10-K – 2026-02-27 – paa-20251231.htm

Equity earnings in unconsolidated entities 382  452  (70) (15) %
Gain on investments in unconsolidated entities, net
31  15  16  107  %
Interest expense, net (1)
(554) (430) (124) (29) %
Other income, net (1)
108  64  44  69  %
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  %
Net income
$ 1,769  $ 1,113  $ 656  59  %
Net income attributable to noncontrolling interests (334) (341) 7  2  %
Net income attributable to PAA $ 1,435  $ 772  $ 663  86  %

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  —  %

(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.
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Continuing Operations

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

Revenues and Purchases

Fluctuations in our revenues and purchases and related costs are primarily associated with our merchant activities and are generally explained by changes in commodity prices and the impact of gains and losses related to derivative instruments used to manage our commodity price exposure. Because both product sales revenues and purchases and related costs are generally based off of the same pricing indices, the market price of the commodities will not necessarily have an impact on the absolute margins related to those sales and purchases.

A majority of our crude oil sales and purchases are indexed to the prompt month price of the NYMEX Light, Sweet crude oil futures contract (“NYMEX Price”). The following table presents the range of the NYMEX Price over the last two years (in dollars per barrel):

NYMEX Price
During the Year Ended December 31,  Low High Average
2025 $ 55  $ 80  $ 65 
2024 $ 66  $ 87  $ 76 

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.

Field Operating Costs

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

General and Administrative Expenses

The increase in general and administrative expenses for the 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 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.
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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.

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

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

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.

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

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

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. As such, the interest expense and interest income associated with these notes is presented on a net basis in the reconciliation of these metrics to Net Income. See the “—Non-GAAP Financial Measures” section below. 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.

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

Year Ended December 31,
2025 2024
Interest expense on third-party borrowings (1)
$ 478  $ 391 
Interest expense on related party promissory notes (2)
87  48 
Capitalized interest
(11) (9)
$ 554  $ 430 

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

Year Ended December 31,
2025 2024
Interest income on related party promissory notes (1)
$ 87  $ 48 
Interest income from other sources
21  22 
Net loss on foreign currency revaluation (2)
(1) (10)

Other 1  4 
$ 108  $ 64 

(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

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

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

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Non-GAAP Financial Performance Measures

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

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

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

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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):

Year Ended December 31, Variance

2025 2024 $ %
Net income (1)
$ 1,769  $ 1,113  $ 656  59  %
Interest expense, net of certain items (2)
467  382  85  22  %
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)
21  1  20  **

Gain on investments in unconsolidated entities, net
(31) (15) (16) (107) %
Depreciation and amortization of unconsolidated entities (4)
84  84  —  —  %
Selected Items Impacting Comparability (1) :

Derivative activities and inventory valuation adjustments
(108) 85  (193) **
Long-term inventory costing adjustments
48  (9) 57  **
Deficiencies under minimum volume commitments, net
(38) (31) (7) **
Rail fleet amortization expense related to discontinued operations (5)
(18) —  (18) **
Equity-indexed compensation expense
37  36  1  **
Foreign currency revaluation
15  (27) 42  **
Line 901 incident
—  345  (345) **
Transaction-related expenses
17  —  17  **
Selected Items Impacting Comparability - Segment Adjusted EBITDA (1) (6)
(47) 399  (446) **

Foreign currency revaluation (7)
1  10  (9) **

Selected Items Impacting Comparability - Adjusted EBITDA (1) (8)
(46) 409  (455) **
Adjusted EBITDA (1) (8)
$ 3,374  $ 3,326  $ 48  1  %
Adjusted EBITDA attributable to noncontrolling interests (9)
(541) (547) 6  1  %
Adjusted EBITDA attributable to PAA (1)
$ 2,833  $ 2,779  $ 54  2  %

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Year Ended December 31, Variance
2025 2024 $ %
Adjusted EBITDA (1) (8) (10)
$ 3,374  $ 3,326  $ 48  1  %
Interest expense, net of certain non-cash and other items (11)
(452) (365) (87) (24) %
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 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)
22  11  11  **
Distributions to noncontrolling interests (15)
(447) (425) (22) (5) %
Implied DCF (1)
$ 2,063  $ 2,005  $ 58  3  %
Preferred unit distributions (15)
(225) (254)
Implied DCF Available to Common Unitholders (1)
$ 1,838  $ 1,751 
Common unit cash distributions (15)
(1,070) (891)
Implied DCF Excess (1) (16)
$ 768  $ 860 

**     Indicates that variance as a percentage is not meaningful.
(1) Includes results from continuing operations and discontinued operations.
(2) Represents “Interest expense, net” as reported on our 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.
(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.
(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.
(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.
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(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.
(13) Investment capital expenditures attributable to noncontrolling interests that reduce Implied DCF available to PAA common unitholders.
(14) Comprised of cash distributions received from unconsolidated entities less equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization, including write-downs related to cancelled projects, and selected items impacting comparability of unconsolidated entities).
(15) Cash distributions paid during the period presented.
(16) Excess DCF is retained to establish reserves for debt repayment, future distributions, common equity repurchases, capital expenditures and other partnership purposes.

Analysis of Operating Segments

We manage our operations through two operating segments: Crude Oil and NGL. Our 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 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. Intersegment transactions are conducted at rates similar to those charged to third parties or rates that we believe approximate market. Intersegment activities are eliminated in consolidation and we believe that the estimates with respect to these rates are reasonable. Also, our segment operating and general and administrative expenses reflect direct costs attributable to each segment; however, we also allocate certain operating expenses and general and administrative overhead expenses between segments based on management’s assessment of the business activities for the period. The proportional allocations by segment require judgment by management and may be adjusted in the future based on the business activities that exist during each period. We believe that the estimates with respect to these allocations are reasonable.

Revenues and expenses from our Canadian based subsidiaries, which use CAD as their functional currency, are translated at the prevailing average exchange rates for the month.

Crude Oil Segment

Our Crude Oil segment operations generally consist of gathering and transporting crude oil using pipelines (including gathering systems), trucks and, at times, on barges or railcars, in addition to providing terminalling, storage and other related services utilizing our integrated assets across the United States and Canada. Our assets provide services to third parties as well as to our merchant activities. Our merchant activities include the purchase of crude oil supply and the movement of this supply on our assets or third-party assets to sales locations, including our terminals, third-party connecting carriers, regional hubs or to refineries. Our merchant activities are governed by our risk management policies.

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Our Crude Oil segment generates revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees, month-to-month and multi-year storage and terminalling agreements and the sale of gathered and bulk-purchased crude oil. Tariffs and other fees on our pipeline systems are typically based on volumes transported and vary by receipt point and delivery point. Fees for our terminalling and storage services are based on capacity leases and throughput volumes. Generally, results from our merchant activities are impacted by (i) increases or decreases in our lease gathering crude oil purchases volumes and (ii) volatility in commodity price differentials, particularly grade and location differentials, as well as time spreads. The segment results also include the direct fixed and variable field costs of operating the crude oil assets, as well as an allocation of indirect operating and general and administrative costs.

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

Operating Results  (1)
(in millions)
Year Ended December 31, Variance

2025 2024 $ %
Revenues $ 44,131  $ 48,720  $ (4,589) (9) %

Purchases and related costs (2)
(40,323) (45,033) 4,710  10  %
Field operating costs (2)
(1,127) (1,440) 313  22  %
Segment general and administrative expenses  (2) (3)
(314) (298) (16) (5) %
Equity earnings in unconsolidated entities
382  452  (70) (15) %

Other segment items (4) :

Depreciation and amortization of unconsolidated entities
84  84  —  —  %
Derivative activities and inventory valuation adjustments (23) 5  (28) **
Long-term inventory costing adjustments
45  1  44  **
Deficiencies under minimum volume commitments, net
(38) (31) (7) **
Equity-indexed compensation expense
37  36  1  **
Foreign currency revaluation
12  (22) 34  **
Line 901 incident
—  345  (345) **
Transaction-related expenses
17  —  17  **
Segment amounts attributable to noncontrolling interests
(539) (543) 4  **
Segment Adjusted EBITDA $ 2,344  $ 2,276  $ 68  3  %

Maintenance capital expenditures
$ 153  $ 183  $ (30) (16) %

Average Volumes Year Ended December 31, Variance

2025 2024 Volumes %
Crude oil pipeline tariff (by region) (5) (6)

Permian Basin
7,333  6,731  602  9  %
South Texas / Eagle Ford
521  403  118  29  %
Mid-Continent
518  506  12  2  %

Other
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.
(1) Revenues and costs and expenses include intersegment amounts.
(2) Represents components of significant segment expenses.
(3) 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.
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(4) Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 20 to our Consolidated Financial Statements for additional discussion of such adjustments.
(5) Average daily volumes in thousands of barrels per day calculated as the total volumes (attributable to our interest for assets owned by unconsolidated entities or through UJIs) for the year divided by the number of days in the year. 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.
(6) Includes volumes (attributable to our interest) from assets owned by unconsolidated entities.

Segment Adjusted EBITDA

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 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. 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 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.

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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)
(in millions)
Year Ended December 31, Variance

2025 2024 $ %
Revenues $ 151  $ 187  $ (36) (19) %

Purchases and related costs (2)
(130) (147) 17  12  %
Field operating costs (2) (3)
(27) (31) 4  13  %
Segment general and administrative expenses (2) (3) (4)
(28) (30) 2  7  %

Segment Adjusted EBITDA
$ (34) $ (21) $ (13) (62) %

Maintenance capital expenditures
$ 3  $ 4  $ (1) (25) %

(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.

Segment Adjusted EBITDA

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

General

Our primary sources of liquidity are (i) cash flow from operating activities and (ii) borrowings under our credit facilities or commercial paper program. In addition, we may supplement these primary sources of liquidity with proceeds from asset sales, and in the past have utilized funds received from sales of equity and debt securities. Our primary cash requirements include, but are not limited to, (i) ordinary course of business uses, such as the payment of amounts related to the purchase of crude oil, NGL and other products, payment of other expenses and interest payments on outstanding debt, (ii) investment and maintenance capital activities, (iii) acquisitions of assets or businesses, (iv) repayment of principal on our long-term debt and (v) distributions to our unitholders and noncontrolling interests. In addition, we may use cash for repurchases of common equity. We generally expect to fund our short-term cash requirements through cash flow generated from operating activities and/or borrowings under our credit facilities or commercial paper program. In addition, we generally expect to fund our long-term needs, such as those resulting from investment capital activities, acquisitions or refinancing our long-term debt, through a variety of sources, which may include any or a combination of the sources listed above.

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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):

As of
December 31, 2025

Availability under senior unsecured revolving credit facility (1) (2)
$ 1,350 
Availability under senior secured hedged inventory facility (1) (2)
1,298 
Amounts outstanding under commercial paper program (970)
Subtotal 1,678 
Cash and cash equivalents
328 
Total $ 2,006 

(1) Represents availability prior to giving effect to borrowings outstanding under our commercial paper program, which reduce available capacity under the facilities.
(2) Available capacity under our senior unsecured revolving credit facility and senior secured hedged inventory facility was reduced by outstanding letters of credit issued under these facilities of less than $1 million and $52 million, respectively.

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. Our borrowing capacity and borrowing costs are also impacted by our credit rating. See Item 1A. “Risk Factors—Risks Related to Our Business—Loss of our investment grade credit rating or the ability to receive open credit could negatively affect our borrowing costs, ability to purchase crude oil, NGL and natural gas supplies or to capitalize on market opportunities.”

We believe that we have, and will continue to have, the ability to access our commercial paper program and credit facilities, which we use to meet our short-term cash needs. We believe that our financial position remains strong and we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow, including extended disruptions in the financial markets and/or energy price volatility resulting from current macroeconomic and geopolitical conditions, including actions by OPEC. A prolonged material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity and cost of borrowing. See Item 1A. “Risk Factors” for further discussion regarding risks that may impact our liquidity and capital resources.

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), 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.

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Non-GAAP Financial Liquidity Measures

Management uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. Adjusted Free Cash Flow is defined as Net cash provided by operating activities, less Net cash provided by/(used in) investing activities, which primarily includes acquisition, investment and maintenance capital expenditures, investments in unconsolidated entities and related party notes and the net impact from the purchase and sale of linefill, net of proceeds from the sales of assets and further impacted by distributions to and contributions from noncontrolling interests and proceeds from the issuance of related party notes. Adjusted Free Cash Flow is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Adjusted Free Cash Flow after Distributions.

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,
2025 2024
Net cash provided by operating activities
$ 2,936  $ 2,490 
Adjustments to reconcile net cash provided by operating activities to adjusted free cash flow:

Net cash used in investing activities (1)
(3,769) (1,504)
Cash contributions from noncontrolling interests 75  57 
Cash distributions paid to noncontrolling interests (2)
(447) (425)
Proceeds from the issuance of related party notes (1)
330  629 

Adjusted Free Cash Flow
$ (875) $ 1,247 
Cash distributions (3)
(1,295) (1,145)
Adjusted Free Cash Flow after Distributions (4)
$ (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.
(2) Cash distributions paid during the period presented.
(3) Cash distributions paid to our preferred and common unitholders during the period presented.
(4) Excess Adjusted Free Cash Flow after Distributions is retained to establish reserves for future distributions, capital expenditures, debt reduction and other partnership purposes. Adjusted Free Cash Flow after Distributions shortages, if any, may be funded from previously established reserves, cash on hand or from borrowings under our credit facilities or commercial paper program.

Cash Flow from Operating Activities

The primary drivers of cash flow from operating activities are (i) the collection of amounts related to the sale of crude oil, NGL and other products, the transportation of crude oil and other products for a fee, and the provision of storage and terminalling services for a fee and (ii) the payment of amounts related to the purchase of crude oil, NGL and other products and other expenses, principally field operating costs, general and administrative expenses and interest expense.

Cash flow from operating activities can be materially impacted by the storage of crude oil in periods of a contango market, when the price of crude oil for future deliveries is higher than current prices. In the month we pay for the stored crude oil, we borrow under our credit facilities or commercial paper program (or use cash on hand) to pay for the crude oil, which negatively impacts operating cash flow. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the stored crude oil. Similarly, the level of NGL and other product inventory stored and held for resale at period end affects our cash flow from operating activities.

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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. During such market conditions, our accounts payable and accounts receivable generally move in tandem as we make payments and receive payments for the purchase and sale of crude oil in the same month, which is the month following such activity. In periods during which we build inventory, regardless of market structure, we may rely on our credit facilities or commercial paper program to pay for the inventory. In addition, we use derivative instruments to manage the risks associated with the purchase and sale of our commodities. Therefore, our cash flow from operating activities may be impacted by the margin deposit requirements related to our derivative activities. See Note 13 to our Consolidated Financial Statements for a discussion regarding our derivatives and risk management activities.

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

Capital Expenditures

In addition to our operating needs, we also use cash for our investment capital projects, maintenance capital activities and acquisition activities. We fund these expenditures with cash generated by operating activities, financing activities and/or proceeds from asset sales. 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 related to continuing operations and discontinued operations (in millions):

Net to PAA (1) (2)
Consolidated (2)
Continuing Operations

Year Ended December 31,
Year Ended December 31,
Year Ended December 31,

Capital Expenditures (3) (4)
2025 2024 2025 2024 2025 2024
Crude Oil:

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 

NGL:

Investment capital
$ 99  $ 115  $ 99  $ 115  $ —  $ — 
Maintenance capital
73  78  73  78  3  4 

$ 172  $ 193  $ 172  $ 193  $ 3  $ 4 

Total:

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

Investment Capital Projects

Our investment capital programs consist of investments in midstream infrastructure projects that build upon our core assets and operations. 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 related to continuing operations and discontinued operations (in millions):

Year Ended December 31,
Projects 2025 2024
Complementary Permian Basin Projects (1)
$ 308  $ 249 
Permian Basin Takeaway Pipeline Projects
39  5 

NGL Projects
99  115 
Other Projects 173  46 
Total $ 619  $ 415 

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

Projected 2026 Capital Expenditures.  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 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. 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

We are continuously engaged in the evaluation of potential transactions that support our current business strategy. In the past, such transactions have included the acquisition of assets that complement our existing footprint, the sale of non-core assets, the sale of partial interests in assets to strategic joint venture partners, and large investment capital projects. With respect to a potential acquisition or divestiture, we may conduct an auction process or participate in an auction process conducted by a third party or we may negotiate a transaction with one or a limited number of potential sellers (in the case of an acquisition) or buyers (in the case of a divestiture). Such transactions could have a material effect on our financial condition and results of operations.

We typically do not announce a transaction until after we have executed a definitive agreement. In certain cases, in order to protect our business interests or for other reasons, we may defer public announcement of a transaction until closing or a later date. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future efforts with respect to any such transactions will be successful, and we can provide no assurance that our financial expectations with respect to such transactions will ultimately be realized. See Item 1A. “Risk Factors—Risks Related to Our Business—Acquisitions and divestitures involve risks that may adversely affect our business.”
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Related Party Promissory Notes

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

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 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, and the payment of distributions to our unitholders and noncontrolling interests. 

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.

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.

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Senior Notes

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

Issuance Date
Description Maturity Face Value Gross
Proceeds (1)
Net
Proceeds (2)

November 14, 2025 4.70% senior notes issued at 99.872%
of face value
January 2031
$ 300  $ 300  $ 297  (3)

November 14, 2025 5.60% senior notes issued at 100.518%
of face value
January 2036
$ 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
January 2036
$ 550  $ 549  $ 544  (4)

January 15, 2025 5.95% senior notes issued at 99.761%
of face value
June 2035
$ 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.

Repayments of Senior Notes.  During 2025 and 2024, we repaid the following senior unsecured notes in full (in millions):

Repayment Date
Description Maturity

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

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.

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Registration Statements

We periodically access the capital markets for both equity and debt financing. We have filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to a specified amount of debt or equity securities (“Traditional Shelf”), under which we had approximately $1.1 billion of unsold securities available at December 31, 2025. We did not conduct any offerings under our Traditional Shelf during the year 2025. We also have access to a universal shelf registration statement (“WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. The offerings of our senior notes during 2025 were conducted under our WKSI Shelf.

Common Equity Repurchase Program

In November 2020, the board of directors of PAGP GP approved a $500 million common equity repurchase program (the “Program”) to be utilized as an additional method of returning capital to investors. The Program authorizes the repurchase from time to time of up to $500 million of our common units and/or PAGP Class A shares via open market purchases or negotiated transactions conducted in accordance with applicable regulatory requirements. Ultimately, the amount, timing and pace of potential repurchase activity will be determined by a number of factors, including market conditions, our financial performance and flexibility, actual and expected free cash flow after distributions, the absolute and relative equity prices of our common units and PAGP Class A shares, and the extent to which we are positioned to achieve and maintain our targeted leverage ratio. No time limit has been set for completion of the Program, and the Program may be suspended or discontinued at any time. The Program does not obligate us or PAGP to acquire a particular number of common units or PAGP Class A shares. Any common units or PAGP Class A shares that are repurchased will be canceled.

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 approximately 12.7 million units, or 18%, of our outstanding Series A preferred units at the issue price of $26.25 per unit for a purchase price of approximately $333 million, plus accrued and unpaid distributions through January 30, 2025 of approximately $10 million. We used a portion of the net proceeds from our January 2025 senior notes offering to fund this repurchase. See Note 12 to our Consolidated Financial Statements for more information regarding our Series A preferred units.

Distributions to Our Unitholders

In accordance with our partnership agreement, after making distributions to holders of our outstanding preferred units, we distribute the remainder of our available cash to our common unitholders of record within 45 days following the end of each quarter. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. Our levels of financial reserves are established by our general partner and include reserves for the proper conduct of our business (including future capital expenditures and anticipated credit needs), compliance with legal or contractual obligations and funding of future distributions to our Series A and Series B preferred unitholders. Our available cash also includes cash on hand resulting from borrowings made after the end of the quarter. See Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy” for additional discussion regarding distributions.

Distributions to our Series A preferred unitholders. Holders of our Series A preferred units are entitled to receive quarterly distributions, subject to customary anti-dilution adjustments, of $0.615 per unit ($2.46 per unit annualized).

Distributions to our Series B preferred unitholders.  Holders of our Series B preferred units are entitled to receive, when, as and if declared by our general partner out of legally available funds for such purpose, cumulative cash distributions, as applicable. Distributions on the Series B preferred units accumulate based on the applicable three-month SOFR, plus a credit spread adjustment of 0.26161%, plus 4.11% per annum. The distribution rate for the quarterly distribution paid on February 17, 2026 was 8.22342% per annum ($21.02 per Series B preferred unit).

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Distributions to our common unitholders. On February 13, 2026, we paid a quarterly distribution of $0.4175 per common unit ($1.67 per common unit on an annualized basis). 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.

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

Distributions to Noncontrolling Interests

Distributions to noncontrolling interests represent amounts paid on interests in consolidated entities that are not owned by us. As of December 31, 2025, noncontrolling interests in our subsidiaries consisted of (i) a 35% interest in the Permian JV, (ii) a 30% interest in Cactus II and (iii) a 33% interest in Red River. See Note 12 to our Consolidated Financial Statements for details of distributions paid to noncontrolling interests during the three years ended December 31, 2025.

Related Party Promissory Notes

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 inflow associated with proceeds from the issuance by our consolidated subsidiary of promissory notes to PAGP has an equal and offsetting cash outflow associated with our investment in promissory notes issued by PAGP to us for the same face value amount, which is included as a component of investing activities. See Note 17 to our Consolidated Financial Statements for additional information on our related party promissory notes.

Contingencies

For a discussion of contingencies that may impact us, see Note 19 to our Consolidated Financial Statements.

Commitments

See Note 11 to our Consolidated Financial Statements for information regarding our debt obligations and Note 19 for information regarding our leases and other commitments.

Purchase Obligations

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. We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy or who have provided credit support we consider adequate.

The following table includes our best estimate of the amount and timing of these payments as of December 31, 2025 (in millions):

2026 2027 2028 2029 2030 2031 and Thereafter Total
Crude oil and other purchases (1)
$ 21,085  $ 17,286  $ 14,974  $ 13,799  $ 11,748  $ 22,806  $ 101,698 

(1) Amounts are primarily based on estimated volumes and market prices based on average activity during December 2025. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.

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Letters of Credit. In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the product is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At December 31, 2025 and 2024, we had outstanding letters of credit of approximately $95 million and $90 million, respectively.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements as defined by Item 303 of Regulation S-K.

Investments in Unconsolidated Entities

We have invested in entities that are not consolidated in our financial statements. None of these entities had debt outstanding as of December 31, 2025. We may elect at any time to make additional capital contributions to any of these entities. The following table sets forth selected information regarding these entities as of December 31, 2025 (unaudited, dollars in millions):

Entity Type of Operation Our
Ownership
Interest Total 
Entity
Assets Total Cash
and
Restricted
Cash
BridgeTex Pipeline Company, LLC Crude Oil Pipeline 40% $ 717  $ 36 
Capline Pipeline Company LLC Crude Oil Pipeline 54% $ 1,171  $ 34 
Diamond Pipeline LLC Crude Oil Pipeline (1)
50% $ 843  $ 14 
Eagle Ford Pipeline LLC Crude Oil Pipeline (1)
50% $ 735  $ 15 
Eagle Ford Terminals Corpus Christi LLC Crude Oil Terminal and Dock (1)
50% $ 200  $ 5 
Saddlehorn Pipeline Company, LLC Crude Oil Pipeline 40% $ 562  $ 23 
White Cliffs Pipeline, L.L.C.
Crude Oil Pipeline 36% $ 305  $ 2 
Wink to Webster Pipeline LLC Crude Oil Pipeline 17% $ 2,268  $ 86 
Other investments $ 396  $ 13 

(1) We serve as operator of the asset.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP and rules and regulations of the SEC requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, as well as the disclosure of contingent assets and liabilities, at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from these estimates. On a regular basis, we evaluate our assumptions, judgments and estimates. We also discuss our critical accounting policies and estimates with the Audit Committee of the Board of Directors.

We believe that the assumptions, judgments and estimates involved in the accounting for our (i) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (ii) fair value of derivatives, (iii) accruals and contingent liabilities, (iv) property and equipment, depreciation and amortization expense and asset retirement obligations, (v) impairment assessments of property and equipment, investments in unconsolidated entities and intangible assets and (vi) inventory valuations have the greatest potential impact on our Consolidated Financial Statements. These areas are key components of our results of operations and are based on complex rules which require us to make judgments and estimates. Therefore, we consider these to be our critical accounting policies and estimates, which are discussed below. For further information on all of our significant accounting policies, see Note 2 to our Consolidated Financial Statements.

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Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets. In accordance with Financial Accounting Standards Board (“FASB”) guidance regarding business combinations, with each acquisition, we allocate the cost of the acquired entity to the assets acquired and liabilities assumed based on their estimated fair values at the date of acquisition. If the initial accounting for the business combination is incomplete when the combination occurs, an estimate will be recorded. We also expense the transaction costs as incurred in connection with each acquisition, except for acquisitions of equity method investments. In addition, we are required to recognize intangible assets separately from goodwill.

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.

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. The fair value of a derivative at a particular period end does not reflect the end results of a particular transaction, and will most likely not reflect the gain or loss at the conclusion of a transaction. We reflect estimates for these items based on our internal records and information from third parties. 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. For our derivatives that are not exchange traded, the estimates we use are based on indicative broker quotations or an internal valuation model. Our valuation models utilize market observable inputs such as price, volatility, correlation and other factors and may not be reflective of the price at which they can be settled due to the lack of a liquid market. Less than 1% of total annual revenues are based on estimates derived from internal valuation models.

Although the resolution of the uncertainties involved in these estimates 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. See Item 7A.  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.

Accruals and Contingent Liabilities.   We record accruals or liabilities for, among other things, environmental remediation, potential legal claims or settlements and fees for legal services associated with loss contingencies, and bonuses. Accruals are made when our assessment indicates that it is probable that a liability has occurred and the amount of liability can be reasonably estimated. Our estimates are based on all known facts at the time 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 environmental 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, the duration of the natural resource damage assessment and the ultimate amount of damages determined, the determination and calculation of fines and penalties, the possibility of existing legal claims giving rise to additional claims and the nature, extent and cost of legal services that will be required in connection with lawsuits, claims and other matters. Our estimates for contingent liability accruals are increased or decreased as additional information is obtained or resolution is achieved. A hypothetical variance of 5% in our aggregate estimate for the accruals and contingent liabilities discussed above would have an impact on earnings of up to approximately $9 million. 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.

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Property and Equipment, Depreciation and Amortization Expense and Asset Retirement Obligations. We compute depreciation and amortization based on estimated useful lives. These estimates are based on various factors including condition, manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives and salvage values that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization.

We record retirement obligations associated with tangible long-lived assets based on estimates related to the costs associated with cleaning, purging and, in some cases, completely removing the assets and returning the land to its original state. In addition, our estimates include a determination of the settlement date or dates for the potential obligation, which may or may not be determinable. Uncertainties that impact these estimates include the costs associated with these activities and the timing of incurring such costs. A hypothetical variance of 5% in our aggregate estimate for the retirement obligations discussed above would have an impact on earnings of up to approximately $6 million. 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.

See Note 7 and Note 10 to our Consolidated Financial Statements for additional information on our property and equipment, intangible assets and depreciation and amortization expense. See Note 2 to our Consolidated Financial Statements for additional information on our asset retirement obligations.

Impairment Assessments of Property and Equipment, Investments in Unconsolidated Entities and Intangible Assets. We periodically evaluate property and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. Any evaluation is highly dependent on the underlying assumptions of related cash flows. We consider the fair value estimate used to calculate impairment of property and equipment a critical accounting estimate. In determining the existence of an impairment of carrying value, we make a number of subjective assumptions as to:

• whether there is an event or circumstance that may be indicative of an impairment;
• the grouping of assets;
• the intention of “holding”, “abandoning” or “selling” an asset;
• the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and
• if an impairment exists, the fair value of the asset or asset group.

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.

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. Examples of such events or circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity’s core business. When it is determined that an indicated impairment is other than temporary, a charge is recognized for the difference between the investment’s carrying amount and its estimated fair value. We consider the fair value estimate used to calculate the impairment of investments in unconsolidated entities a critical accounting estimate. In determining the existence of an other-than-temporary impairment of carrying value, we make a number of subjective assumptions as to:

• whether there is an event or circumstance that may be indicative of a decline in value of the investment;
• whether the decline in value is other than temporary; and
• the fair value of the investment.

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Intangible assets with indefinite lives are not amortized but are instead periodically assessed for impairment. Intangible assets with finite lives are amortized over their estimated useful life as determined by management. Impairment testing entails estimating future net cash flows relating to the business, based on the grouping of assets and management’s estimate of future revenues, future cash flows and market conditions including pricing, demand, competition, operating costs and other factors. Uncertainties associated with these estimates include changes in production decline rates, production interruptions, fluctuations in refinery capacity or product slates, economic obsolescence factors in the area and potential future sources of cash flow. In addition, changes in our weighted average cost of capital from our estimates could have a significant impact on fair value. We cannot provide assurance that actual amounts will not vary significantly from estimated amounts. Resolutions of these uncertainties have resulted, and in the future may result, in impairments that impact our results of operations and financial condition.

A change in our outlook or use could result in impairments that may be material to our results of operations or financial condition. See “—Executive Summary— Market Overview and Outlook” and Note 7, Note 9 and Note 10 to our Consolidated Financial Statements for additional information.

Inventory Valuations.  Inventory, including long-term inventory, primarily consists of crude oil and NGL and is valued at the lower of cost or net realizable value, with cost determined using an average cost method within specific inventory pools. At the end of each reporting period, we assess the carrying value of our inventory and use estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact our estimates are the applicable quality and location differentials to include in our net realizable value analysis. Additionally, we estimate the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value. During the years ended December 31, 2025, 2024 and 2023, we did not record any charges related to the valuation adjustment of our inventory. See Note 6 to our Consolidated Financial Statements for further discussion regarding inventory.

Recent Accounting Pronouncements

See Note 2 to our Consolidated Financial Statements for information regarding the effect of recent accounting pronouncements on our Consolidated Financial Statements.

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

We are exposed to various market risks, including commodity price risk, interest rate risk and currency exchange rate risk. We use various derivative instruments to manage such risks and, in certain circumstances, to realize incremental margin during volatile market conditions. Our risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our exchange-cleared and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. We have a risk management function that has direct responsibility and authority for our risk policies, related controls around commercial activities and certain aspects of corporate risk management. Our risk management function also approves all new risk management strategies through a formal process. The following discussion addresses each category of risk.

Commodity Price Risk

We use derivative instruments to hedge price risk associated with the following commodities:
• Crude oil

We utilize crude oil derivatives to hedge commodity price risk inherent in our pipeline, terminalling and merchant activities. Our objectives for these derivatives include hedging changes in inventory positions associated with our lease gathering activities, anticipated purchases and sales, stored inventory and basis differentials. We manage these exposures with various instruments including futures, forwards, swaps and options.

• Power

We utilize power derivatives to hedge anticipated operational requirements related to our crude oil pipelines. We manage these exposures with various instruments including futures, swaps and options.

See Note 13 to our Consolidated Financial Statements for further discussion regarding our hedging strategies and objectives.
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The fair value of our commodity derivatives and the change in fair value as of December 31, 2025 that would be expected from a 10% price increase or decrease is shown in the table below (in millions):

Fair Value Effect of 10%
Price Increase
Effect of 10%
Price Decrease

Crude oil $ 1  $ (5) $ 5 

Power
(5) $ 1  $ (1)
Total fair value $ (4)

The fair values presented in the table above reflect the sensitivity of the derivative instruments only and do not include the effect of the underlying hedged commodity. Price-risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in near-term commodity prices, the fair value of our derivative portfolio would typically change less than that shown in the table as changes in near-term prices are not typically mirrored in delivery months further out.

Interest Rate Risk

Debt . Our use of variable rate debt and any forecasted issuances of fixed rate debt expose us to interest rate risk. Therefore, from time to time, we use interest rate derivatives to hedge interest rate risk associated with anticipated interest payments and, in certain cases, outstanding debt instruments. We did not have any interest rate derivatives as of December 31, 2025. All of our senior notes are fixed rate notes and thus are not subject to interest rate risk. Our variable rate debt outstanding at December 31, 2025, approximately $2.069 billion, was subject to interest rate resets that generally occur within one month or less. The average interest rate on variable rate debt that was outstanding during the year ended December 31, 2025 was 4.6%, based upon rates in effect during the year. See Note 11 to our Consolidated Financial Statements for additional information regarding our debt arrangements.

Series B Preferred Units . Distributions on the Series B preferred units accumulate and are payable quarterly in arrears on the 15th day of February, May, August and November. Beginning August 15, 2023, distributions on the Series B preferred units accumulate based on the applicable three-month SOFR, plus certain adjustments. Based upon the Series B preferred units outstanding at December 31, 2025 and the liquidation preference of $1,000 per unit, a change of 100 basis points in interest rates would increase or decrease the annual distributions on the Series B preferred units by approximately $8 million. See Note 12 to our Consolidated Financial Statements for additional information regarding our Series B preferred unit distributions.

Currency Exchange Rate Risk

We use foreign currency derivatives to hedge foreign currency exchange rate risk associated with our exposure to fluctuations in the USD-to-CAD exchange rate. The fair value of our foreign currency derivatives was an asset of $8 million as of December 31, 2025. A 10% increase in the exchange rate (USD-to-CAD) would have resulted in an increase of $329 million to the fair value of our foreign currency derivatives. A 10% decrease in the exchange rate (USD-to-CAD) would have resulted in a decrease of $329 million to the fair value of our foreign currency derivatives. See Note 13 to our Consolidated Financial Statements for additional information regarding our currency exchange rate risk hedging.

Item 8.  Financial Statements and Supplementary Data

See “Index to the Consolidated Financial Statements” on page F-1.

Item 9.  Changes In and Disagreements With Accountants on Accounting and Financial Disclosure

None.

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Item 9A.   Controls and Procedures

Disclosure Controls and Procedures

We maintain written disclosure controls and procedures, which we refer to as our “DCP.” Our DCP is designed to ensure that information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 (the “Exchange Act”) is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.

Applicable SEC rules require an evaluation of the effectiveness of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our DCP as of December 31, 2025, the end of the period covered by this report, and, based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our DCP is effective.

Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting. “Internal control over financial reporting” is a process designed by, or under the supervision of, our Chief Executive Officer and our Chief Financial Officer, and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Our management, including our Chief Executive Officer and our Chief Financial Officer, has evaluated the effectiveness of our internal control over financial reporting as of December 31, 2025. See “Management’s Report on Internal Control Over Financial Reporting” on page F-2 of our Consolidated Financial Statements.

Our independent registered public accounting firm, PricewaterhouseCoopers LLP, assessed the effectiveness of our internal control over financial reporting, as stated in the firm’s report. See “ Report of Independent Registered Public Accounting Firm ” on page F-3 of our Consolidated Financial Statements.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting during the fourth quarter of 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Certifications

The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a) are filed with this report as Exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350 are furnished with this report as Exhibits 32.1 and 32.2.

Item 9B.   Other Information

During the quarter ended December 31, 2025, none of our directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted or terminated a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K).

Item 9C.   Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.
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PART III

Item 10.  Directors and Executive Officers of Our General Partner and Corporate Governance
The information required by this item will be set forth in the Proxy Statement for our 2026 Annual Meeting, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2025, and is incorporated herein by reference thereto.
Directors and Executive Officers
As of the date of filing this report, the following individuals were serving as our executive officers and/or directors:

Name Principal Occupation or Employment
Willie Chiang (1)(2)
Chairman of the Board, Chief Executive Officer and President

Chris R. Chandler (1)
Executive Vice President and Chief Operating Officer
Al Swanson (1)
Executive Vice President and Chief Financial Officer
Jeremy L. Goebel (1)
Executive Vice President and Chief Commercial Officer
Richard K. McGee (1)
Executive Vice President, General Counsel and Secretary
Chris Herbold (1)
Senior Vice President, Finance and Chief Accounting Officer
Greg L. Armstrong (2)
Senior Advisor to the Chief Executive Officer (former Chairman and Chief Executive Officer)
Victor Burk (2)
Former Senior Advisor, Alvarez and Marsal

Ellen R. DeSanctis (2)
Former Senior Vice President, ConocoPhillips

Kevin McCarthy (2)
Former Vice Chairman, Kayne Anderson Capital Advisors, L.P.

Harry N. Pefanis (2)
Senior Advisor to the Chief Executive Officer (former President)

Gary R. Petersen (2)
Managing Partner, EnCap Investments L.P.
Alexandra D. Pruner (2)
Senior Advisor, Perella Weinberg Partners
John T. Raymond (2)
Managing Partner and Chief Executive Officer, The Energy & Minerals Group
Bobby S. Shackouls (2)
Former Chairman and CEO, Burlington Resources Inc.
Lawrence M. Ziemba (2)
Former Executive Vice President, Refining, Phillips 66

(1)     Executive officer (for purposes of Item 401(b) of Regulation S-K)
(2)     Director

A complete list of our officers, including the executive officers listed above, is available on our website at www.plains.com under Who We Are—Leadership.

Item 11. Executive Compensation
The information required by this item will be set forth in the Proxy Statement for our 2026 Annual Meeting, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2025, and is incorporated herein by reference thereto.

Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
The information required by this item will be set forth in the Proxy Statement for our 2026 Annual Meeting, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2025, and is incorporated herein by reference thereto.

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Item 13.  Certain Relationships and Related Transactions, and Director Independence
The information required by this item will be set forth in the Proxy Statement for our 2026 Annual Meeting, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2025, and is incorporated herein by reference thereto.

Item 14.  Principal Accountant Fees and Services
The information required by this item will be set forth in the Proxy Statement for our 2026 Annual Meeting, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2025, and is incorporated herein by reference thereto.
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PART IV

Item 15.  Exhibits and Financial Statement Schedules

(a) (1)     Financial Statements

See “Index to the Consolidated Financial Statements” set forth on Page F-1.

(2)     Financial Statement Schedules

All schedules are omitted because they are either not applicable or the required information is shown in the Consolidated Financial Statements or notes thereto.

(3)     Exhibits

Exhibit No. Description
2.1* — Simplification Agreement dated as of July 11, 2016, by and among PAA GP Holdings LLC, Plains GP Holdings, L.P., Plains All American GP LLC, Plains AAP, L.P., PAA GP LLC and Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed July 14, 2016).

2.2* — Agreement and Plan of Merger dated as of July 12, 2021 by and among Plains Pipeline, L.P., Plains Marketing, L.P., Oryx Midstream Holdings LLC, Middle Cadence Holdings LLC, POP HoldCo LLC, Oryx Wink Oil Marketing LLC, Oryx Permian Oil Marketing LLC, Plains Oryx Permian Basin LLC, Plains Oryx Permian Basin Marketing LLC and Plains Oryx Permian Basin Pipeline LLC (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed July 13, 2021).

2.3*
— Share Purchase Agreement dated as of June 17, 2025 by and between Plains Midstream Luxembourg S.A.R.L. and Keyera Corp. (portions of this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (incorporated by reference to Exhibit 2.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2025).

2.4*
— Purchase and Sale Agreement dated August 30, 2025 by and among Altus Midstream Processing LP, Kinetik EC Holdco LLC, Rattler Midstream Operating LLC and Rattler OMOG LLC, as Sellers, and Plains BK Holdco LLC, as Buyer, and the other parties thereto (portions of this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed November 6, 2025).

2.5*
— Equity Purchase Agreement dated November 3, 2025 by and among EPIC Crude Parent, L.P., as Seller, and Plains BK Holdco LLC, as Buyer, and the other parties thereto (portions of this exhibit have been omitted pursuant to Item 601(b)(2) of Registration S-K (incorporated by reference to Exhibit 2.2 to our Current Report on Form 8-K filed November 6, 2025).

3.1 — Seventh Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. dated as of October 10, 2017 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 12, 2017).

3.2 — Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.3 — Amendment No. 1 dated December 31, 2010 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.9 to our Annual Report on Form 10-K for the year ended December 31, 2010).

3.4 — Amendment No. 2 dated January 1, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2010).

3.5 — Amendment No. 3 dated June 30, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.7 to our Annual Report on Form 10-K for the year ended December 31, 2013).

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3.6 — Amendment No. 4 dated January 1, 2013 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P (incorporated by reference to Exhibit 3.8 to our Annual Report on Form 10-K for the year ended December 31, 2013).

3.7 — Amendment No. 5 dated December 1, 2019 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.7 to our Annual Report on Form 10-K for the year ended December 31, 2019.)

3.8 — Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.3 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.9 — Amendment No. 1 dated January 1, 2013 to the Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. (incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2013).

3.10 — Seventh Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated November 15, 2016 (incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K filed November 21, 2016).

3.11 — Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. dated November 15, 2016 (incorporated by reference to Exhibit 3.4 to our Current Report on Form 8-K filed November 21, 2016).

3.12 — Amendment No. 1 dated September 26, 2018 to the Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 2, 2018).

3.13 — Amendment No. 2 dated May 23, 2019 to the Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed May 30, 2019).

3.14 — Amendment No. 3 dated August 17, 2023 to the Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed August 21, 2023).

3.15 — Certificate of Incorporation of PAA Finance Corp. (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2006).

3.16 — Bylaws of PAA Finance Corp. (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.11 to our Annual Report on Form 10-K for the year ended December 31, 2006).

3.17 — Limited Liability Company Agreement of PAA GP LLC dated December 28, 2007 (incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K filed January 4, 2008).

3.18 — Certificate of Limited Partnership of Plains GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to PAGP’s Registration Statement on Form S-1 (333-190227) filed July 29, 2013).

3.19 — Second Amended and Restated Agreement of Limited Partnership of Plains GP Holdings, L.P. dated as of November 15, 2016 (incorporated by reference to Exhibit 3.2 to PAGP’s Current Report on Form 8-K filed November 21, 2016).

3.20 — Amendment No. 1 dated April 6, 2020 to the Second Amended and Restated Agreement of Limited Partnership of Plains GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to PAGP’s Current Report on Form 8-K filed April 9, 2020).

3.21 — Certificate of Formation of PAA GP Holdings LLC (incorporated by reference to Exhibit 3.3 to PAGP’s Registration Statement on Form S-1 (333-190227) filed July 29, 2013).

3.22
— Fourth Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC dated effective as of August 19, 2021 (incorporated by reference to Exhibit 3.21 to our Annual Report on Form 10-K for the year ended December 31, 2021).

4.1 — Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).

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4.2 — Sixth Supplemental Indenture (Series A and Series B 6.70% Senior Notes due 2036) dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed May 12, 2006).

4.3 — Tenth Supplemental Indenture (Series A and Series B 6.650% Senior Notes due 2037) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed October 30, 2006).

4.4 — Twenty-First Supplemental Indenture (5.15% Senior Notes due 2042) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed March 26, 2012).

4.5
— Twenty-Third Supplemental Indenture (4.30% Senior Notes due 2043) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 12, 2012).

4.6 — Twenty-Fifth Supplemental Indenture (4.70% Senior Notes due 2044) dated April 23, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed April 29, 2014).

4.7 — Twenty-Eighth Supplemental Indenture (4.90% Senior Notes due 2045) dated December 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 11, 2014).

4.8 — Thirtieth Supplemental Indenture (4.50% Senior Notes due 2026) dated November 22, 2016, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed November 29, 2016).

4.9 — Thirty-First Supplemental Indenture (3.55% Senior Notes due 2029) dated September 16, 2019, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed September 17, 2019).

4.10 — Thirty-Second Supplemental Indenture (3.80% Senior Notes due 2030) dated June 11, 2020, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed June 11, 2020).

4.11 — Thirty-Third Supplemental Indenture (5.70% Senior Notes due 2034) dated June 27, 2024, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed June 27, 2024).

4.12 — Thirty-Fourth Supplemental Indenture (5.950% Senior Notes due 2035) dated January 15, 2025, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed January 15, 2025).

4.13 — Thirty-Fifth Supplemental Indenture (4.70% Senior Notes due 2031) dated September 8, 2025, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed November 14, 2025) .

4.14 — Thirty-Sixth Supplemental Indenture (5.60% Senior Notes due 2036) dated September 8, 2025, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed November 14, 2025) .

4.15 — Registration Rights Agreement dated September 3, 2009 by and between Plains All American Pipeline, L.P. and Vulcan Gas Storage LLC (incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-3, File No. 333-162477).

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4.16 — Registration Rights Agreement dated as of January 28, 2016 among Plains All American Pipeline, L.P. and the Purchasers named therein (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed February 2, 2016).

4.17 — Registration Rights Agreement by and among Plains All American Pipeline, L.P. and the Holders defined therein, dated November 15, 2016 (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed November 21, 2016).

4.18 — Description of Our Securities (incorporated by refe rence to Exhibit 4.17 to our Annual Report on Form 10-K for the year ended D ecember 31, 2024 ) .

10.1 — Credit Agreement dated as of August 20, 2021, among Plains All American Pipeline, L.P. and Plains Midstream Canada ULC, as Borrowers; certain subsidiaries of Plains All American Pipeline, L.P. from time to time party thereto, as Designated Borrowers; Bank of America, N.A., as Administrative Agent and Swing Line Lender; Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A. and Wells Fargo Bank, National Association, as L/C Issuers; and the other Lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed August 26, 2021).

10.2 — First Amendment to Credit Agreement dated as of August 22, 2022, among Plains All American Pipeline, L.P. and Plains Midstream Canada ULC, as Borrowers; certain subsidiaries of Plains All American Pipeline, L.P. from time to time party thereto, as Designated Borrowers; Bank of America, N.A., as Administrative Agent and Swing Line Lender; Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A. and Wells Fargo Bank, National Association, as L/C Issuers; and the other Lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed August 25, 2022).

10.3
— Second Amendment to Credit Agreement dated as of August 19, 2024, among Plains All American Pipeline, L.P. and Plains Midstream Canada ULC, as Borrowers; certain subsidiaries of Plains All American Pipeline, L.P. from time to time party thereto, as Designated Borrowers; Bank of America, N.A., as Administrative Agent and Swing Line Lender; Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A. and Wells Fargo Bank, National Association, as L/C Issuers; and the other Lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed August 22, 2024).

10.4
— Fourth Amended and Restated Credit Agreement dated as of August 20, 2021, among Plains Marketing, L.P. and Plains Midstream Canada ULC, as Borrowers; Plains All American Pipeline, L.P., as guarantor; Bank of America, N.A., as Administrative Agent and Swing Line Lender; Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A. and Wells Fargo Bank, National Association, as L/C Issuers; and the other Lenders party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed August 26, 2021).

10.5 — First Amendment to Fourth Amended and Restated Credit Agreement dated as of August 22, 2022, among Plains Marketing, L.P. and Plains Midstream Canada ULC, as Borrowers; Plains All American Pipeline, L.P., as guarantor; Bank of America, N.A., as Administrative Agent and Swing Line Lender; Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A. and Wells Fargo Bank, National Association, as L/C Issuers; and the other Lenders party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed August 25, 2022).

10.6 — Second Amendment to Fourth Amended and Restated Credit Agreement dated as of August 19, 2024, among Plains Marketing, L.P. and Plains Midstream Canada ULC, as Borrowers; Plains All American Pipeline, L.P., as guarantor; Bank of America, N.A., as Administrative Agent and Swing Line Lender; Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A. and Wells Fargo Bank, National Association, as L/C Issuers; and the other Lenders party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed August 22, 2024).

10.7 — Credit Agreement, dated as of October 15, 2024, by and among EPIC Crude Holdings, EPIC Crude Services, LP, as borrower, Goldman Sachs Bank USA, as administrative and collateral agent, and the lenders and letters of credit issuers party thereto from time to time, as amended (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed November 6, 2025).

10.8
— Term Loan Agreement, dated as of November 26, 2025, by and among Plains All American Pipeline, L.P., PNC Bank, National Association, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10. 1 to our Current Report on Form 8-K filed December 3 , 202 5 ) .

10.9
— Contribution and Assumption Agreement dated December 28, 2007, by and between Plains AAP, L.P. and PAA GP LLC (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed January 4, 2008).

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10.10
— Omnibus Agreement by and among PAA GP Holdings LLC, Plains GP Holdings, L.P., Plains All American GP LLC, Plains AAP, L.P., PAA GP LLC, and Plains All American Pipeline, L.P., dated November 15, 2016 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed November 21, 2016).

10.11
— Amended and Restated Administrative Agreement by and among PAA GP Holdings LLC, Plains GP Holdings, L.P., Plains All American GP LLC, Plains AAP, L.P., PAA GP LLC, and Plains All American Pipeline, L.P., dated November 15, 2016 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed November 21, 2016).

10.12**
— Amended and Restated Employment Agreement between Plains All American GP LLC and Greg L. Armstrong dated as of June 30, 2001 (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2001).

10.13**
— First Amendment to Amended and Restated Employment Agreement dated December 4, 2008 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10.49 to our Annual Report on Form 10-K for the year ended December 31, 2008).

10.14**
— Waiver Agreement dated as of December 23, 2010 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10.31 to our Annual Report on Form 10-K for the year ended December 31, 2010).

10.15**
— Waiver Agreement dated October 21, 2013 to the Amended and Restated Employment Agreement dated June 30, 2001 of Greg L. Armstrong (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed October 25, 2013).

10.16**
— Second Amended and Restated Employment Agreement dated effective October 1, 2018 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10.6 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2018).

10.17**
— Third Amended and Restated Employment Agreement dated effective January 1, 2020 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10.31 to our Annual Report on Form 10-K for the year ended December 31, 2019.

10.18**
— Amendment No. 1 to Third Amended and Restated Employment Agreement dated effective December 31, 2021 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10.12 to our Annual Report on Form 10-K for the year ended December 31, 2021).

10.19**
— Fourth Amended and Restated Employment Agreement dated effective May 23, 2024 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10. 1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2025) .

10.20**
— Amended and Restated Employment Agreement between Plains All American GP LLC and Harry N. Pefanis dated as of June 30, 2001 (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2001).

10.21**
— First Amendment to Amended and Restated Employment Agreement dated December 4, 2008 between Plains All American GP LLC and Harry N. Pefanis (incorporated by reference to Exhibit 10.50 to our Annual Report on Form 10-K for the year ended December 31, 2008).

10.22**
— Amendment No. 2 dated August 15, 2019 to Harry Pefanis Amended and Restated Employment Agreement (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).

10.23**
— Waiver Agreement dated as of December 23, 2010 between Plains All American GP LLC and Harry N. Pefanis (incorporated by reference to Exhibit 10.32 to our Annual Report on Form 10-K for the year ended December 31, 2010).

10.24**
— Waiver Agreement dated October 21, 2013 to the Amended and Restated Employment Agreement dated June 30, 2001 of Harry N. Pefanis (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed October 25, 2013).

10.25**
— Employment Agreement dated effective June 1, 2025 between Plains All American GP LLC and Harry N. Pefanis (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2025).

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10.26**
— Employment Agreement between Plains All American GP LLC and Willie Chiang dated July 10, 2015 (incorporated by reference to Exhibit 10.53 to our Annual Report on Form 10-K for the year ended December 31, 2015).

10.27**
— Amended and Restated Employment Agreement dated effective October 1, 2018 between Plains All American GP LLC and Willie Chiang (incorporated by reference to Exhibit 10.7 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2018).

10.28**
— LTIP Grant Letter dated August 16, 2018 (Willie Chiang) incorporated by reference to Exhibit 10.8 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2018).

10.29**
— Amendment dated August 14, 2025 to Special Promotional LTIP Grant Letter dated August 16, 2018 (Willie Chiang) (incorporated by reference to Exhibit 10.6 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2025).

10.30**
— Plains All American 2021 Long-Term Incentive Plan (incorporated by reference to Exhibit A to our Definitive Proxy Statement filed on April 12, 2021).

10.31**
— Plains All American 2013 Long-Term Incentive Plan (incorporated by reference to Exhibit A to our Definitive Proxy Statement filed on October 3, 2013).

10.32**
— Plains All American PNG Successor Long-Term Incentive Plan (incorporated by reference to Exhibit 4.4 to our Registration Statement on Form S-8 (333-193139) filed December 31, 2013).

10.33**
— PAA Natural Gas Storage, L.P. 2010 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to PNG’s Current Report on Form 8-K filed May 11, 2010).

10.34**
— Plains GP Holdings, L.P. Long Term Incentive Plan (incorporated by reference to Exhibit 10.3 to PAGP’s Current Report on Form 8-K filed October 25, 2013).

10.35**
— Form of Special Retention LTIP Grant Letter dated November 20, 2019 (incorporated by reference to Exhibit 10.53 to our Annual Report on Form 10-K for the year ended December 31, 2020).

10.36**
— Form of Amended and Restated Special Retention LTIP Grant Letter Dated February 24, 2022 (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2022).

10.37**
— Form of LTIP Grant Letter dated August 17, 2023 (Named Executive Officers) (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2023).

10.38**
— Form of LTIP Grant Letter dated August 15, 2024 (Named Executive Officers) (incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2024).

10.39**
—
Form of LTIP Grant Letter dated August 14, 2025 (Named Executive Officers) (incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 202 5 ) .

10.40**
—
Form of LTIP Grant Letter dated August 14, 2025 (Directors) (incorporated by reference to Exhibit 10. 4 to our Quarterly Report on F orm 10-Q for the quarter ended September 30, 2025) .

10.41**
—
Form of Special Retention LTIP Grant Letter dated August 14, 2025 (incorporated by reference to Exhibit 10. 5 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2025) .

19.1
—
Policy on Insider Trading (incorpor ated by reference to Exhibit 19. 1 to our Annual Report on Form 10-K for the year ended December 31, 2024) .

19.2
—
Policy Regarding Special Trading Procedures (in corporated by reference to Exhibit 19.2 to our Annual Report on Form 10-K for the year ended D ecember 31, 2024) .

21.1 † — List of Subsidiaries of Plains All American Pipeline, L.P.

23.1 † — Consent of PricewaterhouseCoopers LLP.

31.1 † — Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

31.2 † — Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

32.1 †† — Certification of Principal Executive Officer pursuant to 18 U.S.C. 1350.

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32.2 †† — Certification of Principal Financial Officer pursuant to 18 U.S.C. 1350.

97.1
— Amended and Restated Clawback Policy (incorporated by reference to Exhibit 97.1 to our Annual Report on Form 10-K for the year ended December 31, 2023).

101. INS† — XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH† — Inline XBRL Taxonomy Extension Schema Document

101.CAL† — Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF† — Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB† — Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE† — Inline XBRL Taxonomy Extension Presentation Linkbase Document

104† — Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

†     Filed herewith.
††     Furnished herewith.
*    Certain schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule will be furnished supplementally to the SEC upon request.
**    Management compensatory plan or arrangement.

Item 16.  Form 10-K Summary

None.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PLAINS ALL AMERICAN PIPELINE, L.P.

By: PAA GP LLC,
its general partner

By: Plains AAP, L.P.,
its sole member

By: PLAINS ALL AMERICAN GP LLC,
its general partner

By: /s/ Willie Chiang
Willie Chiang,
Chief Executive Officer and President of Plains All American GP LLC

(Principal Executive Officer)

February 27, 2026

By: /s/ Al Swanson
Al Swanson,
Executive Vice President and Chief Financial Officer of Plains All American GP LLC
(Principal Financial Officer)

February 27, 2026

By: /s/ Chris Herbold
Chris Herbold,
Senior Vice President, Finance and Chief Accounting Officer of Plains All American GP LLC
(Principal Accounting Officer)

February 27, 2026

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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name Title Date

/s/ Willie Chiang
Chairman of the Board of PAA GP Holdings LLC and Chief Executive Officer and President of Plains All American GP LLC (Principal Executive Officer)
February 27, 2026
Willie Chiang

/s/ Al Swanson
Executive Vice President and Chief Financial Officer of Plains All American GP LLC (Principal Financial Officer) February 27, 2026
Al Swanson

/s/ Chris Herbold
Senior Vice President, Finance and Chief Accounting Officer of Plains All American GP LLC (Principal Accounting Officer) February 27, 2026
Chris Herbold

/s/ Greg L. Armstrong
Director of PAA GP Holdings LLC February 27, 2026
Greg L. Armstrong

/s/ Victor Burk
Director of PAA GP Holdings LLC February 27, 2026
Victor Burk

/s/ Ellen R. DeSanctis
Director of PAA GP Holdings LLC February 27, 2026
Ellen R. DeSanctis

/s/ Kevin McCarthy
Director of PAA GP Holdings LLC February 27, 2026
Kevin McCarthy

/s/ Harry N. Pefanis
Director of PAA GP Holdings LLC
February 27, 2026
Harry N. Pefanis

/s/ Gary R. Petersen
Director of PAA GP Holdings LLC February 27, 2026
Gary R. Petersen

/s/ Alexandra D. Pruner
Director of PAA GP Holdings LLC February 27, 2026
Alexandra D. Pruner

/s/ John T. Raymond
Director of PAA GP Holdings LLC February 27, 2026
John T. Raymond

/s/ Bobby S. Shackouls
Director of PAA GP Holdings LLC February 27, 2026
Bobby S. Shackouls

/s/ Lawrence M. Ziemba
Director of PAA GP Holdings LLC February 27, 2026
Lawrence M. Ziemba

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Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS

Page
Consolidated Financial Statements
Management’s Report on Internal Control Over Financial Reporting
F- 2

Report of Independent Registered Public Accounting Firm (PCAOB ID: 238 )
F- 3

Consolidated Balance Sheets as of December 31, 202 5 and 202 4
F- 5

Consolidated Statements of Operations for the years ended December 31, 202 5 , 202 4 and 202 3
F- 6

Consolidated Statements of Comprehensive Income for the years ended December 31, 202 5 , 202 4 and 202 3
F- 7

Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss) for the years ended December 31, 202 5 , 202 4 and 202 3
F- 7

Consolidated Statements of Cash Flows for the years ended December 31, 202 5 , 202 4 and 202 3
F- 8

Consolidated Statements of Changes in Partners’ Capital for the years ended December 31, 202 5 , 202 4 and 202 3
F- 9

Notes to the Consolidated Financial Statements:
F- 10

1. Organization and Basis of Consolidation and Presentation
F- 10

2. Summary of Significant Accounting Policies
F- 12

3. D iscontinued Operations
F- 16

4. Revenues and Accounts Receivable
F- 17

5. Net Income Per Common Unit
F- 21

6. Inventory, Linefill and Long-term Inventory
F- 22

7. Property and Equipment
F- 23

8. Acquisitions, Divestitures and Other Transactions
F- 25

9. Investments in Unconsolidated Entities
F- 30

10. Intangible Assets, Net
F- 32

1 1 . Debt
F- 33

1 2 . Partners’ Capital and Distributions
F- 37

1 3 . Derivatives and Risk Management Activities
F- 41

1 4 . Leases
F- 44

1 5 . Income Taxes
F- 47

1 6 . Major Customers and Concentration of Credit Risk
F- 50

1 7 . Related Party Transactions
F- 51

1 8 . Equity-Indexed Compensation Plans
F- 53

1 9 . Commitments and Contingencies
F- 54

20. Segment Information
F- 58

21. Selected Quarterly Financial Data (Unaudited)
F- 63

F-1

Table of Contents
Index to Financial Statements

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Plains All American Pipeline, L.P.’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Internal control over financial reporting has inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

Management has used the framework set forth in the report entitled “Internal Control—Integrated Framework” (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) to evaluate the effectiveness of the Partnership’s internal control over financial reporting. Based on that evaluation, management has concluded that the Partnership’s internal control over financial reporting was effective as of December 31, 2025.

The effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2025 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on Page F-3.
 
/s/ Willie Chiang
Willie Chiang
Chief Executive Officer and President of Plains All American GP LLC

(Principal Executive Officer)

/s/ Al Swanson
Al Swanson
Executive Vice President and Chief Financial Officer of Plains All American GP LLC
(Principal Financial Officer)

February 27, 2026

F-2

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Index to Financial Statements

Report of Independent Registered Public Accounting Firm

To the Board of Directors of PAA GP Holdings LLC and Unitholders of Plains All American Pipeline, L.P.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Plains All American Pipeline, L.P. and its subsidiaries (the “Partnership”) as of December 31, 2025 and 2024, and the related consolidated statements of operations, of comprehensive income, of changes in accumulated other comprehensive income (loss), of changes in partners’ capital and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Partnership’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Partnership’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Partnership’s consolidated financial statements and on the Partnership’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

F-3

Table of Contents
Index to Financial Statements

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Acquisition of EPIC Crude Holdings, LP – Valuation of Pipelines and Equipment

As described in Note 8 to the consolidated financial statements, on October 31, 2025, the Partnership purchased an aggregate 55% equity interest in EPIC Crude Holdings, LP, and in a separate transaction, effective November 1, 2025, acquired the remaining 45% equity interest, for total consideration of $2,016 million. Of the identifiable assets acquired, $2,737 million of property and equipment, net, was recorded, a significant portion of which relates to pipelines and equipment. The acquisition was accounted for as a business combination using the acquisition method of accounting. The fair value of acquired pipelines and equipment was determined by management using a cost approach and included an assumption for replacement cost.

The principal considerations for our determination that performing procedures relating to the valuation of pipelines and equipment acquired in the acquisition of EPIC Crude Holdings, LP is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the pipelines and equipment acquired; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumption related to replacement cost; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the acquisition accounting, including controls over management’s valuation of the pipelines and equipment acquired. These procedures also included, among others (i) reading the purchase agreements; (ii) testing management’s process for developing the fair value estimate of the pipelines and equipment acquired; (iii) evaluating the appropriateness of the cost approach used by management; (iv) testing the completeness and accuracy of the underlying data used in the cost approach; and (v) evaluating the reasonableness of the significant assumption used by management related to replacement cost. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the cost approach and (ii) the reasonableness of the replacement cost assumption.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 27, 2026

We have served as the Partnership’s auditor since 1998.

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Table of Contents
Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions, except unit data)

December 31, 2025 December 31, 2024
ASSETS

CURRENT ASSETS
Cash and cash equivalents $ 328   $ 348  

Trade accounts receivable and other receivables, net 3,598   3,679  
Inventory 211   261  
Current assets of discontinued operations (Note 3) 479   415  
Other current assets 117   99  
Total current assets 4,733   4,802  

PROPERTY AND EQUIPMENT 22,536   18,528  
Accumulated depreciation ( 5,676 ) ( 5,082 )
Property and equipment, net 16,860   13,446  

OTHER ASSETS
Investments in unconsolidated entities 2,846   2,811  

Intangible assets, net 1,754   1,677  
Linefill 900   904  
Long-term operating lease right-of-use assets, net 198   189  
Long-term inventory 214   242  
Long-term assets of discontinued operations (Note 3) 2,557   2,349  
Other long-term assets, net 107   142  
Total assets $ 30,169   $ 26,562  

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES
Trade accounts payable $ 3,457   $ 3,647  
Short-term debt 563   407  
Current liabilities of discontinued operations (Note 3) 382   350  
Other current liabilities 529   546  
Total current liabilities 4,931   4,950  

LONG-TERM LIABILITIES
Senior notes, net 9,118   7,141  
Other long-term debt, net 1,578   70  
Long-term operating lease liabilities 202   192  
Long-term liabilities of discontinued operations (Note 3) 606   576  
Other long-term liabilities and deferred credits 654   537  
Total long-term liabilities 12,158   8,516  

COMMITMENTS AND CONTINGENCIES (NOTE 19)

PARTNERS’ CAPITAL
Series A preferred unitholders ( 58,411,908 and 71,090,468 units outstanding, respectively)
1,248   1,514  
Series B preferred unitholders ( 800,000 and 800,000 units outstanding, respectively)
787   787  
Common unitholders ( 705,520,697 and 703,770,300 units outstanding, respectively)
7,801   7,512  
Total partners’ capital excluding noncontrolling interests 9,836   9,813  
Noncontrolling interests 3,244   3,283  
Total partners’ capital 13,080   13,096  
Total liabilities and partners’ capital $ 30,169   $ 26,562  

The accompanying notes are an integral part of these consolidated financial statements.
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Index to Financial Statements

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

Year Ended December 31,
2025 2024 2023
REVENUES
Product sales revenues $ 42,501   $ 47,199   $ 45,745  
Services revenues 1,761   1,690   1,591  

Total revenues 44,262   48,889   47,336  

COSTS AND EXPENSES
Purchases and related costs 40,433   45,162   43,937  
Field operating costs 1,154   1,471   1,085  
General and administrative expenses 342   328   299  
Depreciation and amortization 953   901   909  
(Gains)/losses on asset sales, asset impairments and other, net (Note 7, Note 8) ( 54 ) 159   ( 152 )

Total costs and expenses 42,828   48,021   46,078  

OPERATING INCOME 1,434   868   1,258  

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities 382   452   369  
Gain on investments in unconsolidated entities, net (Note 8, Note 9) 31   15   28  
Interest expense (net of capitalized interest of $ 11 , $ 9 and $ 10 , respectively)
( 554 ) ( 430 ) ( 386 )
Other income, net 108   64   102  

INCOME FROM CONTINUING OPERATIONS BEFORE TAX 1,401   969   1,371  
Current income tax expense from continuing operations ( 1 ) ( 82 ) ( 70 )
Deferred income tax (expense)/benefit from continuing operations ( 14 ) ( 5 ) 9  
INCOME FROM CONTINUING OPERATIONS, NET OF TAX 1,386   882   1,310  
INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX (NOTE 3) 383   231   192  
NET INCOME 1,769   1,113   1,502  
Net income attributable to noncontrolling interests ( 334 ) ( 341 ) ( 272 )
NET INCOME ATTRIBUTABLE TO PAA $ 1,435   $ 772   $ 1,230  

NET INCOME PER COMMON UNIT (NOTE 5):
Net income allocated to common unitholders — Basic and Diluted:
Continuing operations $ 786   $ 283   $ 784  
Discontinued operations 383   231   192  
Net income allocated to common unitholders — Basic and Diluted $ 1,169   $ 514   $ 976  

Basic and diluted weighted average common units outstanding 704   702   699  

Basic and diluted net income per common unit:
Continuing operations $ 1.12   $ 0.40   $ 1.12  
Discontinued operations 0.54   0.33   0.28  
Basic and diluted net income per common unit $ 1.66   $ 0.73   $ 1.40  

The accompanying notes are an integral part of these consolidated financial statements.
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Index to Financial Statements

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

Year Ended December 31,
2025 2024 2023
Net income $ 1,769   $ 1,113   $ 1,502  
Other comprehensive income/(loss) 187   ( 247 ) 118  
Comprehensive income 1,956   866   1,620  
Comprehensive income attributable to noncontrolling interests ( 334 ) ( 341 ) ( 272 )
Comprehensive income attributable to PAA $ 1,622   $ 525   $ 1,348  

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

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

Derivative
Instruments Translation
Adjustments Other Total
Balance at December 31, 2022 $ ( 107 ) $ ( 846 ) $ ( 1 ) $ ( 954 )

Reclassification adjustments 11   —  —  11  
Unrealized gain on hedges 15   —  —  15  
Currency translation adjustments —  91   —  91  
Other —  —  1   1  
2023 Activity 26   91   1   118  
Balance at December 31, 2023 $ ( 81 ) $ ( 755 ) $ —  $ ( 836 )

Reclassification adjustments 8   —  —  8  
Unrealized gain on hedges 29   —  —  29  
Currency translation adjustments —  ( 284 ) —  ( 284 )

2024 Activity 37   ( 284 ) —  ( 247 )
Balance at December 31, 2024 $ ( 44 ) $ ( 1,039 ) $ —  $ ( 1,083 )

Reclassification adjustments 5   —  —  5  
Unrealized gain on hedges 10   —  —  10  
Currency translation adjustments —  167   —  167  
Other —  —  5   5  
2025 Activity 15   167   5   187  
Balance at December 31, 2025 $ ( 29 ) $ ( 872 ) $ 5   $ ( 896 )

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

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Index to Financial Statements

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

Year Ended December 31,
2025 2024 2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 1,769   $ 1,113   $ 1,502  
Reconciliation of net income to net cash provided by operating activities:
Income from discontinued operations, net of tax ( 383 ) ( 231 ) ( 192 )
Depreciation and amortization 953   901   909  
(Gains)/losses on asset sales, asset impairments and other, net (Note 7, Note 8) ( 54 ) 159   ( 152 )

Equity-indexed compensation expense 49   50   50  

Deferred income tax expense/(benefit) 14   5   ( 9 )

(Gain)/loss on foreign currency revaluation 13   ( 12 ) 3  
Settlement of terminated interest rate hedging instruments (Note 13) 37   57   80  
Change in fair value of Preferred Distribution Rate Reset Option (Note 13) —   —   ( 58 )
Equity earnings in unconsolidated entities ( 382 ) ( 452 ) ( 369 )
Distributions on earnings from unconsolidated entities 486   505   458  
Gain on investments in unconsolidated entities, net (Note 8, Note 9) ( 31 ) ( 15 ) ( 28 )
Other 15   17   18  
Changes in assets and liabilities, net of acquisitions:
Trade accounts receivable and other 204   76   79  
Inventory 96   120   102  
Trade accounts payable and other ( 334 ) ( 57 ) ( 141 )
Cash provided by operating activities - continuing operations 2,452   2,236   2,252  
Cash provided by operating activities - discontinued operations 484   254   475  
Net cash provided by operating activities 2,936   2,490   2,727  

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired (Note 8) ( 2,651 ) ( 248 ) ( 425 )
Investments in unconsolidated entities (Note 9) ( 2 ) ( 4 ) ( 33 )
Additions to property, equipment and other ( 643 ) ( 448 ) ( 408 )
Cash paid for purchases of linefill ( 27 ) ( 21 ) ( 10 )
Proceeds from sales of assets (Note 8) 81   11   328  

Investments in related party notes (Note 17) ( 330 ) ( 629 ) —  
Other investing activities —   5   8  
Cash used in investing activities - continuing operations ( 3,572 ) ( 1,334 ) ( 540 )
Cash used in investing activities - discontinued operations ( 197 ) ( 170 ) ( 162 )
Net cash used in investing activities ( 3,769 ) ( 1,504 ) ( 702 )

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) under commercial paper program (Note 11) 577   ( 40 ) 433  

Repayment under EPIC credit agreement (Note 11) ( 1,114 ) —   —  
Borrowing under term loan (Note 11) 1,100   —   —  
Proceeds from the issuance of senior notes (Note 11) 2,998   650   —  
Repayments of senior notes (Note 11) ( 1,000 ) ( 750 ) ( 1,100 )

Proceeds from the issuance of related party notes (Note 17) 330   629   —  
Repurchase of common units (Note 12) ( 8 ) —   —  
Repurchase of Series A preferred units (Note 12) ( 333 ) —   —  
Distributions paid to Series A preferred unitholders (Note 12) ( 154 ) ( 175 ) ( 166 )
Distributions paid to Series B preferred unitholders (Note 12) ( 71 ) ( 79 ) ( 75 )
Distributions paid to common unitholders (Note 12) ( 1,070 ) ( 891 ) ( 748 )
Distributions paid to noncontrolling interests (Note 12) ( 447 ) ( 425 ) ( 333 )
Contributions from noncontrolling interests 75   57   106  

Other financing activities ( 84 ) ( 53 ) ( 93 )
Net cash provided by/(used in) financing activities 799   ( 1,077 ) ( 1,976 )

Effect of translation adjustment - continuing operations 14   ( 13 ) 3  
Effect of translation adjustment - discontinued operations —   2   ( 3 )

Net increase/(decrease) in cash and cash equivalents and restricted cash ( 20 ) ( 102 ) 49  
Cash and cash equivalents and restricted cash, beginning of period 348   450   401  
Cash and cash equivalents and restricted cash, end of period $ 328   $ 348   $ 450  

Cash paid for:
Interest, net of amounts capitalized $ 516   $ 381   $ 377  
Income taxes, net of amounts refunded (Note 15) $ 98   $ 269   $ 69  

The accompanying notes are an integral part of these consolidated financial statements.
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Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
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
Balance at December 31, 2022 $ 1,505   $ 787   $ 7,765   $ 10,057   $ 3,268   $ 13,325  

Net income 173   76   981   1,230   272   1,502  
Distributions (Note 12) ( 173 ) ( 76 ) ( 748 ) ( 997 ) ( 333 ) ( 1,330 )

Other comprehensive income —  —  118   118   —  118  
Equity-indexed compensation expense —  —  36   36   —  36  

Contributions from noncontrolling interests —  —  —  —  106   106  

Other 4   —  ( 26 ) ( 22 ) ( 3 ) ( 25 )
Balance at December 31, 2023 $ 1,509   $ 787   $ 8,126   $ 10,422   $ 3,310   $ 13,732  

Net income 175   78   519   772   341   1,113  
Distributions (Note 12) ( 175 ) ( 78 ) ( 891 ) ( 1,144 ) ( 425 ) ( 1,569 )
Other comprehensive loss —  —  ( 247 ) ( 247 ) —  ( 247 )
Equity-indexed compensation expense —  —  36   36   —  36  

Contributions from noncontrolling interests —  —  —  —  57   57  

Other 5   —  ( 31 ) ( 26 ) —  ( 26 )
Balance at December 31, 2024 $ 1,514   $ 787   $ 7,512   $ 9,813   $ 3,283   $ 13,096  

Net income 146   70   1,219   1,435   334   1,769  
Distributions (Note 12) ( 146 ) ( 70 ) ( 1,070 ) ( 1,286 ) ( 447 ) ( 1,733 )
Other comprehensive income —  —  187   187   —  187  
Repurchase of Series A preferred units (Note 12) ( 270 ) —  ( 43 ) ( 313 ) —  ( 313 )
Equity-indexed compensation expense —  —  37   37   —  37  
Repurchase of common units (Note 12) —  —  ( 8 ) ( 8 ) —  ( 8 )
Contributions from noncontrolling interests —  —  —  —  75   75  

Other 4   —  ( 33 ) ( 29 ) ( 1 ) ( 30 )
Balance at December 31, 2025 $ 1,248   $ 787   $ 7,801   $ 9,836   $ 3,244   $ 13,080  

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

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Index to Financial Statements
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1— Organization and Basis of Consolidation and Presentation

Organization

Plains All American Pipeline, L.P. (“PAA”) is a Delaware limited partnership formed in 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in this Form 10-K 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 NGL. See Note 20 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 December 31, 2025, AAP also owned a limited partner interest in us through its ownership of approximately 233.0 million of our common units (approximately 31 % of our total outstanding common units and Series A preferred units combined). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole and managing member of GP LLC, and, at December 31, 2025, owned an approximate 85 % limited partner interest in AAP. PAA GP Holdings LLC (“PAGP GP”) is the general partner of PAGP.

As the sole member of GP LLC, PAGP has responsibility for conducting our business and managing our operations; however, the board of directors of PAGP GP has ultimate responsibility for managing the business and affairs of PAGP, AAP and us. GP LLC employs our domestic officers and personnel; our Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC.

References to the “PAGP Entities” include PAGP GP, PAGP, GP LLC, AAP and PAA GP. References to our “general partner,” as the context requires, include any or all of the PAGP Entities. References to the “Plains Entities” include us, our subsidiaries and the PAGP Entities.

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Index to Financial Statements
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Definitions

Additional defined terms may be used in the following notes 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
DERs = Distribution equivalent rights
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
LIBOR = London Interbank Offered Rate
LTIP = Long-term incentive plan

MLP = Master limited partnership
NGL = Natural gas liquids, including ethane, propane and butane
NYMEX = New York Mercantile Exchange
OECD
= Organisation for Economic Co-operation and Development

SEC = United States Securities and Exchange Commission
SOFR
= Secured Overnight Financing Rate
TWh = Terawatt hour
U.S. = United States
USD = United States dollar

Basis of Consolidation and Presentation

The accompanying financial statements and related notes present and discuss our consolidated financial position as of December 31, 2025 and 2024, and the consolidated results of our operations, cash flows, changes in partners’ capital, comprehensive income and changes in accumulated other comprehensive income/(loss) for the years ended December 31, 2025, 2024 and 2023. 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.

The accompanying 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.

Pending Sale of Canadian NGL Business

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

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Index to Financial Statements
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

We determined that in conjunction with entering into the SPA, the operations of the Canadian NGL Business meet the criteria for classification as held for sale and for discontinued operations reporting, as the sale will represent a strategic shift that will have a major effect on our operations and financial results. Accordingly, the assets and liabilities of the Canadian NGL Business have been classified as held for sale, and the balance sheet, results of operations and cash flows of the Canadian NGL Business have been presented as discontinued operations in our consolidated financial statements. Unless otherwise indicated, the disclosures included within the accompanying notes to the consolidated financial statements relate to our continuing operations and exclude amounts related to discontinued operations. These changes have been applied retrospectively to all periods presented. Discontinued operations are not presented separately within our Consolidated Statements of Comprehensive Income, Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss) or the Consolidated Statements of Changes in Partners’ Capital. See Note 3 for additional information regarding discontinued operations. All significant intercompany balances and transactions between the Canadian NGL Business and our continuing operations have been eliminated.

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. Prior to its classification as held for sale and presentation as discontinued operations, the Canadian NGL Business was part of our NGL reportable segment.

In June 2025, we entered into a forward currency instrument to hedge currency exchange risk associated with anticipated proceeds from the pending sale of our Canadian NGL Business. See Note 13 for additional information.

In connection with and contingent upon closing of the pending sale, we and Keyera entered into an agreement for certain hedging arrangements and payments relating to the differential between the price of natural gas and the extracted NGL commodities (“Frac Spread”) for a twelve-month period commencing the first month after the closing date. As a result of this arrangement, we will guarantee a minimum Frac Spread margin on certain volumes. The recognition of an asset or liability will be dependent upon the terms of the specific contracts transferred as part of the sale of the Canadian NGL Business and the market conditions at that time the sale closes. We do not expect any liability we might recognize as a result of this agreement to have a material adverse effect on our consolidated financial condition, results of operations or cash flows; for example, if the sale closed at the end of the first quarter of 2026, based on existing contracts to be transferred and current market conditions as of December 31, 2025, we would recognize a liability of approximately $ 65  million.

Subsequent Events

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

Note 2— Summary of Significant Accounting Policies

Use of Estimates
The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, as well as the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. We make significant estimates with respect to (i) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (ii) fair value of derivatives, (iii) accruals and contingent liabilities, (iv) property and equipment, depreciation and amortization expense and asset retirement obligations, (v) impairment assessments of property and equipment, investments in unconsolidated entities and intangible assets and (vi) inventory valuations. Although we believe these estimates are reasonable, actual results could differ from these estimates.

Purchases and Related Costs

Purchases and related costs include (i) the weighted average cost of crude oil and NGL sold to customers, (ii) fees incurred for storage and transportation, whether by pipeline, truck or rail and (iii) performance-related bonus costs. These costs are recognized when incurred except in the case of products sold, which are recognized at the time title transfers to our customers. Inventory exchanges under buy/sell transactions are presented net in “Purchases and related costs” in our Consolidated Statements of Operations.

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Index to Financial Statements
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Field Operating Costs and General and Administrative Expenses

Field operating costs consist of various field operating expenses, including payroll, compensation and benefits costs for operations personnel; fuel and power costs (including the impact of gains and losses from derivative related activities); third-party trucking transportation costs for our U.S. crude oil operations; maintenance and integrity management costs; regulatory compliance; environmental remediation; insurance; costs for usage of third-party owned pipeline, rail and storage assets; vehicle leases; and property taxes. General and administrative expenses consist primarily of payroll, compensation and benefits costs; certain information systems and legal costs; office rent; contract and consultant costs; and audit and tax fees.

Foreign Currency Transactions/Translation

Certain of our subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of subsidiaries with a Canadian dollar functional currency are translated at period-end rates of exchange, and revenues and expenses are translated at average exchange rates prevailing for each month. The resulting translation adjustments are made directly to a separate component of other comprehensive income, which is reflected in Partners’ Capital on our Consolidated Balance Sheets.

Certain of our subsidiaries also enter into transactions and have monetary assets and liabilities that are denominated in a currency other than the entities’ respective functional currencies. Gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities are generally included in the Consolidated Statements of Operations. However, gains and losses arising from intercompany foreign currency transactions that are of a long-term investment nature are reported in the same manner as translation adjustments. For the years ended December 31, 2025, 2024 and 2023, the revaluation of foreign currency transactions and monetary assets and liabilities resulted in the recognition of a net loss of $ 13  million, a net gain of $ 12  million and a net loss of $ 3  million, respectively, in our Consolidated Statements of Operations.

Cash and Cash Equivalents

Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal.

In accordance with our policy, unless they may be covered by funds on deposit, outstanding checks are classified as trade accounts payable rather than negative cash. As of December 31, 2025 and 2024, trade accounts payable included $ 31 million and $ 27 million, respectively, of outstanding checks that were reclassified from cash and cash equivalents.

Noncontrolling Interests
Noncontrolling interest represents the portion of assets and liabilities in a consolidated subsidiary that is owned by a third party. FASB guidance requires all entities to report noncontrolling interests in subsidiaries as a component of equity in the consolidated financial statements. See Note 12 for additional discussion regarding our noncontrolling interests.

Asset Retirement Obligations
FASB guidance establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including estimates related to (i) the time of the liability recognition, (ii) initial measurement of the liability, (iii) allocation of asset retirement cost to expense, (iv) subsequent measurement of the liability and (v) financial statement disclosures. FASB guidance also requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method.

Some of our assets, primarily our pipelines, and terminals assets, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. These assets have been in existence for many years and with regular maintenance will continue to be in service for many years to come. It is not possible to predict when demand for these transportation, storage or other services will cease, and we do not believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement
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Index to Financial Statements
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

obligations. We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonably estimate the settlement dates.

A small portion of our contractual or regulatory obligations is related to assets that are inactive or that we plan to take out of service and, although the ultimate timing and costs to settle these obligations are not known with certainty, we have recorded a reasonable estimate of these obligations. The following table presents the change in the liability for asset retirement obligations, substantially all of which is reflected in “Other long-term liabilities and deferred credits” on our Consolidated Balance Sheets as of December 31, 2025, 2024 and 2023 (in millions):

December 31,
2025 2024 2023
Beginning balance $ 109   $ 106   $ 103  
Liabilities incurred —   —   1  
Liabilities settled
( 1 ) ( 2 ) ( 1 )
Accretion expense 4   4   4  
Revisions in estimated cash flows —   1   ( 1 )
Ending balance $ 112   $ 109   $ 106  

Fair Value Measurements
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which affects the placement of assets and liabilities within the fair value hierarchy levels. The determination of the fair values includes not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit) but also the impact of our nonperformance risk on our liabilities. The fair value of our commodity, interest rate and foreign currency derivatives includes adjustments for credit risk. Our credit adjustment methodology uses market observable inputs and requires judgment. There were no changes to any of our valuation techniques during the period. See Note 13 for further discussion.

Other Significant Accounting Policies

See the respective footnotes for our accounting policies regarding (i) revenues and accounts receivable, (ii) net income per common unit, (iii) inventory, linefill and long-term inventory, (iv) property and equipment, (v) acquisitions, (vi) investments in unconsolidated entities, (vii) intangible assets, (viii) income allocation for partners’ capital presentation purposes, (ix) derivatives and risk management activities, (x) leases, (xi) income taxes, (xii) equity-indexed compensation and (xiii) legal and environmental matters.

Recent Accounting Pronouncements, Disclosure Rules and Other Legislation

Recent Accounting Pronouncements

In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses , which requires, among other things, disclosure of specified information about certain costs and expenses in the notes to the financial statements. The guidance is effective prospectively for annual periods beginning after December 15, 2026 and interim periods beginning after December 15, 2027 with retrospective application and early adoption permitted. We intend to provide the required disclosures beginning with our annual report for the year ended December 31, 2027.

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures , which requires, among other things, disaggregated information about effective tax rate reconciliation and income taxes paid (net of refunds received) on an annual basis. The guidance is effective prospectively for annual periods beginning after December 15, 2024 with retrospective or early adoption permitted. We adopted this guidance beginning with our annual report for the year ended December 31, 2025. See Note 15 for updated income tax disclosures. Other than such disclosure updates, our adoption did not have a material impact on our financial position, results of operations or cash flows.
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Table of Contents
Index to Financial Statements
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which requires disaggregated disclosure of significant segment expenses and other amounts included within the reported measure of segment profit or loss for each reportable segment on an annual and interim basis. The guidance is effective retrospectively for annual periods beginning after December 15, 2023, and interim periods in fiscal years beginning after December 15, 2024 with early adoption permitted. We adopted this guidance beginning with our annual report for the year ended December 31, 2024. See Note 20 for our segment disclosures. Other than disclosures, our adoption did not have a material impact on our financial position, results of operations or cash flows.

In August 2023, the FASB issued ASU 2023-05, Business Combinations—Joint Venture Formations (Subtopic 805-60): Recognition and Initial Measurement , which requires a newly-formed joint venture to apply a new basis of accounting to its contributed net assets, resulting in the joint venture initially measuring its contributed net assets at fair value on the formation date. This guidance is effective prospectively for all joint ventures with a formation date on or after January 1, 2025, with early adoption permitted. We adopted this guidance for joint venture formations on or after January 1, 2025.

SEC Climate Disclosure Rules

In March 2024, the SEC adopted final rules (“climate disclosure rules”) requiring registrants to disclose, among other things, information about material climate-related risks and their impact on a registrant’s strategy, business model and outlook; information about material direct and indirect greenhouse gas emissions (Scope 1 and Scope 2), which are subject to assurance requirements; and the financial statement effects of severe weather events and other natural conditions. In April 2024, the SEC stayed the climate disclosure rules pending resolution of legal challenges. In March 2025, the SEC voted to withdraw its defense of the climate disclosure rules.

International Tax Reform

Recently, several countries, including Canada, have enacted legislation to implement key aspects of the global minimum top-up tax in accordance with the Pillar Two model rules of the OECD tax framework. We continue to evaluate the new legislation, but do not currently expect a material impact on our financial position, results of operations or cash flows.

F-15

Table of Contents
Index to Financial Statements
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 3— Discontinued Operations

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

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

December 31,
2025 December 31,
2024
Assets:

Current assets:

Trade accounts receivable and other receivables, net
$ 285   $ 222  
Inventory 176   178  
Other current assets 18   15  
Total current assets of discontinued operations
$ 479   $ 415  

Long-term assets:
Property and equipment, net (1)
$ 2,191   $ 1,978  

Linefill 70   64  
Long-term operating lease right-of-use assets, net 138   143  
Long-term inventory 38   38  
Other long-term assets, net 120   126  
Total long-term assets of discontinued operations
$ 2,557   $ 2,349  

Liabilities:

Current liabilities:
Trade accounts payable
$ 295   $ 234  

Other current liabilities 87   116  
Total current liabilities of discontinued operations
$ 382   $ 350  

Long-term liabilities:

Long-term operating lease liabilities $ 96   $ 121  
Other long-term liabilities and deferred credits 510   455  
Total long-term liabilities of discontinued operations
$ 606   $ 576  

(1) Amounts are net of accumulated depreciation of $ 876  million and $ 794  million as of December 31, 2025 and 2024, respectively.
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Table of Contents
Index to Financial Statements
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE 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):

Year Ended December 31,

2025 2024 2023
Revenues:

Product sales
$ 1,186   $ 1,055   $ 1,229  
Services
131   129   147  
Total revenues
1,317   1,184   1,376  
Cost and Expenses:

Purchases and related costs
411   398   594  
Field operating costs 259   297   340  
General and administrative expenses 47   53   51  
Depreciation and amortization
57   125   139  
Losses on asset sales, net
21   1   —  
Total costs and expenses
795   874   1,124  
Other income, net
—   1   —  
Income from discontinued operations before tax 522   311   252  
Current income tax expense
( 99 ) ( 113 ) ( 75 )
Deferred income tax (expense)/benefit
( 40 ) 33   15  
Income from discontinued operations, net of tax $ 383   $ 231   $ 192  

Note 4— 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):

Year Ended December 31,
2025 2024 2023
Crude Oil segment revenues from contracts with customers
Sales $ 42,408   $ 47,036   $ 45,621  
Transportation 1,330   1,231   1,144  
Terminalling, Storage and Other 349   384   381  
Total Crude Oil segment revenues from contracts with customers $ 44,087   $ 48,651   $ 47,146  

Year Ended December 31,
2025 2024 2023
NGL segment revenues from contracts with customers
Sales $ 144   $ 180   $ 179  

Terminalling, Storage and Other 6   7   7  

Total NGL segment revenues from contracts with customers $ 150   $ 187   $ 186  

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Table of Contents
Index to Financial Statements
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS