10-K – 2026-02-27 – paa-20251231.htm

Sales Revenues. Revenues from sales of crude oil and NGL are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. The consideration received under these contracts is variable based on commodity prices. Inventory exchanges under buy/sell transactions are excluded from sales revenues in our Consolidated Statements of Operations.

Transportation Revenues. Transportation revenues include revenues from transporting crude oil on pipelines and trucks. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil at a published tariff. We primarily recognize pipeline tariff and fee revenues over time as services are rendered, based on the volumes transported. As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor. We recognize the allowance volumes collected as part of the transaction price and record this non-cash consideration at fair value, measured as of the contract inception date.

Terminalling, Storage and Other Revenues. Revenues in this category include (i) fees that are generated when we receive liquids from one connecting source and deliver the applicable product to another connecting carrier, (ii) fees from storage capacity agreements, (iii) fees from loading and unloading services at our terminals and (iv) fees from natural gas and condensate processing services. We generate revenue through a combination of month-to-month and multi-year agreements and processing arrangements. Storage fees are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized as our performance obligation is to make available storage capacity for a period of time. Terminal fees (including throughput and loading/unloading fees) are recognized as the liquids enter or exit the terminal and are received from or delivered to the connecting carrier or third-party terminal, as applicable. We recognize loading and unloading fees when the volumes are delivered or received.

Reconciliation to Total Revenues of Reportable Segments. The following disclosures only include information regarding revenues associated with consolidated entities; revenues from entities accounted for by the equity method are not included. The following tables present the reconciliation of our revenues from contracts with customers (as described above for each segment) to total revenues of reportable segments and total revenues as disclosed in our Consolidated Statements of Operations (in millions):

Year Ended December 31, 2025 Crude Oil NGL Total
Revenues from contracts with customers $ 44,087   $ 150   $ 44,237  
Other revenues
44   1   45  
Total revenues of reportable segments $ 44,131   $ 151   $ 44,282  
Intersegment revenues elimination ( 20 )
Total revenues $ 44,262  

Year Ended December 31, 2024 Crude Oil NGL Total
Revenues from contracts with customers $ 48,651   $ 187   $ 48,838  
Other revenues
69   —   69  
Total revenues of reportable segments $ 48,720   $ 187   $ 48,907  
Intersegment revenues elimination ( 18 )
Total revenues $ 48,889  

Year Ended December 31, 2023 Crude Oil NGL Total
Revenues from contracts with customers $ 47,146   $ 186   $ 47,332  
Other revenues
28   —   28  
Total revenues of reportable segments $ 47,174   $ 186   $ 47,360  
Intersegment revenues elimination ( 24 )
Total revenues $ 47,336  

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Minimum Volume Commitments. We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right as a contract liability and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote.

The following table presents counterparty deficiencies associated with contracts with customers and buy/sell arrangements that include minimum volume commitments for which we had remaining performance obligations and the customers still had the ability to meet their obligations (in millions):

December 31,
Counterparty Deficiencies Financial Statement Classification 2025 2024
Billed and collected Other current liabilities $ 47   $ 83  

Contract Balances . Our contract balances consist of amounts received associated with services or sales for which we have not yet completed the related performance obligation. The following table presents the changes in the liability balance associated with contracts with customers (in millions):

Contract Liabilities
Balance at December 31, 2023 $ 101  
Amounts recognized as revenue
( 36 )

Additions
23  
Other ( 1 )
Balance at December 31, 2024 $ 87  
Amounts recognized as revenue ( 42 )
Additions 42  

Balance at December 31, 2025 $ 87  

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

2026
2027
2028
2029
2030
2031 and Thereafter

Pipeline revenues supported by minimum volume commitments and capacity agreements (1)
$ 398   $ 330   $ 296   $ 210   $ 152   $ 835  
Terminalling, storage and other agreement revenues
241   211   153   109   72   423  
Total $ 639   $ 541   $ 449   $ 319   $ 224   $ 1,258  

(1) Calculated as volumes committed under contracts multiplied by the current applicable tariff rate.
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The presentation above does not include (i) expected revenues from legacy shippers not underpinned by minimum volume commitments, (ii) intersegment revenues and (iii) the amount of consideration associated with certain income generating contracts, which include a fixed minimum level of service, that are either not within the scope of ASC 606 or do not meet the requirements for presentation as remaining performance obligations. The following are examples of contracts that are not included in the table above because they are not within the scope of ASC 606 or do not meet the requirements for presentation:

• Minimum volume commitments on certain of our joint venture pipeline systems;
• Acreage dedications;
• Buy/sell arrangements with future committed volumes;
• Short-term contracts and those with variable consideration due to the election of practical expedients, as discussed below;
• Contracts within the scope of ASC Topic 842, Leases ; and
• Contracts within the scope of ASC Topic 815, Derivatives and Hedging .

We have elected practical expedients to exclude the presentation of remaining performance obligations for variable consideration which relates to wholly unsatisfied performance obligations. Certain contracts do not meet the requirements for presentation of remaining performance obligations due to variability in amount of performance obligation remaining, variability in the timing of recognition or variability in consideration. Acreage dedications require us to perform future services but do not contain a minimum level of services and are therefore excluded from this presentation. Long-term merchant arrangements contain variable timing, volumes and/or consideration and are excluded from this presentation. The duration of these contracts varies across the periods presented above.

Additionally, we have elected practical expedients to exclude contracts with terms of one year or less, and therefore exclude the presentation of remaining performance obligations for short-term transportation, storage and processing services, merchant arrangements, including the non-cancelable period of evergreen arrangements, and any other types of arrangements with terms of one year or less.

Trade Accounts Receivable and Other Receivables, Net
 
Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL. These purchasers include, but are not limited to, refiners, producers, marketing and trading companies and financial institutions. The majority of our accounts receivable relate to our crude oil merchant activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes.

To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions and perform credit reviews of each customer to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit, credit insurance or parental guarantees. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. For a majority of these net-cash arrangements, we also enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet).
 
Accounts receivable from the sale of crude oil are generally settled with counterparties on the industry settlement date, which is typically in the month following the month in which the title transfers. Otherwise, we generally invoice customers within 30 days of when the products or services were provided and generally require payment within 30 days of the invoice date. We review all outstanding accounts receivable balances on a monthly basis and record our receivables net of expected credit losses. We do not write-off accounts receivable balances until we have exhausted substantially all collection efforts. At December 31, 2025 and 2024, substantially all of our trade accounts receivable were less than 30 days past their invoice date. Our expected credit losses are immaterial. Although we consider our credit procedures to be adequate to mitigate any significant credit losses, the actual amount of current and future credit losses could vary significantly from estimated amounts.

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The following is a reconciliation of trade accounts receivable from revenues from contracts with customers to total Trade accounts receivable and other receivables, net as presented on our Consolidated Balance Sheets (in millions):

December 31,
2025 2024
Trade accounts receivable arising from revenues from contracts with customers
$ 3,639   $ 3,922  
Other trade accounts receivables and other receivables (1)
7,357   7,339  
Impact due to contractual rights of offset with counterparties ( 7,398 ) ( 7,582 )
Trade accounts receivable and other receivables, net $ 3,598   $ 3,679  

(1) The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of ASC 606.

Note 5— Net Income Per Common Unit

After consideration of distributions to preferred unitholders, basic and diluted net income per common unit is determined pursuant to the two-class method as prescribed in FASB guidance. This method is an earnings allocation formula that is used to determine allocations to our limited partners and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings or distributions in excess of earnings. Under the two-class method, income from continuing operations is reduced by distributions pertaining to the period, and all remaining earnings or distributions in excess of earnings are then allocated to our common unitholders and participating securities based on their respective rights to share in distributions, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. Participating securities include equity-indexed compensation plan awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units.

We calculate basic and diluted net income per common unit by dividing income from continuing operations attributable to PAA (after deducting amounts allocated to the preferred unitholders and participating securities) and income from discontinued operations by the basic and diluted weighted average number of common units outstanding during the period.

The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units and (ii) our equity-indexed compensation plan awards. See Note 12 for additional information regarding our Series A preferred units. See Note 18 for a complete discussion of our equity-indexed compensation plan awards. When applying the if-converted method prescribed by FASB guidance, the possible conversion of approximately 59  million, 71  million and 71  million Series A preferred units, on a weighted-average basis, were excluded from the calculation of diluted net income per common unit for the years ended December 31, 2025, 2024 and 2023, respectively, as the effect was antidilutive for all periods. Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that are deemed to be dilutive during the year are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.

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The following table sets forth the computation of basic and diluted net income per common unit (in millions, except per unit data):

Year Ended December 31,
2025 2024 2023
Basic and Diluted Net Income per Common Unit
Continuing Operations:
Income from continuing operations, net of tax
$ 1,386   $ 882   $ 1,310  
Net income attributable to noncontrolling interests
( 334 ) ( 341 ) ( 272 )
Net income from continuing operations attributable to PAA 1,052   541   1,038  
Distributions to Series A preferred unitholders ( 146 ) ( 175 ) ( 173 )
Distributions to Series B preferred unitholders ( 70 ) ( 78 ) ( 76 )
Amounts allocated to participating securities ( 11 ) ( 10 ) ( 10 )
Impact from repurchase of Series A preferred units (1)
( 43 ) —   —  
Other 4   5   5  
Net income from continuing operations allocated to common unitholders - Basic and Diluted (2)
$ 786   $ 283   $ 784  

Discontinued Operations:
Net income from discontinued operations allocated to common unitholders - Basic and Diluted (3)
$ 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  

(1) We repurchased approximately 12.7  million Series A preferred units on January 31, 2025. See Note 12 for additional discussion of this transaction. The difference between the cash we paid for the repurchase of such units and their carrying value on our balance sheet is considered a return to Series A preferred unitholders for the calculation of net income from continuing operations allocated to common unitholders.
(2) We calculate net income from continuing operations allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (i.e., undistributed loss), if any, are allocated to the common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method.
(3) Net income from discontinued operations allocated to common unitholders is Income from discontinued operations, net of tax as presented on our Consolidated Statements of Operations.

Note 6— Inventory, Linefill and Long-term Inventory

Inventory, including long-term inventory, primarily consists of crude oil and NGL in pipelines, storage facilities and railcars that are 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 make any adjustments necessary to reduce the carrying value to the applicable net realizable value. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Consolidated Statements of Operations. No adjustments were recorded during the years ended December 31, 2025, 2024 or 2023.

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Linefill in assets we own is recorded at historical cost. We classify as linefill (i) our proportionate share of barrels used to fill a pipeline that we own such that when an incremental barrel is pumped into or enters a pipeline it forces product out at another location and (ii) barrels that represent the minimum working requirements in tanks and caverns that we own. Linefill carrying amounts are reviewed for impairment in accordance with FASB guidance with respect to accounting for the impairment or disposal of long-lived assets. Carrying amounts that are not expected to be recoverable through future cash flows are written down to estimated fair value. See Note 7 for further discussion regarding impairment of long-lived assets. During 2025, 2024 and 2023, we did not recognize any material impairments of linefill.

Minimum working inventory requirements in third-party assets and other working inventory in our assets that are needed for our commercial operations are included within specific inventory pools in inventory (a current asset) in determining the average cost of operating inventory. At the end of each period, we reclassify the inventory not expected to be liquidated within the succeeding twelve months out of “Inventory,” at the average cost of the applicable inventory pools, and into “Long-term inventory,” which is reflected as a separate line item under “Other assets” on our Consolidated Balance Sheets.

Inventory, linefill and long-term inventory consisted of the following (barrels in thousands and carrying value in millions):

December 31, 2025 December 31, 2024
Volumes Unit of
Measure Carrying
Value Price/
Unit  (1)
Volumes Unit of
Measure Carrying
Value Price/
Unit  (1)

Inventory
Crude oil 2,948   barrels $ 166   $ 56.31   3,321   barrels $ 221   $ 66.55  
NGL 562   barrels 27   $ 48.04   603   barrels 26   $ 43.12  

Other N/A 18   N/A N/A 14   N/A
Inventory subtotal 211   261  

Linefill
Crude oil 15,112   barrels 898   $ 59.42   15,463   barrels 903   $ 58.40  
NGL 33   barrels 2   $ 60.61   32   barrels 1   $ 31.25  

Linefill subtotal 900   904  

Long-term inventory
Crude oil 3,724   barrels 213   $ 57.20   3,413   barrels 238   $ 69.73  
NGL 26   barrels 1   $ 38.46   90   barrels 4   $ 44.44  
Long-term inventory subtotal 214   242  

Total $ 1,325   $ 1,407  

(1) Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products.

Note 7— Property and Equipment

In accordance with our capitalization policy, expenditures made to expand the existing operating and/or earnings capacity of our assets are capitalized, as are certain costs directly related to the construction of such assets, including related internal labor costs, engineering costs and interest costs. We also capitalize 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. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are expensed as incurred.

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Property and equipment, net is stated at cost and consisted of the following (in millions):

Estimated Useful
Lives (Years)
December 31,
2025 2024
Crude oil pipeline systems
10 - 50
$ 18,428   $ 14,612  
Crude oil storage and terminal facilities
10 - 50
2,808   2,679  
NGL storage, terminal, fractionation and processing facilities
10 - 50
365   364  

Office property and equipment and rolling stock
2 - 50
373   430  
Construction in progress N/A 238   148  
Land and other N/A 324   295  
Property and equipment, gross (1)
22,536   18,528  
Accumulated depreciation ( 5,676 ) ( 5,082 )
Property and equipment, net $ 16,860   $ 13,446  

(1) We include rights-of-way, which are intangible assets, within property and equipment.

We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets. Depreciation expense for the years ended December 31, 2025, 2024 and 2023 was $ 673 million, $ 639 million and $ 618 million, respectively.

As of December 31, 2025, 2024 and 2023, we incurred liabilities of $ 43  million, $ 44  million and $ 40  million, respectively, for construction in progress that had not been paid.

Impairment of Long-Lived Assets (Held and Used)

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value in accordance with FASB guidance with respect to the accounting for the impairment or disposal of long-lived assets. Under this guidance, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized.

We periodically evaluate property and equipment and other long-lived assets for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. The subjective assumptions used to determine the existence of an impairment in carrying value include:
• whether there is an indication of 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.

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During the fourth quarter of 2024, we recognized approximately $ 140  million of non-cash charges related to the write-down of certain of our long-lived U.S. based NGL terminal assets included in our NGL segment due to asset impairments and accelerated depreciation. Such charges are reflected in “ (Gains)/losses on asset sales, asset impairments and other, net ” on our Consolidated Statement of Operations. We have experienced a decrease in demand for our services at certain of our terminals within two asset groups related to changing market conditions specific to their locations, which was a triggering event that required us to assess the recoverability of carrying value of such long-lived assets. As a result of our impairment review, we wrote-off the portion of the carrying amount of these long-lived assets that exceeded their fair value. Our estimated fair value was based on the determination that a portion of the long-lived assets had no residual value. We consider such inputs to be a Level 3 input in the fair value hierarchy. Further, we determined that an acceleration of depreciation was appropriate for another portion of the long-lived assets.

We did not recognize any material asset impairments during the years ended December 31, 2025 and 2023.

Note 8— Acquisitions, Divestitures and Other Transactions

Acquisitions

EPIC (Cactus III)

On October 31, 2025, we purchased an aggregate 55 % equity interest in EPIC Crude Holdings, LP (“EPIC Crude Holdings”), which owns the EPIC Crude Oil Pipeline (which we now refer to as our “Cactus III Pipeline”), from subsidiaries of Diamondback Energy, Inc. and Kinetik Holdings Inc., for approximately $ 1.568  billion, subject to certain adjustments and inclusive of $ 613  million of debt assumed. We also agreed to a potential earnout payment of $ 193  million contingent upon the formal sanctioning before the end of 2027 of one or more expansions of Cactus III Pipeline that in the aggregate will increase the capacity of the pipeline to at least 900,000 barrels per day. In a separate transaction, effective November 1, 2025, we acquired the remaining 45 % equity interest in EPIC Crude Holdings from a portfolio company of Ares Private Equity funds for approximately $ 1.327  billion, subject to certain adjustments and inclusive of $ 501  million of debt assumed. We also agreed to a potential earnout payment to the seller of up to $ 157  million depending on the timing and amount of incremental expansion capacity up to 300,000 barrels per day in excess of 650,000 barrels per day that is formally sanctioned before the end of 2028. The aggregate cash consideration also includes closing cash and working capital of approximately $ 121  million. The estimated fair value of the aggregate earnout consideration recorded in connection with these transactions was approximately $ 115  million. The fair value of the aggregate earnout consideration was determined based on weighted-average probabilities of certain capacity expansion scenarios and the related timing thereof.

Subsequent to these two transactions (collectively, the “EPIC acquisition”), we now own 100 % of EPIC Crude Holdings and are the operator of record for the Cactus III Pipeline, which provides long-haul crude oil takeaway from the Permian and Eagle Ford basins to the Gulf Coast market at Corpus Christi. We believe this acquisition is highly synergistic and strategic to our existing footprint. The EPIC acquisition will be accounted for in our Crude Oil segment.

The EPIC acquisition was accounted for as a business combination using the acquisition method of accounting. The following table presents the fair value of the consideration in the EPIC acquisition (in millions):

Consideration:
Recognized Amount
Cash consideration $ 1,901  
Contingent consideration 115  

Total consideration $ 2,016  

In accordance with applicable accounting guidance, the fair value of the assets acquired and liabilities assumed following the acquisition was utilized as the consideration transferred for the purchase price allocation. The determination of the fair value of the assets and liabilities assumed was estimated in accordance with applicable accounting guidance. The analysis was performed based on estimates that are reflective of market participant assumptions. The following table reflects our preliminary determination of the fair value of the assets acquired and liabilities assumed in connection with the EPIC acquisition (in millions):

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Identifiable Assets Acquired and Liabilities Assumed: Estimated Useful Lives
(in years) Recognized Amount
Working capital and other assets, net
N/A
$ 160  
Property and equipment, net
47 2,737  
Intangible assets
5 - 10
267  
Other long-term debt, net
N/A
( 1,114 )
Long-term operating lease liability
N/A
( 34 )

Total $ 2,016  

The acquired Property and equipment, net is primarily comprised of pipelines, equipment and rights of way. The intangible assets recognized in this transaction relate to long-term contracts which contain rates that are favorable to current market conditions. We utilized widely accepted valuation techniques for these types of assets that represent Level 3 measurements in the fair value hierarchy. A Level 3 measurement is one for which there are no observable market inputs.

The fair value of acquired pipelines and equipment was determined using a cost approach with an assumption for replacement cost. The fair value of acquired rights of way was determined using a market approach for similar assets.

The fair value of the favorable contracts was determined using an income approach that considers the projected volumes to be transported over the life of the contracts, assumptions for current market rates, and a discount rate that a theoretical market participant would assign to the intangible asset of approximately 17 %.

The useful lives of the favorable contracts range from 5 to 10 years, and amortization of these intangible assets is recognized using the declining balance method of amortization. Amortization expense was approximately $ 15  million for the year ended December 31, 2025, and the future amortization expense through 2030 is estimated as follows (in millions):

2026 $ 67  
2027 $ 53  
2028 $ 34  
2029 $ 29  
2030 $ 21  

In connection with the EPIC acquisition, 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 (the “EPIC revolver”). On December 1, 2025, we repaid the $ 1.1  billion of borrowings outstanding under the EPIC term loan and terminated the EPIC credit agreement. See Note 11 for additional information regarding the EPIC credit agreement. The EPIC term loan was valued at par based on the expectation of terminating the loan at such value.

During the year ended December 31, 2025, we incurred approximately $ 9  million of transaction-related costs associated with the EPIC acquisition. Such costs are reflected as a component of “General and administrative expenses” on our Consolidated Statements of Operations.

Pro Forma and Other Financial Results

Financial results from the EPIC acquisition have been included in our results of operations within the Crude Oil segment since the date of the acquisition. The EPIC revenues and earnings generated during the period since the acquisition date were not material for disclosure purposes.

The following selected unaudited pro forma results of operations were derived from the historical financial statements of EPIC Crude Holdings, and gives effect to the EPIC acquisition as if it had occurred on January 1, 2024. The pro forma results of operations do not include any cost savings or other synergies that may result from the EPIC acquisition or any estimated costs that have been or will be incurred by us to integrate the assets acquired. These results are not necessarily indicative of the results that might have actually occurred had the acquisition taken place on January 1, 2024; furthermore, this financial information is not intended to be a projection of future results (in millions, except per unit amounts):
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Year Ended December 31,

2025 2024
Total revenues
$ 44,464   $ 49,124  
Net income attributable to PAA from continuing operations
$ 979   $ 347  
Net income allocated to common unitholders from continuing operations
$ 713   $ 89  
Basic and diluted net income per common unit from continuing operations
$ 1.01   $ 0.13  

Ironwood Midstream

On January 31, 2025, we acquired Ironwood Midstream Energy Partners II, LLC (“Ironwood Midstream”), which owns a gathering system in the Eagle Ford Basin, for approximately $ 481  million in cash from EnCap Flatrock Midstream. The Ironwood Midstream acquisition is accounted for in our Crude Oil segment. In January 2025, in a separate transaction, we also repurchased from EnCap Flatrock Midstream, a portion of our outstanding Series A preferred units. EnCap Flatrock Midstream is affiliated with EnCap Investments, L.P, an entity that is associated with a member of the board of directors of PAGP GP. See Note 12 for additional information.

The Ironwood Midstream acquisition was accounted for as a business combination using the acquisition method of accounting. In accordance with applicable accounting guidance, the fair value of the assets acquired and liabilities assumed following the acquisition was utilized as the consideration transferred for the purchase price allocation. The determination of the fair value of the assets and liabilities assumed was estimated in accordance with applicable accounting guidance. The analysis was performed based on estimates that are reflective of market participant assumptions. The following table reflects our preliminary determination of the fair value of the Ironwood Midstream acquisition assets and liabilities (in millions):

Identifiable Assets Acquired and Liabilities Assumed: Estimated Useful Lives
(in years) Recognized Amount
Property and equipment 3 - 30
$ 435  
Intangible assets
16 27  
Working capital and other assets and liabilities N/A 19  
$ 481  

The fair value of the tangible asset is a Level 3 measurement in the fair value hierarchy and was determined using a cost approach for tangible assets, with an assumption for replacement cost, and a market approach for rights-of-way. A Level 3 measurement is one for which there are no observable market inputs. The fair value of the intangible assets is also a Level 3 measurement in the fair value hierarchy and was determined by applying a discounted cash flow approach. Such approach utilized a discount rate of 18 %, based on our estimate of the risk that a theoretical market participant would assign to the intangible asset. The projection of future crude oil volumes transported and the estimated tariff rates for transportation were also key assumptions in the valuation of the intangible assets. Projected future volumes and estimated tariff rates were based on current contracts in place with assumptions for forecasted rate increases and contract renewals.

The fair value of intangible asset is comprised of customer relationships that will be amortized over their useful lives, which have a remaining weighted average life of approximately 16 years. The value assigned to such intangible asset will be amortized to earnings under the declining balance method of amortization . Amortization expense was approximately $ 4  million for the year ended December 31, 2025, and the future amortization expense through 2030 is estimated as follows (in millions):

2026 $ 5  
2027 $ 4  
2028 $ 3  
2029 $ 3  
2030 $ 2  

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Pro forma financial information assuming the acquisition had occurred as of the beginning of the calendar year prior to the year of the acquisition, as well as the revenues and earnings generated during the period since the acquisition date, were not material for disclosure purposes.

Rattler Permian Transaction

In the third quarter of 2023, we completed a transaction with Rattler Midstream Operating LLC (“Rattler”) pursuant to which the Permian JV acquired the remaining 43 % interest in OMOG JV Holdings LLC (“OMOG”) and certain gathering assets in the Southern Delaware basin. The transaction had an aggregate purchase price of $ 294  million ($ 191  million net to our 65 % interest in the Permian JV). As a result of the transaction, the Permian JV now owns 100 % of OMOG and its subsidiaries and such entities are reflected as consolidated subsidiaries in our Consolidated Financial Statements. Prior to this transaction, the Permian JV’s 57 % interest in OMOG was accounted for as an equity method investment.

The transaction was accounted for as a business combination using the acquisition method of accounting. In accordance with applicable accounting guidance, the fair value of the assets acquired and liabilities assumed following the transaction was utilized as the consideration transferred for the purchase price allocation.

As a result of us obtaining control over OMOG, the Permian JV’s previously-held 57 % interest in OMOG was remeasured to its fair value of $ 239  million based upon a valuation of the acquired business, as of the date of acquisition. We considered multiple factors in determining the fair value of the previously-held equity method investment, including, (i) the price negotiated with Rattler for its 43 % interest in OMOG and (ii) a discounted cash flow approach. The discounted cash flow approach utilized a discount rate of approximately 11 %, based on the estimate of the risk that a theoretical market participant would assign to the business. The remeasurement of the Permian JV’s investment in OMOG to fair value resulted in a gain of $ 29  million. This gain has been recognized in the line item “ Gain on investments in unconsolidated entities, net ” on our Consolidated Statement of Operations.

The determination of the fair value of the assets and liabilities assumed was estimated in accordance with applicable accounting guidance. The analysis was performed based on estimates that are reflective of market participant assumptions. While the purchase price for the transaction was $ 294  million, all of the OMOG assets and liabilities were remeasured to fair value and therefore, the fair value of the assets and liabilities that are now consolidated on the balance sheet as a result of this transaction is $ 532  million. The following table reflects our determination of the fair value of the assets acquired and liabilities assumed in connection with the transaction (in millions):

Identifiable Assets Acquired and Liabilities Assumed: Estimated Useful Lives
(in years) Recognized Amount
Property and equipment 3 - 30
$ 484  
Intangible assets 10 34  
Working capital and other assets and liabilities N/A 14  
$ 532  

The fair value of the tangible assets is a Level 3 measurement in the fair value hierarchy and was determined using the cost approach based on costs incurred on similar recent construction projects. The fair value of the intangible assets is also a Level 3 measurement in the fair value hierarchy and was determined by applying a discounted cash flow approach. Such approach utilized discount rates varying from approximately 21 % to 23 %, based on our estimate of the risk that a theoretical market participant would assign to the respective intangible assets. The projection of future crude oil volumes transported and the estimated tariff rates for transportation were also key assumptions in the valuation of the intangible assets. Projected future volumes and estimated tariff rates were based on current contracts in place with assumptions for forecasted rate increases and contract renewals.

The fair value of intangible assets is comprised of customer relationships that will be amortized over their useful lives, which have a remaining weighted average life of approximately 10 years. The value assigned to such intangible assets will be amortized to earnings under the declining balance method of amortization. Amortization expense was approximately $ 10  million, $ 8  million and $ 4  million during the years ended December 31, 2025, 2024 and 2023, respectively, and the future amortization expense through 2028 is estimated as follows (in millions):

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2026 $ 4  
2027 $ 3  
2028 $ 2  

Pro forma financial information assuming the acquisition had occurred as of the beginning of the calendar year prior to the year of the acquisition, as well as the revenues and earnings generated during the period since the acquisition date, were not material for disclosure purposes.

Other Acquisitions

2025
During the year ended December 31, 2025, we completed the following additional acquisitions:

• the acquisition in July 2025 of an additional 20 % interest in BridgeTex Pipeline Company, LLC (“BridgeTex”) for approximately $ 180  million, increasing our ownership interest from 20 % to 40 %. See Note 9 for additional information about our investments in unconsolidated entities.

• the acquisition during the second quarter of 2025 of Black Knight Midstream, LLC (“Black Knight Midstream”), which owns a crude oil gathering business in the Permian Basin, for $ 59  million (approximately $ 38  million net to our 65 % interest in the Permian JV), subject to certain adjustments. The Black Knight Midstream assets are accounted for in our Crude Oil segment.

• the acquisition in February 2025, through a non-monetary transaction, of the remaining 50 % interest in Cheyenne Pipeline LLC (“Cheyenne”) in exchange for the termination of certain obligations. As a result of this transaction, we now own 100 % of Cheyenne and reflect such entity as a consolidated subsidiary in our Consolidated Financial Statements within our Crude Oil segment. The transaction resulted in a net gain of approximately $ 31  million, which represents the difference between the fair value of the entity and the historical book value of our investment. This gain is reflected in “Gain on investments in unconsolidated entities, net” on our Consolidated Statement of Operations.

• the acquisition in January 2025 of EMG Medallion 2 Holdings, LLC and its subsidiaries, which own a crude oil gathering and transportation business in the Delaware Basin, for $ 163  million (approximately $ 106  million net to our 65 % interest in the Permian JV), subject to certain adjustments. A cash deposit of approximately $ 16  million was paid upon signing in December 2024. EMG Medallion 2 Holdings was a portfolio company of The Energy & Minerals Group (“EMG”), which is associated with a member of the board of directors of PAGP GP.

2024

During the year ended December 31, 2024, we also completed the following acquisitions:

• the acquisition in December 2024 of the remaining 50 % interest in Midway Pipeline LLC (“Midway”) for approximately $ 90  million. As a result of this transaction, we now own 100 % of Midway and reflect such entity as a consolidated subsidiary in our Consolidated Financial Statements. The remeasurement of our previously-held investment in Midway to fair value resulted in a gain of approximately $ 15  million. This gain is reflected in “ Gain on investments in unconsolidated entities, net ” on our Consolidated Statement of Operations.

• the acquisition of additional interests in certain unconsolidated entities, including (i) the acquisition in August 2024 of an additional approximate 0.67 % interest in Wink to Webster Pipeline LLC (increasing our ownership interest from 16 % to 17 %) for $ 20  million and (ii) the acquisition in March 2024 of an additional 10 % interest in Saddlehorn Pipeline Company, LLC (increasing our ownership interest from 30 % to 40 %) for $ 91  million. See Note 9 for additional information about our investments in unconsolidated entities.

• the acquisition in the second and third quarters of 2024 of pipeline and terminal assets within our asset footprint for approximately $ 32  million.

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2023

In November 2023, we acquired a crude oil gathering system in the Northern Delaware Basin from a subsidiary of LM Energy Partners for approximately $ 135  million (approximately $ 88  million net to our 65 % interest in the Permian JV), subject to certain adjustments. This transaction was accounted for as an asset acquisition since substantially all of the value of the assets acquired was concentrated in a single asset.

Divestitures

During the year ended December 31, 2025, we received cash proceeds of $ 81  million, primarily from the sale of non-core assets, which were previously included in our Crude Oil segment. We recognized gains of approximately $ 44  million related to these asset sales, which is included in “(Gains)/losses on asset sales, asset impairments and other, net” on our Consolidated Statement of Operations.

In February 2023, we sold our 21 % non-operated/undivided joint interest in the Keyera Fort Saskatchewan facility to Keyera Corporation for approximately $ 270  million. As of December 31, 2022, we classified the assets related to this transaction (primarily “Property and equipment” in our NGL segment), valued at the lower of the carrying amount or fair value less costs to sell, of approximately $ 130  million as assets held for sale on our Consolidated Balance Sheet (in “Other current assets”). At the time of this transaction, we concluded that this disposition did not meet the criteria for discontinued operations. Upon the sale of this facility, we recognized a gain of approximately $ 140  million which is included in “(Gains)/losses on asset sales, asset impairments and other, net” on our Consolidated Statement of Operations.

Note 9— Investments in Unconsolidated Entities

Investments in entities over which we have significant influence but not control are accounted for under the equity method. We do not consolidate any part of the assets or liabilities of our equity investees. Our share of net income or loss is reflected as one line item on our Consolidated Statements of Operations entitled “Equity earnings in unconsolidated entities” and will increase or decrease, as applicable, the carrying value of our investments in unconsolidated entities on our Consolidated Balance Sheets. We evaluate our equity investments for impairment in accordance with FASB guidance with respect to the equity method of accounting for investments in common stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature.

Our investments in unconsolidated entities consisted of the following (in millions, except percentage data):

Ownership
Interest at December 31,
2025
Investment Balance
December 31,

Entity (1)
Type of Operation 2025 2024
BridgeTex Pipeline Company, LLC (“BridgeTex”) Crude Oil Pipeline 40 % $ 574   $ 403  

Capline Pipeline Company LLC (“Capline”) (2)
Crude Oil Pipeline 54 % 473   501  
Diamond Pipeline LLC
Crude Oil Pipeline 50 % 432   440  
Eagle Ford Pipeline LLC
Crude Oil Pipeline 50 % 347   364  
Eagle Ford Terminals Corpus Christi LLC
Crude Oil Terminal and Dock 50 % 110   113  

Saddlehorn Pipeline Company, LLC (“Saddlehorn”)
Crude Oil Pipeline 40 % 262   275  
White Cliffs Pipeline, L.L.C.
Crude Oil Pipeline 36 % 109   123  
Wink to Webster Pipeline LLC (“W2W Pipeline”) (3)
Crude Oil Pipeline 17 % 383   393  
Other investments 156   199  
Total Investments in Unconsolidated Entities $ 2,846   $ 2,811  

(1) The financial results from these entities are reported in our Crude Oil segment.
(2) Although we own more than 50% of Capline, we use the equity method to account for the investment because the other joint venture members still retain substantive participating rights.
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(3) Although we own less than 20% of W2W Pipeline, we use the equity method to account for the investment because we believe we have significant influence over the financial and operating decisions of the company.

Acquisitions

During 2025, we acquired the remaining 50 % interest in Cheyenne (which was previously presented in “Other investments” in the table above). Prior to our acquisition, our 50 % interest in Cheyenne was accounted for as an equity method investment. In addition, during 2025, we acquired an additional interest in BridgeTex, which we continue to account for as an equity method investment. See Note 8 for additional information regarding these transactions.

During 2024, we acquired the remaining 50 % interest in Midway (which was previously presented in “Other investments” in the table above). Prior to our acquisition, our 50 % interest in Midway was accounted for as an equity method investment. In addition, during 2024, we acquired additional interests in W2W Pipeline and Saddlehorn, which we continue to account for as equity method investments. See Note 8 for additional information regarding these transactions.

In the third quarter of 2023, we acquired the remaining 43 % interest in OMOG. We now reflect OMOG and its subsidiaries as consolidated subsidiaries in our Consolidated Financial Statements. See “Rattler Permian Transaction” in Note 8 for additional information.

Distributions

Distributions received from unconsolidated entities are classified based on the nature of the distribution approach, which looks to the activity that generated the distribution. We consider distributions received from unconsolidated entities as a return on investment in those entities to the extent that the distribution was generated through operating results, and therefore classify these distributions as cash flows from operating activities in our Consolidated Statement of Cash Flows. Other distributions received from unconsolidated entities are considered a return of investment and classified as cash flows from investing activities on the Consolidated Statement of Cash Flows.

Contributions

We generally fund our portion of development, construction or capital investment projects of our equity method investees through capital contributions. During the years ended December 31, 2025, 2024 and 2023, we made cash contributions of $ 2 million, $ 4 million and $ 29 million, respectively, to certain of our equity method investees. We capitalize interest costs associated with contributions to unconsolidated entities for projects under development and construction. Our contributions to these entities (including capitalized interest costs) increase the carrying value of our investments and are reflected in our Consolidated Statements of Cash Flows as cash used in investing activities.

Basis Differences

Our investments in unconsolidated entities exceeded our share of the underlying equity in the net assets of such entities by $ 237 million and $ 213 million at December 31, 2025 and 2024, respectively. Such basis differences are included in the carrying values of our investments on our Consolidated Balance Sheets. The portion of the basis differences attributable to depreciable or amortizable assets is amortized on a straight-line basis over the estimated useful life of the related assets, which reduces “Equity earnings in unconsolidated entities” on our Consolidated Statements of Operations. The portion of the basis differences attributable to goodwill is not amortized. The majority of the basis difference at both December 31, 2025 and 2024 was attributable to goodwill related to our ownership interest in BridgeTex with the remaining basis difference primarily related to capitalized interest incurred during construction of the assets of our unconsolidated entities.

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Summarized Financial Information of Unconsolidated Entities

Combined summarized financial information for all of our unconsolidated entities is shown in the tables below (in millions). None of our unconsolidated entities have noncontrolling interests.

December 31,
2025 2024
Current assets $ 441   $ 475  
Noncurrent assets $ 6,755   $ 6,996  
Current liabilities $ 317   $ 261  
Noncurrent liabilities $ 13   $ 12  

Year Ended December 31,
2025 2024 2023
Revenues $ 1,926   $ 2,193   $ 1,667  
Operating income $ 1,075   $ 1,373   $ 921  
Net income $ 1,094   $ 1,407   $ 947  

Note 10— Intangible Assets, Net

Intangible assets, net of accumulated amortization, consisted of the following (in millions):

December 31, 2025 December 31, 2024
Estimated Useful
Lives (Years) Cost Accumulated
Amortization Net Cost Accumulated
Amortization Net
Customer contracts and relationships
1 – 20
$ 3,034   $ ( 1,295 ) $ 1,739   $ 2,677   $ ( 1,015 ) $ 1,662  

Other agreements 15 – 70
29   ( 14 ) 15   28   ( 13 ) 15  
Intangible assets (1) (2)
$ 3,063   $ ( 1,309 ) $ 1,754   $ 2,705   $ ( 1,028 ) $ 1,677  

(1) We include rights-of-way, which are intangible assets, within property and equipment. See Note 7 for a discussion of property and equipment.
(2) The increase in intangible assets in 2025 is associated with the assets acquired during the period. See Note 8 for additional information.

Intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. We did not recognize any impairments of finite-lived intangible assets during the three years ended December 31, 2025.

The majority of our finite-lived intangible assets are amortized under the declining balance method. Amortization expense for finite-lived intangible assets for the years ended December 31, 2025, 2024 and 2023 was $ 280  million, $ 262  million and $ 291  million, respectively. We estimate that our amortization expense related to finite-lived intangible assets for the next five years will be as follows (in millions):

2026 $ 301  
2027 $ 261  
2028 $ 215  
2029 $ 192  
2030 $ 165  

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Note 11— Debt

Debt consisted of the following (in millions):

December 31,
2025 December 31,
2024
SHORT-TERM DEBT
Commercial paper notes, bearing a weighted-average interest rate of 3.9 % and 4.6 %, respectively (1)
$ 554   $ 393  

Other 9   14  
Total short-term debt 563   407  

LONG-TERM DEBT
Senior notes:

4.65 % senior notes due October 2025 (2)
—   1,000  
4.50 % senior notes due December 2026 (3)
750   750  
3.55 % senior notes due December 2029
1,000   1,000  
3.80 % senior notes due September 2030
750   750  
4.70 % senior notes due January 2031
1,000   —  
5.70 % senior notes due September 2034
650   650  
5.95 % senior notes due June 2035
1,000   —  
5.60 % senior notes due January 2036
1,000   —  
6.70 % senior notes due May 2036
250   250  
6.65 % senior notes due January 2037
600   600  
5.15 % senior notes due June 2042
499   499  
4.30 % senior notes due January 2043
348   348  
4.70 % senior notes due June 2044
687   687  
4.90 % senior notes due February 2045
649   649  
Unamortized discounts and debt issuance costs ( 65 ) ( 42 )
Senior notes, net of unamortized discounts and debt issuance costs 9,118   7,141  
Other long-term debt:
Commercial paper notes, bearing a weighted-average interest rate of 3.9 % (4)
416   —  

Term loan, net of debt issuance costs of $ 1 , bearing a weighted-average interest rate of 5.0 %
1,099   —  
Other 63   70  
Total long-term debt 10,696   7,211  
Total debt (5)
$ 11,259   $ 7,618  

(1) We classified these commercial paper notes as short-term as of December 31, 2025 and 2024, as these notes were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.
(2) As of December 31, 2024, we classified our $ 1.0  billion, 4.65 % senior notes due October 2025 as long-term based on our ability and intent to refinance the notes on a long-term basis at that time. We redeemed these senior notes on October 3, 2025.
(3) As of December 31, 2025, we classified our $ 750 million, 4.50 % senior notes due December 2026 as long-term based on our ability and intent to refinance the notes on a long-term basis.
(4) As of December 31, 2025, we classified a portion of our commercial paper notes as long-term based on our ability and intent to refinance such amounts on a long-term basis.
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(5) Our fixed-rate senior notes had a face value of approximately $ 9.2  billion and $ 7.2 billion as of December 31, 2025 and 2024, respectively. We estimated the aggregate fair value of these notes as of December 31, 2025 and 2024 to be approximately $ 9.0  billion and $ 6.7 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under our commercial paper program and our term loan approximate fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, commercial paper program and our term loan are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

Commercial Paper Program

We have a commercial paper program under which we may issue (and have outstanding at any time) up to $ 2.7 billion in the aggregate of privately placed, unsecured commercial paper notes. Such notes are backstopped by our senior unsecured revolving credit facility and our senior secured hedged inventory facility; as such, any borrowings under our commercial paper program reduce the available capacity under these facilities.

Credit Agreements

Senior secured hedged inventory facility . We have a credit agreement that provides for a senior secured hedged inventory facility with a committed borrowing capacity of $ 1.35  billion. Subject to obtaining additional or increased lender commitments and other terms and conditions, the committed capacity of the facility may be increased to $ 1.9  billion. The credit agreement provides for the issuance of letters of credit of up to $ 400  million. Proceeds from the facility are primarily used to finance purchased or stored hedged inventory, including NYMEX and ICE margin deposits. Such obligations under the committed facility are secured by the financed inventory and the associated accounts receivable and are repaid from the proceeds of the sale of the financed inventory. Borrowings accrue interest based, at our election, on certain floating rate indices as defined in the credit agreement, in each case plus a margin based on our credit rating at the applicable time. The amended credit agreement also provides for one or more one-year extensions, subject to applicable approval and other terms and conditions. The maturity date of the facility is August 2027 with respect to all extending lenders under the facility, except for a non-extending lender (which represents a commitment of approximately $ 64  million out of total commitments of $ 1.35  billion from all lenders), which has a maturity date of August 2026.

Senior unsecured revolving credit facility. We have a credit agreement that provides for a senior unsecured revolving credit facility with a committed borrowing capacity of $ 1.35  billion, of which $ 400  million is available for the issuance of letters of credit. Subject to obtaining additional or increased lender commitments and other terms and conditions, the committed capacity may be increased to $ 2.1  billion. Borrowings accrue interest based, at our election, on certain floating rate indices as defined in the credit agreement, in each case plus a margin based on our credit rating at the applicable time. The credit agreement provides for one or more one-year extensions, subject to applicable approval and other terms and conditions. The maturity date of the facility is August 2029 with respect to all extending lenders under the facility, except for a non-extending lender (which represents a commitment of approximately $ 64  million out of total commitments of $ 1.35  billion from all lenders), which has a maturity date of August 2027.

EPIC credit agreement . In connection with the EPIC Acquisition, completed on November 1, 2025, we assumed the EPIC credit agreement, which provided for a $ 1.2  billion term loan and a $ 125  million revolving credit facility. Borrowings under the EPIC credit agreement accrued interest based, at our election, on certain floating rate indices as defined in the EPIC credit agreement, in each case, plus an applicable margin. On December 1, 2025, we terminated the EPIC credit agreement and repaid the $ 1.1  billion of borrowings outstanding under the EPIC term loan.

Term Loan Agreement

On November 26, 2025, we entered into a term loan agreement that provides for a $ 1.1  billion senior unsecured term loan, which was funded on December 1, 2025. The term loan will mature in November 2027. We may at any time prepay amounts outstanding under the term loan agreement, in whole or in part, without premium or penalty. 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. Borrowings accrue interest based, at our election, on either Term SOFR or the Base Rate, in each case, plus an applicable rate. From the closing date to (but excluding) the first anniversary of the closing date, the applicable rate is 1.125 % for Term SOFR Loans and 0.125 % for Base Rate Loans; on and after the first anniversary, the applicable rate increases to 1.250 % for Term SOFR Loans and 0.250 % for Base Rate Loans.
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Senior Notes

Our senior notes are co-issued, jointly and severally, by Plains All American Pipeline, L.P. and a 100 %-owned consolidated finance subsidiary (neither of which have independent assets or operations) and are unsecured senior obligations of such entities and rank equally in right of payment with existing and future senior indebtedness of the issuers. We may, at our option, redeem any series of senior notes at any time in whole or from time to time in part, prior to maturity, at the redemption prices described in the indentures governing the senior notes. Our senior notes are not guaranteed by any of our subsidiaries.

Senior Notes Issuances. The table below summarizes our issuances of senior unsecured notes during the three years ended December 31, 2025 (face value in millions):

Issuance Date
Description Maturity Face Value Interest Payment Dates
November 14, 2025 4.70 % senior notes issued at 99.872 % of face value
January 2031
$ 300   January 15 and July 15
(1)

November 14, 2025 5.60 % senior notes issued at 100.518 % of face value
January 2036
$ 450   January 15 and July 15
(2)

September 8, 2025 4.70 % senior notes issued at 99.865 % of face value
January 2031 $ 700   January 15 and July 15

September 8, 2025 5.60 % senior notes issued at 99.798 % of face value
January 2036
$ 550   January 15 and July 15

January 15, 2025 5.95 % senior notes issued at 99.761 % of face value
June 2035
$ 1,000   June 15 and December 15

June 27, 2024 5.70 % senior notes issued at 99.953 % of face value
September 2034
$ 650   March 15 and September 15

(1) Additional issuance of our 4.70 % senior notes due 2031 that were issued on September 8, 2025, and trade interchangeably with such notes.
(2) Additional issuance of our 5.60 % senior notes due 2036 that were issued on September 8, 2025, and trade interchangeably with such notes.

Senior Notes Repayments.  During the three years ended December 31, 2025, we repaid the following senior unsecured notes in full:

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.

Maturities

The weighted average maturity of our senior notes outstanding at December 31, 2025 was approximately 10 years. The following table presents the aggregate contractually scheduled maturities of such senior notes for the next five years and thereafter. The amounts presented exclude unamortized discounts and debt issuance costs.

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Calendar Year Payment
(in millions)

2026 $ 750  
2027 $ —  
2028 $ —  
2029 $ 1,000  
2030 $ 750  
Thereafter $ 6,683  

Covenants and Compliance

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 agreement and the indentures governing our senior notes contain cross-default provisions. Our credit agreements prohibit declaration or payments of distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting our ability to, among other things:

• grant liens on certain property;
• incur indebtedness, including finance leases;
• sell substantially all of our assets or enter into a merger or consolidation;
• engage in certain transactions with affiliates; and
• enter into certain burdensome agreements.

The credit agreements for our senior unsecured revolving credit facility and senior secured hedged inventory facility and the term loan agreement treat a change of control as an event of default and also require us to maintain a debt-to-EBITDA coverage ratio that, on a trailing four-quarter basis, will not be greater than  5.00  to 1.00 (or  5.50  to 1.00 on all outstanding debt during an acquisition period (generally, the period consisting of three fiscal quarters following an acquisition greater than $ 150  million)). For covenant compliance purposes, Consolidated EBITDA may include certain adjustments, including those for material projects and certain non-recurring expenses. Additionally, letters of credit and borrowings to fund hedged inventory and margin requirements are excluded when calculating the debt coverage ratio

A default under our credit agreements, term loan agreement or indentures would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with the provisions contained in our credit agreements and term loan agreement, our ability to make distributions of available cash is not restricted. As of December 31, 2025, we were in compliance with the covenants contained in our credit agreements, term loan agreement and indentures.

Borrowings and Repayments

Total borrowings under our credit facilities and commercial paper program for the years ended December 31, 2025, 2024 and 2023 were approximately $ 56.4  billion, $ 28.1  billion and $ 18.1  billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately $ 55.8  billion, $ 28.1  billion and $ 17.7  billion for the years ended December 31, 2025, 2024 and 2023, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.

Letters of Credit

In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil and NGL. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil or NGL 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 $ 95  million and $ 90  million, respectively.
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Debt Issuance Costs

Costs incurred in connection with the issuance of senior notes are recorded as a direct deduction from the related debt liability and are amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization.

Note 12— Partners’ Capital and Distributions

Units Outstanding

At December 31, 2025, partners’ capital consisted of outstanding common units and Series A and Series B preferred units, which represent limited partner interests in us and which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges as outlined in our partnership agreement. Our general partner has a non-economic interest in us.

Series A Preferred Units

Our Series A preferred units were issued in a private placement in 2016 at a price of $ 26.25 per unit (the “Issue Price”). The Series A preferred units represent limited partner interests in us, rank pari passu with our Series B preferred units, and senior to our common units and to each other class or series of our equity securities with respect to distribution rights and rights upon liquidation. The holders of the Series A preferred units receive cumulative quarterly distributions, subject to customary antidilution adjustments, to unitholders of record within 45 days following the end of each quarter.

The initial Series A preferred unit distribution was equal to $ 0.525 per unit ($ 2.10 per unit annualized). After the fifth anniversary of the January 28, 2016 issuance date (the “Issuance Date”) of the Series A preferred units, the holders of the Series A preferred units, acting by majority vote, had the option to make a one-time election to reset the Series A preferred unit distribution rate to equal the then applicable rate of ten-year U.S. Treasury Securities plus 5.85 % (the “Preferred Distribution Rate Reset Option”). The Preferred Distribution Rate Reset Option was accounted for as an embedded derivative. See Note 13 for additional information regarding the Preferred Distribution Rate Reset Option. In January 2023, the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option. Effective January 31, 2023, the new Series A preferred unit distribution rate is equal to 9.375 % per annum of the original Issue Price (approximately $ 2.46 per unit annualized). The quarterly distribution paid in May 2023 reflected a pro-rated amount of approximately $ 0.585 per unit.

We may redeem all or any portion of the outstanding Series A preferred units (subject to certain redemption size limitations and limited to two redemption transactions) in exchange for cash, common units (valued at 95 % of the volume-weighted average price of our common units for a trading period specified in our partnership agreement) or a combination of cash and common units at a redemption price equal to 110 % of the Issue Price, plus any accrued and unpaid distributions. The holders may convert their Series A preferred units into common units, generally on a one -for-one basis and subject to customary anti-dilution adjustments, at any time, in whole or in part, subject to certain minimum conversion amounts (and not more often than once per quarter). The Series A preferred units vote on an as-converted basis with our common units on the election of directors and have certain other class voting rights with respect to any amendment to our partnership agreement that would adversely affect any rights, preferences or privileges of the Series A preferred units. In addition, upon certain events involving a change of control, the holders of the Series A preferred units may elect, among other potential elections, to convert the Series A preferred units into common units at the then applicable conversion rate.

On January 31, 2025, we repurchased approximately 12.7  million of our outstanding Series A preferred units from EnCap Flatrock Midstream at the Issue Price for a purchase price of approximately $ 333  million, plus accrued and unpaid distributions through January 30, 2025 of approximately $ 10  million. EnCap Flatrock Midstream is affiliated with EnCap Investments, L.P., an entity that is associated with a member of the board of directors of PAGP GP. The repurchase also resulted in a reduction to the related Preferred Distribution Rate Reset Option liability. The difference between the cash we paid for the repurchase of such units and their carrying value on our balance sheet was $ 43  million. Such amount was considered a return to Series A preferred unitholders and thus reduced amounts attributable to our common unitholders in our Consolidated Statement of Changes in Partners’ Capital and the calculation of net income per common unit.
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Series B Preferred Units

Our Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in us (the “Series B preferred units”) were issued in 2017 at a price to the public of $ 1,000  per unit. Our Series B preferred units represent perpetual equity interests in us, have no stated maturity or mandatory redemption date and are not redeemable at the option of the holders under any circumstances. Holders of the Series B preferred units generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our partnership agreement that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series B preferred units, (ii) the creation or issuance of any parity securities if the cumulative distributions payable on then outstanding Series B preferred units are in arrears, (iii) the creation or issuance of any senior securities and (iv) the payment of distributions to our common unitholders out of capital surplus. The Series B preferred units rank, as to the payment of distributions and amounts payable on a liquidation event, pari passu with our outstanding Series A preferred units and senior to our common units.

The Series B preferred units have a liquidation preference of $ 1,000  per unit. 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 semiannual or quarterly cash distributions, as applicable. Through November 15, 2022, distributions on the Series B preferred units were paid semiannually in arrears on the 15th day of May and November. After November 15, 2022, distributions are payable quarterly in arrears on the 15th day of February, May, August and November of each year (or on the immediately succeeding Business Day). The initial distribution rate for the Series B preferred units from and including October 10, 2017 to, but not including, November 15, 2022 was  6.125 % per year of the liquidation preference per unit (equal to $ 61.25  per unit per year). From November 15, 2022 through August 14, 2023, distributions on the Series B preferred units accumulated for each distribution period at a percentage of the liquidation preference equal to the applicable three-month LIBOR plus a spread of  4.11 % per annum. Beginning August 15, 2023, 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).

At any time, we may redeem the Series B preferred units, at our option, in whole or in part, at a redemption price of $ 1,000  per Series B preferred unit plus an amount equal to all accumulated and unpaid distributions thereon to, but not including, the date of redemption, whether or not declared.

The following table presents the activity for our preferred and common units:

Limited Partners
Series A
Preferred Units
Series B
Preferred Units Common Units
Outstanding at December 31, 2022
71,090,468   800,000   698,354,498  

Issuances of common units under equity-indexed compensation plans
—   —   2,654,251  
Outstanding at December 31, 2023
71,090,468   800,000   701,008,749  

Issuances of common units under equity-indexed compensation plans
—   —   2,761,551  
Outstanding at December 31, 2024
71,090,468   800,000   703,770,300  
Repurchase of Series A preferred units
( 12,678,560 ) —   —  
Repurchase and cancellation of common units under the Common Equity Repurchase Program —   —   ( 476,695 )
Issuances of common units under equity-indexed compensation plans
—   —   2,227,092  
Outstanding at December 31, 2025
58,411,908   800,000   705,520,697  

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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. 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. PAGP Class C shares held by us associated with any publicly held common units that are repurchased will also be canceled. See Note 17 for additional information regarding our ownership of PAGP Class C shares.

During the year ended December 31, 2025, we repurchased common units under the Program through open market purchases for a total purchase price of $ 8  million, including commissions and fees. The repurchased common units were canceled immediately upon acquisition, as were the PAGP Class C shares held by us associated with the repurchased common units. There were no repurchases under the Program during the years ended December 31, 2024 or 2023. At December 31, 2025, the remaining available capacity under the Program was $ 190  million.

Income Allocation

We allocate net income for partners’ capital presentation purposes by applying the allocation methodology in our partnership agreement. Net income is allocated 100 % to our common unitholders, after giving effect to income allocations for cash distributions to our Series A preferred unitholders and guaranteed payments attributable to our Series B preferred unitholders.

For purposes of determining basic and diluted net income per common unit, income is allocated as prescribed in FASB guidance for calculating earnings per unit, including a deduction to income available to common unitholders for distributions attributable to the period on our Series A and Series B preferred units. See Note 5 for additional information.

Distributions to 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 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 available cash also includes cash on hand resulting from borrowings made after the end of the quarter.

Preferred Unit Distributions

Series A Preferred Unit Distributions. The following table details distributions paid to our Series A preferred unitholders during the years presented (in millions, except unit data):

Series A Preferred Unitholders

Year Cash Distribution
Distribution per Unit

2025 (1)
$ 154   $ 2.46  
2024 $ 175   $ 2.46  
2023 $ 166   $ 2.34  

(1) In connection with our repurchase of approximately 12.7  million of our outstanding Series A preferred units in January 2025, we paid accrued and unpaid distributions through January 30, 2025 of approximately $ 10  million.

On February 13, 2026, we paid a cash distribution of $ 36 million to our Series A preferred unitholders outstanding as of January 30, 2026. At December 31, 2025, such amount was accrued as distributions payable in “Other current liabilities” on our Consolidated Balance Sheet.

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Series B Preferred Unit Distributions. The following table details distributions paid to our Series B preferred unitholders during the years presented (in millions, except unit data):

Series B Preferred Unitholders

Year Cash Distribution
Distribution per Unit

2025 $ 71   $ 88.38  
2024 $ 79   $ 98.14  
2023 $ 75   $ 93.43  

On February 17, 2026, we paid a cash distribution of $ 17  million ($ 21.02 per unit) to our Series B preferred unitholders. At December 31, 2025, approximately $ 9 million of accrued distributions payable to our Series B preferred unitholders was included in “Other current liabilities” on our Consolidated Balance Sheet.

Common Unit Distributions

The following table details distributions paid to common unitholders during the years presented (in millions, except per unit data):

Distributions Paid Distributions per
Common Unit

Year Public AAP Total
2025 $ 716   $ 354   $ 1,070   $ 1.5200  
2024 $ 595   $ 296   $ 891   $ 1.2700  
2023 $ 492   $ 256   $ 748   $ 1.0700  

On January 5, 2026, we declared a cash distribution of $ 0.4175 per unit on our outstanding common units. The total distribution of $ 295 million was paid on February 13, 2026 to unitholders of record at the close of business on January 30, 2026, for the period from October 1, 2025 through December 31, 2025. Of this amount, approximately $ 97 million was paid to AAP.

Noncontrolling Interests in Subsidiaries

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 Pipeline Company LLC (“Red River”).

Distributions to Noncontrolling Interests

Distributions of available cash from the Permian JV, Cactus II and Red River are paid in proportion to each owner’s interest in the entity. Cash available for distribution is cash on hand less the amount of cash required to fund normal operations and capital projects. The following table details distributions paid to noncontrolling interests during the years presented (in millions):

2025 2024 2023
Permian JV
$ 360   $ 322   $ 249  
Cactus II 72   77   63  
Red River 15   26   21  
$ 447   $ 425   $ 333  

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Note 13— Derivatives and Risk Management Activities

We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. We use various derivative instruments to manage our exposure to commodity price risk, interest rate risk, and currency exchange rate risk. Our commodity price risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate risk and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on changes in commodity prices or interest rates. When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. At the inception of the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions. Throughout the hedging relationship, retrospective and prospective hedge effectiveness is assessed on a qualitative basis.

We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives designated as cash flow hedges, changes in fair value are deferred in AOCI and recognized in earnings in the periods during which the underlying hedged transactions are recognized in earnings. Derivatives that are not designated in a hedging relationship for accounting purposes are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Consolidated Statements of Cash Flows.

Our financial derivatives, used for hedging risk, are governed through ISDA master agreements and clearing brokerage agreements. These agreements include stipulations regarding the right of set off in the event that we or our counterparty default on performance obligations. If a default were to occur, both parties have the right to net amounts payable and receivable into a single net settlement between parties.

At December 31, 2025 and 2024, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our exchange-traded derivatives transacted through a clearing brokerage account, as described below, we do not require our non-cleared derivative counterparties to post collateral with us.

Commodity Price Risk Hedging

Our core business activities involve certain commodity price-related risks that we manage in various ways, including through the use of derivative instruments. Our policy is to (i) only purchase inventory for which we have a sales market, (ii) structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold material physical inventory or derivatives for the purpose of speculating on commodity price changes. The material commodity-related risks inherent in our business activities are described below.

In the normal course of our operations, we purchase and sell commodities. We use derivatives to manage the associated risks and, in certain circumstances, to optimize profits. As of December 31, 2025, net derivative positions related to these activities included:
• A net long position of 5.8 million barrels associated with our crude oil purchases, which will be unwound ratably through March 2026 to match monthly average pricing.
• A net short time spread position of 1.9 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through April 2026.
• A net crude oil basis spread position of 1.5 million barrels at multiple locations through December 2026. These derivatives allow us to lock in grade and location basis differentials.
• A net short position of 6.9 million barrels through December 2029 related to anticipated net sales of crude oil inventory.
• A net long position of 0.5 TWh through December 2030 related to anticipated power supply requirements.

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Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchases and normal sales scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings. We have determined that substantially all of our physical commodity contracts qualify for the normal purchases and normal sales scope exception.

Our commodity derivatives are not designated in a hedging relationship for accounting purposes; as such, changes in the fair value are reported in earnings. The following table summarizes the impact of our commodity derivatives recognized in earnings (in millions):

Year Ended December 31,
2025 2024 2023
Product sales revenues $ ( 20 ) $ ( 24 ) $ ( 10 )
Field operating costs 2   ( 8 ) 19  
Net gain/(loss) from commodity derivative activity $ ( 18 ) $ ( 32 ) $ 9  

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

December 31,
2025 2024
Initial margin $ 16   $ 16  
Variation margin posted
4   15  
Letters of credit ( 1 ) ( 9 )
Net broker receivable
$ 19   $ 22  

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

December 31, 2025 December 31, 2024
Effect of Collateral Netting Net Carrying Value Presented on the Balance Sheet Effect of Collateral Netting Net Carrying Value Presented on the Balance Sheet
Commodity Derivatives Commodity Derivatives
Assets Liabilities Assets Liabilities
Derivative Assets
Other current assets $ 18   $ ( 24 ) $ 19   $ 13   $ 25   $ ( 24 ) $ 22   $ 23  
Other long-term assets, net 1   —   —   1   —   —   —   —  
Derivative Liabilities
Other current liabilities ( 1 ) —   —   ( 1 ) ( 5 ) 5   —   —  
Other long-term liabilities and deferred credits 10   ( 8 ) —   2   2   ( 6 ) —   ( 4 )
Total $ 28   $ ( 32 ) $ 19   $ 15   $ 22   $ ( 25 ) $ 22   $ 19  

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Interest Rate Risk Hedging

We use interest rate derivatives to hedge the benchmark interest rate associated with interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist of forward starting interest rate swaps and treasury locks. These derivatives are designated as cash flow hedges. As such, changes in fair value are deferred in AOCI and are reclassified to interest expense as we incur the interest expense associated with the underlying debt. 

During the year ended December 31, 2025, we terminated $ 200  million of notional interest hedging instruments previously expected to terminate in October 2025 for proceeds of $ 7  million and $ 200  million of notional interest hedging instruments previously expected to terminate in June 2026 for proceeds of $ 30  million which were recorded in AOCI. As of December 31, 2025, there was a net loss of $ 29  million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with interest expense accruals associated with underlying debt instruments. The early termination did not result in an impact to the relationship between the hedging instrument and hedged item. We estimate that substantially all of the remaining deferred loss will be reclassified to earnings through 2056 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of December 31, 2025; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

The following table summarizes the net unrealized gain recognized in AOCI for derivatives (in millions):

Year Ended December 31,
2025 2024 2023
Interest rate derivatives, net $ 10   $ 29   $ 15  

At December 31, 2025, we did not have any interest rate hedges recorded on our Consolidated Balance Sheet. At December 31, 2024, the net fair value of these hedges totaled $ 27  million, which was included in “Other long-term assets, net” on our Consolidated Balance Sheet.

Currency Exchange Rate Risk Hedging

In connection with the pending sale of the Canadian NGL Business, we entered into a forward currency instrument (CAD$ 4.5  billion notional amount) to hedge currency exchange risk. The instrument is contingent upon the sale occurring and will settle at closing. The cost of the deal-contingent structure is embedded in the hedge rate. As of December 31, 2025, the sale of the Canadian NGL Business is probable and the fair value of the instrument is an $ 8  million asset, presented in “Other current assets” on our Consolidated Balance Sheet. For the year ended December 31, 2025, we recognized the gains of $ 8  million, which was included in “(Gains)/losses on asset sales, asset impairments and other, net” on our Consolidated Statements of Operations. As of December 31, 2025, for the periods covered by the instrument, the average fixed USD to CAD rate of the instrument is $ 1.37 and the average forward USD to CAD rate is $ 1.37 . See Note 1 for additional information regarding the pending sale of the Canadian NGL Business.

Preferred Distribution Rate Reset Option
 
In January 2023, we received notice that the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option. Prior to this election, the Preferred Distribution Rate Reset Option was accounted for as an embedded derivative. A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. The Preferred Distribution Rate Reset Option embedded derivative was required to be bifurcated from the related host contract, our partnership agreement, and recorded at fair value on our Consolidated Balance Sheet. The Preferred Distribution Rate Reset Option embedded derivative was not designated in a hedging relationship for accounting purposes and corresponding changes in fair value were recognized in “Other income, net” in our Consolidated Statements of Operations. The Preferred Distribution Rate Reset Option was settled at a fair value of $ 131  million when we received notice that the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option, which resulted in a gain of $ 58  million for the year ended December 31, 2023. See Note 12 for additional information regarding the Preferred Distribution Rate Reset Option.

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Recurring Fair Value Measurements

Derivative Financial Assets and Liabilities

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions):

Fair Value as of December 31, 2025 Fair Value as of December 31, 2024
Recurring Fair Value Measures  (1)
Level 1 Level 2 Total Level 1 Level 2 Total
Commodity derivatives $ ( 2 ) $ ( 2 ) $ ( 4 ) $ 11   $ ( 14 ) $ ( 3 )
Interest rate derivatives —   —   —   —   27   27  

Foreign currency derivatives —   8   8   —   —   —  
Total net derivative asset/(liability) $ ( 2 ) $ 6   $ 4   $ 11   $ 13   $ 24  

(1) Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.

Level 1

Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives and over-the-counter commodity contracts such as futures and swaps. The fair value of exchange-traded commodity derivatives and over-the-counter commodity contracts is based on unadjusted quoted prices in active markets.

Level 2

Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives, over-the-counter commodity, foreign exchange and interest rate derivatives that are traded in observable markets with less volume and transaction frequency than active markets. In addition, it includes certain physical commodity contracts. The fair values of these derivatives are corroborated with market observable inputs.

Note 14— Leases

Lessee

We evaluate all agreements entered into or modified that convey to us the use of property or equipment for a term to determine whether the agreement is or contains a lease. Significant judgment is required when determining whether we obtain the right to direct the use of identified property or equipment. We lease certain property and equipment under noncancelable and cancelable operating and finance leases. Our operating leases primarily relate to office space, land, vehicles and storage tanks, and our finance leases primarily relate to tractor trailers, storage tanks and vehicles. One of our finance leases is for storage tanks owned by an equity method investee, in which we own a 50 % interest. For leases with an initial term of greater than 12 months, we recognize a right-of-use asset and lease liability on the balance sheet. Leases with an initial term of 12 months or less are not recorded on the balance sheet. We have elected the non-lease component separation practical expedient for certain classes of assets where we are the lessee. Our lease agreements have remaining lease terms ranging from one year to approximately 55 years. When applicable, this range includes additional terms associated with leases for which we are reasonably certain to exercise the option to renew and such renewal options are recognized as part of our right-of-use assets and lease liabilities. We have renewal options for leases with terms ranging from one year to 25 years that are not recognized as part of our right-of-use assets or lease liabilities as we have determined we are not reasonably certain to exercise the option to renew.

Certain of our leases have variable lease payments, many of which are based on changes in market indices such as the Consumer Price Index. Our lease agreements for our tractor trailers contain residual value guarantees equal to the fair market value of the tractor trailers at the end of the lease term in the event that we elect not to purchase the asset for an amount equal to the fair value. Our lease agreements do not contain any material restrictive covenants.

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For determining the present value of lease payments, we use the discount rate implicit in the lease when readily determinable; however, such rate is not readily determinable for most of our leases. For those leases for which the discount rate is not readily determinable, we utilize incremental borrowing rates that reflect collateralized borrowing with payments and terms that mirror our lease portfolio to discount the lease payments based on information available at the lease commencement date.

The following table presents components of lease cost, including both amounts recognized in income and amounts capitalized (in millions):

Year Ended December 31,
Lease Cost 2025 2024 2023
Operating lease cost $ 37   $ 44   $ 48  
Short-term lease cost 13   13   13  
Other (1)
19   16   8  
Total lease cost $ 69   $ 73   $ 69  

(1) Includes finance lease costs, variable lease costs and sublease income.

The following table presents information related to cash flows arising from lease transactions (in millions):

Year Ended December 31,
2025 2024 2023
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases $ 40   $ 41   $ 44  
Operating cash flows for finance leases $ 9   $ 7   $ 6  
Financing cash flows for finance leases $ 23   $ 15   $ 10  

Non-cash change in lease liabilities arising from obtaining new right-of-use assets or modifications:
Operating leases $ 30   $ 50   $ 12  
Finance leases
$ 7   $ 23   $ 27  

Information related to the weighted-average remaining lease term and discount rate is presented in the table below:

December 31,
2025 2024
Weighted-average remaining lease term (in years):
Operating leases 21 20
Finance leases 8 7

Weighted-average discount rate:
Operating leases 5.5   % 5.5   %
Finance leases 11.1   % 10.7   %

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The following table presents the amount and location of our operating and finance lease right-of-use assets and liabilities on our Consolidated Balance Sheets (in millions):

December 31,
Leases Balance Sheet Location 2025 2024
Assets
Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 198   $ 189  

Finance lease right-of-use assets (1)
Property and equipment $ 90   $ 103  
Accumulated depreciation ( 27 ) ( 28 )
Property and equipment, net $ 63   $ 75  

Total lease right-of-use assets $ 261   $ 264  

Liabilities
Operating lease liabilities
Current Other current liabilities $ 27   $ 30  
Noncurrent Long-term operating lease liabilities 202   192  
Total operating lease liabilities $ 229   $ 222  

Finance lease liabilities (1)

Current Short-term debt $ 9   $ 14  
Noncurrent Other long-term debt, net 63   70  
Total finance lease liabilities $ 72   $ 84  

Total lease liabilities $ 301   $ 306  

(1) Includes right-of-use assets of $ 23  million and $ 26  million and lease liabilities of $ 32  million and $ 33  million as of December 31, 2025 and 2024, respectively, associated with leased storage tanks owned by an equity method investee, in which we own a 50 % interest.

The following table presents the maturity of undiscounted cash flows for future minimum lease payments under noncancelable leases as of December 31, 2025 reconciled to our lease liabilities on our Consolidated Balance Sheet (amounts in millions):

Operating Finance (2)

Future minimum lease payments (1) :

2026 $ 31   $ 15  
2027 29   15  
2028 26   17  
2029 22   12  
2030 19   9  
Thereafter 303   43  
Total 430   111  
Less: Present value discount ( 201 ) ( 39 )
Lease liabilities $ 229   $ 72  

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(1) Excludes future minimum payments for short-term and other immaterial leases not included on our Consolidated Balance Sheet.
(2) Includes payments of approximately $ 6  million for each of the years ending 2026 through 2030 and approximately $ 33  million thereafter associated with leased storage tanks owned by an equity method investee, in which we own a 50 % interest.

Lessor

We evaluate all agreements entered into or modified that convey to others the use of property or equipment for a term to determine whether the agreement is or contains a lease. Significant judgment is required when determining whether a customer obtains the right to direct the use of identified property or equipment. The underlying assets associated with these agreements are evaluated for future use beyond the lease term. We have elected the non-lease component separation practical expedient for all classes of assets where we are the lessor.

We enter into agreements to conduct activities associated with (i) providing storage services primarily for crude oil and (ii) transporting crude oil. Certain of these agreements convey counterparties the right to direct the operation of physically distinct assets. Such agreements include (i) fixed consideration, which is measured based on an available capacity during the period multiplied by the rate in the agreement, or (ii) a fixed monthly fee and variable consideration based on usage. These agreements often include options to extend or terminate the lease, with advance notice. These agreements are operating leases.

The following table presents our lease revenue for the periods indicated (in millions):

Year Ended December 31,
2025 2024 2023
Operating lease revenue (1)
$ 8   $ 10   $ 16  

(1) These amounts are included in “Services revenues” on our Consolidated Statements of Operations.

The table below presents the maturity of lease payments for operating lease agreements in effect as of December 31, 2025. This presentation includes minimum fixed lease payments and does not include an estimate of variable lease consideration. These agreements have remaining lease terms ranging from one year to 6 years. The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions):

2026 2027 2028 2029 2030 Thereafter
Future minimum lease revenue $ 6   $ 2   $ 2   $ 2   $ 2   $ 1  

Note 15— Income Taxes

Income tax expense is estimated using the tax rate in effect or to be in effect during the relevant periods in the jurisdictions in which we operate. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes and are stated at enacted tax rates expected to be in effect when taxes are actually paid or recovered. To the extent we do not consider it more likely than not that a deferred tax asset will be recovered, a valuation allowance is established. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. We review contingent tax liabilities for estimated exposures on a more likely than not standard related to our current tax positions.

Pursuant to FASB guidance related to accounting for uncertainty in income taxes, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and precedents of the taxing authority. As of December 31, 2025 and 2024, we had not recognized any material amounts in connection with uncertainty in income taxes.

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U.S. Federal and State Taxes

As an MLP, we are not subject to U.S. federal income taxes; rather the tax effect of our operations is passed through to our unitholders. Although we are subject to state income taxes in some states, the impact to the years ended December 31, 2025, 2024, and 2023 was immaterial.

Canadian Federal and Provincial Taxes

All of our Canadian operations are conducted by entities that are treated as corporations for Canadian tax purposes (flow through for U.S. income tax purposes) and thus are subject to Canadian federal and provincial taxes. Additionally, payments of interest and dividends from our Canadian entities to other Plains entities are subject to Canadian withholding tax that is treated as income tax expense.

Tax Components

Pre-tax book income by geography is as follows (in millions):

Year Ended December 31,
2025 2024 2023
United States
$ 1,356   $ 838   $ 1,139  
Canada
45   131   232  
Total pre-tax book income
$ 1,401   $ 969   $ 1,371  

Components of income tax expense are as follows (in millions):

Year Ended December 31,
2025 2024 2023
Current income tax expense/(benefit):

State income tax $ 2   $ 2   $ 2  
Canadian federal and provincial income and withholding taxes
( 1 ) 80   68  
Total current income tax expense $ 1   $ 82   $ 70  

Deferred income tax expense/(benefit):
Canadian federal and provincial income and withholding taxes
$ 14   $ 5   $ ( 9 )
Total deferred income tax expense/(benefit) $ 14   $ 5   $ ( 9 )
Total income tax expense
$ 15   $ 87   $ 61  

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The difference between income tax expense based on the statutory federal income tax rate and our effective income tax expense is summarized as follows (in millions, except percentages):

Year Ended December 31,
2025 2024 2023
Amount Percent
Amount Percent
Amount Percent

U.S. federal statutory tax rate
$ 294   21.00   % $ 204   21.00   % $ 288   21.00   %

State and local income taxes (1)
2   0.14   % 2   0.21   % 2   0.15   %

Foreign tax effects:

Canada

Foreign rate differential
( 3 ) ( 0.19 ) % ( 8 ) ( 0.81 ) % ( 14 ) ( 1.01 ) %
Provincial taxes
5   0.35   % 13   1.35   % 20   1.51   %
Foreign withholding taxes
3   0.21   % 52   5.39   % —   —   %
Other
( 2 ) ( 0.13 ) % —   —   % 4   0.29   %

Nontaxable or nondeductible items:

Nontaxable income - U.S. partnership income
( 284 ) ( 20.33 ) % ( 176 ) ( 18.17 ) % ( 239 ) ( 17.45 ) %

Effective tax rate
$ 15   1.06   % $ 87   8.95   % $ 61   4.48   %

(1) The state and local income tax category of the rate reconciliation is primarily comprised of income taxes in Texas, which represents more than 50 percent of the state and local tax effect.

Supplemental Disclosures

Cash taxes paid were as follows (in millions):

Year Ended December 31,
2025 2024 2023

State income tax:

Texas
$ 1   $ 2   2  

Total state income tax paid 1   2   2  

Canadian federal and provincial income and withholding taxes
97   267   67  

Total cash tax paid
$ 98   $ 269   $ 69  

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Deferred tax assets and liabilities are aggregated by the applicable tax paying entity and jurisdiction and result from the following (in millions):

December 31,
2025 2024
Deferred tax assets:
Derivative instruments $ —   $ 6  
Lease liabilities 10   8  

Other 7   8  
Total deferred tax assets 17   22  

Deferred tax liabilities:
Property and equipment in excess of tax values ( 204 ) ( 185 )

Lease assets ( 9 ) ( 10 )
Other ( 1 ) ( 1 )
Total deferred tax liabilities ( 214 ) ( 196 )
Net deferred tax liabilities $ ( 197 ) $ ( 174 )

Balance sheet classification of deferred tax assets/(liabilities):

Other long-term liabilities and deferred credits $ ( 197 ) $ ( 174 )
$ ( 197 ) $ ( 174 )

Generally, tax returns for our Canadian entities are open to audit from 2018 through 2025. Our U.S. and state tax years are generally open to examination from 2022 to 2025.

As of December 31, 2025, in reference to tax years 2012 to 2019, we had received notices of reassessment (“notices”) from the Canada Revenue Agency and the Alberta Tax and Revenue Administration (the “Canadian Tax Authorities”) related primarily to transfer pricing associated with cross-border intercompany financing transactions. The notices include assessments, including penalties and interest, associated with these transfer pricing matters totaling approximately $ 189  million (based on the exchange rate as of December 31, 2025). Payment of a portion of the assessment is required in order to file a notice of objection to dispute the reassessment. Accordingly, we have remitted approximately $ 86  million (based on the exchange rate as of December 31, 2025) related to the assessments, which is included in “Other long-term assets, net,” on our Consolidated Balance Sheets. We disagree with these notices and have contested the reassessments. We intend to vigorously defend our position, and we plan to pursue all remedies available to us to successfully resolve these matters, including administrative remedies with the Canadian Tax Authorities, and judicial remedies, if necessary. As of December 31, 2025, we believe that our tax position associated with these matters is “more likely than not” to be sustained and have not recognized any amounts for uncertainty in income taxes related to these notices.

Note 16— Major Customers and Concentration of Credit Risk

ExxonMobil Corporation and its subsidiaries accounted for approximately 31 %, 31 % and 27 % of our revenues for the years ended December 31, 2025, 2024 and 2023, respectively. BP p.l.c. and its subsidiaries accounted for approximately 10 % of our revenues for the year ended December 31, 2023. No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2025. The majority of revenues from these customers pertain to our Crude Oil segment merchant activities, and sales to these customers occur at multiple locations. If we were to lose one or more of these customers, there is risk that we would not be able to identify and access a replacement market at a comparable margin.

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Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL. This industry concentration has the potential to impact our overall exposure to credit risk in that the customers may be similarly affected by changes in economic, industry or other conditions. We review credit exposure and financial information of our counterparties and generally require letters of credit for receivables from customers that are not considered creditworthy, unless the credit risk can otherwise be reduced. See Note 4 for additional discussion of our accounts receivable and our review of credit exposure.

Note 17— Related Party Transactions

Ownership of PAGP Class C Shares

As of December 31, 2025 and 2024, we owned 530,932,175 and 542,004,838 , respectively, Class C shares of PAGP. Each Class C share represents a non-economic limited partner interest in PAGP. The Class C shares function as a “pass-through” voting mechanism through which we vote at the direction of and as proxy for our common unitholders (other than AAP) and Series A preferred unitholders in such director elections. The number of Class C shares that we own is equal to the number of outstanding common units and Series A preferred units that are entitled to vote, pro rata with the holders of PAGP Class A and Class B shares, for the election of eligible PAGP GP directors. Common units held by AAP and Series B preferred units are not entitled to vote in the election of directors.

Reimbursement of Our General Partner and its Affiliates

Our general partner provides services necessary to manage and operate our business, properties and assets, including employing or retaining personnel. We do not pay our general partner a management fee, but we do reimburse our general partner for all direct and indirect costs it incurs or payments it makes on our behalf, including the costs of employee, officer and director compensation and benefits allocable to us as well as all other expenses necessary or appropriate to conduct our business. We record these costs on the accrual basis in the period in which our general partner incurs them. Our partnership agreement provides that our general partner will, in a manner it deems in its sole discretion to be reasonable, determine the expenses that are allocable to us. Total costs reimbursed by us to our general partner for the years ended December 31, 2025, 2024 and 2023 were $ 570 million, $ 583 million and $ 546 million, respectively.

Omnibus Agreement

The Plains Entities entered into an Omnibus Agreement on November 15, 2016, which provides for, among other things, the following:

• that we will pay all direct or indirect expenses of any of the PAGP Entities, other than income taxes, including, but not limited to, (i) compensation for the directors of PAGP GP, (ii) director and officer liability insurance, (iii) listing exchange fees, (iv) investor relations expenses and (v) fees related to legal, tax, financial advisory and accounting services. Amounts paid on behalf of the PAGP Entities during the years ended December 31, 2025, 2024 and 2023 were not material;

• the ability of PAGP to issue additional Class A shares and use the net proceeds therefrom to purchase a like number of AAP units from AAP, and the corresponding ability of AAP to use the net proceeds therefrom to purchase a like number of our common units from us; and

• the ability of PAGP to lend proceeds of any future indebtedness incurred by it to AAP, and AAP’s corresponding ability to lend such proceeds to us, in each case on substantially the same terms as incurred by PAGP.

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Promissory Notes with our General Partner

During the three years ended December 31, 2025, we and certain Plains entities have issued promissory notes to facilitate financing as follows:

Related Party Notes Payable (1)
Issuance Date
Holder
Face Value (in millions)
Maturity
Interest Rate per Annum
Interest Payable

February 2025 note payable (2)
February 2025
PAGP
CAD$ 473 (approximately $ 330 )
June 2035
5.75 % Semi-annually

July 2024 note payable (2)
July 2024
PAGP CAD$ 865 (approximately $ 629 )
September 2034
6.50 % Semi-annually
March 2023 note payable (3)
March 2023
PAGP CAD$ 500 (approximately $ 370 )
April 2027
8.25 % Semi-annually

Related Party Notes Receivable (1)
Issuance Date
Issuer
Face Value (in millions)
Maturity
Interest rate per Annum
Interest Payable

February 2025 note receivable (2)
February 2025
PAGP
CAD$ 473 (approximately $ 330 )
June 2035
5.75 % Semi-annually

July 2024 note receivable (2)
July 2024
PAGP CAD$ 865 (approximately $ 629 )
September 2034
6.50 % Semi-annually
March 2023 note receivable (3)
March 2023
PAGP CAD$ 500 (approximately $ 370 )
April 2027
8.25 % Semi-annually

(1) We determined the interest rates for the related party notes in accordance with the arm’s-length principle set forth in the OECD’s Transfer Pricing Guidelines for Multinational Enterprises and Tax Administrations (the “OECD Guidelines”), issued January 20, 2022, and the transfer pricing provisions of Section 247 of Canada’s Income Tax Act.
(2) A consolidated subsidiary issued an unsecured promissory note to PAGP. Concurrently, PAGP issued an unsecured promissory note to us for the same face value amounts. We received cash from PAGP of approximately $ 330  million and $ 629  million in connection with the related party notes issued in February 2025 and July 2024, respectively, which are reflected in “Proceeds from the issuance of related party notes” (a component of cash flows from financing activities), and we paid equal and offsetting amounts of cash to PAGP, which are reflected in “Investments in related party notes” (a component of cash flows from investing activities) on our Consolidated Statement of Cash Flows.
(3) We assigned PAGP our interest in an existing unsecured promissory note due from a consolidated subsidiary. Concurrently, PAGP issued an unsecured promissory note to us for the same face value amount.

Accrued and unpaid interest receivable/payable was $ 30  million and $ 27  million as of December 31, 2025 and 2024, respectively. Interest income/expense on the related party notes totaled $ 87  million, $ 48  million and $ 25  million for the years ended December 31, 2025, 2024, and 2023, respectively.

As of December 31, 2025 and 2024, our outstanding related party notes receivable and related party notes payable balances were as follows (in millions):

December 31,
2025 December 31,
2024
Related party notes receivable (1)
$ 1,339   $ 948  
Related party notes payable (1)
$ 1,339   $ 948  

(1) We have elected to present our related party notes with the same counterparty on a net basis on our Consolidated Balance Sheets because there is a legal right to offset and we intend to offset with the counterparty.

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Transactions with Other Related Parties

Our other related parties include entities in which we hold investments and account for under the equity method of accounting (see Note 9 for information regarding such entities). During the three years ended December 31, 2025, we recognized sales and transportation revenues, purchased petroleum products and utilized transportation and storage services from our related parties. These transactions were conducted at posted tariff rates or prices that we believe approximate market.

The impact to our Consolidated Statements of Operations from these transactions is included below (in millions):

Year Ended December 31,
2025 2024 2023

Revenues from related parties
$ 49   $ 46   $ 48  

Purchases and related costs from related parties
$ 358   $ 400   $ 404  

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

December 31,
2025 2024

Trade accounts receivable and other receivables, net from related parties (1)
$ 49   $ 40  

Trade accounts payable to related parties (1) (2)
$ 64   $ 66  

(1) Primarily includes amounts related to transportation and storage services.
(2) We have agreements to store crude oil at facilities and transport crude oil or utilize capacity on pipelines that are owned by equity method investees. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities.

Note 18— Equity-Indexed Compensation Plans

Our equity-indexed compensation plans primarily include LTIPs. Although other types of awards are contemplated under certain of the LTIPs, currently outstanding awards are limited to “phantom units,” which mature into the right to receive common units of PAA (or cash equivalent) upon vesting, and “tracking units,” which, upon vesting, represent the right to receive a cash payment in an amount based upon the market value of a PAA common unit at the time of vesting. Some awards also include DERs, which, subject to applicable vesting criteria, entitle the grantee to a cash payment equal to the cash distribution paid on an outstanding PAA common unit. The DERs terminate with the vesting or forfeiture of the underlying LTIP award.

Our LTIP awards include both liability-classified and equity-classified awards. In accordance with FASB guidance regarding share-based payments, the fair value of liability-classified LTIP awards is calculated based on the closing market price of the underlying PAA unit at each balance sheet date and adjusted for the present value of any distributions that are estimated to occur on the underlying units over the vesting period that will not be received by the award recipients. The fair value for equity-classified awards is calculated in a similar manner on the respective grant dates. These fair values are recognized as compensation expense over the service period. We have elected to recognize forfeitures of awards when they occur.

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Our LTIP awards contain (i) time-based vesting criteria, (ii) performance conditions, (iii) market conditions or (iv) a combination of time-based vesting criteria and performance conditions. For awards with performance conditions, expense is accrued over the service period only if the performance condition is considered probable of occurring. When awards with performance conditions that were previously considered improbable become probable, we incur additional expense in the period that the probability assessment changes. This is necessary to bring the accrued obligation associated with these awards up to the level it would have been if we had been accruing for these awards since the grant date. For awards with market conditions, the probable outcomes are determined on the respective dates that the fair values are calculated, and the resulting expense is accrued over the service period.

The following is a summary of the awards authorized under our LTIPs (including those associated with discontinued operations) as of December 31, 2025 (in millions):

LTIP LTIP
Awards Authorized
Plains All American 2021 Long-Term Incentive Plan 28.8  
Plains All American PNG Successor Long-Term Incentive Plan 1.3  
Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan 13.4  
Total (1)
43.5  

(1) Of the 43.5 million total awards authorized, 13.4 million awards are currently available for future grant. The remaining balance has already vested or is currently outstanding.

As of December 31, 2025, 10.5 million LTIP awards were outstanding (including those associated with discontinued operations). Of the awards outstanding, 8.9 million include associated DERs. At December 31, 2025, certain of the outstanding LTIP awards were considered probable of vesting and such awards are expected to vest at various dates between August 2026 and August 2030. As of December 31, 2025, the outstanding awards that are considered probable of vesting have a remaining unrecognized fair value of approximately $ 69  million.

Note 19— Commitments and Contingencies

Commitments

We have commitments (some of which are leases) related to real property, equipment and operating facilities. Future noncancelable commitments related to these items at December 31, 2025 are summarized below (in millions):

2026 2027 2028 2029 2030 Thereafter Total
Leases (1)
$ 46   $ 44   $ 43   $ 34   $ 28   $ 346   $ 541  
Other commitments (2)
245   215   116   114   117   141   948  
Total $ 291   $ 259   $ 159   $ 148   $ 145   $ 487   $ 1,489  

(1) Includes both operating and finance leases as defined by FASB guidance. Leases are primarily for (i) office space, (ii) land, (iii) vehicles, (iv) storage tanks and (v) tractor trailers. See Note 14 for additional information.
(2) Primarily includes storage, transportation and pipeline throughput agreements. Expense associated with such agreements was approximately $ 363 million, $ 341 million and $ 348 million for 2025, 2024 and 2023, respectively. A majority of the storage, transportation and pipeline throughput commitments are associated with agreements to store crude oil at facilities and transport crude oil on pipelines owned by equity method investees at posted tariff rates or prices that we believe approximate market. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities.

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Loss Contingencies — General

To the extent we are able to assess the likelihood of a negative outcome for a contingency, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred.

We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss.

Legal Proceedings — General

In the ordinary course of business, we are involved in various legal proceedings, including those arising from regulatory and environmental matters. In connection with determining the probability of loss associated with such legal proceedings and whether any potential losses associated therewith are estimable, we take into account what we believe to be all relevant known facts and circumstances, and what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing agreements, laws and regulations. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully protect us from losses arising from current or future legal proceedings.

Accordingly, we can provide no assurance that the outcome of the various legal proceedings that we are currently involved in, or will become involved with in the future, will not, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

Environmental — General

We currently own or lease, and in the past have owned and leased, properties where hazardous liquids, including hydrocarbons, are or have been handled. These properties and the hazardous liquids or associated wastes disposed thereon may be subject to the U.S. federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, and the U.S. federal Resource Conservation and Recovery Act, as amended, as well as state and Canadian federal and provincial laws and regulations. Under such laws and regulations, we could be required to remove or remediate hazardous liquids or associated wastes (including wastes disposed of or released by prior owners or operators) and to clean up contaminated property (including contaminated groundwater). Assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified or insured.

Although we have made significant investments in our maintenance and integrity programs, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail, storage and other facility operations. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. We also may discover environmental impacts from past releases that were previously unidentified. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated. Generally, our recording of these liabilities coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. We record receivables for amounts we believe are recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery.
 
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Environmental expenditures that pertain to current operations or to future revenues are expensed or capitalized consistent with our capitalization policy for property and equipment. Expenditures that result from the remediation of an existing condition caused by past operations and that do not contribute to current or future profitability are expensed.

Our estimated undiscounted reserves for environmental liabilities (excluding liabilities related to the Line 901 incident, as discussed further below) were reflected on our Consolidated Balance Sheets as follows (in millions):

December 31,
2025 December 31,
2024
Other current liabilities $ 13   $ 11  
Other long-term liabilities and deferred credits
70   69  
Total $ 83   $ 80  

In some cases, the actual cash expenditures associated with these liabilities may not occur for several years. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing or future legal claims giving rise to additional liabilities. Therefore, although we believe that our reserves are adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of such reserves and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

Specific Legal, Environmental or Regulatory Matters

Line 901 Incident . In May 2015, we experienced a release of crude oil from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. Effective as of December 31, 2025, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $ 870  million, which includes actual emergency response and clean-up costs, natural resource damage assessments, fines and penalties incurred, certain third-party claims settlements, and estimated costs associated with our remaining Line 901 lawsuits and claims as described below, as well as estimates for certain legal fees and statutory interest where applicable. We accrue such estimates of aggregate total costs to “Field operating costs” in our Consolidated Statements of Operations. This estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the resolution of certain third-party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and (ii) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. Our estimate does not include any lost revenue associated with the shutdown of Line 901 or 903 and does not include any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, with respect to potential losses that we regard as only reasonably possible or remote, we have made assumptions regarding the strength of our legal position based on our assessment of the relevant facts and applicable law and precedent; if our assumptions regarding such matters turn out to be inaccurate (i.e., we are found to be liable under circumstances where we regard the likelihood of loss as being only reasonably possible or remote), we could be responsible for significant costs and expenses that are not currently included in our estimates and accruals. In addition, for any potential losses that we regard as probable and for which we have accrued an estimate of the potential losses, our estimates regarding damages, legal fees, court costs and interest could turn out to be inaccurate and the actual losses we incur could be significantly higher than the amounts included in our estimates and accruals. Also, the amount of time it takes for us to resolve all of the current and future lawsuits and claims that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated.

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During the year ended December 31, 2025, we did not recognize any costs related to the Line 901 incident. During the years ended December 31, 2024 and 2023, we recognized costs, net of amounts probable of recovery from insurance (as applicable) of $ 345  million and $ 10  million, respectively. As of December 31, 2025 and 2024, we had a remaining undiscounted gross liability of approximately $ 22  million and $ 5  million, respectively, related to the Line 901 incident, which aggregate amounts are reflected in “Current liabilities” on our Consolidated Balance Sheet.

We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such liabilities. To date, we have collected approximately $ 295  million of the $ 500  million available under our 2015 insurance program. With respect to the Line 901 incident, we do not have any amounts recorded as receivables that are recognized on our Consolidated Balance Sheets as of December 31, 2025 and 2024.

We have completed the required clean-up and remediation work with respect to the Line 901 incident; however, we expect to make payments for additional legal and professional costs during future periods. During the second quarter of 2025, we agreed to confidential settlement terms for various lawsuits filed in California Superior Court in Santa Barbara County by companies and individuals who provided labor, goods, or services associated with oil production activities they claim were disrupted following the Line 901 incident, the agreed aggregate settlement amount has been factored into our Line 901 total cost estimate. The only other remaining Line 901 lawsuit is pending in California Superior Court in Santa Barbara County, in which a landowner on an adjacent pipeline is alleging property damage from the “stigma” of the Line 901 incident. We are vigorously defending this remaining lawsuit, which has not yet been set for trial, and believe we have strong defenses. Taking into account the costs that we have included in our total estimate of costs for the Line 901 incident and considering what we regard as very strong defenses to the claims made in our remaining Line 901 lawsuits, we do not believe the ultimate resolution of such remaining lawsuit will have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

L48 Pipeline Release. In March of 2025, our subsidiary, Pacific Pipeline System LLC, experienced a crude oil release of approximately 125 barrels on a segment of the Line 48 pipeline in Carson, California. Clean-up and remediation activities were conducted in cooperation with applicable state and federal regulatory agencies. An investigation by the California Office of the State Fire Marshall is not complete. To date no charges, fines or penalties have been assessed against us with respect to this release; however, it is possible that charges, fines or penalties may be assessed against us in the future. We provided notification to our applicable insurance carriers and intend to pursue reimbursement of any costs incurred in excess of our $ 10  million self-insured retention. We estimate that the aggregate cost to clean-up and remediate the site will be approximately $ 20  million. Through December 31, 2025, we incurred $ 12  million in connection with clean-up and remediation activities.

Hartree. On July 19, 2022, Hartree Natural Gas Storage, LLC (“Hartree”) filed a lawsuit under seal in the Superior Court for the State of Delaware asserting claims against PAA Natural Gas Storage, L.P. and PAA arising out of a Membership Interest Purchase Agreement relating to the 2021 sale of the Pine Prairie Energy Center natural gas storage facility to Hartree. In early 2025, w e entered into a settlement agreement with Hartree; the terms of the settlement are confidential and the amount paid is not material to our operations. All of Hartree’s claims were dismissed with prejudice and without any admission of wrongdoing by Plains.

Louisiana Coastal Erosion Lawsuit. Various coastal parishes, the State of Louisiana and some of its departments have filed lawsuits in Louisiana against a number of energy companies seeking damages for coastal erosion in connection with oil and gas operations in Louisiana. One of our subsidiaries has been named in such a lawsuit filed by The Louisiana Department of Wildlife and Fisheries (“LADWF”). LADWF filed a lawsuit in the 24 th Judicial District Court of Jefferson Parish, Louisiana on October 30, 2023 against our subsidiary, Plains Pipeline, L.P., Chevron Pipe Line Company, BP Oil Pipeline Company and Arrowhead Gulf Coast Pipeline, LLC (collectively, “Defendants”), as the former and current parties to certain pipeline right of way agreements (“ROWs”) in the vicinity of the Elmer Island Wildlife Refuge. LADWF alleges that the Defendants breached the terms of the ROWs by failing to prevent erosion and seeks restoration of the Wildlife Refuge or alternatively monetary compensatory damages including restoration costs, legal fees and disgorgement of profits derived from the alleged trespass. Our subsidiary owned and operated a pipeline in the vicinity of the refuge from 2006 through 2016. We settled this lawsuit in January 2026 for a payment from Plains of $ 1.5  million.

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Note 20— Segment Information

Our operating segments, Crude Oil and NGL, which are also our reportable segments, are organized by product as our Crude Oil and NGL businesses are generally impacted by different market fundamentals and require the use of different assets and business strategies. The Crude Oil segment includes our crude oil pipelines, crude oil storage and marine terminals and related crude oil marketing activities. Our crude oil marketing activities are included in our Crude Oil reporting segment as its primary purpose is to support the utilization of our assets by entering into transactions that facilitate increased volumes handled by our assets, resulting in additional earnings for the segment. The NGL segment includes our NGL assets primarily located in the Southwestern United States.

Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below). The measure of Segment Adjusted EBITDA forms the basis of our internal financial reporting and is the primary performance measure of segment profit/(loss) used by our CODM in assessing performance and allocating resources among our operating segments. We define Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) significant segment expenses including: (i) purchases and related costs, (ii) field operating costs and (iii) segment general and administrative expenses, plus (b) our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities, further adjusted (c) for certain selected items including (i) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance and (d) to exclude the portion of all preceding items that is attributable to noncontrolling interests (“Segment amounts attributable to noncontrolling interests”).

Our CODM uses Segment Adjusted EBITDA to evaluate the performance of each segment, including analyzing actual results compared to budget and guidance, to assess investment opportunities and to optimize and align assets to maximize returns to stakeholders.

Segment Adjusted EBITDA excludes depreciation and amortization. As an MLP, we make quarterly distributions of our “available cash” (as defined in our partnership agreement) to our unitholders. We look at each period’s earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of Segment Adjusted EBITDA as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as pipelines and facilities, caused by age-related decline and wear and tear. We compensate for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance investments, which act to partially offset the aging and wear and tear in the value of our principal fixed assets. These maintenance investments are a component of field operating costs included in Segment Adjusted EBITDA or in maintenance capital, depending on the nature of the cost. Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as investment capital. Capital expenditures made to replace and/or refurbish partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as maintenance capital, which is deducted in determining “available cash.” Maintenance capital is reviewed by our CODM on a segment basis. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are charged to expense as incurred. Assets are not reviewed by our CODM on a segmented basis; therefore, such information is not presented.

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The following tables reflect certain financial data from continuing operations for each segment (in millions):

Crude Oil NGL Intersegment
Elimination
Total
Year Ended December 31, 2025
Revenues (1) :

Product sales $ 42,373   $ 145   $ ( 17 ) $ 42,501  
Services 1,758   6   ( 3 ) 1,761  
Total revenues $ 44,131   $ 151   $ ( 20 ) $ 44,262  

Significant segment expenses:
Purchases and related costs (1)
$ ( 40,323 ) $ ( 130 ) $ 20   $ ( 40,433 )
Field operating costs ( 1,127 ) ( 27 ) —   ( 1,154 )
Segment general and administrative expenses ( 314 ) ( 28 ) —   ( 342 )
Total significant segment expenses $ ( 41,764 ) $ ( 185 ) $ 20   $ ( 41,929 )

Equity earnings in unconsolidated entities $ 382   $ —  

Other segment items (2) :

Depreciation and amortization of unconsolidated entities (3)
84   —  
Derivative activities and inventory valuation adjustments (4)
( 23 ) —  
Long-term inventory costing adjustments (5)
45   —  
Deficiencies under minimum volume commitments, net (6)
( 38 ) —  
Equity-indexed compensation expense (7)
37   —  
Foreign currency revaluation (8)
12   —  

Transaction-related expenses (9)
17   —  
Segment amounts attributable to noncontrolling interests (10)
( 539 ) —  
Total other segment items $ ( 405 ) $ —  

Segment Adjusted EBITDA $ 2,344   $ ( 34 )

Investment and acquisition capital expenditures  (11) (12)
$ 3,321   $ —   $ 3,321  
Maintenance capital expenditures (12)
$ 153   $ 3   $ 156  

As of December 31, 2025

Investments in unconsolidated entities $ 2,846   $ —   $ 2,846  

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Crude Oil NGL Intersegment
Elimination
Total
Year Ended December 31, 2024
Revenues (1) :

Product sales $ 47,034   $ 181   $ ( 16 ) $ 47,199  
Services 1,686   6   ( 2 ) 1,690  
Total revenues $ 48,720   $ 187   $ ( 18 ) $ 48,889  

Significant segment expenses:
Purchases and related costs (1)
$ ( 45,033 ) $ ( 147 ) $ 18   $ ( 45,162 )
Field operating costs ( 1,440 ) ( 31 ) —   ( 1,471 )
Segment general and administrative expenses ( 298 ) ( 30 ) —   ( 328 )
Total significant segment expenses $ ( 46,771 ) $ ( 208 ) $ 18   $ ( 46,961 )

Equity earnings in unconsolidated entities $ 452   $ —  

Other segment items (2) :

Depreciation and amortization of unconsolidated entities (3)
84   —  
Derivative activities and inventory valuation adjustments (4)
5   —  
Long-term inventory costing adjustments (5)
1   —  
Deficiencies under minimum volume commitments, net (6)
( 31 ) —  
Equity-indexed compensation expense (7)
36   —  
Foreign currency revaluation (8)
( 22 ) —  
Line 901 incident (13)
345   —  

Segment amounts attributable to noncontrolling interests (10)
( 543 ) —  
Total other segment items $ ( 125 ) $ —  

Segment Adjusted EBITDA $ 2,276   $ ( 21 )

Investment and acquisition capital expenditures  (11) (12)
$ 554   $ —   $ 554  
Maintenance capital expenditures (12)
$ 183   $ 4   $ 187  

As of December 31, 2024

Investments in unconsolidated entities $ 2,811   $ —   $ 2,811  

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Crude Oil NGL Intersegment
Elimination
Total
Year Ended December 31, 2023
Revenues (1) :

Product sales $ 45,587   $ 180   $ ( 22 ) $ 45,745  
Services 1,587   6   ( 2 ) 1,591  
Total revenues $ 47,174   $ 186   $ ( 24 ) $ 47,336  

Significant segment expenses:
Purchases and related costs (1)
$ ( 43,805 ) $ ( 156 ) $ 24   $ ( 43,937 )
Field operating costs ( 1,053 ) ( 32 ) —   ( 1,085 )
Segment general and administrative expenses ( 271 ) ( 28 ) —   ( 299 )
Total significant segment expenses $ ( 45,129 ) $ ( 216 ) $ 24   $ ( 45,321 )

Equity earnings in unconsolidated entities $ 369   $ —  

Other segment items (2) :

Depreciation and amortization of unconsolidated entities (3)
87   —  
Derivative activities and inventory valuation adjustments (4)
17   —  
Long-term inventory costing adjustments (5)
22   —  
Deficiencies under minimum volume commitments, net (6)
12   —  
Equity-indexed compensation expense (7)
35   —  
Foreign currency revaluation (8)
19   —  
Line 901 incident (13)
10   —  
Transaction-related expenses (9)
1   —  
Segment amounts attributable to noncontrolling interests (10)
( 454 ) —  
Total other segment items $ ( 251 ) $ —  

Segment Adjusted EBITDA $ 2,163   $ ( 30 )

Investment and acquisition capital expenditures  (11) (12)
$ 765   $ —   $ 765  
Maintenance capital expenditures (12)
$ 145   $ 6   $ 151  

As of December 31, 2023      

Investments in unconsolidated entities $ 2,820   $ —   $ 2,820  

(1) Segment revenues include intersegment amounts that are eliminated in Purchases and related costs. Intersegment activities are conducted at posted tariff rates where applicable, or otherwise at rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated.
(2) Represents adjustments utilized by our CODM in the evaluation of segment results.
(3) Includes our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities.
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(4) We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify differences in the timing of earnings from the derivative instruments and the underlying transactions and exclude the related gains and losses in determining Segment Adjusted EBITDA such that the earnings from the derivative instruments and the underlying transactions impact Segment Adjusted EBITDA in the same period. In addition, we exclude gains and losses on derivatives that are related to (i) investing activities, such as the purchase of linefill, and (ii) purchases of long-term inventory. We also exclude the impact of corresponding inventory valuation adjustments, as applicable.
(5) We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We exclude the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and write-downs of such inventory that result from price declines from Segment Adjusted EBITDA.
(6) We, and certain of our equity method investees, have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue or equity earnings, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to Segment Adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.
(7) Our total equity-indexed compensation expense includes expense associated with awards that will be settled in units and awards that will be settled in cash. The awards that will be settled in units are included in our diluted net income per unit calculation when the applicable performance criteria have been met. We exclude compensation expense associated with these awards in determining Segment Adjusted EBITDA as the dilutive impact of the outstanding awards is included in our diluted net income per unit calculation, as applicable. The portion of compensation expense associated with awards that will be settled in cash is not excluded in determining Segment Adjusted EBITDA. See Note 18 for information regarding our equity-indexed compensation plans.
(8) During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. These gains and losses are not integral to our core operating performance and were therefore excluded in determining Segment Adjusted EBITDA.
(9) Primarily related to deal-specific costs incurred during the years presented. See Note 8 for additional discussion. An adjustment for these non-recurring expenses is included in the calculation of Segment Adjusted EBITDA for the years ended December 31, 2025 and 2023 as our CODM does not view such expenses as integral to understanding our core segment operating performance.
(10) Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River.
(11) Investment capital and acquisition capital expenditures, including investments in unconsolidated entities.
(12) These amounts combined represent total capital expenditures.
(13) Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance (as applicable). The year ended December 31, 2024 includes the write-off of a receivable for Line 901 insurance proceeds in the fourth quarter of 2024 and the impact of settlements in the third quarter of 2024. See Note 19 for additional information regarding the Line 901 incident.

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Segment Adjusted EBITDA Reconciliation

The following table reconciles Segment Adjusted EBITDA to Income from continuing operations, net of tax (in millions):

Year Ended December 31,
2025 2024 2023
Segment Adjusted EBITDA $ 2,310   $ 2,255   $ 2,133  
Total other segment items (1)
405   125   251  
Depreciation and amortization ( 953 ) ( 901 ) ( 909 )
Gains/(losses) on asset sales, asset impairments and other, net
54   ( 159 ) 152  
Gain on investments in unconsolidated entities, net 31   15   28  
Interest expense, net ( 554 ) ( 430 ) ( 386 )
Other income, net
108   64   102  
Income from continuing operations before tax
1,401   969   1,371  
Income tax expense from continuing operations
( 15 ) ( 87 ) ( 61 )
Income from continuing operations, net of tax
$ 1,386   $ 882   $ 1,310  

(1) See footnotes to the segment financial data tables above for a more detailed discussion of Other segment items.

Geographic Data

We have operations in the United States and Canada. Set forth below are revenues and long-lived assets attributable to these geographic areas (in millions):

Year Ended December 31,
Revenues  (1)
2025 2024 2023
United States $ 39,761   $ 43,535   $ 41,738  
Canada 4,501   5,354   5,598  
$ 44,262   $ 48,889   $ 47,336  

(1) Revenues are primarily attributed to each region based on where the services are provided or the product is shipped.

December 31,
Long-Lived Assets  (1)
2025 2024
United States $ 21,398   $ 17,955  
Canada 1,480   1,429  
$ 22,878   $ 19,384  

(1) Excludes long-term derivative assets and long-term deferred tax assets.

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Note 21— Selected Quarterly Financial Data (Unaudited)

On June 17, 2025, we entered into a SPA with Keyera, pursuant to which Keyera agreed to acquire all of the issued and outstanding shares of Plains Midstream Canada ULC, our wholly-owned subsidiary that owns substantially all of our Canadian NGL Business. See Note 1 for additional information. 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.

The following table sets forth selected quarterly financial data (in millions, except per unit data):

First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Total (1)

Year Ended December 31, 2025
Total revenues
$ 11,477   $ 10,642   $ 11,578   $ 10,565   $ 44,262  
Gross margin (2)
$ 440   $ 321   $ 567   $ 447   $ 1,776  
Operating income
$ 354   $ 239   $ 484   $ 355   $ 1,434  
Income from continuing operations, net of tax
$ 380   $ 227   $ 453   $ 325   $ 1,386  
Income from discontinued operations, net of tax
$ 136   $ 70   $ 76   $ 102   $ 383  
Net income
$ 516   $ 297   $ 529   $ 427   $ 1,769  
Net income attributable to PAA
$ 443   $ 210   $ 441   $ 342   $ 1,435  

Basic and diluted net income per common unit:

Continuing operations
$ 0.30   $ 0.11   $ 0.44   $ 0.26   $ 1.12  
Discontinued operations
0.19   0.10   0.11   0.15   0.54  
Basic and diluted net income per common unit
$ 0.49   $ 0.21   $ 0.55   $ 0.41   $ 1.66  

Year Ended December 31, 2024
Total revenues
$ 11,639   $ 12,757   $ 12,456   $ 12,035   $ 48,889  
Gross margin (2)
$ 437   $ 411   $ 282   $ 65   $ 1,196  
Operating income/(loss)
$ 356   $ 332   $ 196   $ ( 16 ) $ 868  
Income from continuing operations, net of tax
$ 341   $ 298   $ 198   $ 45   $ 882  
Income from discontinued operations, net of tax
$ 10   $ 32   $ 114   $ 74   $ 231  
Net income
$ 351   $ 330   $ 312   $ 119   $ 1,113  
Net income attributable to PAA
$ 266   $ 250   $ 220   $ 36   $ 772  

Basic and diluted net income/(loss) per common unit:

Continuing operations
$ 0.28   $ 0.21   $ 0.06   $ ( 0.15 ) $ 0.40  
Discontinued operations
0.01   0.05   0.16   0.11   0.33  
Basic and diluted net income/(loss) per common unit
$ 0.29   $ 0.26   $ 0.22   $ ( 0.04 ) $ 0.73  

(1) The sum of the four quarters may not equal the year due to rounding.
(2) Gross margin is calculated as Total revenues less (i) Purchases and related costs, (ii) Field operating costs, (iii) Depreciation and amortization and (iv) (Gains)/losses on asset sales, asset impairments and other, net.
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