What changed in this filing

/stocks — the workspaceLOADING

Item 9A. Controls and Procedures

2025-02-28 compared with 2024-02-29 · 455 added, 470 removed, 1938 unchanged (32% of the section changed)

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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.

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Applicable SEC rules require an evaluation of the effectiveness of our DCP.

Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our DCP as of December 31, 2024, 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.

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Internal Control over Financial Reporting

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Not applicable.

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Directors and Executive Officers of Our General Partner and Corporate Governance

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Pefanis (1)(2)

President and Director

Executive Vice President and Chief Operating Officer

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Victor Burk (2)

Senior Advisor, Alvarez and Marsal

Former Senior Advisor, Alvarez and Marsal

DeSanctis (2)

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Former Chairman and CEO, Burlington Resources Inc.

Christopher M.

President, DelTex Capital LLC

Former Executive Vice President, Refining, Phillips 66

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

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

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

Executive Compensation

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The information required by this item will be set forth in the Proxy Statement for our 2025 Annual Meeting, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2024, and is incorporated herein by reference thereto.

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Certain Relationships and Related Transactions, and Director Independence

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Exhibits and Financial Statement Schedules

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(incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2013).

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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).

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Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed March 26, 2012).

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— 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.

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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-Sixth Supplemental Indenture (3.60% Senior Notes due 2024) dated September 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp.

Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed September 11, 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.

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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 203 4 ) dated June 27 , 202 4 , by and among Plains All American Pipeline, L.P., PAA Finance Corp.

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 , 202 4 ).

4.13 — Thirty- Fourth Supplemental Indenture ( 5.950 % Senior Notes due 20 35 ) dated J anuary 15 , 202 5 , by and among Plains All American Pipeline, L.P., PAA Finance Corp.

Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed J anuary 15, 2025 ).

4.14 — Registration Rights Agreement dated September 3, 2009 by and between Plains All American Pipeline, L.P.

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and the other Lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed August 26, 2021).

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10.2 — First Amendment to Credit Agreement dated as of August 22, 2022, among Plains All American Pipeline, L.P.

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and the other Lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed August 25, 2022).

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— Second Amendment to Credit Agreement dated as of August 19, 2024, among Plains All American Pipeline, L.P.

and Plains Midstream Canada ULC, as Borrowers;

certain subsidiaries of Plains All American Pipeline, L.P.

from time to time party thereto, as Designated Borrowers;

Bank of America, N.A., as Administrative Agent and Swing Line Lender;

Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A.

and Wells Fargo Bank, National Association, as L/C Issuers;

and the other Lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed August 22, 2024).

— Fourth Amended and Restated Credit Agreement dated as of August 20, 2021, among Plains Marketing, L.P.

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and the other Lenders party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed August 25, 2022).

10.6 — Second Amendment to Fourth Amended and Restated Credit Agreement dated as of August 19, 2024, among Plains Marketing, L.P.

and Plains Midstream Canada ULC, as Borrowers;

Plains All American Pipeline, L.P., as guarantor;

Bank of America, N.A., as Administrative Agent and Swing Line Lender;

Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A.

and Wells Fargo Bank, National Association, as L/C Issuers;

and the other Lenders party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed August 22, 2024).

10.7 — Contribution and Assumption Agreement dated December 28, 2007, by and between Plains AAP, L.P.

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Armstrong (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed October 25, 2013).

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— Second Amended and Restated Employment Agreement dated effective October 1, 2018 between Plains All American GP LLC and Greg L.

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2 dated August 15, 2019 to Harry Pefanis Amended and Restated Employment Agreement (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).

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— Waiver Agreement dated as of December 23, 2010 between Plains All American GP LLC and Harry N.

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

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

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— Form of LTIP Grant Letter dated August 18, 2022 (Named Executive Officers) (incorporated by reference to Exhibit 10.4 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2022).

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

— Form of LTIP Grant Letter dated August 17, 2023 (Directors) (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2023).

— Form of LTIP Grant Letter dated August 15, 2024 (Named Executive Officers) (incorporated by reference to Exhibit 10.

3 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 202 4 ) .

— Form of LTIP Grant Letter dated August 15, 2024 (Directors) (incorporated by reference to Exhibit 10.

4 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2024) .

— P olicy on Insider Trading .

— P oli cy Regarding Special Trading Proc edures .

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

23.1 † — Consent of PricewaterhouseCoopers LLP.

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

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

— Amended and Restated Clawback Policy .

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

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.

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A copy of any omitted schedule will be furnished supplementally to the SEC upon request.

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** Management compensatory plan or arrangement.

Form 10-K Summary

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

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February 27, 2025

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

Name Title Date

/s/ Willie Chiang

Chairman of the Board of PAA GP Holdings LLC and Chief Executive Officer of Plains All American GP LLC (Principal Executive Officer) February 28, 2024

/s/ Willie Chiang Chairman of the Board of PAA GP Holdings LLC and Chief Executive Officer of Plains All American GP LLC (Principal Executive Officer) February 27, 2025

Willie Chiang

Director of PAA GP Holdings LLC and President of Plains All American GP LLC February 27, 2025

/s/ Al Swanson

Executive Vice President and Chief Financial Officer of Plains All American GP LLC (Principal Financial Officer) February 28, 2024

/s/ Chris Herbold

Senior Vice President, Finance and Chief Accounting Officer of Plains All American GP LLC (Principal Accounting Officer) February 28, 2024

/s/ Al Swanson Executive Vice President and Chief Financial Officer of Plains All American GP LLC (Principal Financial Officer) February 27, 2025

/s/ Chris Herbold Senior Vice President, Finance and Chief Accounting Officer of Plains All American GP LLC (Principal Accounting Officer) February 27, 2025

Chris Herbold

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Director of PAA GP Holdings LLC February 27, 2025

/s/ Christopher M.

Director of PAA GP Holdings LLC February 28, 2024

Christopher M.

/s/ Lawrence M.

Director of PAA GP Holdings LLC February 27, 2025

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PLAINS ALL AMERICAN PIPELINE, L.P.

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Segment Information

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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February 27, 2025

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Report of Independent Registered Public Accounting Firm

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and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

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The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Fair Value of the Preferred Distribution Rate Reset Option

As described in Note 12 to the consolidated financial statements, the Preferred Distribution Rate Reset Option of the Partnership’s Series A preferred units was an embedded derivative that was bifurcated from the related host contract and recorded at fair value.

The fair value on the settlement date was $131 million, which resulted in a gain of $58 million recognized in other income.

Management determined the fair value based on a Monte Carlo valuation model that estimated the fair value of the Series A preferred units with and without the Preferred Distribution Rate Reset Option.

This model relied on assumptions for forecasts for the ten-year U.S.

Treasury rate, the Partnership’s common unit price, and default probabilities which impacted timing estimates as to when the option will be exercised.

The principal considerations for our determination that performing procedures relating to the fair value of the Preferred Distribution Rate Reset Option is a critical audit matter are the significant judgment by management when developing the fair value estimate of the Preferred Distribution Rate Reset Option using the Monte Carlo valuation model.

This in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the Monte Carlo valuation model and management’s significant assumption related to forecasts for the ten-year U.S.

Treasury rate.

Also, the audit effort involved the use of professionals with specialized skill and knowledge.

Revenue Recognition – Crude Oil Sales

As described in Note 3 to the consolidated financial statements, revenue from sales of crude oil 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.

The Partnership recognized crude oil sales of $47,036 million for the year ended December 31, 2024.

The principal consideration for our determination that performing procedures relating to revenue recognition for crude oil sales is a critical audit matter is a high degree of auditor effort in performing procedures related to the Partnership’s revenue recognition.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements.

These procedures included testing the effectiveness of controls relating to the fair value of the Preferred Distribution Rate Reset Option, including the appropriateness of the Monte Carlo valuation model, the significant assumption, and data used in developing the fair value estimate.

These procedures also included, among others (i) testing the completeness and accuracy of the contractual information from the Series A preferred unit agreement that is used in the valuation model, (ii) evaluating the reasonableness of, and testing the accuracy of, inputs used to estimate the fair value of the Preferred Distribution Rate Reset Option, and (iii) the involvement of professionals with specialized skill and knowledge to assist in evaluating the reasonableness of management’s estimate by developing (a) an independent Monte Carlo valuation model and (b) an independent range of fair values using independently developed forecasts for the ten-year U.S.

Treasury rate and comparing the independent range of fair values to management’s estimate.

These procedures included testing the effectiveness of controls relating to the revenue recognition process for crude oil sales.

These procedures also included, among others (i) testing revenue recognized for a sample of crude oil sales revenue transactions by obtaining and inspecting source documents, such as contracts, settlement statements, invoices, and payment receipts and (ii) confirming a sample of outstanding customer invoice balances as of December 31, 2024, and for confirmations not returned, obtaining and inspecting source documents, such as contracts, settlement statements, invoices, and subsequent payment receipts.

/s/ PricewaterhouseCoopers LLP

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

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PLAINS ALL AMERICAN PIPELINE, L.P.

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

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PLAINS ALL AMERICAN PIPELINE, L.P.

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Depreciation and amortization 1,026 1,048 965

(Gains)/losses on asset sales and asset impairments, net (Note 6, Note 7) ( 152 ) 269 592

(Gains)/losses on asset sales, asset impairments and other, net (Note 6, Note 7) 160 ( 152 ) 269

Total costs and expenses 48,895 47,202 56,050

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Equity earnings in unconsolidated entities 452 369 403

Gains/(losses) on investments in unconsolidated entities, net (Note 7, Note 8) 28 346 2

Gain on investments in unconsolidated entities, net (Note 7, Note 8) 15 28 346

Interest expense (net of capitalized interest of $ 9 , $ 10 and $ 5 , respectively)

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

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PLAINS ALL AMERICAN PIPELINE, L.P.

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Currency translation adjustments — ( 204 ) — ( 204 )

Other — — 2 2

2022 Activity 101 ( 204 ) 2 ( 101 )

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Currency translation adjustments — ( 284 ) — ( 284 )

Other — — 1 1

2024 Activity 37 ( 284 ) — ( 247 )

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

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PLAINS ALL AMERICAN PIPELINE, L.P.

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Depreciation and amortization 1,026 1,048 965

(Gains)/losses on asset sales and asset impairments, net (Note 6, Note 7) ( 152 ) 269 592

(Gains)/losses on asset sales, asset impairments and other, net (Note 6, Note 7) 160 ( 152 ) 269

Equity-indexed compensation expense 50 50 40

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(Gain)/loss on foreign currency revaluation ( 17 ) 8 41

Settlement of terminated interest rate hedging instruments 80 42 —

Settlement of terminated interest rate hedging instruments (Note 12) 57 80 42

Change in fair value of Preferred Distribution Rate Reset Option (Note 12) — ( 58 ) 189

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Distributions on earnings from unconsolidated entities 505 458 488

(Gains)/losses on investments in unconsolidated entities, net (Note 7, Note 8) ( 28 ) ( 346 ) ( 2 )

Gain on investments in unconsolidated entities, net (Note 7, Note 8) ( 15 ) ( 28 ) ( 346 )

Other 17 20 16

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Cash received from sales of linefill — 9 72

Investments in related party notes (Note 16) ( 629 ) — —

Other investing activities 4 1 44

Net cash provided by/(used in) investing activities ( 702 ) ( 526 ) 386

Net cash used in investing activities ( 1,504 ) ( 702 ) ( 526 )

CASH FLOWS FROM FINANCING ACTIVITIES

Net borrowings/(repayments) under commercial paper program (Note 10) ( 40 ) 433 —

Net repayments under senior secured hedged inventory facility (Note 10) — — ( 167 )

Repayment of GO Zone term loans (Note 10) — — ( 200 )

Proceeds from the issuance of senior notes (Note 10) 650 — —

Repayments of senior notes (Note 10) ( 750 ) ( 1,100 ) ( 750 )

Proceeds from the issuance of related party notes (Note 16) 629 — —

Repurchase of common units (Note 11) — — ( 74 )

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

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PLAINS ALL AMERICAN PIPELINE, L.P.

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Distributions (Note 11) ( 149 ) ( 52 ) ( 584 ) ( 785 ) ( 298 ) ( 1,083 )

Other comprehensive income — — 65 65 — 65

Other comprehensive loss — — ( 101 ) ( 101 ) — ( 101 )

Equity-indexed compensation expense — — 32 32 — 32

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Contributions from noncontrolling interests — — — — 26 26

Plains Oryx Permian Basin LLC joint venture formation (Note 7) — — 605 605 2,651 3,256

Cactus II Pipeline LLC transaction (Note 7)

— — — — 526 526

Other — — ( 24 ) ( 24 ) ( 15 ) ( 39 )

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Distributions (Note 11) ( 173 ) ( 76 ) ( 748 ) ( 997 ) ( 333 ) ( 1,330 )

Other comprehensive loss — — ( 101 ) ( 101 ) — ( 101 )

Other comprehensive income — — 118 118 — 118

Equity-indexed compensation expense — — 36 36 — 36

Repurchase of common units (Note 11) — — ( 74 ) ( 74 ) — ( 74 )

Contributions from noncontrolling interests — — — — 106 106

Plains Oryx Permian Basin LLC joint venture formation (Note 7) — — ( 10 ) ( 10 ) ( 16 ) ( 26 )

Cactus II Pipeline LLC transaction (Note 7) — — — — 526 526

Other 4 — ( 26 ) ( 22 ) ( 3 ) ( 25 )

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Distributions (Note 11) ( 175 ) ( 78 ) ( 891 ) ( 1,144 ) ( 425 ) ( 1,569 )

Other comprehensive income — — 118 118 — 118

Other comprehensive loss — — ( 247 ) ( 247 ) — ( 247 )

Equity-indexed compensation expense — — 36 36 — 36

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

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

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

Our assets and the services we provide are primarily focused on and conducted through two operating segments:

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Additional defined terms are used in the following notes and shall have the meanings indicated below:

Additional defined terms may be used in the following notes and shall have the meanings indicated below:

AOCI = Accumulated other comprehensive income/(loss)

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NYMEX = New York Mercantile Exchange

= Organisation for Economic Co-operation and Development

SEC = United States Securities and Exchange Commission

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We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests.

Subsequent Events

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

Our reporting currency is U.S.

dollars, and all references to dollars are U.S.

dollars, unless stated otherwise.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Subsequent Events

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

Note 2— Summary of Significant Accounting Policies

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However, gains and losses arising from intercompany foreign currency transactions that are of a long-term investment nature are reported in the same manner as translation adjustments.

For the years ended December 31, 2023, 2022 and 2021, the revaluation of foreign currency transactions and monetary assets and liabilities resulted in the recognition of a net loss of $ 8 million, a net loss of $ 41 million and a net gain of $ 7 million, respectively, in our Consolidated Statements of Operations.

For the years ended December 31, 2024, 2023 and 2022, the revaluation of foreign currency transactions and monetary assets and liabilities resulted in the recognition of a net gain of $ 17 million, a net loss of $ 8 million and a net loss of $ 41 million, respectively, in our Consolidated Statements of Operations.

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PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Cash and Cash Equivalents

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As of December 31, 2024 and 2023, trade accounts payable included $ 27 million and $ 26 million, respectively, of outstanding checks that were reclassified from cash and cash equivalents.

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PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Noncontrolling Interests

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See Note 7 and Note 18 for additional information.

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PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Measurements

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See Note 12 for further discussion.

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PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Other Significant Accounting Policies

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

Recent Accounting Pronouncements, Disclosure Rules and Other Legislation

Recent Accounting Pronouncements

In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40):

Disaggregation of Income Statement Expenses , which requires, among other things, disclosure of specified information about certain costs and expenses in the notes to the financial statements.

The guidance is effective prospectively for annual periods beginning after December 15, 2026 and interim periods beginning after December 15, 2027 with retrospective application and early adoption permitted.

We intend to provide the required disclosures beginning with our annual report for the year ended December 31, 2027.

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740):

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The guidance is effective prospectively for annual periods beginning after December 15, 2024 with retrospective or early adoption permitted.

We intend to provide the required disclosures prospectively for annual periods beginning after December 15, 2024.

We intend to provide the required disclosures prospectively beginning with our annual report for the year ended December 31, 2025.

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280):

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The guidance is effective retrospectively for annual periods beginning after December 15, 2023, and interim periods in fiscal years beginning after December 15, 2024 with early adoption permitted.

We intend to provide the required disclosures beginning with our annual report for the year ended December 31, 2024.

We adopted this guidance beginning with our annual report for the year ended December 31, 2024.

See Note 19 for updated segment disclosures.

Other than such disclosure updates, our adoption did not have a material impact on our financial position, results of operations or cash flows.

In August 2023, the FASB issued ASU 2023-05, Business Combinations—Joint Venture Formations (Subtopic 805-60):

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This guidance is effective prospectively for all joint ventures with a formation date on or after January 1, 2025, with early adoption permitted.

We intend to adopt this guidance for joint venture formations on January 1, 2025.

In October 2021, the FASB issued ASU 2021-08, Business Combinations (Topic 805):

Accounting for Contract Assets and Contract Liabilities from Contracts with Customers .

This guidance requires that an acquirer recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with Topic 606, Revenue from Contracts with Customers, as if it had originated the contracts.

The guidance is effective prospectively for interim and annual periods beginning after December 15, 2022, with early adoption permitted.

We adopted this guidance as of January 1, 2023, and our adoption did not have a material impact on our financial position, results of operations or cash flows.

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848):

Facilitation of the Effects of Reference Rate Reform on Financial Reporting , which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform.

This guidance was effective prospectively upon issuance through December 31, 2022.

In December 2022, the FASB issued ASU 2022-06, Reference Rate Reform (Topic 848):

Deferral of the Sunset Date of Topic 848, which defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024.

We will continue to apply applicable expedients and exceptions to contract modifications through December 31, 2024, as applicable.

We will adopt this guidance for joint venture formations on or after January 1, 2025.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

SEC Climate Disclosure Rules

In March 2024, the SEC adopted final rules (“climate disclosure rules”) requiring registrants to disclose, among other things, information about material climate-related risks and their impact on a registrant’s strategy, business model and outlook;

information about material direct and indirect greenhouse gas emissions (Scope 1 and Scope 2), which are subject to assurance requirements;

and the financial statement effects of severe weather events and other natural conditions.

In April 2024, the SEC stayed the climate disclosure rules pending resolution of legal challenges.

We are monitoring the status of the stay and the outcome of the legal challenge for the applicability of the climate disclosure rules.

International Tax Reform

Recently, several countries, including Canada, have enacted legislation to implement key aspects of the global minimum top-up tax in accordance with the Pillar Two model rules of the OECD tax framework.

We continue to evaluate the new legislation, but do not currently expect a material impact on our financial position, results of operations or cash flows.

Note 3— Revenues and Accounts Receivable

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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.

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PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Terminalling, Storage and Other Revenues.

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Fees from NGL fractionation and isomerization services and gas processing services are recognized in the period when the services are performed.

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PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Reconciliation to Total Revenues of Reportable Segments.

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Other revenues

69 ( 148 ) ( 79 )

Total revenues of reportable segments $ 48,720 $ 1,724 $ 50,444

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Other revenues

( 80 ) ( 431 ) ( 511 )

Total revenues of reportable segments $ 55,080 $ 2,761 $ 57,841

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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):

Counterparty Deficiencies Financial Statement Classification 2023 2022

Billed and collected Other current liabilities $ 77 $ 104

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Counterparty Deficiencies Financial Statement Classification 2024 2023

Billed and collected Other current liabilities $ 83 $ 77

Contract Balances .

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Amounts recognized as revenue

Additions (1)

Balance at December 31, 2023 $ 228

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Balance at December 31, 2024 $ 208

(1) Includes approximately $ 122 million associated with a gas processing agreement that was entered into in conjunction with the purchase of an additional ownership interest in certain straddle plants.

Such amount is expected to be recognized as revenue over a 50-year term.

See Note 7 for additional information.

Remaining Performance Obligations .

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(1) Calculated as volumes committed under contracts multiplied by the current applicable tariff rate.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The presentation above does not include (i) expected revenues from legacy shippers not underpinned by minimum volume commitments, including pipelines where there are no or limited alternative pipeline transportation options, (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.

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• Contracts within the scope of ASC Topic 815, Derivatives and Hedging .

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

We have elected practical expedients to exclude the presentation of remaining performance obligations for variable consideration which relates to wholly unsatisfied performance obligations.

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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.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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):

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 4— Net Income Per Common Unit

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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.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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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.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

On January 31, 2025, we repurchased approximately 12.7 million Series A preferred units.

See Note 11 for additional discussion of this transaction.

Note 5— Inventory, Linefill and Long-term Inventory

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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.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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Accordingly, these prices may not coincide with any published benchmarks for such products.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 6— Property and Equipment

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Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are expensed as incurred.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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• 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.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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.

We did not recognize any material impairments during the year ended December 31, 2023.

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 year ended December 31, 2023.

During the third quarter of 2022, we temporarily ceased service on a crude oil pipeline in California as a precautionary measure following a routine inspection and initiated a program of additional tests and inspections.

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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.

We recognized a non-cash loss of approximately $ 330 million, which amount is reflected in “ (Gains)/losses on asset sales and asset impairments, net ” on our Consolidated Statement of Operations.

We recognized a non-cash loss of approximately $ 330 million, which amount is reflected in “ (Gains)/losses on asset sales, asset impairments and other, net ” on our Consolidated Statement of Operations.

Our estimated fair values (which we consider a Level 3 measurement in the fair value hierarchy) were based upon a discounted cash flow approach utilizing various assumptions and the application of a discount rate of approximately 15 %, which represents our estimate of the cost of capital of a theoretical market participant for the asset group.

Such assumptions included (but were not limited to) (i) future commodity volumes (consistent with historical information and estimates of future drilling and completion activity), (ii) tariff rates, (iii) estimated fixed and variable costs, (iv) the length of time the assets operate and (v) the amount for which assets in the asset group could be sold.

During the year ended December 31, 2021, we recognized approximately $ 220 million of non-cash impairment losses related to certain crude oil storage terminal assets included in our Crude Oil segment.

This amount is reflected in “ (Gains)/losses on asset sales and asset impairments, net ” on our Consolidated Statements of Operations.

Decreased demand for our services related to changing market conditions resulted in decreases in expected future cash flows for certain of our assets, which was a triggering event that required us to assess the recoverability of our 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 (which we consider a Level 3 measurement in the fair value hierarchy) was primarily based upon an assumption for the amount for which the relevant assets and land could be sold.

Note 7— Acquisitions, Divestitures and Other Transactions

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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 “Gains/(losses) on investments in unconsolidated entities, net” on our Consolidated Statement of Operations.

This gain has been recognized in the line item “Gain on investments in unconsolidated entities, net” on our Consolidated Statement of Operations.

Index to Financial Statements

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The value assigned to such intangible assets will be amortized to earnings under the declining balance method of amortization.

Amortization expense was approximately $ 4 million during the year ended December 31, 2023, and the future amortization expense through 2028 is estimated as follows (in millions):

Amortization expense was approximately $ 8 million and $ 4 million during the years ended December 31, 2024 and 2023, respectively, and the future amortization expense through 2028 is estimated as follows (in millions):

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.

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Accounting for such impact, the remeasurement of our investment in Cactus II to fair value resulted in a gain of $ 370 million.

This gain has been recognized in the line item “Gains/(losses) on investments in unconsolidated entities, net” on our Consolidated Statement of Operations

This gain has been recognized in the line item “Gain on investments in unconsolidated entities, net” on our Consolidated Statement of Operations.

In accordance with applicable accounting guidance, the fair value of Cactus II following the acquisition is utilized as the consideration transferred for the purchase price allocation.

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The value assigned to such intangible assets will be amortized to earnings under the declining balance method of amortization.

Amortization expense was approximately $ 61 million and $ 13 million during the years ended December 31, 2023 and 2022, respectively, and the future amortization expense through 2027 is estimated as follows (in millions):

Amortization expense was approximately $ 51 million, $ 61 million and $ 13 million during the years ended December 31, 2024, 2023 and 2022, respectively, and the future amortization expense through 2027 is estimated as follows (in millions):

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

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Other Acquisitions

In January 2025, we acquired Ironwood Midstream Energy Partners II, LLC, which owns a gathering system in the Eagle Ford Basin, for approximately $ 475 million from EnCap Flatrock Midstream.

In January 2025, in a separate transaction, we also repurchased from EnCap Flatrock Midstream, approximately 18 % of our outstanding Series A preferred units, which equated to less than 2 % of our outstanding common units and Series A preferred units combined (our “common unit equivalents”).

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 11 for additional information.

In January 2025, we acquired EMG Medallion 2 Holdings, LLC and its subsidiaries, which own a crude oil gathering and transportation business in the Delaware Basin, for $ 161 million (approximately $ 105 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.

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 8 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.

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.

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As a result of this transaction, we now own 100 % of Advantage and its subsidiaries and such entities are reflected as consolidated subsidiaries in our Consolidated Financial Statements.

• the acquisition in October 2022 of an additional ownership interest in certain straddle plants included in our NGL segment in a non-cash transaction whereby we agreed to provide processing capacity over a 50-year term at specified terms and conditions.

This transaction was accounted for as an asset acquisition.

The fair value of the straddle plant assets acquired and liabilities assumed was approximately $ 122 million, and we recognized an equally offsetting contract liability that will be amortized on a straight-line basis into “Services revenue” over the 50-year term of the agreement.

Asset Exchange

In June 2021, we closed on an asset exchange agreement (the “Asset Exchange”) with Inter Pipeline Ltd., through which we acquired additional interests in two straddle plants included in our NGL segment that we currently operate, in exchange for a pipeline and related storage and truck offload facilities previously included in our Crude Oil segment and cash consideration of $ 32 million, including working capital and other adjustments.

We recognized a gain of $ 106 million on the divestiture of the pipeline and related storage and truck offload facilities, which is included in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statement of Operations, based on the difference between the fair value of the divested assets and their carrying value.

Joint Venture Transaction

In October 2021, we and Oryx Midstream completed the merger, in a cashless, debt-free transaction, of our respective Permian Basin assets, operations and commercial activities into a newly formed joint venture, the Permian JV.

The Permian JV includes all of Oryx Midstream’s Permian Basin assets and, with the exception of our long-haul pipeline systems and certain of our intra-basin terminal assets, the vast majority of our assets located within the Permian Basin.

We own 65 % of the Permian JV, operate the combined assets and reflect the Permian JV as a consolidated subsidiary in our consolidated financial statements.

The formation of the joint venture was accounted for as a business combination using the acquisition method of accounting.

As the majority owner and the controlling entity, we are considered the acquirer and the transfer of our predecessor business to the joint venture was accounted for at historical cost, while the Oryx Midstream predecessor business was recorded based on the fair value of the assets acquired and liabilities assumed.

In accordance with applicable accounting guidance, the fair value of Oryx Midstream’s ownership interest in the joint venture following the formation of $ 3.230 billion is utilized as the consideration transferred for the purchase price allocation.

The combination of the historical cost and fair value, discussed above, resulted in net assets of the joint venture of approximately $ 7.529 billion upon formation.

Oryx Midstream’s 35 % interest in the net assets of the Permian JV was recognized as noncontrolling interest in partners’ capital.

The difference between the noncontrolling interest recognized and the fair value of Oryx Midstream’s assets acquired and liabilities assumed was recorded as an increase to our partners’ capital excluding noncontrolling interests.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the amounts recognized in partners’ capital associated with this transaction (in millions):

Recognized Amount

Noncontrolling interests $ 2,635

Partners’ capital, excluding noncontrolling interests 595

The fair value of the $ 3.230 billion consideration is a Level 3 measurement in the fair value hierarchy and was determined by valuing both the enterprise value of Oryx Midstream’s Permian Basin business and the enterprise value of our Permian Basin assets that were contributed to the joint venture.

The enterprise value of Oryx Midstream’s Permian Basin business was calculated by weighting the results of (i) a discounted cash flow approach and (ii) a guideline public company method (“GPCM”).

The value of our Permian Basin assets that were contributed to the joint venture was based on a GPCM.

The discounted cash flow approach utilized a discount rate of 12 %, based on our estimate of the risk that a theoretical market participant would assign to the business.

The projection of future crude volumes gathered and transported was also a key assumption in the discounted cash flow approach and was based on projected rig activity on the associated acreage.

The GPCM applies market multiples to estimated earnings to derive the fair value.

The GPCM values for Oryx Midstream’s Permian Basin business and for our Permian Basin assets that were contributed to the joint venture assumed market multiples ranging from 9.5 to 11.0 , which were derived from assumptions of market multiples for similar businesses.

The determination of the fair value of the assets acquired and liabilities assumed was estimated in accordance with the applicable accounting guidance.

The analysis was performed based on estimates that are reflective of market participant assumptions.

The following table reflects our determination of the fair value of those assets and liabilities (in millions):

Identifiable Assets Acquired and Liabilities Assumed Estimated Useful Lives

(in years) Recognized Amount

Property and equipment 3 - 30

Intangible assets 20 1,247

Investment in unconsolidated entities N/A 103

Working capital and other assets and liabilities N/A ( 6 )

The fair value of the tangible assets is a Level 3 measurement in the fair value hierarchy and was determined using a 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 a discount rate of 16 %, 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 gathered and transported was also a key assumption in the valuation of the intangible assets and was based on projected rig activity on the associated acreage.

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 20 years.

The value assigned to such intangible assets will be amortized to earnings under the declining balance method of amortization.

Amortization expense was approximately $ 138 million, $ 142 million and $ 28 million during the years ended December 31, 2023, 2022 and 2021, respectively, and the future amortization expense through 2026 is estimated as follows (in millions):

During the year ended December 31, 2021, we incurred approximately $ 17 million of transaction-related costs associated with the joint venture formation transaction.

Such costs are reflected as a component of “General and administrative expenses” on our Consolidated Statements of Operations.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Distributions of available cash from the Permian JV to us and Oryx Midstream are subject to a tiered modified sharing arrangement (“MSA”) for up to ten years .

Pursuant to the terms of the governing documents for the Permian JV, the MSA will terminate in October 2031, or sooner if Oryx Midstream exercises its right to terminate the MSA at any time by delivery of written notice to us.

Upon termination of the MSA, monthly distributions of available cash will be paid 65 % to PAA and 35 % to Oryx.

Through the third quarter of 2022, the Permian JV made quarterly distributions, but starting in December 2022, the Permian JV began making monthly distributions to the members after renegotiation of the MSA.

Under the MSA, distributions will be allocated as follows (in millions):

Available Cash Distributions Percentages

Tier Annualized PAA Oryx

1 Up to $300 50 % 50 %

2 $300 - $428 100 % —%

3 $428 - $815 65 % 35 %

4 $815 and above 70 % 30 %

Oryx Midstream is a portfolio company of Stonepeak Infrastructure Partners (“Stonepeak”).

Affiliates of Stonepeak own approximately 8.9 % of our outstanding Series A preferred units, which equates to less than 1 % of our outstanding common units and Series A preferred units (our “common unit equivalents”) combined.

Pro Forma and Other Financial Results

Financial results of the Permian JV have been included in the results of operations within the Crude Oil segment since the date of the formation.

Disclosure of the revenues and earnings from the Oryx Midstream predecessor business for the period subsequent to the joint venture formation is not practicable as it is not being operated as a standalone subsidiary.

The following selected unaudited pro forma results of operations were derived from the historical financial statements of PAA and Oryx Midstream, and gives effect to the joint venture formation as if it had occurred on January 1, 2021.

The pro forma results of operations do not include any cost savings or other synergies that may result from the Permian JV or any estimated costs that have been or will be incurred by us to integrate Oryx Midstream’s assets.

These results are not necessarily indicative of the results that might have actually occurred had the merger taken place on January 1, 2021;

furthermore, this financial information is not intended to be a projection of future results (in millions, except per unit amounts):

December 31, 2021

Total revenues $ 42,359

Net income attributable to PAA

Net income allocated to common unitholders

Basic and diluted net income per common unit

This transaction was accounted for as an asset acquisition.

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”).

Upon the sale of this facility, we recognized a gain of approximately $ 140 million which is included in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statement of Operations.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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.

During the year ended December 31, 2022, we sold certain non-core assets for total proceeds of $ 60 million.

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We recognized gains of $ 61 million related to these asset sales, a portion of which relates to the transfer of an asset retirement obligation to the purchaser.

Such amounts are included in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statement of Operations.

In August 2021, we sold our Pine Prairie and Southern Pines natural gas storage facilities, which were included in our Crude Oil segment for periods prior to the sale, for net proceeds of approximately $ 850 million, including working capital adjustments.

Prior to the sale, we classified the assets related to this transaction (primarily “Property and equipment”), valued at the lower of the carrying amount or fair value less costs to sell, of approximately $ 832 million as assets held for sale with approximately $ 18 million of deferred losses on hedges remaining in other comprehensive income until the closing of the sale.

Upon classification of the assets to held for sale in the second quarter of 2021, we recognized a non-cash impairment loss of $ 475 million which is included in “(Gains)/losses on asset sales and asset impairments, net” on our Consolidated Statement of Operations.

Such amounts are included in “(Gains)/losses on asset sales, asset impairments and other, net” on our Consolidated Statement of Operations.

Note 8— Investments in Unconsolidated Entities

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Crude Oil Terminal and Dock 50 % 113 116

OMOG JV LLC (“OMOG”) (2)

Saddlehorn Pipeline Company, LLC (“Saddlehorn”)

Crude Oil Pipeline 40 % 275 192

Saddlehorn Pipeline Company, LLC

White Cliffs Pipeline, L.L.C.

Crude Oil Pipeline 36 % 123 138

White Cliffs Pipeline, LLC Crude Oil Pipeline 36 % 138 150

Wink to Webster Pipeline LLC (“W2W Pipeline”) (3)

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(1) The financial results from these entities are reported in our Crude Oil segment.

(2) 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 Note 7 for additional information.

(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.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(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.

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 7 for additional information regarding these transactions.

During the fourth quarter of 2022, through a non-monetary transaction, we acquired an additional interest in OMOG in exchange for the contribution of portions of two pipeline systems.

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Subsequent to this transaction, we continued to account for OMOG as an equity method investment because the joint venture partner still retained substantive participating rights.

The transaction resulted in a loss of approximately $ 25 million, which represents the difference between the fair value and historical book value of the assets contributed.

This loss is reflected in “Gains/(losses) on investments in unconsolidated entities, net” on our Consolidated Statement of Operations.

The transaction resulted in a loss of approximately $ 25 million, which represented the difference between the fair value and historical book value of the assets contributed.

This loss was reflected in “Gain on investments in unconsolidated entities, net” on our Consolidated Statement of Operations.

In the third quarter of 2023, we acquired the remaining 43 % interest in OMOG.

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The portion of the basis differences attributable to goodwill is not amortized.

The majority of the basis difference at both December 31, 2023 and 2022 was attributable to goodwill related to our ownership interest in BridgeTex and Capline with the remaining basis difference primarily related to capitalized interest incurred during construction of the assets of our unconsolidated entities.

The majority of the basis difference at both December 31, 2024 and 2023 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.

Index to Financial Statements

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SHORT-TERM DEBT

Commercial paper notes, bearing a weighted-average interest rate of 5.8 % (1)

Senior notes:

2.85 % senior notes due January 2023

3.85 % senior notes due October 2023

Commercial paper notes, bearing a weighted-average interest rate of 4.6 % and 5.8 %, respectively (1)

Total short-term debt 408 446

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3.80 % senior notes due September 2030

5.70 % senior notes due September 2034

6.70 % senior notes due May 2036

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$ 7,621 $ 7,751

(1) We classified these commercial paper notes as short-term as of December 31, 2023, 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, 2023, we classified our 3.60 %, $ 750 million senior notes due November 2024 as long-term based on our ability and intent to refinance these notes on a long-term basis.

(1) We classified these commercial paper notes as short-term as of December 31, 2024 and 2023, 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, 2023, we classified our $ 750 million, 3.60 % senior notes due November 2024 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 November 1, 2024.

(3) As of December 31, 2024, we classified our $ 1 billion, 4.65 % senior notes due October 2025 as long-term based on our ability and intent to refinance these notes on a long-term basis.

(4) Our fixed-rate senior notes had a face value of approximately $ 7.2 billion and $ 7.3 billion at December 31, 2024 and 2023, respectively.

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The amended credit agreement also provides for one or more one-year extensions, subject to applicable approval and other terms and conditions.

In August 2023, we extended the maturity date of the facility to August 2026 for each existing lender.

In August 2024, we amended the facility agreement to, among other things, extend the maturity date of the facility to August 2027 for each extending lender.

The maturity date with respect to the non-extending lender (which represents a commitment of approximately $ 64 million out of total commitments of $ 1.35 billion from all lenders) remains August 2026.

Senior unsecured revolving credit facility.

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The credit agreement provides for one or more one-year extensions, subject to applicable approval and other terms and conditions.

In August 2023, we extended the maturity date of the facility to August 2028 for each extending lender.

In August 2024, we amended the facility agreement to, among other things, extend the maturity date of the facility to August 2029 for each extending lender.

GO Zone term loans .

In August 2021, in connection with the sale of the Southern Pines natural gas storage facility, we repaid $ 200 million of term loans (the “Go Zone term loans”) that were initially assumed in connection with our acquisition of that facility.

See Note 7 for additional information.

Our senior notes are co-issued, jointly and severally, by Plains All American Pipeline, L.P.

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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, 2024 (in millions):

Year Description Maturity Face Value Interest Payment Dates

2024 5.70 % Senior Notes issued at 99.953 % of face value

September 2034

$ 650 March 15 and September 15

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

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Senior Notes Repayments.

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Year Description Repayment Date

2024 $ 750 million 3.60 % Senior Notes due November 2024

November 2024

2023 $ 700 million 3.85 % Senior Notes due October 2023

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March 2022 (2)

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

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The weighted average maturity of our senior notes outstanding at December 31, 2024 was approximately 10 years.

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• enter into certain burdensome agreements.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The credit agreements for our senior unsecured revolving credit facility and senior secured hedged inventory facility 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)).

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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.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Letters of Credit

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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.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The initial Series A preferred unit distribution was equal to $ 0.525 per unit ($ 2.10 per unit annualized).

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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.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

On January 31, 2025, we repurchased approximately 12.7 million units, or 18 %, of our outstanding Series A preferred units 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.

Series B Preferred Units

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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.

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).

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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.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

9 unchanged sentences

71,090,468 800,000 698,354,498

Repurchase and cancellation of common units under the Common Equity Repurchase Program — — ( 7,251,361 )

Issuances of common units under equity-indexed compensation plans

— — 2,654,251

Outstanding at December 31, 2023

4 unchanged sentences

71,090,468 800,000 703,770,300

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Common Equity Repurchase Program.

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See Note 16 for additional information regarding our ownership of PAGP Class C shares.

There were no repurchases under the Program during the year ended December 31, 2023.

During the years ended December 31, 2022 and 2021, we repurchased common units under the Program through open market purchases for a total purchase price of $ 74 million and $ 178 million, respectively, including commissions and fees.

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

During the year ended December 31, 2022, we repurchased common units under the Program through open market purchases for a total purchase price of $ 74 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.

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Preferred Unit Distributions

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2022 $ 149 $ 2.10

On February 14, 2024, we paid a cash distribution of $ 44 million to our Series A preferred unitholders.

On February 14, 2025, we paid a cash distribution of $ 36 million to our Series A preferred unitholders outstanding as of January 31, 2025.

At December 31, 2024, such amount was accrued as distributions payable in “Other current liabilities” on our Consolidated Balance Sheet.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Series B Preferred Unit Distributions.

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As of December 31, 2024, 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”).

The transactions resulting in the recognition of noncontrolling interests in the Permian JV and Cactus II are described below.

In November 2022, we acquired an additional 5 % interest in Cactus II which, combined with changes in governance, resulted in our obtaining control of the entity.

We own 70 % of Cactus II and reflect the entity as a consolidated subsidiary in our Consolidated Financial Statements, with Enbridge’s 30 % interest accounted for as a noncontrolling interest.

This transaction resulted in the recognition of partners’ capital attributable to noncontrolling interests of approximately $ 526 million.

See Note 7 for more details regarding this transaction.

In October 2021, we formed a joint venture, the Permian JV, with Oryx Midstream.

We own 65 % of the Permian JV and consolidate based on control, with Oryx Midstream’s 35 % interest accounted for as a noncontrolling interest.

This transaction resulted in the recognition of partners’ capital attributable to noncontrolling interests of approximately $ 2.6 billion and an increase to our partners’ capital excluding noncontrolling interests of approximately $ 595 million.

See Note 7 for more details regarding this transaction.

The transaction resulting in the recognition of noncontrolling interests in Cactus II is described below.

Index to Financial Statements

2 unchanged sentences

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

In November 2022, we acquired an additional 5 % interest in Cactus II which, combined with changes in governance, resulted in our obtaining control of the entity.

We own 70 % of Cactus II and reflect the entity as a consolidated subsidiary in our Consolidated Financial Statements, with Enbridge’s 30 % interest accounted for as a noncontrolling interest.

This transaction resulted in the recognition of partners’ capital attributable to noncontrolling interests of approximately $ 526 million.

See Note 7 for more details regarding this transaction.

Distributions to Noncontrolling Interests

Pursuant to the terms of the governing documents for the Permian JV, with the exception of the initial distribution paid in the first quarter of 2022, distributions of available cash from the Permian JV are subject to a tiered modified sharing arrangement.

See Note 7 for additional information.

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.

Distributions from Cactus II and Red River are paid in proportion to each owners interest in the entity.

The following table details distributions paid to noncontrolling interests during the years presented (in millions):

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• A net long position of 7.4 million barrels associated with our crude oil purchases, which was unwound ratably during January 2025 to match monthly average pricing.

• A net short time spread position of 5.6 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through January 2025.

• A net short time spread position of 4.8 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through November 2025.

• A net crude oil basis spread position of 1.8 million barrels at multiple locations through December 2025.

These derivatives allow us to lock in grade and location basis differentials.

• A net short position of 18.2 million barrels through March 2025 related to anticipated net sales of crude oil and NGL inventory.

• A net short position of 16.7 million barrels through December 2028 related to anticipated net sales of crude oil and NGL inventory.

We purchase natural gas for processing and operational needs.

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Natural gas purchases 49.3 Bcf

December 2025

Propane sales ( 8.8 ) MMbls

December 2025

Butane sales ( 1.3 ) MMbls

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We have determined that substantially all of our physical commodity contracts qualify for the normal purchases and normal sales scope exception.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Our commodity derivatives are not designated in a hedging relationship for accounting purposes;

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Net gain/(loss) from commodity derivative activity $ ( 255 ) $ ( 32 ) $ 238

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists.

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Initial margin $ 53 $ 77

Variation margin returned

( 65 ) ( 236 )

Variation margin posted/(returned)

Letters of credit ( 30 ) ( 25 )

Net broker payable

Net broker receivable/(payable)

$ 72 $ ( 13 )

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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.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the terms of our outstanding interest rate derivatives as of December 31, 2024 (notional amounts in millions):

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$ 200 6/15/2026 3.09 % Cash flow hedge

Anticipated interest payments 4 forward starting swaps

$ 100 6/14/2024 0.74 % Cash flow hedge

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

During the year ended December 31, 2023, we terminated $ 200 million of notional interest hedging instruments previously expected to terminate in June 2023 for proceeds of $ 80 million, of which $ 73 million was recorded in AOCI.

During the year ended December 31, 2024, we terminated $ 100 million of notional interest hedging instruments previously expected to terminate in June 2024 for proceeds of $ 57 million, which was recorded in AOCI.

As of December 31, 2024, there was a net loss of $ 44 million deferred in AOCI.

8 unchanged sentences

Interest rate derivatives, net $ 29 $ 15 $ 94

At December 31, 2023, the net fair value of our interest rate hedges, which were included in “Other current assets” and “Other long-term assets, net” on our Consolidated Balance Sheet, totaled $ 51 million and $ 4 million, respectively.

At December 31, 2024, the net fair value of our interest rate hedges, which was included in “Other long-term assets, net” on our Consolidated Balance Sheet, totaled $ 27 million.

At December 31, 2023, the net fair value of these hedges totaled $ 51 million and $ 4 million, which were included in “Other current assets” and “Other long-term assets, net”, respectively.

8 unchanged sentences

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/(expense), net” in our Consolidated Statements of Operations.

For the years ended December 31, 2023, 2022 and 2021, we recognized a gain of $ 58 million, a net loss of $ 189 million, and a net gain of $ 14 million, respectively.

For the years ended December 31, 2023 and 2022, we recognized a gain of $ 58 million and a net loss of $ 189 million, respectively.

See Note 11 for additional information regarding the Preferred Distribution Rate Reset Option.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Recurring Fair Value Measurements

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Recurring Fair Value Measures (1)

Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total

Level 1 Level 2 Total Level 1 Level 2 Total

Commodity derivatives $ 14 $ ( 90 ) $ ( 76 ) $ 9 $ ( 9 ) $ —

Interest rate derivatives — 27 27 — 55 55

Preferred Distribution Rate Reset Option — — — — — — ( 189 ) ( 189 )

Total net derivative asset/(liability) $ 14 $ ( 63 ) $ ( 49 ) $ 9 $ 46 $ 55

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives and over-the-counter commodity contracts such as futures and swaps.

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Treasury rate, our common unit price, and default probabilities which impacted timing estimates as to when the option would be exercised.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Rollforward of Level 3 Net Asset/(Liability)

The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 (in millions):

Year Ended December 31,

The following table provides a reconciliation of changes in fair value of the beginning and ending balances for the Preferred Distribution Rate Reset Option embedded derivative, which was classified as Level 3 in the fair value hierarchy (in millions):

Beginning Balance $ ( 189 )

Net gains/(losses) for the period included in earnings 58 ( 189 )

Gain for the period included in earnings

Settlements 131

1 unchanged sentence

Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period

$ — $ ( 189 )

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 13— Leases

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We lease certain property and equipment under noncancelable and cancelable operating and finance leases.

Our operating leases primarily relate to railcars, office space, land, vehicles, and storage tanks, and our finance leases primarily relate to tractor trailers, land, storage tanks and vehicles.

Our operating leases primarily relate to railcars, office space, land, vehicles, and storage tanks, and our finance leases primarily relate to tractor trailers, storage tanks, land and vehicles.

One of our finance leases is for storage tanks owned by an equity method investee, in which we own a 50 % interest.

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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.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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Finance leases

$ 25 $ 27 $ 2

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

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State income tax $ 2 $ 2 $ 1

Canadian federal and provincial income tax 143 83 48

Canadian federal and provincial income and withholding taxes

Total current income tax expense $ 195 $ 145 $ 84

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$ 106 $ 117 $ 175

Canadian withholding tax $ 52 $ — $ —

Canadian permanent differences

$ 2 $ 13 $ ( 13 )

State income tax 2 2 1

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Deferred tax assets:

Derivative instruments $ 19 $ —

Lease liabilities 46 40

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ExxonMobil Corporation and its subsidiaries accounted for 30 %, 26 % and 20 % of our revenues for the years ended December 31, 2024, 2023 and 2022, respectively.

and its subsidiaries accounted for 10 % of our revenues for the years ended December 31, 2023 and 2021.

Marathon Petroleum Corporation and its subsidiaries accounted for 12 % of our revenues for the year ended December 31, 2021.

and its subsidiaries accounted for 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, 2024.

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Omnibus Agreement

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

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.

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Promissory Notes with our General Partner

In March 2023, PAGP issued an unsecured promissory note to us with a face value of CAD$ 500 million (“related party note receivable”).

Concurrently, we assigned PAGP our interest in an existing unsecured promissory note for the same face value amount due from a consolidated subsidiary (“related party note payable”).

We and certain Plains entities have issued promissory notes to facilitate financing.

In March 2023, we assigned PAGP our interest in an existing unsecured promissory note due from a consolidated subsidiary (“March 2023 note payable”) with a face value of CAD$ 500 million (approximately $ 370 million).

Concurrently, PAGP issued an unsecured promissory note to us (“March 2023 note receivable”) for the same face value amount.

Both notes are due April 2027 and bear interest at a rate of 8.25 % per annum, payable semi-annually.

Accrued and unpaid interest receivable/payable was $ 10 million as of December 31, 2023.

Interest income/expense on the related party notes totaled $ 25 million for the year ended December 31, 2023.

Index to Financial Statements

2 unchanged sentences

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2023, our outstanding related party note receivable and related party note payable balances were as follows (in millions):

Related party note receivable (1)

Related party note payable (1)

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

In July 2024, a consolidated subsidiary issued additional unsecured promissory notes to PAGP (collectively with the March 2023 note payable, the “related party notes payable”) with a face value of CAD$ 865 million (approximately $ 629 million).

Concurrently, PAGP issued unsecured promissory notes to us (collectively with the March 2023 note receivable, the “related party notes receivable”) for the same face value amount.

These notes are due September 2034 and bear interest at a rate of 6.50 % per annum, payable semi-annually.

In connection with the July 2024 issuance of related party notes, we received cash from PAGP of $ 629 million, which is reflected in “Proceeds from the issuance of related party notes” (a component of cash flows from financing activities), and we paid an equal and offsetting amount of cash to PAGP, which is reflected in “Investments in related party notes” (a component of cash flows from investing activities) on our Consolidated Statement of Cash Flows.

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.

Accrued and unpaid interest receivable/payable was $ 27 million and $ 10 million as of December 31, 2024 and 2023, respectively.

Interest income/expense on the related party notes totaled $ 48 million and $ 25 million for the years ended December 31, 2024 and 2023, respectively.

As of December 31, 2024 and 2023, our outstanding related party notes receivable and related party notes payable balances were as follows (in millions):

2024 December 31,

Related party notes receivable (1)

Related party notes payable (1)

(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.

In February 2025, a consolidated subsidiary issued an additional unsecured promissory note to PAGP with a face value of CAD$ 473 million (approximately $ 330 million).

Concurrently, PAGP issued an unsecured promissory note to us for the same face value amount.

These notes are due June 2035 and bear interest at a rate of 5.75 % per annum, payable semi-annually.

The interest rate for such notes was determined in accordance with the arm’s-length principle set forth in the OECD Guidelines and the transfer pricing provisions of Section 247 of Canada’s Income Tax Act.

Transactions with Other Related Parties

Our other related parties include (i) entities in which we hold investments and account for under the equity method of accounting (see Note 8 for information regarding such entities) and (ii) principal owners and their affiliated entities.

We recognize as our principal owners entities that have a designated representative on the board of directors of PAGP GP and/or own greater than 10 % of the limited partner interests in AAP.

Such limited partner interests in AAP translate into a significantly smaller indirect ownership interest in PAA.

We also consider subsidiaries or funds identified as affiliated with principal owners to be related parties.

As of December 31, 2023, no entities met the criteria to be recognized as a principal owner.

In August 2021, the board of directors of PAGP GP approved and adopted an amendment to PAGP GP’s limited liability company agreement (the “Amendment”) which eliminated all previously negotiated “director designation” rights and requires that all directors be subject to public election, including Kayne Anderson Capital Advisors, L.P.’s (“Kayne Anderson”) legacy contractual right to designate an individual to serve on the PAGP GP board without being subject to public election.

The Amendment also eliminated all previously negotiated rights, including Kayne Anderson’s right, to appoint a PAGP GP board observer under certain circumstances.

As a result of these changes, we no longer recognize Kayne Anderson and its affiliates as related parties.

Our other related parties include entities in which we hold investments and account for under the equity method of accounting (see Note 8 for information regarding such entities).

During the three years ended December 31, 2024, we recognized sales and transportation revenues, purchased petroleum products and utilized transportation and storage services from our related parties.

7 unchanged sentences

$ 400 $ 404 $ 365

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

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

Trade accounts payable to related parties (1) (2)

(1) Includes amounts related to transportation and storage services and amounts owed to us or advanced to us related to investment capital projects of equity method investees where we serve as construction manager.

Index to Financial Statements

2 unchanged sentences

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

Trade accounts payable to related parties (1) (2)

(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.

22 unchanged sentences

The remaining balance has already vested or is currently outstanding.

As of December 31, 2023, 12.2 million LTIP awards were outstanding.

Of the awards outstanding, 9.6 million include associated DERs.

At December 31, 2023, certain of the outstanding LTIP awards were considered probable of vesting and such awards are expected to vest at various dates between May 2024 and August 2028.

As of December 31, 2023, the outstanding awards that are considered probable of vesting have a remaining unrecognized fair value of approximately $ 73 million.

Index to Financial Statements

2 unchanged sentences

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2024, 10.5 million LTIP awards were outstanding.

Of the awards outstanding, 8.6 million include associated DERs.

At December 31, 2024, certain of the outstanding LTIP awards were considered probable of vesting and such awards are expected to vest at various dates between August 2025 and August 2028.

As of December 31, 2024, the outstanding awards that are considered probable of vesting have a remaining unrecognized fair value of approximately $ 65 million.

Note 18— Commitments and Contingencies

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A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities.

Other commitments for 2025 also include amounts associated with an agreement to purchase a crude oil gathering business in the Delaware Basin for $ 161 million (approximately $ 105 million net to our 65 % interest in the Permian JV), net of a cash deposit of approximately $ 16 million paid in December 2024.

See Note 7 for additional information.

Loss Contingencies — General

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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.

Index to Financial Statements

2 unchanged sentences

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Environmental — General

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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.

At December 31, 2023, our estimated undiscounted reserve for environmental liabilities (excluding liabilities related to the Line 901 incident, as discussed further below) totaled $ 56 million, of which $ 10 million was classified as short-term and $ 46 million was classified as long-term.

At December 31, 2022, our estimated undiscounted reserve for environmental liabilities (excluding liabilities related to the Line 901 incident) totaled $ 55 million, of which $ 10 million was classified as short-term and $ 45 million was classified as long-term.

Such short-term liabilities are reflected in “ Other current liabilities ” and long-term liabilities are reflected in “ Other long-term liabilities and deferred credits ” on our Consolidated Balance Sheets.

At both December 31, 2023 and 2022, we had recorded receivables (excluding receivables related to the Line 901 incident) totaling $ 4 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, approximately $ 1 million of which for each period is reflected in “Other long-term assets, net” and the remainder is reflected in “Trade accounts receivable and other receivables, net” on our Consolidated Balance Sheets.

In some cases, the actual cash expenditures associated with these liabilities may not occur for three years or longer.

Our estimated undiscounted reserve 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):

2024 December 31,

Other current liabilities $ 15 $ 10

Other long-term liabilities and deferred credits (1)

Total $ 96 $ 56

(1) The 2024 balance reflects an increase in estimated costs for long-term environmental remediation obligations.

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.

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A Unified Command, which included the United States Coast Guard, the EPA, the State of California Department of Fish and Wildlife (“CDFW”), the California Office of Spill Prevention and Response and the Santa Barbara Office of Emergency Management, was established for the response effort.

Clean-up and remediation operations with respect to impacted shoreline and other areas has been determined by the Unified Command to be complete, and the Unified Command has been dissolved.

Clean-up and remediation operations with respect to impacted shoreline and other areas were determined by the Unified Command to be complete in 2016, and the Unified Command was dissolved.

Our estimate of the amount of oil spilled, based on relevant facts, data and information, and as set forth in the Consent Decree described below, is approximately 2,934 barrels;

of this amount, we estimate that 598 barrels reached the Pacific Ocean.

As a result of the Line 901 incident, several governmental agencies and regulators initiated investigations into the Line 901 incident, various claims have been made against us and a number of lawsuits have been filed against us, the majority of which have been resolved.

Set forth below is a brief summary of actions and matters that are currently pending or recently resolved.

As the “responsible party” for the Line 901 incident we are liable for various costs and for certain natural resource damages under the Oil Pollution Act.

In this regard, following the Line 901 incident, we entered into a cooperative Natural Resource Damage Assessment (“NRDA”) process with the federal and state agencies designated or authorized by law to act as trustees for the natural resources of the United States and the State of California (collectively, the “Trustees”).

Additionally, various government agencies sought to collect civil fines and penalties under applicable state and federal regulations.

On March 13, 2020, the United States and the People of the State of California filed a civil complaint against Plains All American Pipeline, L.P.

and Plains Pipeline L.P.

along with a pre-negotiated settlement agreement in the form of a Consent Decree (the “Consent Decree”) that was signed by the United States Department of Justice, Environmental and Natural Resources Division, the United States Department of Transportation, Pipeline and Hazardous Materials Safety Administration, the EPA, CDFW, the California Department of Parks and Recreation, the California State Lands Commission, the California Department of Forestry and Fire Protection’s Office of the State Fire Marshal, Central Coast Regional Water Quality Control Board, and Regents of the University of California.

The Consent Decree was approved and entered by the Federal District Court for the Central District of California on October 14, 2020.

Pursuant to the terms of the Consent Decree, Plains paid $ 24 million in civil penalties and $ 22.325 million as compensation for injuries to, destruction of, loss of, or loss of use of natural resources resulting from the Line 901 incident.

The Consent Decree, which resolved all regulatory claims related to the incident, also contains requirements for implementing certain agreed-upon injunctive relief, as well as requirements for potentially restarting Line 901 and the Sisquoc to Pentland portion of Line 903.

On October 13, 2022, Plains sold Line 901 and the Sisquoc to Pentland portion of Line 903 to Pacific Pipeline Company, an indirect wholly owned subsidiary of Exxon Mobil Corporation.

As required by the terms of the Consent Decree, such purchaser assumed responsibility for compliance with the Consent Decree as it relates to the future ownership and operation of Line 901 and the Sisquoc to Pentland portion of Line 903.

Following an investigation and grand jury proceedings, in May of 2016, PAA was charged by a California state grand jury, pursuant to an indictment filed in California Superior Court, Santa Barbara County (the “May 2016 Indictment”), with alleged violations of California law in connection with the Line 901 incident.

Fifteen charges from the May 2016 Indictment were the subject of a jury trial in California Superior Court in Santa Barbara County, and the jury returned a verdict on September 7, 2018, pursuant to which we were (i) found guilty on one felony discharge count and eight misdemeanor counts (which included one reporting count, one strict liability discharge count and six strict liability animal takings counts) and (ii) found not guilty on one strict liability animal takings count.

The remaining counts were subsequently dismissed by the Court.

On April 25, 2019, PAA was sentenced to pay fines and penalties in the aggregate amount of just under $ 3.35 million for the convictions covered by the September 2018 jury verdict (the “2019 Sentence”).

The fines and penalties imposed in connection with the 2019 Sentence have been paid.

In September 2021, the Superior Court concluded a series of hearings on the issue of whether there were any “direct victims” of the spill that are entitled to restitution under applicable criminal law.

Through a series of final orders issued at the trial court level and without affecting any rights of the claimants under civil law, the Court dismissed the vast majority of the claims and ruled that the claimants were not entitled to restitution under applicable criminal laws.

The Court did award an aggregate amount of less than $ 150,000 to a handful of claimants and we settled with approximately 40 claimants before the hearings for aggregate consideration that is not material.

The prosecution and certain separately represented claimants have appealed the Court’s rulings.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

We also received several individual lawsuits and claims from companies, governmental agencies and individuals alleging damages arising out of the Line 901 incident.

Several pending or recently resolved lawsuits and claims were filed by companies, governmental agencies and individuals alleging damages arising out of the Line 901 incident.

These lawsuits and claims generally seek restitution, compensatory and punitive damages, and/or injunctive relief.

The majority of these lawsuits have been settled or dismissed by the court.

In addition to the other lawsuits disclosed herein, the following lawsuits remain:

(i) a lawsuit filed in the United States District Court for the Central District of California that was remanded to the California Superior Court in Santa Barbara County for lost revenue or profit asserted by a former oil producer that declared bankruptcy and shut in its offshore production platform following the Line 901 incident;

(ii) a lawsuit filed by the California State Land Commission in California Superior Court in Santa Barbara County seeking lost royalties following the shut-down of Line 901, as well as costs related to the decommissioning of such platform, and (iii) lawsuits filed in California Superior Court in Santa Barbara County by various companies and individuals who provided labor, goods, or services associated with oil production activities they claim were disrupted following the Line 901 incident.

We are vigorously defending these remaining lawsuits and believe we have strong defenses.

Furthermore, shortly following the Line 901 incident, we established a claims line and encouraged any parties that were damaged by the release to contact us to discuss their damage claims.

We received a number of claims through the claims line and we have processed those claims and made payments as appropriate.

Additionally, a class action lawsuit was filed against us in United States District Court for the Central District of California in which the class plaintiffs seek a declaratory judgment that Plains’ right-of-way agreements would not allow Plains to lay a new pipeline to replace Line 901 and/or the non-operating segment of Line 903 without paying additional compensation.

The purchaser of Line 901 and the Sisquoc to Pentland portion of Line 903 has assumed liability for these claims with respect to its interest in such acquired pipelines and Plains has been dismissed from this portion of the lawsuit.

In the same proceeding, a small subset of plaintiffs are also claiming damages to compensate them for the alleged diminished value of their properties due to the stigma of the oil spill.

We are vigorously defending against these stigma damages claims.

In a separate class action lawsuit that was pending in United States District Court for the Central District of California, the plaintiffs claimed two different classes of claimants were damaged by the release:

(i) commercial fishermen who landed fish in certain specified fishing blocks in the waters off the coast of Southern California or persons or businesses who resold commercial seafood caught in those areas;

and (ii) owners and lessees of residential beachfront properties, or properties with a private easement to a beach, where plaintiffs claim oil from the spill washed up.

In 2022, in order to fully and finally resolve all claims and litigation for both classes, we reached an agreement to settle this case in exchange for a payment of $ 230 million (the “Class Action Settlement”).

The Class Action Settlement was formally approved by the trial court on September 20, 2022, and we made the $ 230 million settlement payment on October 27, 2022 and the lawsuit was subsequently dismissed.

Plains formally submitted claims for reimbursement of the Class Action Settlement to our insurance carriers on November 7, 2022.

To date, we have received payment of approximately $ 3.6 million from one insurer, which represents the final payment obligation of such insurer and brings the total amount collected from all insurers under such program to $ 275 million of the $ 500 million policy limits as of December 31, 2023.

Insurers responsible for $ 185 million of the remaining $ 225 million of coverage formally communicated a denial of coverage for the Class Action Settlement generally alleging that some or all damages encompassed by the Class Action Settlement are not covered by their policies and that all or some portion of the $ 275 million for which Plains has already received insurance reimbursement does not properly exhaust the underlying policies that paid those sums.

The insurer responsible for the final $ 40 million of coverage under such insurance program has not formally responded to our reimbursement demands.

We have initiated final and binding arbitration proceedings against the insurers responsible for $ 175 million of coverage and intend to vigorously pursue recovery from our insurers of all amounts for which we have claimed reimbursement.

We believe that our claim for reimbursement from our insurers of the Class Action Settlement payment is strong and that our ultimate recovery of such amounts is probable.

Our belief is based on:

(i) our analysis of the terms of the underlying insurance policies as applied to the facts and circumstances that comprise our claim for reimbursement, (ii) our experience with the cost submissions and timely collection of claims for the $ 275 million collected to date for this incident under the same insurance program as the denied claims, including from some of the same insurers who are now denying claims, (iii) our extensive legal review and assessment of the insurer’s claimed basis for denial of coverage, which review and assessment includes the advice of external legal counsel experienced in these type of matters and solidly supports our belief that our insurers are required to provide coverage based on the terms of the policies and the nature of our claims, and (iv) the financial strength of the insurance carriers as determined by an independent credit ratings agency.

Various factors could impact the timing and amount of recovery of our insurance receivable, including future developments that adversely impact our assessment of the strength of our coverage claims, the outcome of any dispute resolution proceedings with respect to our coverage claims and the extent to which insurers may become insolvent in the future.

An unfavorable resolution could have a material impact on our results of operations.

Most of these lawsuits have been settled or dismissed by the court.

We recently settled the following two lawsuits (the “2024 Settlements”):

(i) a lawsuit in California Superior Court in Santa Barbara County for lost revenue or profit asserted by a former oil producer that declared bankruptcy and shut in its offshore production platform following the Line 901 incident;

and (ii) a lawsuit filed by the California State Land Commission in California Superior Court in Santa Barbara County seeking lost royalties following the shut-down of Line 901, as well as costs related to the decommissioning of such platform.

In connection with the 2024 Settlements, we recognized additional costs related to the Line 901 incident of $ 120 million.

Our remaining Line 901 lawsuits include various lawsuits filed in California Superior Court in Santa Barbara County by (x) companies and individuals who provided labor, goods, or services associated with oil production activities they claim were disrupted following the Line 901 incident and (y) a landowner on an adjacent pipeline alleging property damage from the “stigma” of the Line 901 incident.

We are vigorously defending these remaining lawsuits, which have not yet been set for trial, and believe we have strong defenses.

The ultimate outcome of such matters is uncertain, and an unfavorable resolution could have a material impact on our results of operations.

In November 2022, we submitted claims to several of our insurance carriers seeking reimbursement for a $ 230 million payment made in October of 2022 to settle a class action lawsuit stemming from the Line 901 incident (the “Class Action Settlement”).

We had previously received payment of approximately $ 3.6 million from one insurer, which represented the final payment obligation of such insurer and brought the total amount collected from all insurers under such program to $ 275 million of the $ 500 million policy limits.

In response to denials of coverage or other failures to timely tender payment, we initiated final and binding insurance arbitration proceedings against the insurers responsible for the remaining $ 225 million of coverage.

Such insurers generally alleged that some or all damages encompassed by the Class Action Settlement were not covered by their policies and that all or some portion of the $ 275 million for which we had already received insurance reimbursement did not, for purposes of determining whether their policies were triggered, properly exhaust the underlying policies that paid those sums.

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

Our belief at that time was based on:

(i) our analysis of the terms of the underlying insurance policies as applied to the facts and circumstances that comprised our claim for reimbursement, (ii) our experience with the cost submissions and timely collection of claims for the $ 275 million previously collected for this incident under the same insurance program as the denied claims, including from some of the same insurers who were then denying claims, (iii) our extensive legal review and assessment of the insurer’s claimed basis for denial of coverage, which review and assessment included the advice of external legal counsel experienced in these type of matters that supported our belief that our insurers were required to provide coverage based on the terms of the policies and the nature of our claims, and (iv) the financial strength of the insurance carriers as determined by an independent credit ratings agency.

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

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

In connection with the foregoing, including the Class Action Settlement, we have made adjustments to our total estimated Line 901 costs and the portion of such costs that we believe are probable of recovery from insurance carriers, net of deductibles.

Effective as of December 31, 2023, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $ 750 million, which includes actual and projected emergency response and clean-up costs, natural resource damage assessments, fines and penalties payable pursuant to the Consent Decree, certain third-party claims settlements (including the Class Action Settlement), and estimated costs associated with our remaining Line 901 lawsuits and claims as described above, as well as estimates for certain legal fees and statutory interest where applicable.

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

The panel ruled that a substantial portion of our claims subject to the proceeding were not covered under the applicable policy and therefore we were not entitled to reimbursement of our $ 175 million claim against the applicable insurers.

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

In connection with the foregoing, including the 2024 Settlements, we have made adjustments to our total estimated Line 901 costs and the portion of such costs that we believe are probable of recovery from insurance carriers, net of deductibles.

Effective as of December 31, 2024, 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 and projected emergency response and clean-up costs, natural resource damage assessments, fines and penalties incurred, certain third-party claims settlements (including the Class Action Settlement and the 2024 Settlements), and estimated costs associated with our remaining Line 901 lawsuits and claims as described above, 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 excluding future claims and lawsuits 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.

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.

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therefore, we can provide no assurance that we will not have to accrue significant additional costs in the future with respect to the Line 901 incident.

During the years ended December 31, 2023, 2022 and 2021, we recognized costs, net of amounts probable of recovery from insurance carriers, of $ 10 million, $ 95 million and $ 15 million, respectively.

During the years ended December 31, 2024, 2023 and 2022, we recognized costs, net of amounts probable of recovery from insurance (as applicable), of $ 345 million, $ 10 million, and $ 95 million, respectively.

As of December 31, 2024 and 2023, we had a remaining undiscounted gross liability of approximately $ 5 million and $ 94 million, respectively, related to the Line 901 incident, which aggregate amounts are reflected in “Current liabilities” on our Consolidated Balance Sheet.

As discussed above, we maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such liabilities.

As of December 31, 2023, our incurred costs for the Line 901 incident have exceeded our insurance coverage limit of $ 500 million related to our 2015 insurance program applicable to the Line 901 incident by $ 250 million.

Through December 31, 2023, we had collected, subject to customary reservations, approximately $ 280 million out of the $ 505 million of release costs that we believe are probable of recovery from insurance carriers (including the 2015 insurance program and our directors and officers (D&O) insurance policies), net of deductibles.

Therefore, as of December 31, 2023, we have recognized a long-term receivable of approximately $ 225 million for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected.

We anticipate that the process to enforce our coverage claims with respect to the Class Action Settlement will take time and, accordingly, have recognized such amount as a long-term asset in “Other assets” on our Consolidated Balance Sheet.

We have completed the required clean-up and remediation work as determined by the Unified Command and the Unified Command has been dissolved;

however, we expect to make payments for additional legal, professional and regulatory costs during future periods.

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 lawsuits will have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

As of December 31, 2023, we had recognized a receivable of approximately $ 225 million for the portion of the release costs that we believed were probable of recovery from insurance, net of deductibles and amounts already collected (approximately $ 280 million out of the $ 505 million submitted, including the 2015 insurance program and our directors and officers (D&O) insurance policies).

Of this amount, we had classified $ 175 million as a short-term asset in “Trade accounts receivable and other receivables, net” with the remaining $ 50 million recognized as a long-term asset in “Other long-term assets, net” on our Consolidated Balance Sheet as of December 31, 2023.

Following the arbitration panel ruling discussed above, we wrote off the full $ 225 million insurance receivable in the fourth quarter of 2024.

Therefore, as of December 31, 2024, we no longer have any amounts recorded as receivables related to the Line 901 incident recognized on our Consolidated Balance Sheet.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

We have completed the required clean-up and remediation work as determined by the Unified Command and the Unified Command has been dissolved;

however, we expect to make payments for additional legal, professional and regulatory costs during future periods.

Other Litigation Matters.

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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.

We believe the claims are without merit and that the outcome of the lawsuit will not have a material adverse effect on our financial condition, results of operations or cash flows.

We intend to vigorously defend against the claims asserted in this lawsuit.

We have entered into a confidential settlement agreement and anticipate that in connection with the settlement, all of Hartree’s claims will be dismissed with prejudice and without any admission of wrongdoing by Plains.

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 damages in an unspecified amount.

Our subsidiary owned and operated a pipeline in the vicinity of the refuge from 2006 through 2016.

The damages have not been quantified and are not yet reasonably estimable, but we believe the claims in the lawsuit lack merit and intend to vigorously defend this lawsuit in coordination with the other Defendants.

Note 19— Segment Information

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Our crude oil and NGL marketing activities are included in the respective reporting segments as their 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 each of our segments.

Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below) and maintenance capital.

The measure of Segment Adjusted EBITDA forms the basis of our internal financial reporting and is the primary performance measure 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) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus (d) our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities, further adjusted (e) 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 (f) to exclude the portion of all preceding items that is attributable to noncontrolling interests (“Segment amounts attributable to noncontrolling interests”).

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.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Segment Adjusted EBITDA excludes depreciation and amortization.

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Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as investment capital.

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 are classified as maintenance capital, which is deducted in determining “available cash.” Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are charged to expense as incurred.

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;

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

Crude Oil NGL Intersegment Revenues

Elimination Total

Crude Oil NGL Intersegment

Year Ended December 31, 2024

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Total revenues $ 48,720 $ 1,724 $ ( 371 ) $ 50,073

Equity earnings in unconsolidated entities $ 369 $ — $ 369

Segment Adjusted EBITDA $ 2,163 $ 522 $ 2,685

Investment and acquisition capital expenditures (2) (3)

$ 765 $ 65 $ 830

Maintenance capital expenditures (3)

Significant segment expenses:

Purchases and related costs (1)

$ ( 45,033 ) $ ( 898 ) $ 371 $ ( 45,560 )

As of December 31, 2023

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

Crude Oil NGL Intersegment Revenues

Elimination Total

Year Ended December 31, 2022

Revenues (1) :

Product sales $ 53,840 $ 2,575 $ ( 467 ) $ 55,948

Services 1,240 186 ( 32 ) 1,394

Total revenues $ 55,080 $ 2,761 $ ( 499 ) $ 57,342

Field operating costs ( 1,440 ) ( 328 ) — ( 1,768 )

Segment general and administrative expenses ( 298 ) ( 83 ) — ( 381 )

Total significant segment expenses $ ( 46,771 ) $ ( 1,309 ) $ 371 $ ( 47,709 )

Equity earnings in unconsolidated entities $ 452 $ —

Other segment items (2) :

Depreciation and amortization of unconsolidated entities (3)

Derivative activities and inventory valuation adjustments (4)

Long-term inventory costing adjustments (5)

Deficiencies under minimum volume commitments, net (6)

Equity-indexed compensation expense (7)

Foreign currency revaluation (8)

Line 901 incident (9)

Segment amounts attributable to noncontrolling interests (10)

Total other segment items $ ( 125 ) $ 65

Segment Adjusted EBITDA $ 2,276 $ 480

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

Crude Oil NGL Intersegment Revenues

Elimination Total

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Crude Oil NGL Intersegment

Year Ended December 31, 2023

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Total revenues $ 47,174 $ 1,935 $ ( 397 ) $ 48,712

Significant segment expenses:

Purchases and related costs (1)

$ ( 43,805 ) $ ( 1,123 ) $ 397 $ ( 44,531 )

Field operating costs ( 1,053 ) ( 372 ) — ( 1,425 )

Segment general and administrative expenses ( 271 ) ( 79 ) — ( 350 )

Total significant segment expenses $ ( 45,129 ) $ ( 1,574 ) $ 397 $ ( 46,306 )

Equity earnings in unconsolidated entities $ 369 $ —

Other segment items (2) :

Depreciation and amortization of unconsolidated entities (3)

Derivative activities and inventory valuation adjustments (4)

Long-term inventory costing adjustments (5)

Deficiencies under minimum volume commitments, net (6)

Equity-indexed compensation expense (7)

Foreign currency revaluation (8)

Line 901 incident (9)

Transaction-related expenses (13)

Segment amounts attributable to noncontrolling interests (10)

Total other segment items $ ( 251 ) $ 161

Segment Adjusted EBITDA $ 2,163 $ 522

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(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) Investment and acquisition capital expenditures, including investments in unconsolidated entities.

(3) These amounts combined represent total capital expenditures.

Segment Adjusted EBITDA Reconciliation

The following table reconciles Segment Adjusted EBITDA to Net income attributable to PAA (in millions):

Crude Oil NGL Intersegment

Year Ended December 31, 2022

Revenues (1) :

Product sales $ 53,840 $ 2,575 $ ( 467 ) $ 55,948

Services 1,240 186 ( 32 ) 1,394

Total revenues $ 55,080 $ 2,761 $ ( 499 ) $ 57,342

Significant segment expenses:

Purchases and related costs (1)

$ ( 52,088 ) $ ( 1,587 ) $ 499 $ ( 53,176 )

Segment Adjusted EBITDA $ 2,685 $ 2,504 $ 2,194

Adjustments (1) :

Field operating costs ( 1,003 ) ( 312 ) — ( 1,315 )

Segment general and administrative expenses ( 250 ) ( 75 ) — ( 325 )

Total significant segment expenses $ ( 53,341 ) $ ( 1,974 ) $ 499 $ ( 54,816 )

Equity earnings in unconsolidated entities $ 403 $ —

Other segment items (2) :

Depreciation and amortization of unconsolidated entities (3)

( 87 ) ( 85 ) ( 123 )

Derivative activities and inventory valuation adjustments (4)

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Deficiencies under minimum volume commitments, net (6)

( 12 ) ( 7 ) 7

Equity-indexed compensation expense (7)

( 36 ) ( 32 ) ( 19 )

Foreign currency revaluation (8)

( 24 ) ( 4 ) 4

Line 901 incident (9)

( 10 ) ( 95 ) ( 15 )

Transaction-related expenses (9)

( 1 ) — ( 16 )

Segment amounts attributable to noncontrolling interests (10)

Depreciation and amortization ( 1,048 ) ( 965 ) ( 774 )

Gains/(losses) on asset sales and asset impairments, net 152 ( 269 ) ( 592 )

Gains/(losses) on investments in unconsolidated entities, net 28 346 2

Interest expense, net ( 386 ) ( 405 ) ( 425 )

Other income/(expense), net 102 ( 219 ) 19

Income before tax

1,623 1,417 721

Income tax expense

( 121 ) ( 189 ) ( 73 )

Total other segment items $ ( 156 ) $ ( 269 )

Segment Adjusted EBITDA $ 1,986 $ 518

Investment and acquisition capital expenditures (11) (12)

$ 461 $ 157 $ 618

Net income attributable to noncontrolling interests ( 272 ) ( 191 ) ( 55 )

Net income attributable to PAA

Maintenance capital expenditures (12)

$ 112 $ 99 $ 211

As of December 31, 2022

Investments in unconsolidated entities $ 3,084 $ — $ 3,084

(1) Segment revenues include intersegment amounts that are eliminated in Purchases and related costs.

(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.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(4) We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction.

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We also exclude the impact of corresponding inventory valuation adjustments, as applicable.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(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.

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These gains and losses are not integral to our core operating performance and were therefore excluded in determining Segment Adjusted EBITDA.

(8) 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.

(9) 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 18 for additional information regarding the Line 901 incident.

(9) Includes expenses associated with the Rattler Permian Transaction in 2023 and the Permian JV transaction in 2021.

(10) Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II (beginning November 2022) 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 expenses associated with the Rattler Permian Transaction in 2023.

See Note 7 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, 2023 and 2021 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 (beginning October 2021), Cactus II (beginning November 2022) and Red River.

An adjustment for these non-recurring expenses is included in the calculation of Segment Adjusted EBITDA for the year ended December 31, 2023 as our CODM does not view such expenses as integral to understanding our core segment operating performance.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Segment Adjusted EBITDA Reconciliation

The following table reconciles Segment Adjusted EBITDA to Net income attributable to PAA (in millions):

Year Ended December 31,

2024 2023 2022

Segment Adjusted EBITDA $ 2,756 $ 2,685 $ 2,504

Total other segment items (1)

Depreciation and amortization ( 1,026 ) ( 1,048 ) ( 965 )

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

( 160 ) 152 ( 269 )

Gain on investments in unconsolidated entities, net 15 28 346

Interest expense, net ( 430 ) ( 386 ) ( 405 )

Other income/(expense), net 65 102 ( 219 )

Income before tax

1,280 1,623 1,417

Income tax expense

( 167 ) ( 121 ) ( 189 )

1,113 1,502 1,228

Net income attributable to noncontrolling interests ( 341 ) ( 272 ) ( 191 )

Net income attributable to PAA

$ 772 $ 1,230 $ 1,037

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

Geographic Data

13 unchanged sentences

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What changed 10-K

Item 9A. Controls and Procedures