.

We used a portion of the net proceeds from our January 2025 senior notes offering to fund these acquisitions.

Investment Capital Projects

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The majority of this investment capital consists of highly-contracted projects that complement our broader system capabilities and support the long-term needs of the upstream and downstream sectors of the industry value chain.

The following table summarizes our investment in capital projects (in millions):

The following table summarizes our investment in capital projects related to continuing operations and discontinued operations (in millions):

Year Ended December 31,

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Complementary Permian Basin Projects (1)

Selected Facilities/Downstream Projects (2)

Permian Basin Takeaway Pipeline Projects

Other Projects 173 46

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(1) Includes projects associated with assets included in the Permian JV.

(2) Includes projects at our St.

James and Fort Saskatchewan terminals.

Index to Financial Statements

Projected 2026 Capital Expenditures.

Total investment capital for the year ending December 31, 2025 is currently projected to be approximately $500 million ($400 million net to our interest).

Total investment capital for the year ending December 31, 2026 is currently projected to be approximately $440 million ($350 million net to our interest), which includes approximately $15 million related to discontinued operations.

Approximately half of our projected investment capital expenditures are expected to be invested in the Permian JV assets.

Additionally, maintenance capital for 2025 is currently projected to be approximately $260 million ($240 million net to our interest).

Additionally, maintenance capital for 2026 is currently projected to be approximately $185 million ($165 million net to our interest), which includes approximately $15 million related to discontinued operations.

We expect to fund our 2026 investment and maintenance capital expenditures primarily with retained cash flow.

Proceeds from the sale of assets have historically generally been used to fund our investment capital projects and reduce debt levels.

The following table summarizes the proceeds received from divestitures during the last two years (in millions):

Year Ended December 31,

Proceeds from divestitures (1)

(1) Represents proceeds, including working capital adjustments, net of transaction costs.

The proceeds from divestitures for the year ended December 31, 2023 are primarily from the sale of our 21% non-operated/UJI in the Keyera Fort Saskatchewan facility in February 2023.

See Note 7 to our Consolidated Financial Statements for additional information.

Note that potential variation to current capital cost estimates may result from (i) changes to project design, (ii) final cost of materials and labor, (iii) timing of incurrence of costs due to uncontrollable factors such as receipt of permits or regulatory approvals and weather and (iv) timely closing of the Canadian NGL Business divestiture.

Ongoing Activities Related to Strategic Transactions

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“Risk Factors—Risks Related to Our Business—Acquisitions and divestitures involve risks that may adversely affect our business.”

Index to Financial Statements

Related Party Promissory Notes

In July 2024, promissory notes with a face value of CAD$865 million (approximately $629 million) were issued by and among us and certain Plains entities.

In February 2025 and July 2024, promissory notes with a face value of CAD$473 million (approximately $330 million) and CAD$865 million (approximately $629 million), respectively, were issued by and among us and certain Plains entities.

The cash outflow associated with our investment in promissory notes issued by PAGP to us has an equal and offsetting cash inflow associated with proceeds from the issuance by our consolidated subsidiary of promissory notes to PAGP for the same face value amount, which is included as a component of financing activities.

In February 2025, additional promissory notes with a face value of CAD$473 million (approximately $330 million) were issued by and among us and certain Plains entities.

See Note 16 to our Consolidated Financial Statements for additional information about our related party promissory notes.

See Note 17 to our Consolidated Financial Statements for additional information on our related party promissory notes.

Pending Sale of Canadian NGL Business

This transaction is expected to close around the end of the first quarter of 2026, subject to the satisfaction or waiver of customary closing conditions, including receipt of regulatory approvals.

We expect to receive net proceeds from the sale of approximately $3.2 billion, after taxes, expenses and a potential special one-time distribution that is subject to approval by the board of directors of PAGP GP.

Any proceeds from the pending sale of the Canadian NGL Business will be used to reduce leverage.

