10-Q – 2025-11-07 – paa-20250930.htm

**     Indicates that variance as a percentage is not meaningful.
(1) Includes results from continuing operations and discontinued operations.
(2) Represents “Interest expense, net” as reported on our Condensed Consolidated Statements of Operations, net of interest income associated with promissory notes by and among us and certain Plains entities.
(3) See Note 2 to our Condensed Consolidated Financial Statements for additional information.
(4) We exclude our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities when reviewing Adjusted EBITDA, similar to our consolidated assets.
(5) Depreciation and amortization on the long-lived assets of the Canadian NGL Business disposal group ceased upon meeting the criteria to be classified as assets held for sale. Management believes that the presentation of Adjusted EBITDA and Implied DCF on a consolidated basis (e.g., the aggregate of continuing operations and discontinued operations) provides more relevant and useful information regarding our performance and results of operations than presenting such metrics only on a continuing operations or discontinued operations basis. We therefore include an adjustment for the impact of amortization of the rail fleet associated with the Canadian NGL Business in our calculation of Adjusted EBITDA. See Note 1 to our Condensed Consolidated Financial Statements for additional information regarding the pending sale of the Canadian NGL Business. Also see the “—Non-GAAP Financial Measures” section above.
(6) For a more detailed discussion of these selected items impacting comparability, see the footnotes to the segment financial data tables in Note 11 to our Condensed Consolidated Financial Statements.
(7) During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability.
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(8) “Other income, net” on our Condensed Consolidated Statements of Operations, excluding interest income associated with promissory notes by and among us and certain Plains entities, adjusted for selected items impacting comparability (“Adjusted other income, net”) is included in Adjusted EBITDA and excluded from Segment Adjusted EBITDA.
(9) Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River.
(10) See the table above for a reconciliation from Net Income to Adjusted EBITDA.
(11) Amount excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps and is net of interest income associated with promissory notes by and among us and certain Plains entities.
(12) Maintenance capital expenditures are defined as capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets.
(13) Investment capital expenditures attributable to noncontrolling interests that reduce Implied DCF available to PAA common unitholders.
(14) Comprised of cash distributions received from unconsolidated entities less equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization, including write-downs related to cancelled projects, and selected items impacting comparability of unconsolidated entities). 
(15) Cash distributions paid during the period presented.
(16) Excess DCF is retained to establish reserves for debt repayment, future distributions, common equity repurchases, capital expenditures and other partnership purposes.

Analysis of Operating Segments
 
We manage our operations through two operating segments: Crude Oil and NGL. Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA. See Note 11 to our Condensed Consolidated Financial Statements for our definition of Segment Adjusted EBITDA and a reconciliation of Segment Adjusted EBITDA to Income from Continuing Operations, Net of Tax. See Note 19 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for our definition of maintenance capital.

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

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

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

Operating Results  (1)
Three Months Ended
September 30, Variance Nine Months Ended
September 30, Variance
(in millions) 2025 2024 $ % 2025 2024 $ %
Revenues $ 11,559  $ 12,444  $ (885) (7) % $ 33,620  $ 36,761  $ (3,141) (9) %
Purchases and related costs (10,572) (11,529) 957  8  % (30,802) (34,014) 3,212  9  %
Field operating costs (281) (400) 119  30  % (853) (938) 85  9  %
Segment general and administrative expenses (2)
(74) (78) 4  5  % (229) (223) (6) (3) %
Equity earnings in unconsolidated entities 96  97  (1) (1) % 292  298  (6) (2) %

Other segment items (3) :

Depreciation and amortization of unconsolidated entities 21  22  (1) ** 62  59  3  **
Derivative activities and inventory valuation adjustments (30) (13) (17) ** (2) 20  (22) **
Long-term inventory costing adjustments 10  34  (24) ** 27  10  17  **
Deficiencies under minimum volume commitments, net (6) 15  (21) ** (21) 10  (31) **
Equity-indexed compensation expense 10  9  1  ** 28  28  —  **
Foreign currency revaluation (3) 2  (5) ** 6  (18) 24  **
Line 901 incident —  120  (120) ** —  120  (120) **
Transaction-related expenses —  —  —  ** 7  —  7  **
Segment amounts attributable to noncontrolling interests (137) (146) 9  ** (402) (406) 4  **
Segment Adjusted EBITDA $ 593  $ 577  $ 16  3  % $ 1,733  $ 1,707  $ 26  2  %

Maintenance capital expenditures $ 36  $ 48  $ (12) (25) % $ 110  $ 135  $ (25) (19) %

Three Months Ended
September 30, Variance Nine Months Ended
September 30, Variance
Average Volumes 2025 2024 Volumes % 2025 2024 Volumes %

Crude oil pipeline tariff (by region) (4) (5)
               
Permian Basin
7,490  6,944  546  8  % 7,196  6,692  504  8  %
South Texas / Eagle Ford
538  416  122  29  % 524  396  128  32  %
Mid-Continent
564  532  32  6  % 506  516  (10) (2) %

Other 1,291  1,274  17  1  % 1,319  1,298  21  2  %
Total crude oil pipeline tariff 9,883  9,166  717  8  % 9,545  8,902  643  7  %

**     Indicates that variance as a percentage is not meaningful.
(1) Revenues and costs and expenses include intersegment amounts. 
(2) Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
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(3) Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 11 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.
(4) Average daily volumes in thousands of barrels per day calculated as the total volumes (attributable to our interest for assets owned by unconsolidated entities or through undivided joint interests) for the period divided by the number of days in the period. Volumes associated with acquisitions represent total volumes for the number of days we actually owned the assets divided by the number of days in the period. 
(5) Includes volumes (attributable to our interest) from assets owned by unconsolidated entities.
 
Segment Adjusted EBITDA

Crude Oil Segment Adjusted EBITDA for the three and nine months ended September 30, 2025 increased versus comparable results for the three and nine months ended September 30, 2024. The benefit to the 2025 period from higher tariff volumes on our pipelines, tariff escalations and contributions from recently completed acquisitions was largely offset by fewer market-based opportunities.

The following is a more detailed discussion of the significant factors impacting Segment Adjusted EBITDA for the three and nine months ended September 30, 2025 compared to the same periods in 2024.

Net Revenues and Equity Earnings. Our results were favorably impacted by (i) volume growth across our pipeline systems largely driven by increased production in the Permian Basin region, (ii) contributions from recently completed acquisitions in the Permian Basin and South Texas regions and (iii) the benefit of tariff escalations. These favorable impacts were partially offset by (iv) fewer market-based opportunities, (v) lower commodity prices, which resulted in lower revenues from pipeline loss allowance in the 2025 periods, and (vi) the impact from certain Permian long-haul contract rates resetting to market in the third quarter of 2025.

Field Operating Costs. The decrease in field operating costs for the three and nine months ended September 30, 2025 compared to the same periods in 2024 was primarily due to the recognition in the third quarter of 2024 of costs associated with settlements related to the Line 901 incident that occurred in May 2015 (which impact field operating costs, but are excluded from Segment Adjusted EBITDA, and thus are reflected as an “Adjustment” in the table above). This was partially offset by higher expenses resulting from acquisitions and higher volumes in the 2025 periods. In addition, the nine-month period was further impacted by higher expenses associated with (i) environmental remediation costs and (ii) property taxes.

Maintenance Capital

The decrease in maintenance capital spending for the three and nine months ended September 30, 2025 compared to the same periods in 2024 was primarily due to lower costs resulting from timing of certain pipeline integrity activities.

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NGL Segment

Our NGL segment operations involve NGL storage and terminalling from our four NGL assets located in the United States, namely our Bumstead, Shafter, San Pedro and Tampa facilities. Our NGL segment revenues are primarily derived from (i) providing storage and/or terminalling services at these facilities to third-party customers for a fee and (ii) the transport, storage and sale of specification NGL products. The segment results also include the direct fixed and variable field costs of operating our four NGL facilities, as well as an allocation of indirect operating costs and general and administrative expenses.
 
The following table sets forth our operating results from our NGL segment:

Operating Results  (1)
Three Months Ended
September 30, Variance Nine Months Ended
September 30, Variance
(in millions) 2025 2024 $ % 2025 2024 $ %
Revenues $ 24  $ 20  $ 4  20  % $ 92  $ 106  $ (14) (13) %
Purchases and related costs (18) (19) 1  5  % (74) (85) 11  13  %
Field operating costs (2)
(7) (8) 1  13  % (20) (24) 4  17  %
Segment general and administrative expenses (2) (3)
(9) (8) (1) (13) % (22) (23) 1  4  %

Segment Adjusted EBITDA $ (10) $ (15) $ 5  33  % $ (24) $ (26) $ 2  8  %

Maintenance capital expenditures $ —  $ 2  $ (2) (100) % $ 2  $ 5  $ (3) (60) %

(1) Revenues and costs and expenses include intersegment amounts.
(2) Field operating costs and segment general and administrative expenses include certain costs that are part of the overhead of continuing operations.
(3) Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.

Segment Adjusted EBITDA

The Segment Adjusted EBITDA loss for all periods presented is largely driven by costs that are part of the overhead of our NGL activities and are included in continuing operations as they are not related to contracts or arrangements that will be included in the sale of the Canadian NGL Business. These costs include information technology, insurance and other shared services costs.

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

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As of September 30, 2025, we had a working capital surplus of $218 million and approximately $3.9 billion of liquidity available to meet our ongoing operating, investing and financing needs (subject to continued covenant compliance) as noted below (in millions):

  As of
September 30, 2025
Availability under senior unsecured revolving credit facility (1) (2) (3)
$ 1,350 
Availability under senior secured hedged inventory facility (1) (2) (3)
1,323 
Amounts outstanding under commercial paper program (3)
— 
Subtotal 2,673 
Cash and cash equivalents (4)
1,180 
Total $ 3,853 

(1) Represents availability prior to giving effect to borrowings outstanding under our commercial paper program, which reduce available capacity under our credit facilities.
(2) Available capacity under our senior unsecured revolving credit facility and senior secured hedged inventory facility was reduced by outstanding letters of credit issued under these facilities of less than $1 million and $27 million, respectively.
(3) We borrowed approximately $1.8 billion under our commercial paper program and credit facilities to initially fund the EPIC acquisition in November 2025. See Note 12 to our Condensed Consolidated Financial Statements for additional information regarding the EPIC acquisition.
(4) Cash on hand at September 30, 2025 was utilized to redeem our $1.0 billion, 4.65% senior notes on October 3, 2025.

Usage of our credit facilities, and, in turn, our commercial paper program, is subject to ongoing compliance with covenants. The credit agreements for our revolving credit facilities (which impact our ability to access our commercial paper program because they provide the financial backstop that supports our short-term credit ratings) and the indentures governing our senior notes contain cross-default provisions. A default under our credit agreements or indentures would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with the provisions in our credit agreements, our ability to make distributions of available cash is not restricted. We were in compliance with the covenants contained in our credit agreements and indentures as of September 30, 2025.

We believe that we have, and will continue to have, the ability to access our commercial paper program and credit facilities, which we use to meet our short-term cash needs. We believe that our financial position remains strong and we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow, including extended disruptions in the financial markets and/or energy price volatility resulting from current macroeconomic and geopolitical conditions, including actions by the Organization of Petroleum Exporting Countries (OPEC). A prolonged material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity and cost of borrowing. Our borrowing capacity and borrowing costs are also impacted by our credit rating. See Item 1A. “Risk Factors” included in our 2024 Annual Report on Form 10-K for further discussion regarding risks that may impact our liquidity and capital resources.

Non-GAAP Financial Liquidity Measures

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

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The following table sets forth the reconciliation of the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions from Net Cash Provided by Operating Activities (in millions):

Nine Months Ended
September 30,
2025 2024
Net cash provided by operating activities (1)
$ 2,150  $ 1,763 
Adjustments to reconcile net cash provided by operating activities to adjusted free cash flow:

Net cash used in investing activities (1) ( 2)
(1,831) (1,240)
Cash contributions from noncontrolling interests 34  40 
Cash distributions paid to noncontrolling interests (3)
(339) (310)
Proceeds from the issuance of related party notes (2)
330  629 

Adjusted Free Cash Flow (1) (4)
$ 344  $ 882 
Cash distributions (4)
(973) (858)
Adjusted Free Cash Flow after Distributions (1) (5)
$ (629) $ 24 

(1) Includes results from continuing operations and discontinued operations for all periods presented.
(2) Certain Plains entities have issued promissory notes by and among such entities to facilitate financing. “Proceeds from the issuance of related party notes” has an equal and offsetting cash outflow associated with our investment in related party notes, which is included as a component of “Net cash used in investing activities.” See Note 9 to our Condensed Consolidated Financial Statements for additional information on our related party notes.
(3) Cash distributions paid during the period presented.
(4) Cash distributions paid to our preferred and common unitholders during the period presented.
(5) Excess Adjusted Free Cash Flow after Distributions is retained to establish reserves for future distributions, capital expenditures, debt reduction and other partnership purposes. Adjusted Free Cash Flow after Distributions shortages, if any, may be funded from previously established reserves, cash on hand or from borrowings under our credit facilities or commercial paper program.

Cash Flow from Operating Activities
 
For a comprehensive discussion of the primary drivers of cash flow from operating activities, including the impact of varying market conditions and the timing of settlement of our derivatives, see Item 7. “Liquidity and Capital Resources—Cash Flow from Operating Activities” included in our 2024 Annual Report on Form 10-K.
 
Net cash provided by operating activities from continuing operations for the first nine months of 2025 and 2024 was $1.836 billion and $1.597 billion, respectively, and primarily resulted from earnings from our operations.
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Investing Activities

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

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

Nine Months Ended
September 30, Nine Months Ended
September 30, Nine Months Ended
September 30,
Capital Expenditures (3) (4)
2025 2024 2025 2024 2025 2024
Crude Oil:

Investment capital
$ 312  $ 158  $ 404  $ 221  $ 404  $ 221 
Maintenance capital
98  121  110  135  110  135 
Acquisition capital (5)
832  141  904  146  904  146 
  $ 1,242  $ 420  $ 1,418  $ 502  $ 1,418  $ 502 

NGL:

Investment capital
$ 89  $ 74  $ 89  $ 74  $ —  $ — 
Maintenance capital
51  53  51  53  2  5 

$ 140  $ 127  $ 140  $ 127  $ 2  $ 5 

Total:

Investment capital
$ 401  $ 232  $ 493  $ 295  $ 404  $ 221 
Maintenance capital
149  174  161  188  112  140 
Acquisition capital (5)
832  141  904  146  904  146 
$ 1,382  $ 547  $ 1,558  $ 629  $ 1,420  $ 507 

(1) Excludes expenditures attributable to noncontrolling interests, which primarily relate to the Permian JV. Includes results from continuing operations and discontinued operations for all periods presented.
(2) Includes results from continuing operations and discontinued operations for all periods presented. Capital expenditures related to discontinued operations were $89 million and $49 million for investment and maintenance capital for the nine months ended September 30, 2025, respectively. Capital expenditures for investment and maintenance capital related to discontinued operations were $74 million and $48 million for the nine months ended September 30, 2024, respectively. There was no acquisition capital related to discontinued operations for any period presented.
(3) Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as “Investment capital.” Capital expenditures made to replace and/or refurbish partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as “Maintenance capital.”
(4) Contributions to unconsolidated entities, accounted for under the equity method of accounting, that are related to investment capital projects by such entities are recognized in “Investment capital.” Acquisitions of initial investments or additional interests in unconsolidated entities are included in “Acquisition capital.”
(5) Acquisition capital for the 2025 period primarily included the acquisitions of (i) Ironwood Midstream, (ii) Medallion Midstream by the Permian JV, (iii) the remaining 50% interest in Cheyenne Pipeline LLC through a non-cash transaction, (iv) Black Knight Midstream and (v) an additional 20% interest in BridgeTex Pipeline. See Note 12 to our Condensed Consolidated Financial Statements for additional information. Acquisition capital for the 2024 period primarily included the acquisition of additional ownership interests in equity method investees.

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2025 Investment and Maintenance Capital. Total investment capital for the year ending December 31, 2025 is projected to be approximately $600 million ($490 million net to our interest), which includes approximately $110 million related to discontinued operations. Approximately half of our projected investment capital expenditures are expected to be invested in the Permian JV assets. Additionally, maintenance capital for 2025 is projected to be approximately $230 million ($215 million net to our interest), which includes approximately $70 million related to discontinued operations.

Ongoing Activities Related to Strategic Transactions

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

We typically do not announce a transaction until after we have executed a definitive agreement. In certain cases, in order to protect our business interests or for other reasons, we may defer public announcement of a transaction until closing or a later date. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future efforts with respect to any such transactions will be successful, and we can provide no assurance that our financial expectations with respect to such transactions will ultimately be realized. See Item 1A. “Risk Factors—Risks Related to Our Business—Acquisitions and divestitures involve risks that may adversely affect our business” included in our 2024 Annual Report on Form 10-K.

Related Party Promissory Notes

In February 2025, promissory notes with a face value of CAD$473 million (approximately $330 million) were issued by and among us and certain Plains entities. The cash outflow associated with our investment in promissory notes issued by PAGP to us has an equal and offsetting cash inflow associated with proceeds from the issuance by our consolidated subsidiary of promissory notes to PAGP for the same face value amount, which is included as a component of financing activities. See Note 9 to our Condensed Consolidated Financial Statements for additional information on our related party notes.

Financing Activities

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

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Borrowings and Repayments Under Credit Agreements

During the nine months ended September 30, 2025, we had net repayments under our commercial paper program of $393 million. The net repayments resulted primarily from cash flow from operating activities and proceeds from the issuance of $1.25 billion aggregate principal amount of senior notes in September 2025, which offset borrowings during the period related to funding needs for capital investments, inventory purchases and other general partnership purposes.

During the nine months ended September 30, 2024, we had net repayments under our commercial paper program of $433 million. The net repayments resulted primarily from cash flow from operating activities and proceeds from the issuance of $650 million, 5.70% senior notes in June 2024, which offset borrowings during the period related to funding needs for capital investments, inventory purchases and other general partnership purposes.

Senior Notes

In January 2025, we completed the offering of $1.0 billion, 5.95% senior notes due June 2035 at a public offering price of 99.761%. Interest payments are due on June 15 and December 15 of each year, commencing on June 15, 2025. We used the net proceeds from this offering of approximately $988 million, after deducting the underwriting discount and offering expenses, to (i) fund the acquisitions completed during the nine months ended September 30, 2025, (ii) fund the repurchase of approximately 12.7 million Series A preferred units in January 2025 and (iii) repay outstanding borrowings under our credit facilities and commercial paper program and for general partnership purposes.

In September 2025, we completed the offering of $1.25 billion aggregate principal amount of senior notes, consisting of $700 million, 4.70% senior notes due January 2031 and $550 million, 5.60% senior notes due January 2036 at a public offering price of 99.865% and 99.798%, respectively. Interest payments on these notes are due on January 15 and July 15 of each year, commencing on January 15, 2026. We used the net proceeds from this offering of approximately $1.2 billion, after deducting the underwriting discount and offering expenses, to (i) redeem on October 3, 2025 the principal amount of our $1.0 billion, 4.65% senior notes due October 2025 and (ii) fund a portion of the purchase price for the EPIC Pipeline acquisition.

See Note 7 and Note 12 to our Condensed Consolidated Financial Statements for additional information regarding our Series A preferred units and our recently completed and pending acquisitions, respectively.

Common Equity Repurchase Program

We repurchased 0.5 million common units under the Common Equity Repurchase Program (the “Program”) through open market purchases that settled during the nine months ended September 30, 2025, 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 nine months ended September 30, 2024. At September 30, 2025, the remaining available capacity under the Program was $190 million. See Note 11 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for additional information regarding the Program.

Registration Statements

We periodically access the capital markets for both equity and debt financing. We have filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to a specified amount of debt or equity securities (“Traditional Shelf”), under which we had approximately $1.1 billion of unsold securities available at September 30, 2025. We did not conduct any offerings under our Traditional Shelf during the nine months ended September 30, 2025. We also have access to a universal shelf registration statement (“WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. The offerings of $1.0 billion, 5.95% senior notes in January 2025, $700 million, 4.70% senior notes and $550 million, 5.60% senior notes in September 2025 were conducted under our WKSI Shelf.

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Series A Preferred Unit Repurchase

On January 31, 2025, we repurchased approximately 12.7 million units, or 18%, of our outstanding Series A preferred units at the issue price of $26.25 per unit for a purchase price of approximately $333 million, plus accrued and unpaid distributions through January 30, 2025 of approximately $10 million. We used a portion of the net proceeds from our January 2025 senior notes offering to fund this repurchase. See Note 7 to our Condensed Consolidated Financial Statements for more information regarding our Series A preferred units.

Distributions to Our Unitholders

Series A preferred unitholders. On November 14, 2025, we will pay a quarterly cash distribution of approximately $0.615 per unit to Series A preferred unitholders of record at the close of business on October 31, 2025 for the period from July 1, 2025 through September 30, 2025.

Series B preferred unitholders. On November 17, 2025, we will pay a quarterly cash distribution of approximately $21.93 per unit to Series B preferred unitholders of record at the close of business on November 3, 2025 for the period from August 15, 2025 through November 14, 2025.

Common Unitholders . On November 14, 2025, we will pay a quarterly cash distribution of $0.38 per common unit ($1.52 per unit on an annualized basis) to common unitholders of record at the close of business on October 31, 2025 for the period from July 1, 2025 through September 30, 2025.

See Note 7 to our Condensed Consolidated Financial Statements for details of distributions paid during or pertaining to the first nine months of 2025, including distributions to our preferred unitholders.

Distributions to Noncontrolling Interests

Distributions to noncontrolling interests represent amounts paid on interests in consolidated entities that are not owned by us. As of September 30, 2025, noncontrolling interests in our subsidiaries consisted of (i) a 35% interest in the Permian JV, (ii) a 30% interest in Cactus II and (iii) a 33% interest in Red River. See Note 7 to our Condensed Consolidated Financial Statements for details of distributions paid to noncontrolling interests during the nine months ended September 30, 2025.

Related Party Promissory Notes

In February 2025, promissory notes with a face value of CAD$473 million (approximately $330 million) were issued by and among us and certain Plains entities. The cash inflow associated with proceeds from the issuance by our consolidated subsidiary of promissory notes to PAGP has an equal and offsetting cash outflow associated with our investment in promissory notes issued by PAGP to us for the same face value amount, which is included as a component of investing activities. See Note 9 to our Condensed Consolidated Financial Statements for additional information on our related party notes.

Contingencies
 
For a discussion of contingencies that may impact us, see Note 10 to our Condensed Consolidated Financial Statements.

Commitments
 
Purchase Obligations. In the ordinary course of doing business, we purchase crude oil from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years, with a limited number of contracts with remaining terms extending up to 10 years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy or who have provided credit support we consider adequate.

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The following table includes our best estimate of the amount and timing of these payments as of September 30, 2025 (in millions):

Remainder of 2025 2026 2027 2028 2029 2030 and Thereafter Total
Crude oil and other purchases (1)
$ 6,546  $ 20,496  $ 18,425  $ 16,159  $ 15,072  $ 35,624  $ 112,322 

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

EPIC Acquisition. Through two separate transactions completed in the fourth quarter of 2025, we acquired 100% of the entity that owns the EPIC Pipeline for aggregate consideration of approximately $2.9 billion, inclusive of approximately $1.1 billion of debt assumed. We initially funded the EPIC acquisition by assuming the $1.1 billion of existing debt and funding the $1.8 billion equity portion through a combination of commercial paper and credit facility borrowings and cash on hand. See Note 12 to our Condensed Consolidated Financial Statements for additional information regarding the EPIC acquisition.

Letters of Credit. In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the product is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At September 30, 2025 and December 31, 2024, we had outstanding letters of credit of approximately $70 million and $90 million, respectively.

Recent Accounting Pronouncements

See Note 1 to our Condensed Consolidated Financial Statements.
 

FORWARD-LOOKING STATEMENTS

All statements included in this report, other than statements of historical fact, are forward-looking statements, including but not limited to statements incorporating the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast,” as well as similar expressions and statements regarding our business strategy, plans and objectives for future operations. The absence of such words, expressions or statements, however, does not mean that the statements are not forward-looking. Any such forward-looking statements reflect our current views with respect to future events, based on what we believe to be reasonable assumptions. Certain factors could cause actual results or outcomes to differ materially from the results or outcomes anticipated in the forward-looking statements. The most important of these factors include, but are not limited to:

• risks related to the Canadian NGL Business divestiture (as defined herein), including the risk that the Canadian NGL Business divestiture is not consummated on the terms expected or on the anticipated schedule, or at all, and the effect of the announcement or pendency of the Canadian NGL Business divestiture on our business relationships, operating results, employees, stakeholders and business generally;
• general economic, market or business conditions in the United States and elsewhere (including the potential for a recession or significant slowdown in economic activity levels, the risk of persistently high inflation and supply chain issues, the impact of global public health events, such as pandemics, on demand and growth, and the timing, pace and extent of economic recovery) that impact (i) demand for crude oil, drilling and production activities and therefore the demand for the midstream services we provide and (ii) commercial opportunities available to us;
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• declines in global crude oil demand and/or crude oil prices or other factors that correspondingly lead to a significant reduction of North American crude oil and NGL production (whether due to reduced producer cash flow to fund drilling activities or the inability of producers to access capital, or both, the unavailability of pipeline and/or storage capacity, the shutting-in of production by producers, government-mandated pro-ration orders, or other factors), which in turn could result in significant declines in the actual or expected volume of crude oil and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets and/or the reduction of the margins we can earn or the commercial opportunities that might otherwise be available to us;
• fluctuations in refinery capacity and other factors affecting demand for various grades of crude oil and NGL and resulting changes in pricing conditions or transportation throughput requirements;
• unanticipated changes in crude oil and NGL market structure, grade differentials and volatility (or lack thereof);
• the effects of competition and capacity overbuild in areas where we operate, including downward pressure on rates, volumes and margins, contract renewal risk and the risk of loss of business to other midstream operators who are willing or under pressure to aggressively reduce transportation rates in order to capture or preserve customers;
• the availability of, and our ability to consummate, acquisitions, divestitures, joint ventures or other strategic opportunities and realize benefits therefrom, including the Canadian NGL Business divestiture and the EPIC acquisition;
• the successful operation of joint ventures and joint operating arrangements we enter into from time to time, whether relating to assets operated by us or by third parties, and the successful integration and future performance of acquired assets or businesses, including the EPIC acquisition;
• environmental liabilities, litigation or other events that are not covered by an indemnity, insurance or existing reserves;
• negative societal sentiment regarding the hydrocarbon energy industry and the continued development and consumption of hydrocarbons, which could influence consumer preferences and governmental or regulatory actions that adversely impact our business;
• the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event that materially impacts our operations, including cyber or other attacks on our or our service providers’ electronic and computer systems;
• weather interference with business operations or project construction, including the impact of extreme weather events or conditions (including hurricanes, floods, wildfires and drought);
• the impact of current and future laws, rulings, legislation, governmental regulations, executive orders, trade policies, trade tariffs, accounting standards and statements, and related interpretations that (i) prohibit, restrict or regulate the development of oil and gas resources and the related infrastructure on lands dedicated to or served by our pipelines, (ii) negatively impact our ability to develop, operate or repair midstream assets, or (iii) otherwise negatively impact our business or increase our exposure to risk;
• negative impacts on production levels in the Permian Basin or elsewhere due to issues associated with (or laws, rules or regulations relating to) hydraulic fracturing and related activities (including wastewater injection or disposal), including earthquakes, subsidence, expansion or other issues;
• the pace of development of natural gas or other infrastructure and its impact on expected crude oil production growth in the Permian Basin;
• the refusal or inability of our customers or counterparties to perform their obligations under their contracts with us (including commercial contracts, asset sale agreements and other agreements), whether justified or not and whether due to financial constraints (such as reduced creditworthiness, liquidity issues or insolvency), market constraints, legal constraints (including governmental orders or guidance), the exercise of contractual or common law rights that allegedly excuse their performance (such as force majeure or similar claims) or other factors;
• loss of key personnel and inability to attract and retain new talent;
• disruptions to futures markets for crude oil, NGL and other petroleum products, which may impair our ability to execute our commercial or hedging strategies;
• the effectiveness of our risk management activities;
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• shortages or cost increases of supplies, materials or labor;
• maintenance of our credit ratings and ability to receive open credit from our suppliers and trade counterparties;
• our inability to perform our obligations under our contracts, whether due to non-performance by third parties, including our customers or counterparties, market constraints, third-party constraints, supply chain issues, legal constraints (including governmental orders or guidance), or other factors or events;
• the incurrence of costs and expenses related to unexpected or unplanned capital or maintenance expenditures, third-party claims or other factors;
• failure to implement or capitalize, or delays in implementing or capitalizing, on investment capital projects, whether due to permitting delays, permitting withdrawals or other factors;
• tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, investment capital projects, working capital requirements and the repayment or refinancing of indebtedness;
• the amplification of other risks caused by volatile or closed financial markets, capital constraints, liquidity concerns and inflation;
• the use or availability of third-party assets upon which our operations depend and over which we have little or no control;
• the currency exchange rate of the Canadian dollar to the United States dollar;
• the deferral of current revenue recognition attributable to deficiency payments received from customers who fail to ship or move their minimum contracted volumes;
• significant under-utilization of our assets and facilities;
• increased costs, or lack of availability, of insurance;
• fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans;
• risks related to the development and operation of our assets; and
• other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, as well as in the processing, transportation, fractionation, storage and marketing of NGL.
 
Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read “Risk Factors” discussed in Item 1A of our 2024 Annual Report on Form 10-K. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.
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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various market risks, including commodity price risk, interest rate risk and currency exchange rate risk. We use various derivative instruments to manage such risks and, in certain circumstances, to realize incremental margin during volatile market conditions. Our risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our exchange-cleared and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. We have a risk management function that has direct responsibility and authority for our risk policies, related controls around commercial activities and certain aspects of corporate risk management. Our risk management function also approves all new risk management strategies through a formal process. The following discussion addresses each category of risk.
 
Commodity Price Risk
 
We use derivative instruments to hedge price risk associated with the following commodities:
 
• Crude oil
 
We utilize crude oil derivatives to hedge commodity price risk inherent in our pipeline, terminalling and merchant activities. Our objectives for these derivatives include hedging changes in inventory positions associated with our lease gathering activities, anticipated purchases and sales, stored inventory and basis differentials. We manage these exposures with various instruments including futures, forwards, swaps and options.

• Power
 
We utilize power derivatives to hedge anticipated operational requirements related to our crude oil pipelines. We manage these exposures with various instruments including futures, swaps and options.
 
See Note 8 to our Condensed Consolidated Financial Statements for further discussion regarding our hedging strategies and objectives.

The fair value of our commodity derivatives and the change in fair value as of September 30, 2025 that would be expected from a 10% price increase or decrease is shown in the table below (in millions):

Fair Value Effect of 10%
Price Increase Effect of 10%
Price Decrease
Crude oil $ 1  $ 27  $ (27)
Power
(5) $ 2  $ (2)

Total fair value $ (4)    

 
The fair values presented in the table above reflect the sensitivity of the derivative instruments only and do not include the effect of the underlying hedged commodity. Price-risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in near-term commodity prices, the fair value of our derivative portfolio would typically change less than that shown in the table as changes in near-term prices are not typically mirrored in delivery months further out.
 
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Interest Rate Risk
 
Debt . Our use of variable rate debt and any forecasted issuances of fixed rate debt expose us to interest rate risk. Therefore, from time to time, we use interest rate derivatives to hedge interest rate risk associated with anticipated interest payments and, in certain cases, outstanding debt instruments. All of our senior notes are fixed rate notes and thus are not subject to interest rate risk. We did not have any variable rate debt outstanding at September 30, 2025. The average interest rate on variable rate debt that was outstanding during the nine months ended September 30, 2025 was approximately 4.7%, based upon rates in effect during such period. The fair value of our interest rate derivatives was a net asset of $29 million as of September 30, 2025. A 10% increase in the forward SOFR curve as of September 30, 2025 would have resulted in an increase of $13 million to the fair value of our interest rate derivatives. A 10% decrease in the forward SOFR curve as of September 30, 2025 would have resulted in a decrease of $13 million to the fair value of our interest rate derivatives. See Note 8 to our Condensed Consolidated Financial Statements for a discussion of our interest rate risk hedging activities.

Series B Preferred Units . Distributions on the Series B preferred units accumulate and are payable quarterly in arrears on the 15th day of February, May, August and November. Distributions on the Series B preferred units accumulate based on the applicable three-month SOFR, plus certain adjustments. Based upon the Series B preferred units outstanding at September 30, 2025 and the liquidation preference of $1,000 per unit, a change of 100 basis points in interest rates would increase or decrease the annual distributions on the Series B preferred units by approximately $8 million. See Note 11 to our Consolidated Financial Statements included in Part IV of our 2024 Annual Report on Form 10-K for additional information regarding our Series B preferred unit distributions.

Currency Exchange Rate Risk

We use foreign currency derivatives to hedge foreign currency exchange rate risk associated with our exposure to fluctuations in the USD-to-CAD exchange rate. The fair value of our foreign currency derivatives was an asset of $41 million as of September 30, 2025. A 10% increase in the exchange rate (USD-to-CAD) would have resulted in an increase of $325 million to the fair value of our foreign currency derivatives. A 10% decrease in the exchange rate (USD-to-CAD) would have resulted in a decrease of $325 million to the fair value of our foreign currency derivatives. See Note 8 to our Condensed Consolidated Financial Statements for additional information regarding our currency exchange rate risk hedging.

Item 4. CONTROLS AND PROCEDURES
 
Disclosure Controls and Procedures
 
We maintain written disclosure controls and procedures, which we refer to as our “DCP.” Our DCP is designed to ensure that information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 (the “Exchange Act”) is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.
 
Applicable SEC rules require an evaluation of the effectiveness of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our DCP as of September 30, 2025, the end of the period covered by this report, and, based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our DCP is effective.
 
Changes in Internal Control over Financial Reporting

We substantially completed the implementation of our new Enterprise Resource Planning (“ERP”) system during the quarter ended September 30, 2025. The implementation of our ERP system (i) resulted in changes to controls that are reliant upon system configurations, integrations and outputs, and (ii) is expected to, among other things, improve user access security and enable convergence of accounting, back office and reporting processes and activities. Except for the implementation of our new ERP system and corresponding changes to controls reliant upon system configurations, integrations and outputs, there was no change in our internal control over financial reporting that occurred during the third quarter of 2025 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
 
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Certifications
 
The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a) are filed with this report as Exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350 are furnished with this report as Exhibits 32.1 and 32.2.
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PART II. OTHER INFORMATION

Item 1.    LEGAL PROCEEDINGS
 
The information required by this item is included in Note 10 to our Condensed Consolidated Financial Statements, and is incorporated herein by reference thereto.
 

Item 1A. RISK FACTORS
 
For a discussion of our risk factors, see Item 1A. of our 2024 Annual Report on Form 10-K. Those risks and uncertainties are not the only ones facing us and there may be additional matters of which we are unaware or that we currently consider immaterial. All of those risks and uncertainties could adversely affect our business, financial condition and/or results of operations.
 

Item 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
 
Sales of Unregistered Securities

The Omnibus Agreement, entered into as part of the Simplification Transactions, which closed on November 15, 2016, provides for the mechanics by which (i) the total number of PAGP’s outstanding Class A shares will equal the number of AAP units held by PAGP, and (ii) the total number of our common units held by AAP will equal the sum of the number of outstanding Class A units of AAP (“AAP units”) and the number of AAP units that are issuable to the holders of vested and earned Class B units of AAP (“AAP Management Units”). As such, we are obligated to issue common units to AAP in connection with PAGP’s issuance of Class A shares upon PAGP LTIP award vestings. During the three months ended September 30, 2025, we issued 144,500 common units to AAP in connection with PAGP LTIP award vestings. This issuance was exempt from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof.

Issuer Purchases of Equity Securities

None.
    

Item 3.    DEFAULTS UPON SENIOR SECURITIES
 
None.
 

Item 4.    MINE SAFETY DISCLOSURES
 
Not applicable.
 

Item 5.    OTHER INFORMATION
 
During the quarter ended September 30, 2025, none of our directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted or terminated any Rule 10b5-1 trading arrangement or any non-Rule 10b5-1 trading arrangement (as defined in Item 408 of Regulation S-K).
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Item 6.    EXHIBITS
 

Exhibit No. Description

2.1*
— Share Purchase Agreement dated as of June 17, 2025 by and between Plains Midstream Luxembourg S.A.R.L. and Keyera Corp. (portions of this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (incorporated by reference to Exhibit 2.1 to our Quarterly Report on Form 1 0-Q for the quarter ended June 30, 2025) .

2.2 *
— Purchase and Sale Agreement dated August 30, 2025 by and among Altus Midstream Processing LP, Kinetik EC Holdco LLC, Rattler Midstream Operating LLC and Rattler OMOG LLC, as Sellers, and Plains BK Holdco LLC, as Buyer, and the other parties thereto (portions of this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed November 6, 2025).

2.3 *
— Equity Purch ase Agree ment dated November 3 , 2025 by and among EPI C Crude Parent, L.P., as Seller, and Plains BK Holdco LLC, as B uyer, and the other parties there to (portions of this exhibit have been omitted pursuant to Item 601(b) (2) of Registration S -K (incorporated by reference to Exhibit 2.2 to our Current Report on Form 8-K filed November 6, 2025).

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

4.8 — Twenty-Ninth Supplemental Indenture (4.65% Senior Notes due 2025) dated August 24, 2015, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed August 26, 2015).

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

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

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

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

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

4.14 — Thirty-Fifth Supplemental Indenture (4.7 0 % Senior Notes due 2031) dated September 8, 2025, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed September 8, 2025) .

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

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

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

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

4.19 — Description of Our Securities (incorporated by reference to Exhibit 4.17 to our Annual Report on Form 10-K for the year ended December 31, 2024).

10.1 **†
— Fourth Amended and Restated Employment Agreement dated effective May 23, 2024 between Plains All American GP LLC and Greg L. Armstrong.

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10.2 **†
— Employment Agreement dated effective June 1, 2025 between Plains All American GP LLC and Harry N. Pefanis.

10.3 **†
— Form of LTIP Grant Letter dated August 14, 2025 (Named Executive Officers).

10.4 **†
— Form of LTIP Grant Letter dated August 14, 2025 (Directors).

10.5 **†
— Form of Special Retention LTIP Grant Letter dated August 14, 2025 .

10.6 **†
— Amendment dated August 14, 2025 to Special Promotional LTIP Grant Letter dated August 16, 2018 (Willie Chiang).

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

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

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

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

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

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

101.SCH† — Inline XBRL Taxonomy Extension Schema Document

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

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

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

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

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

†      Filed herewith.
††      Furnished herewith.
*     Certain information has been omitted from this exhibit as such omitted information is both (i) not material and (ii) the type of information that the registrant treats as private or confidential.
**    Management compensatory plan or arrangement.

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SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
  PLAINS ALL AMERICAN PIPELINE, L.P.
     
  By: PAA GP LLC,
    its general partner
     
  By: Plains AAP, L.P.,
    its sole member
     
  By: Plains All American GP LLC,
    its general partner
     
  By: /s/ Willie Chiang
    Willie Chiang,
    Chief Executive Officer and President of Plains All American GP LLC

    (Principal Executive Officer)
     
November 7, 2025    
     
  By: /s/ Al Swanson
    Al Swanson,
    Executive Vice President and Chief Financial Officer of Plains All American GP LLC
    (Principal Financial Officer)
     
November 7, 2025    
     
  By: /s/ Chris Herbold
    Chris Herbold,
    Senior Vice President, Finance and Chief Accounting Officer of Plains All American GP LLC
    (Principal Accounting Officer)
   
November 7, 2025  

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