See Note 1 to our Consolidated Financial Statements for additional information regarding the pending sale of the Canadian NGL Business.

Financing Activities

Our financing activities primarily relate to funding investment capital projects, acquisitions and refinancing of our debt maturities, as well as short-term working capital (including borrowings for NYMEX and ICE margin deposits) and hedged inventory borrowings related to our NGL business and contango market activities.

Index to Financial Statements

Borrowings and Repayments Under Credit Arrangements

Borrowings and Repayments Under Credit Agreements and Term Loans

During the year ended December 31, 2025, we had net borrowings under our commercial paper program of $577 million.

The net borrowings resulted primarily from funding needs for EPIC acquisition.

See Note 8 to our Consolidated Financial Statements for additional information regarding this acquisition.

During the year ended December 31, 2024, we had net repayments under our commercial paper program of $40 million.

The net repayments resulted primarily from cash flow from operating activities and proceeds from the issuance of $650 million, 5.70% senior notes in June 2024, which offset borrowings during the year related to funding needs for capital investments, inventory purchases, repayment of $750 million, 3.60% senior notes due November 2024, and other general partnership purposes.

During the year ended December 31, 2023, we had net borrowings under our commercial paper program of $433 million.

The net borrowings resulted primarily from borrowings during the year related to funding needs for capital investments, inventory purchases and other general partnership purposes.

In connection with the EPIC acquisition completed in November 2025, we assumed the EPIC credit agreement, which provided for a $1.2 billion term loan (the “EPIC term loan”) and a $125 million revolving credit facility.

In November 2025, we entered into a term loan agreement that provides for a $1.1 billion senior unsecured term loan.

On December 1, 2025, we used the proceeds from this term loan to repay the $1.1 billion of borrowings outstanding under the EPIC term loan and terminated the EPIC credit agreement.

The closing of the Canadian NGL Business divestiture will trigger mandatory prepayment of all amounts outstanding under the term loan agreement within seven business days of the closing of such divestiture.

We intend to use a portion of the proceeds from the pending sale of the Canadian NGL Business to repay the borrowings outstanding under the term loan.

See Note 11 for additional information regarding the EPIC credit agreement and the term loan agreement.

Index to Financial Statements

Issuances of Senior Notes.

We did not issue any senior unsecured notes during 2023.

During 2024, we issued senior unsecured notes as summarized in the table below (in millions):

Year Description Maturity Face Value Gross

2024 5.70% Senior Notes issued at 99.953% of face value September 2034 $ 650 $ 650 $ 643 (3)

During 2025 and 2024, we issued senior unsecured notes as summarized in the table below (in millions):

Issuance Date

Description Maturity Face Value Gross

November 14, 2025 4.70% senior notes issued at 99.872%

of face value

$ 300 $ 300 $ 297 (3)

November 14, 2025 5.60% senior notes issued at 100.518%

of face value

$ 450 $ 452 $ 448 (3)

September 8, 2025 4.70% senior notes issued at 99.865%

of face value

January 2031 $ 700 $ 699 $ 693 (4)

September 8, 2025 5.60% senior notes issued at 99.798%

of face value

$ 550 $ 549 $ 544 (4)

January 15, 2025 5.95% senior notes issued at 99.761%

of face value

$ 1,000 $ 998 $ 988 (5)

June 27, 2024 5.70% senior notes issued at 99.953%

of face value

September 2034 $ 650 $ 650 $ 643 (6)

(1) Face value of notes less the applicable premium or discount (before deducting for initial purchaser discounts, commissions and offering expenses).

(2) Face value of notes less the applicable premium or discount, initial purchaser discounts, commissions and offering expenses.

(3) We used the net proceeds from these offerings for general partnership purposes.

(4) We used the net proceeds from these offerings to (i) redeem on October 3, 2025 the principal amount of our $1.0 billion, 4.65% senior notes due October 2025 and (ii) fund a portion of the purchase price for the EPIC Pipeline acquisition.

See Note 8 to our Consolidated Financial Statements for additional information regarding this acquisition.

(5) We used the net proceeds from this offering to (i) fund the acquisitions completed during the first quarter of 2025, (ii) fund the repurchase in January 2025 of 12.7 million Series A preferred units, including accrued and unpaid distributions and (iii) repay outstanding borrowings under our credit facilities and commercial paper program, and, pending such uses, for general partnership purposes.

See Note 8 and Note 12 to our Consolidated Financial Statements for additional information regarding our recently completed acquisitions and our Series A preferred units, respectively.

(6) We used the net proceeds from the offering, along with other cash on hand, to repay on November 1, 2024 the principal amount of our $750 million, 3.60% senior notes due November 2024.

Prior to such repayment, we used a portion of the net proceeds from the offering to repay outstanding borrowings under our commercial paper program and for general partnership purposes.

In January 2025, we also completed the offering of $1 billion, 5.95% senior notes due June 2035 at a public offering price of 99.761%.

Interest payments are due on June 15 and December 15 of each year, commencing on June 15, 2025.

We used the net proceeds from this offering of approximately $988 million, after deducting the underwriting discount and offering expenses, to (i) fund the acquisitions completed during the first quarter of 2025, (ii) fund the repurchase in January 2025 of 12.7 million Series A preferred units, including accrued and unpaid distributions and (iii) repay outstanding borrowings under our credit facilities and commercial paper program, and, pending such uses, for general partnership purposes.

See Note 7 and Note 11 to our Consolidated Financial Statements for additional information regarding our recently completed acquisitions and our Series A preferred units, respectively.

Repayments of Senior Notes.

During 2025 and 2024, we repaid the following senior unsecured notes in full (in millions):

Year Description Repayment Date

2024 $750 million 3.60% Senior Notes due November 2024 November 2024 (1)

2023 $700 million 3.85% Senior Notes due October 2023 October 2023 (2)

2023 $400 million 2.85% Senior Notes due January 2023 January 2023 (2)

(1) We repaid these senior notes with proceeds from our 5.70% senior notes issued in June 2024, cash on hand and borrowings under our commercial paper program.

(2) We repaid these senior notes with cash on hand and borrowings under our commercial paper program.

Repayment Date

Description Maturity

October 3, 2025 $1,000 million 4.65% senior notes

November 1, 2024 $750 million 3.60% senior notes

November 2024 (2)

(1) We repaid these senior notes with a combination of proceeds from our senior notes issued in September 2025, cash on hand and borrowings under our commercial paper program.

(2) We repaid these senior notes with a combination of proceeds from our senior notes issued in June 2024, cash on hand and borrowings under our commercial paper program.

Index to Financial Statements

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We also have access to a universal shelf registration statement (“WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs.

The offerings of $650 million, 5.70% senior notes in June 2024 and $1 billion, 5.95% senior notes in January 2025 were conducted under our WKSI Shelf.

The offerings of our senior notes during 2025 were conducted under our WKSI Shelf.

Common Equity Repurchase Program

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Any common units or PAGP Class A shares that are repurchased will be canceled.

There were no repurchases under the Program during the years ended December 31, 2024 and 2023.

We repurchased approximately 0.5 million common units under the Program during the year ended December 31, 2025 for a total purchase price of $8 million, including commissions and fees.

There were no repurchases under the Program during the year ended December 31, 2024.

The remaining available capacity under the Program as of December 31, 2025 was $190 million.

Preferred Unit Repurchase

On January 31, 2025, we repurchased 12.7 million units, or 18%, of our outstanding Series A preferred units at the issue price of $26.25 per unit for a purchase price of approximately $333 million, plus accrued and unpaid distributions through January 30, 2025 of approximately $10 million.

On January 31, 2025, we repurchased approximately 12.7 million units, or 18%, of our outstanding Series A preferred units at the issue price of $26.25 per unit for a purchase price of approximately $333 million, plus accrued and unpaid distributions through January 30, 2025 of approximately $10 million.

We used a portion of the net proceeds from our January 2025 senior notes offering to fund this repurchase.

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The distribution rate for the quarterly distribution paid on February 17, 2026 was 8.22342% per annum ($21.02 per Series B preferred unit).

Index to Financial Statements

Distributions to our common unitholders.

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The total distribution of $295 million was paid to common unitholders of record as of January 30, 2026, with respect to the quarter ended December 31, 2025.

Index to Financial Statements

See Note 12 to our Consolidated Financial Statements for details of distributions paid during the three years ended December 31, 2025.

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Related Party Promissory Notes

In July 2024, promissory notes with a face value of CAD$865 million (approximately $629 million) were issued by and among us and certain Plains entities.

The cash inflow associated with proceeds from the issuance by our consolidated subsidiary of promissory notes to PAGP has an equal and offsetting cash outflow associated with our investment in promissory notes issued by PAGP to us for the same face value amount, which is included as a component of investing activities.

In February 2025, additional promissory notes with a face value of CAD$473 million (approximately $330 million) were issued by and among us and certain Plains entities.

See Note 16 to our Consolidated Financial Statements for additional information about our related party promissory notes.

See Note 17 to our Consolidated Financial Statements for additional information on our related party promissory notes.

Contingencies

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Purchase Obligations

In the ordinary course of doing business, we purchase crude oil and NGL from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years, with a limited number of contracts with remaining terms extending up to 10 years.

In the ordinary course of doing business, we purchase crude oil from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years, with a limited number of contracts with remaining terms extending up to 10 years.

We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other.

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2026 2027 2028 2029 2030 2031 and Thereafter Total

Crude oil, NGL and other purchases (1)

Crude oil and other purchases (1)

$ 21,085 $ 17,286 $ 14,974 $ 13,799 $ 11,748 $ 22,806 $ 101,698

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Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items as customer relationships, acreage dedications and other contracts, involves professional judgment and is ultimately based on acquisition models and management’s assessment of the value of the assets acquired and, to the extent available, third-party assessments.

In the third quarter of 2023, our Permian JV acquired the remaining 43% interest in OMOG JV Holdings LLC (“OMOG”) and certain gathering assets in the Southern Delaware basin from Rattler Midstream Operating LLC.

The transaction had an aggregate purchase price of $294 million ($191 million net to our 65% interest in the Permian JV).

As a result of the transaction, the Permian JV now owns 100% of OMOG and its subsidiaries and such entities are reflected as consolidated subsidiaries in our Consolidated Financial Statements.

Prior to this transaction, the Permian JV’s 57% interest in OMOG was accounted for as an equity method investment.

See Note 7 to our Consolidated Financial Statements for discussion of the methods, assumptions and estimates used in the determination of the fair value of the assets and liabilities acquired and identification of associated intangible assets.

In November 2022, we and Enbridge Inc.

(“Enbridge”) purchased Western Midstream Partners, LP (“WES”)’s 15% interest in Cactus II Pipeline, LLC (“Cactus II”) for an aggregate amount of $265 million.

Enbridge acquired 10% and we acquired 5% of Cactus II, with each paying a proportionate share of the purchase price.

We and Enbridge are now the sole owners of Cactus II, with 70% and 30% respective ownership interests.

We previously accounted for our 65% interest in Cactus II as an equity method investment.

In addition to the change in ownership, there were changes in governance which led to a change in control.

We now control Cactus II and reflect Cactus II as a consolidated subsidiary in our Consolidated Financial Statements, with Enbridge’s 30% interest reflected as a noncontrolling interest.

Through two separate transactions completed in the fourth quarter of 2025, we acquired 100% of the entity that owns EPIC Crude Oil Pipeline for aggregate consideration of approximately $2.9 billion, inclusive of approximately $1.1 billion of debt assumed.

We also agreed to aggregate potential earnout payments of up to approximately $350 million.

On January 31, 2025, we acquired Ironwood Midstream Energy Partners II, LLC (“Ironwood Midstream”), which owns a gathering system in the Eagle Ford Basin, for approximately $481 million in cash.

See Note 8 to our Consolidated Financial Statements for discussion of the methods, assumptions and estimates used in the determination of the fair value of the assets and liabilities acquired and identification of associated intangible assets for these transactions.

Fair Value of Derivatives.

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We reflect estimates for these items based on our internal records and information from third parties.

We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value on our Consolidated Balance Sheets.

We have commodity, interest rate and foreign currency derivatives that are accounted for as assets and liabilities at fair value on our Consolidated Balance Sheets.

The valuations of our derivatives that are exchange traded are based on market prices on the applicable exchange on the last day of the period.

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Quantitative and Qualitative Disclosures About Market Risk and Note 13 to our Consolidated Financial Statements for a discussion regarding our derivatives and risk management activities.

Index to Financial Statements

Accruals and Contingent Liabilities.

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Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

Index to Financial Statements

Property and Equipment, Depreciation and Amortization Expense and Asset Retirement Obligations.

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In addition, when we evaluate property and equipment and other long-lived assets for recoverability, it may also be necessary to review related depreciation estimates and methods.

Index to Financial Statements

Investments in unconsolidated entities accounted for under the equity method of accounting are assessed for impairment when events or circumstances suggest that a decline in value may be other than temporary.

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• the fair value of the investment.

Index to Financial Statements

Intangible assets with indefinite lives are not amortized but are instead periodically assessed for impairment.

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See Note 6 to our Consolidated Financial Statements for further discussion regarding inventory.

Line 901 Incident Insurance Receivable.

In May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California.

As of December 31, 2024, we have estimated that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $870 million, which includes actual and projected emergency response and clean-up costs, natural resource damage assessments, fines and penalties incurred, certain third-party claims settlements, and estimated costs associated with our remaining Line 901 lawsuits and claims, as well as estimates for certain legal fees and statutory interest where applicable.

We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such liabilities.

In November 2022, we submitted claims to several of our insurance carriers seeking reimbursement for a payment made in October of 2022 to settle a class action lawsuit stemming from the Line 901 incident.

As of December 31, 2023, we had recognized a receivable of approximately $225 million, of which we had classified $175 million as a short-term asset with the remaining $50 million recognized as a long-term asset.

As of December 31, 2023, we believed that our claim for reimbursement was probable of recovery despite the ongoing arbitration proceedings.

However, at that time we also noted that various factors could impact the timing and amount of recovery of our insurance receivable, including future developments that adversely impacted our assessment of the strength of our coverage claims, the outcome of any dispute resolution proceedings with respect to our coverage claims (including arbitration proceedings) and the extent to which insurers may become insolvent in the future.

Due to these factors, we noted that we could not provide complete assurance that actual receivable amounts recovered would not vary significantly from our estimated amounts.

Index to Financial Statements

A binding arbitration hearing with respect to our insurance claim against insurers representing $175 million of our total $225 million reimbursement claim concluded in early October 2024, and the arbitration panel’s final and binding decision was returned in January 2025.

The panel ruled that a substantial portion of our claims subject to the proceeding were not covered

under the applicable policy and therefore we were not entitled to reimbursement of our $175 million claim against the applicable insurers.

With respect to our remaining $50 million claim against different insurance carriers, we now regard collection of those claims as being less than “probable.” As a result, we wrote off the entire $225 million receivable in the fourth quarter of 2024 and will recognize any future collections as and if they are received.

See Note 18 to our Consolidated Financial Statements for further discussion regarding the Line 901 incident and our related insurance receivable.

Recent Accounting Pronouncements

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis