What changed in this filing

/stocks — the workspaceLOADING

Item 9A. Controls and Procedures

2026-02-27 compared with 2025-02-28 · 725 added, 490 removed, 1875 unchanged (39% of the section changed)

2 unchanged sentences

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.

Index to Financial Statements

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

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

Index to Financial Statements

Internal Control over Financial Reporting

22 unchanged sentences

Willie Chiang (1) (2)

Chairman of the Board and Chief Executive Officer

Pefanis (1)(2)

President and Director

Chairman of the Board, Chief Executive Officer and President

Executive Vice President and Chief Operating Officer

13 unchanged sentences

Former Vice Chairman, Kayne Anderson Capital Advisors, L.P.

Senior Advisor to the Chief Executive Officer (former President)

Managing Partner, EnCap Investments L.P.

24 unchanged sentences

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

— Share Purchase Agreement dated as of June 17, 2025 by and between Plains Midstream Luxembourg S.A.R.L.

and Keyera Corp.

(portions of this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (incorporated by reference to Exhibit 2.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2025).

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

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

3.1 — Seventh Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P.

9 unchanged sentences

(incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed May 30, 2019).

Index to Financial Statements

3.6 — Amendment No.

9 unchanged sentences

(incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed April 9, 2020).

Index to Financial Statements

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

13 unchanged sentences

Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 11, 2014).

4.8 — Twenty-Ninth Supplemental Indenture (4.65% Senior Notes due 2025) dated August 24, 2015, by and among Plains All American Pipeline, L.P., PAA Finance Corp.

Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed August 26, 2015).

— Thirtieth Supplemental Indenture (4.50% Senior Notes due 2026) dated November 22, 2016, by and among Plains All American Pipeline, L.P., PAA Finance Corp.

2 unchanged sentences

Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed September 17, 2019).

Index to Financial Statements

— Thirty-Second Supplemental Indenture (3.80% Senior Notes due 2030) dated June 11, 2020, by and among Plains All American Pipeline, L.P., PAA Finance Corp.

4 unchanged sentences

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

Index to Financial Statements

— Thirty-Fifth Supplemental Indenture (4.70% Senior Notes due 2031) dated September 8, 2025, by and among Plains All American Pipeline, L.P., PAA Finance Corp.

Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA's Current Report on Form 8-K filed November 14, 2025 ).

— Thirty-Sixth Supplemental Indenture (5.60% Senior Notes due 2036) dated September 8, 2025, by and among Plains All American Pipeline, L.P., PAA Finance Corp.

Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.3 to PAA's Current Report on Form 8-K filed November 14 , 2025).

— Shareholder and Registration Rights Agreement dated October 21, 2013 by and among Plains GP Holdings, L.P.

and the other parties signatory thereto (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed October 25, 2013).

— Description of Our Securities.

4.16 — Description of Our Securities (incorporated by reference to Exhibit 4.1 5 to our Annual Report on Form 10-K for the year ended December 31, 2024) .

10.1 — Credit Agreement dated as of August 20, 2021, among Plains All American Pipeline, L.P.

36 unchanged sentences

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).

Index to Financial Statements

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

5 unchanged sentences

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

— Term Loan Agreement, dated as of November 26, 2025, by and among Plains All American Pipeline, L.P., PNC Bank, National Association, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed December 3, 2025).

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

4 unchanged sentences

Armstrong dated as of June 30, 2001 (incorporated by reference to Exhibit 10.1 to PAA’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001).

Index to Financial Statements

— First Amendment to Amended and Restated Employment Agreement dated December 4, 2008 between Plains All American GP LLC and Greg L.

11 unchanged sentences

Armstrong (incorporated by reference to Exhibit 10.12 to our Annual Report on Form 10-K for the year ended December 31, 2021).

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

Armstrong (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2025).

— Amended and Restated Employment Agreement between Plains All American GP LLC and Harry N.

Pefanis dated as of June 30, 2001 (incorporated by reference to Exhibit 10.2 to PAA’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001).

Index to Financial Statements

— First Amendment to Amended and Restated Employment Agreement dated December 4, 2008 between Plains All American GP LLC and Harry N.

6 unchanged sentences

Pefanis (incorporated by reference to Exhibit 10.5 to our Current Report on Form 8-K filed October 25, 2013).

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

Pefanis (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2025).

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

1 unchanged sentence

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

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

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

1 unchanged sentence

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

Index to Financial Statements

— PAA Natural Gas Storage, L.P.

2 unchanged sentences

Long Term Incentive Plan (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed October 25, 2013).

— Form of LTIP Grant Letter dated August 15, 2019 (Officers) (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).

— Form of LTIP Grant Letter dated August 13, 2020 (Directors) (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2020).

— Contribution Agreement dated October 21, 2013, by and among Plains GP Holdings, L.P., PAA GP Holdings LLC and the other parties signatory thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed October 25, 2013).

2 unchanged sentences

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

— Form of LTIP Grant Letter dated August 19, 2021 (Directors) (incorporated by reference to Exhibit 10.4 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2021).

— 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).

Index to Financial Statements

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

— 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 14, 2025 (Named Executive Officers) (incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2025).

— Form of LTIP Grant Letter dated August 14, 2025 (Directors) (incorporated by reference to Exhibit 10.4 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2025).

— P oli cy on Insider Trading.

— P olicy Regarding Special Tra ding Procedures.

— Form of Special Retention LTIP Grant Letter dated August 14, 2025 (incorporated by reference to Exhibit 10.5 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2025).

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

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

21.1 † — List of Subsidiaries of Plains GP Holdings, L.P.

4 unchanged sentences

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

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

— 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.

Index to Financial Statements

101.SCH† — Inline XBRL Taxonomy Extension Schema Document

17 unchanged sentences

Willie Chiang,

Chairman of the Board and Chief Executive Officer of PAA GP Holdings LLC

Chairman of the Board, Chief Executive Officer and President of PAA GP Holdings LLC

(Principal Executive Officer)

14 unchanged sentences

/s/ Willie Chiang

Chairman of the Board and Chief Executive Officer of PAA GP Holdings LLC (Principal Executive Officer) February 27, 2025

Chairman of the Board, Chief Executive Officer and President of PAA GP Holdings LLC (Principal Executive Officer)

February 27, 2026

Willie Chiang

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

/s/ Al Swanson

11 unchanged sentences

Director of PAA GP Holdings LLC February 27, 2026

/s/ Alexandra D.

20 unchanged sentences

Summary of Significant Accounting Policies

Discontinued Operations

Revenues and Accounts Receivable

12 unchanged sentences

Segment Information

S elected Quarterly Financial Data (Unaudited)

Index to Financial Statements

13 unchanged sentences

Willie Chiang

Chairman of the Board and Chief Executive Officer of PAA GP Holdings LLC

Chairman of the Board, President and Chief Executive Officer of PAA GP Holdings LLC

(Principal Executive Officer)

36 unchanged sentences

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.

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.

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

As described in Note 8 to the consolidated financial statements, on October 31, 2025, the Partnership purchased an aggregate 55% equity interest in EPIC Crude Holdings, LP, and in a separate transaction, effective November 1, 2025, acquired the remaining 45% equity interest, for total consideration of $2,016 million.

Of the identifiable assets acquired, $2,737 million of property and equipment, net, was recorded, a significant portion of which relates to pipelines and equipment.

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

The fair value of acquired pipelines and equipment was determined by management using a cost approach and included an assumption for replacement cost.

The principal considerations for our determination that performing procedures relating to the valuation of pipelines and equipment acquired in the acquisition of EPIC Crude Holdings, LP is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the pipelines and equipment acquired;

(ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumption related to replacement cost;

and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

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

These procedures included testing the effectiveness of controls relating to the 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.

These procedures included testing the effectiveness of controls relating to the acquisition accounting, including controls over management’s valuation of the pipelines and equipment acquired.

These procedures also included, among others (i) reading the purchase agreements;

(ii) testing management’s process for developing the fair value estimate of the pipelines and equipment acquired;

(iii) evaluating the appropriateness of the cost approach used by management;

(iv) testing the completeness and accuracy of the underlying data used in the cost approach;

and (v) evaluating the reasonableness of the significant assumption used by management related to replacement cost.

Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the cost approach and (ii) the reasonableness of the replacement cost assumption.

/s/ PricewaterhouseCoopers LLP

12 unchanged sentences

Inventory 211 261

Current assets of discontinued operations (Note 3) 479 415

Other current assets 87 72

9 unchanged sentences

Long-term inventory 214 242

Long-term assets of discontinued operations (Note 3) 2,557 2,349

Other long-term assets, net 107 142

4 unchanged sentences

Short-term debt 563 407

Current liabilities of discontinued operations (Note 3) 382 350

Other current liabilities 500 520

4 unchanged sentences

Long-term operating lease liabilities 202 192

Long-term liabilities of discontinued operations (Note 3) 606 576

Other long-term liabilities and deferred credits 654 537

30 unchanged sentences

( 467 ) ( 382 ) ( 386 )

Other income/(expense), net 17 102 ( 219 )

INCOME BEFORE TAX 1,274 1,614 1,409

Current income tax expense ( 195 ) ( 145 ) ( 84 )

Deferred income tax expense ( 9 ) ( 44 ) ( 162 )

Other income, net 21 16 102

INCOME FROM CONTINUING OPERATIONS BEFORE TAX 1,395 963 1,362

Current income tax expense from continuing operations ( 1 ) ( 82 ) ( 70 )

Deferred income tax expense from continuing operations ( 91 ) ( 42 ) ( 59 )

INCOME FROM CONTINUING OPERATIONS, NET OF TAX 1,303 839 1,233

INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX (NOTE 3)

NET INCOME 1,686 1,070 1,425

Net income attributable to noncontrolling interests from continuing operations ( 1,151 ) ( 800 ) ( 1,089 )

Net income attributable to noncontrolling interests from discontinued operations ( 275 ) ( 167 ) ( 138 )

Net income attributable to noncontrolling interests ( 1,426 ) ( 967 ) ( 1,227 )

Net income attributable to PAGP from continuing operations 152 39 144

Net income attributable to PAGP from discontinued operations 108 64 54

NET INCOME ATTRIBUTABLE TO PAGP $ 260 $ 103 $ 198

Basic and diluted weighted average Class A shares outstanding

Basic and diluted net income per Class A share

$ 0.52 $ 1.01 $ 0.86

Basic weighted average Class A shares outstanding

Basic Net Income per Class A Share:

Continuing operations $ 0.77 $ 0.19 $ 0.74

Discontinued operations 0.54 0.33 0.27

Basic net income per Class A share $ 1.31 $ 0.52 $ 1.01

Diluted weighted average Class A shares outstanding 233 232 239

Diluted Net Income per Class A Share:

Continuing operations $ 0.77 $ 0.19 $ 0.74

Discontinued operations 0.53 0.32 0.26

Diluted net income per Class A share $ 1.30 $ 0.51 $ 1.00

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

29 unchanged sentences

Currency translation adjustments — ( 284 ) — ( 284 )

Other — — 1 1

2024 Activity 37 ( 284 ) — ( 247 )

3 unchanged sentences

Currency translation adjustments — 167 — 167

Other — — 5 5

2025 Activity 15 167 5 187

11 unchanged sentences

Reconciliation of net income to net cash provided by operating activities:

Income from discontinued operations, net of tax ( 383 ) ( 231 ) ( 192 )

Depreciation and amortization 953 901 912

2 unchanged sentences

Deferred income tax expense 91 42 59

Gains on sales of linefill — ( 2 ) ( 35 )

(Gain)/loss on foreign currency revaluation 13 ( 12 ) 3

9 unchanged sentences

Trade accounts payable and other ( 337 ) ( 77 ) ( 141 )

Cash provided by operating activities - continuing operations 2,447 2,230 2,247

Cash provided by operating activities - discontinued operations 484 254 475

Net cash provided by operating activities 2,931 2,484 2,722

5 unchanged sentences

Proceeds from sales of assets (Note 8) 81 11 328

Cash received from sales of linefill — 9 72

Other investing activities — 5 8

Cash used in investing activities - continuing operations ( 3,242 ) ( 705 ) ( 540 )

Cash used in investing activities - discontinued operations ( 197 ) ( 170 ) ( 162 )

Net cash used in investing activities ( 3,439 ) ( 875 ) ( 702 )

1 unchanged sentence

Net borrowings/(repayments) under PAA commercial paper program (Note 11) 577 ( 40 ) 433

Repayment under PAA EPIC credit agreement (Note 11) ( 1,114 ) — —

Borrowing under PAA term loan (Note 11) 1,100 — —

Proceeds from the issuance of PAA senior notes (Note 11) 2,998 650 —

1 unchanged sentence

Repurchase of common units by a subsidiary (Note 12) ( 8 ) — —

Repurchase of Series A preferred units by a subsidiary (Note 12) ( 333 ) — —

Distributions paid to Class A shareholders (Note 12) ( 301 ) ( 251 ) ( 209 )

2 unchanged sentences

Other financing activities ( 79 ) ( 49 ) ( 88 )

Net cash used in financing activities ( 1,702 ) ( 1,971 ) ( 1,927 )

Effect of translation adjustment ( 11 ) — ( 3 )

Net cash provided by/(used in) financing activities 474 ( 1,702 ) ( 1,971 )

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

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

Net increase/(decrease) in cash and cash equivalents and restricted cash ( 20 ) ( 104 ) 49

3 unchanged sentences

Interest, net of amounts capitalized $ 431 $ 351 $ 377

Income taxes, net of amounts refunded $ 269 $ 69 $ 112

Income taxes, net of amounts refunded (Note 15) $ 98 $ 269 $ 69

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

9 unchanged sentences

Deferred tax asset (Note 15) ( 2 ) — ( 2 )

Other comprehensive loss (Note 11) ( 28 ) ( 73 ) ( 101 )

Other comprehensive income (Note 12) 33 85 118

Equity-indexed compensation expense 11 26 37

Repurchase of common units by a subsidiary (Note 11) 2 ( 76 ) ( 74 )

Contributions from noncontrolling interests — 106 106

Cactus II Pipeline LLC transaction (Note 7)

Other ( 7 ) ( 13 ) ( 20 )

3 unchanged sentences

Deferred tax asset (Note 15) 18 — 18

Other comprehensive income (Note 11) 33 85 118

Other comprehensive loss (Note 12) ( 69 ) ( 178 ) ( 247 )

Equity-indexed compensation expense 12 26 38

5 unchanged sentences

Deferred tax asset (Note 15) ( 4 ) — ( 4 )

Other comprehensive loss (Note 11) ( 69 ) ( 178 ) ( 247 )

Other comprehensive income (Note 12) 53 134 187

Equity-indexed compensation expense 12 26 38

Repurchase of common units by a subsidiary (Note 12) 1 ( 9 ) ( 8 )

Repurchase of Series A preferred units by a subsidiary (Note 12) ( 12 ) ( 301 ) ( 313 )

Contributions from noncontrolling interests — 75 75

19 unchanged sentences

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

As one of the largest crude oil midstream service providers in North America, PAA owns 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.

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

PAA’s assets and the services it provides are primarily focused on and conducted through two operating segments:

10 unchanged sentences

ASU = Accounting Standards Update

Bcf = Billion cubic feet

Btu = British thermal unit

CAD = Canadian dollar

2 unchanged sentences

EBITDA = Earnings before interest, taxes, depreciation and amortization

EPA = United States Environmental Protection Agency

FASB = Financial Accounting Standards Board

1 unchanged sentence

ICE = Intercontinental Exchange

ISDA = International Swaps and Derivatives Association

LIBOR = London Interbank Offered Rate

LTIP = Long-term incentive plan

Index to Financial Statements

2 unchanged sentences

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

ISDA = International Swaps and Derivatives Association

LIBOR = London Interbank Offered Rate

LTIP = Long-term incentive plan

Mcf = Thousand cubic feet

MMbls = Million barrels

NGL = Natural gas liquids, including ethane, propane and butane

6 unchanged sentences

USD = United States dollar

WTI = West Texas Intermediate

Basis of Consolidation and Presentation

1 unchanged sentence

All significant intercompany balances and transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation.

These reclassifications had no impact on net income or total partners’ capital.

The accompanying consolidated financial statements include the accounts of PAGP and all of its wholly owned subsidiaries and those entities that it controls.

12 unchanged sentences

• PAGP is the primary beneficiary of AAP because it has the power to direct the activities that most significantly impact AAP’s performance and the right to receive benefits, and obligation to absorb losses, that could be significant to AAP.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

With the exception of a deferred tax asset of $ 1.136 billion and $ 1.220 billion as of December 31, 2025 and 2024, respectively, substantially all assets and liabilities presented on PAGP’s Consolidated Balance Sheets are those of PAA.

2 unchanged sentences

See Note 17 for information regarding the Omnibus Agreement entered into by the Plains Entities on November 15, 2016.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Pending Sale of Canadian NGL Business

On June 17, 2025, a subsidiary of PAA entered into a definitive Share Purchase Agreement (“SPA”) with Keyera Corp.

(“Keyera”), an Alberta corporation, pursuant to which Keyera agreed to acquire all of the issued and outstanding shares of Plains Midstream Canada ULC, PAA’s wholly-owned subsidiary that owns substantially all of the NGL business in Canada (the “Canadian NGL Business”), for cash consideration of approximately CAD$ 5.15 billion (approximately $ 3.75 billion), subject to certain post-closing adjustments, as defined in the SPA.

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

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

Accordingly, the assets and liabilities of the Canadian NGL Business have been classified as held for sale, and the balance sheet, results of operations and cash flows of the Canadian NGL Business have been presented as discontinued operations in our consolidated financial statements.

Unless otherwise indicated, the disclosures included within the accompanying notes to the consolidated financial statements relate to our continuing operations and exclude amounts related to discontinued operations.

These changes have been applied retrospectively to all periods presented.

Discontinued operations are not presented separately within our Consolidated Statements of Comprehensive Income, Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss) or the Consolidated Statements of Changes in Partners’ Capital.

See Note 3 for additional information regarding discontinued operations.

All significant intercompany balances and transactions between the Canadian NGL Business and our continuing operations have been eliminated.

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

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

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

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

See Note 13 for additional information.

In connection with and contingent upon closing of the pending sale, we and Keyera entered into an agreement for certain hedging arrangements and payments relating to the differential between the price of natural gas and the extracted NGL commodities (“Frac Spread”) for a twelve-month period commencing the first month after the closing date.

As a result of this arrangement, we will guarantee a minimum Frac Spread margin on certain volumes.

The recognition of an asset or liability will be dependent upon the terms of the specific contracts transferred as part of the sale of the Canadian NGL Business and the market conditions at that time the sale closes.

We do not expect any liability we might recognize as a result of this agreement to have a material adverse effect on our consolidated financial condition, results of operations or cash flows;

for example, if the sale closed at the end of the first quarter of 2026, based on existing contracts to be transferred and current market conditions as of December 31, 2025, we would recognize a liability of approximately $ 65 million.

Subsequent Events

6 unchanged sentences

Although we believe these estimates are reasonable, actual results could differ from these estimates.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Purchases and Related Costs

24 unchanged sentences

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, 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.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023, the revaluation of foreign currency transactions and monetary assets and liabilities resulted in the recognition of a net loss of $ 13 million, a net gain of $ 12 million and a net loss of $ 3 million, respectively, in our Consolidated Statements of Operations.

Cash and Cash Equivalents

10 unchanged sentences

FASB guidance also requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method.

Some of our assets, primarily our pipelines, certain processing and fractionation facilities and terminals assets, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned.

Index to Financial Statements

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Some of our assets, primarily our pipelines and terminals assets, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned.

These obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state.

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Ending balance $ 112 $ 109 $ 106

(1) The 2022 amount primarily relates to the transfer of liabilities to the third party purchaser associated with the sale of Line 901 and the Sisquoc to Pentland portion of Line 903 pipeline.

See Note 7 and Note 18 for additional information.

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Fair Value Measurements

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The determination of the fair values includes not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit) but also the impact of our nonperformance risk on our liabilities.

The fair value of our commodity derivatives and interest rate derivatives includes adjustments for credit risk.

The fair value of our commodity, interest rate and foreign currency derivatives includes adjustments for credit risk.

Our credit adjustment methodology uses market observable inputs and requires judgment.

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

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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 beginning with our annual report for the year ended December 31, 2025.

We adopted this guidance beginning with our annual report for the year ended December 31, 2025.

See Note 15 for updated income tax disclosures.

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

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

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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.

See Note 20 for our segment disclosures.

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

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

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

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

SEC Climate Disclosure Rules

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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.

In March 2025, the SEC voted to withdraw its defense of the climate disclosure rules.

International Tax Reform

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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.

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Note 3— Discontinued Operations

The operations of the Canadian NGL Business meet the criteria for classification as held for sale and for discontinued operations reporting.

The Canadian NGL Business disposal group is recorded at its historical carrying value, as the fair value of the disposal group, less estimated costs to sell, is greater than the carrying value of the Canadian NGL Business disposal group.

Depreciation and amortization on the long-lived assets of the Canadian NGL Business disposal group ceased upon meeting the criteria to be classified as assets held for sale.

See Note 1 for information regarding the pending sale of the Canadian NGL Business.

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

2025 December 31,

Current assets:

Trade accounts receivable and other receivables, net

Inventory 176 178

Other current assets 18 15

Total current assets of discontinued operations

Long-term assets:

Property and equipment, net (1)

$ 2,191 $ 1,978

Linefill 70 64

Long-term operating lease right-of-use assets, net 138 143

Long-term inventory 38 38

Other long-term assets, net 120 126

Total long-term assets of discontinued operations

$ 2,557 $ 2,349

Current liabilities:

Trade accounts payable

Other current liabilities 87 116

Total current liabilities of discontinued operations

Long-term liabilities:

Long-term operating lease liabilities $ 96 $ 121

Other long-term liabilities and deferred credits 510 455

Total long-term liabilities of discontinued operations

(1) Amounts are net of accumulated depreciation of $ 876 million and $ 794 million as of December 31, 2025 and 2024, respectively.

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The following table provides a reconciliation of the line items comprising income from discontinued operations before tax to income from discontinued operations, net of tax (in millions):

Year Ended December 31,

2025 2024 2023

Product sales

$ 1,186 $ 1,055 $ 1,229

Total revenues

1,317 1,184 1,376

Cost and Expenses:

Purchases and related costs

Field operating costs 259 297 340

General and administrative expenses 47 53 51

Depreciation and amortization

Losses on asset sales, net

Total costs and expenses

795 874 1,124

Other income, net

Income from discontinued operations before tax 522 311 252

Current income tax expense

( 99 ) ( 113 ) ( 75 )

Deferred income tax (expense)/benefit

Income from discontinued operations, net of tax $ 383 $ 231 $ 192

Note 4— Revenues and Accounts Receivable

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Sales $ 144 $ 180 $ 179

Transportation 36 30 30

Terminalling, Storage and Other 6 7 7

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

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Sales Revenues.

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Transportation Revenues.

Transportation revenues include revenues from transporting crude oil and NGL on pipelines and trucks.

Revenues from pipeline tariffs and fees are associated with the transportation of crude oil and NGL at a published tariff.

Transportation revenues include revenues from transporting crude oil on pipelines and trucks.

Revenues from pipeline tariffs and fees are associated with the transportation of crude oil at a published tariff.

We primarily recognize pipeline tariff and fee revenues over time as services are rendered, based on the volumes transported.

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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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Terminalling, Storage and Other Revenues.

Revenues in this category include (i) fees that are generated when we receive liquids from one connecting source and deliver the applicable product to another connecting carrier, (ii) fees from storage capacity agreements, (iii) fees from loading and unloading services at our terminals and (iv) fees from natural gas and condensate processing services and from NGL fractionation and isomerization service.

We generate revenue through a combination of month-to-month and multi-year agreements and processing arrangements.

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We recognize loading and unloading fees when the volumes are delivered or received.

Natural gas storage related activities fees were recognized in the period the natural gas moved across our header system.

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

Reconciliation to Total Revenues of Reportable Segments.

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Total revenues $ 47,336

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Minimum Volume Commitments.

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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.

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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):

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

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.

The following are examples of contracts that are not included in the table above because they are not within the scope of ASC 606 or do not meet the requirements for presentation:

• Minimum volume commitments on certain of our joint venture pipeline systems;

• Acreage dedications;

• Buy/sell arrangements with future committed volumes;

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The presentation above does not include (i) expected revenues from legacy shippers not underpinned by minimum volume commitments, (ii) intersegment revenues and (iii) the amount of consideration associated with certain income generating contracts, which include a fixed minimum level of service, that are either not within the scope of ASC 606 or do not meet the requirements for presentation as remaining performance obligations.

The following are examples of contracts that are not included in the table above because they are not within the scope of ASC 606 or do not meet the requirements for presentation:

• Minimum volume commitments on certain of our joint venture pipeline systems;

• Acreage dedications;

• Buy/sell arrangements with future committed volumes;

• Short-term contracts and those with variable consideration due to the election of practical expedients, as discussed below;

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Note 5— Net Income Per Class A Share

Basic net income per Class A share is determined by dividing net income attributable to PAGP by the weighted average number of Class A shares outstanding during the period.

Basic net income per Class A share is determined by dividing net income attributable to PAGP from continuing operations and net income attributable to PAGP from discontinued operations by the weighted average number of Class A shares outstanding during the period.

Our Class B and Class C shares do not share in the earnings of the Partnership;

accordingly, basic and diluted net income per Class B and Class C share has not been presented.

Diluted net income per Class A share is determined by dividing net income attributable to PAGP by the diluted weighted average number of Class A shares outstanding during the period.

Diluted net income per Class A share is determined by dividing net income attributable to PAGP from continuing operations and net income attributable to PAGP from discontinued operations by the diluted weighted average number of Class A shares outstanding during the period.

For purposes of calculating diluted net income per Class A share, both the net income attributable to PAGP and the diluted weighted average number of Class A shares outstanding consider the impact of possible future exchanges of AAP units and the associated Class B shares into our Class A shares.

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See Note 18 for information regarding PAGP LTIP awards.

On a weighted-average basis, for the years ended December 31, 2024, 2023 and 2022, the possible exchange of 35 million, 44 million and 47 million AAP units, respectively, would not have had a dilutive effect on basic net income per Class A share.

For the years ended December 31, 2024, 2023 and 2022, our PAGP LTIP awards were dilutive;

however, this did not change the presentation of diluted weighted average Class A shares outstanding or diluted net income per Class A share.

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

Year Ended December 31,

2024 2023 2022

Basic and Diluted Net Income per Class A Share

Net income attributable to PAGP $ 103 $ 198 $ 168

Basic and diluted weighted average Class A shares outstanding 197 195 194

Basic and diluted net income per Class A share $ 0.52 $ 1.01 $ 0.86

On a weighted-average basis, for the years ended December 31, 2025, 2024 and 2023, the possible exchange of 35 million, 35 million and 44 million AAP units, respectively, was dilutive to net income per Class A share from discontinued operations.

The possible exchange did not result in dilution for net income per Class A share from continuing operations for any of the years presented.

Accordingly, the effect of the possible exchange of AAP units is included in the computation of diluted net income per Class A share for discontinued operations for these years and excluded from the calculation for all others.

For each of the years ended December 31, 2025, 2024 and 2023, our PAGP LTIP awards were also dilutive and are included in the calculation of diluted weighted average Class A shares outstanding, as applicable.

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

Year Ended December 31,

2025 2024 2023

Basic Net Income per Class A Share

Net income attributable to PAGP from continuing operations $ 152 $ 39 $ 144

Net income attributable to PAGP from discontinued operations

$ 108 $ 64 $ 54

Basic weighted average Class A shares outstanding 198 197 195

Basic Net Income per Class A Share:

Continuing operations $ 0.77 $ 0.19 $ 0.74

Discontinued operations 0.54 0.33 0.27

Basic net income per Class A share $ 1.31 $ 0.52 $ 1.01

Diluted Net Income per Class A Share

Net income attributable to PAGP from continuing operations $ 152 $ 39 $ 144

Net income attributable to PAGP from discontinued operations $ 108 $ 64 $ 54

Incremental net income attributable to PAGP resulting from assumed exchange of AAP Management Units 15 9 9

Net income attributable to PAGP from discontinued operations including incremental net income from assumed exchange of AAP Management Units

$ 123 $ 73 $ 63

Basic weighted average Class A shares outstanding

Dilutive shares resulting from assumed exchange of AAP Management Units 35 35 44

Diluted weighted average Class A shares outstanding 233 232 239

Diluted Net Income per Class A Share:

Continuing operations $ 0.77 $ 0.19 $ 0.74

Discontinued operations 0.53 0.32 0.26

Diluted net income per Class A share $ 1.30 $ 0.51 $ 1.00

Note 6— Inventory, Linefill and Long-term Inventory

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No adjustments were recorded during the years ended December 31, 2025, 2024 or 2023.

Linefill in assets we own is recorded at historical cost and consists of crude oil and NGL.

Linefill in assets we own is recorded at historical cost.

We classify as linefill (i) our proportionate share of barrels used to fill a pipeline that we own such that when an incremental barrel is pumped into or enters a pipeline it forces product out at another location and (ii) barrels that represent the minimum working requirements in tanks and caverns that we own.

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During 2025, 2024 and 2023, we did not recognize any material impairments of linefill.

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Minimum working inventory requirements in third-party assets and other working inventory in our assets that are needed for our commercial operations are included within specific inventory pools in inventory (a current asset) in determining the average cost of operating inventory.

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

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Note 7— 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.

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

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NGL storage, terminal, fractionation and processing facilities

NGL pipeline systems

Office property and equipment and rolling stock

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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.

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

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.

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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.

After assessing the results of such tests and the changing operating conditions of our California assets, we determined that we had a triggering event due to the effect on future cash flows for certain of our assets that required us to assess the recoverability of our carrying value of our California crude oil assets (which includes the temporarily idled pipeline) reported in our Crude Oil segment.

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, 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.

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

Note 8— Acquisitions, Divestitures and Other Transactions

Rattler Permian Transaction

In the third quarter of 2023, we completed a transaction with Rattler Midstream Operating LLC (“Rattler”) pursuant to which the Permian JV acquired the remaining 43 % interest in OMOG JV Holdings LLC (“OMOG”) and certain gathering assets in the Southern Delaware basin.

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

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

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

The transaction was accounted for as a business combination using the acquisition method of accounting.

In accordance with applicable accounting guidance, the fair value of the assets acquired and liabilities assumed following the transaction was utilized as the consideration transferred for the purchase price allocation.

As a result of us obtaining control over OMOG, the Permian JV’s previously-held 57 % interest in OMOG was remeasured to its fair value of $ 239 million based upon a valuation of the acquired business, as of the date of acquisition.

We considered multiple factors in determining the fair value of the previously-held equity method investment, including, (i) the price negotiated with Rattler for its 43 % interest in OMOG and (ii) a discounted cash flow approach.

The discounted cash flow approach utilized a discount rate of approximately 11 %, based on the estimate of the risk that a theoretical market participant would assign to the business.

The remeasurement of the Permian JV’s investment in OMOG to fair value resulted in a gain of $ 29 million.

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

EPIC (Cactus III)

On October 31, 2025, we purchased an aggregate 55 % equity interest in EPIC Crude Holdings, LP (“EPIC Crude Holdings”), which owns the EPIC Crude Oil Pipeline (which we now refer to as our “Cactus III Pipeline”), from subsidiaries of Diamondback Energy, Inc.

and Kinetik Holdings Inc., for approximately $ 1.568 billion, subject to certain adjustments and inclusive of $ 613 million of debt assumed.

We also agreed to a potential earnout payment of $ 193 million contingent upon the formal sanctioning before the end of 2027 of one or more expansions of Cactus III Pipeline that in the aggregate will increase the capacity of the pipeline to at least 900,000 barrels per day.

In a separate transaction, effective November 1, 2025, we acquired the remaining 45 % equity interest in EPIC Crude Holdings from a portfolio company of Ares Private Equity funds for approximately $ 1.327 billion, subject to certain adjustments and inclusive of $ 501 million of debt assumed.

We also agreed to a potential earnout payment to the seller of up to $ 157 million depending on the timing and amount of incremental expansion capacity up to 300,000 barrels per day in excess of 650,000 barrels per day that is formally sanctioned before the end of 2028.

The aggregate cash consideration also includes closing cash and working capital of approximately $ 121 million.

The estimated fair value of the aggregate earnout consideration recorded in connection with these transactions was approximately $ 115 million.

The fair value of the aggregate earnout consideration was determined based on weighted-average probabilities of certain capacity expansion scenarios and the related timing thereof.

Subsequent to these two transactions (collectively, the “EPIC acquisition”), we now own 100 % of EPIC Crude Holdings and are the operator of record for the Cactus III Pipeline, which provides long-haul crude oil takeaway from the Permian and Eagle Ford basins to the Gulf Coast market at Corpus Christi.

We believe this acquisition is highly synergistic and strategic to our existing footprint.

The EPIC acquisition will be accounted for in our Crude Oil segment.

The EPIC acquisition was accounted for as a business combination using the acquisition method of accounting.

The following table presents the fair value of the consideration in the EPIC acquisition (in millions):

Consideration:

Recognized Amount

Cash consideration $ 1,901

Contingent consideration 115

Total consideration $ 2,016

In accordance with applicable accounting guidance, the fair value of the assets acquired and liabilities assumed following the acquisition was utilized as the consideration transferred for the purchase price allocation.

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

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

The following table reflects

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our preliminary determination of the fair value of the assets acquired and liabilities assumed in connection with the EPIC acquisition (in millions):

Identifiable Assets Acquired and Liabilities Assumed:

Estimated Useful Lives

(in years) Recognized Amount

Working capital and other assets, net

Property and equipment, net

Intangible assets

Other long-term debt, net

Long-term operating lease liability

Total $ 2,016

The acquired Property and equipment, net is primarily comprised of pipelines, equipment and rights of way.

The intangible assets recognized in this transaction relate to long-term contracts which contain rates that are favorable to current market conditions.

We utilized widely accepted valuation techniques for these types of assets that represent Level 3 measurements in the fair value hierarchy.

A Level 3 measurement is one for which there are no observable market inputs.

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

The fair value of acquired rights of way was determined using a market approach for similar assets.

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

The useful lives of the favorable contracts range from 5 to 10 years, and amortization of these intangible assets is recognized using the declining balance method of amortization.

Amortization expense was approximately $ 15 million for the year ended December 31, 2025, and the future amortization expense through 2030 is estimated as follows (in millions):

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

On December 1, 2025, we repaid the $ 1.1 billion of borrowings outstanding under the EPIC term loan and terminated the EPIC credit agreement.

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

The EPIC term loan was valued at par based on the expectation of terminating the loan at such value.

During the year ended December 31, 2025, we incurred approximately $ 9 million of transaction-related costs associated with the EPIC acquisition.

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

Pro Forma and Other Financial Results

Financial results from the EPIC acquisition have been included in our results of operations within the Crude Oil segment since the date of the acquisition.

The EPIC revenues and earnings generated during the period since the acquisition date were not material for disclosure purposes.

The following selected unaudited pro forma results of operations were derived from the historical financial statements of EPIC Crude Holdings, and gives effect to the EPIC acquisition as if it had occurred on January 1, 2024.

The pro forma results of operations do not include any cost savings or other synergies that may result from the EPIC acquisition or any

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estimated costs that have been or will be incurred by us to integrate the assets acquired.

These results are not necessarily indicative of the results that might have actually occurred had the acquisition taken place on January 1, 2024;

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

Year Ended December 31,

Total revenues

$ 44,464 $ 49,124

Net income/(loss) attributable to PAGP from continuing operations

$ 136 $ ( 4 )

Basic and diluted net income/(loss) per Class A share from continuing operations

$ 0.69 $ ( 0.02 )

Ironwood Midstream

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

The Ironwood Midstream acquisition is accounted for in our Crude Oil segment.

In January 2025, in a separate transaction, we also repurchased from EnCap Flatrock Midstream, a portion of our outstanding Series A preferred units.

EnCap Flatrock Midstream is affiliated with EnCap Investments, L.P, an entity that is associated with a member of the board of directors of PAGP GP.

See Note 12 for additional information.

The Ironwood Midstream acquisition was accounted for as a business combination using the acquisition method of accounting.

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

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

While the purchase price for the transaction was $ 294 million, all of the OMOG assets and liabilities were remeasured to fair value and therefore, the fair value of the assets and liabilities that are now consolidated on the balance sheet as a result of this transaction is $ 532 million.

The following table reflects our determination of the fair value of the assets acquired and liabilities assumed in connection with the transaction (in millions):

The following table reflects our preliminary determination of the fair value of the Ironwood Midstream acquisition assets and liabilities (in millions):

Identifiable Assets Acquired and Liabilities Assumed:

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Working capital and other assets and liabilities N/A 19

The fair value of the tangible assets is a Level 3 measurement in the fair value hierarchy and was determined using the cost approach based on costs incurred on similar recent construction projects.

The fair value of the tangible asset is a Level 3 measurement in the fair value hierarchy and was determined using a cost approach for tangible assets, with an assumption for replacement cost, and a market approach for rights-of-way.

A Level 3 measurement is one for which there are no observable market inputs.

The fair value of the intangible assets is also a Level 3 measurement in the fair value hierarchy and was determined by applying a discounted cash flow approach.

Such approach utilized discount rates varying from approximately 21 % to 23 %, based on our estimate of the risk that a theoretical market participant would assign to the respective intangible assets.

Such approach utilized a discount rate of 18 %, based on our estimate of the risk that a theoretical market participant would assign to the intangible asset.

The projection of future crude oil volumes transported and the estimated tariff rates for transportation were also key assumptions in the valuation of the intangible assets.

Projected future volumes and estimated tariff rates were based on current contracts in place with assumptions for forecasted rate increases and contract renewals.

The fair value of intangible assets is comprised of customer relationships that will be amortized over their useful lives, which have a remaining weighted average life of approximately 10 years.

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

Amortization expense was approximately $ 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.

In November 2022, we and Enbridge Inc.

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

Enbridge acquired 10 % and we acquired 5 % of Cactus II, with each paying a proportionate share ($ 177 million and $ 88 million, respectively) of the aggregate purchase price.

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

We will continue to serve as operator.

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

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

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

The acquisition was accounted for as a business combination achieved in stages, or a “step acquisition”, using the acquisition method of accounting.

As the majority owner and the controlling entity, we are considered the acquirer and the Cactus II predecessor business was recorded based on the fair value of the assets acquired and liabilities assumed, with Enbridge’s 30 % interest in Cactus II of $ 526 million recognized as noncontrolling interest in partners’ capital.

The fair value of intangible asset is comprised of customer relationships that will be amortized over their useful lives, which have a remaining weighted average life of approximately 16 years.

The value assigned to such intangible asset will be

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As a result of us obtaining control over Cactus II, our previously held 65 % interest in Cactus II was remeasured to its fair value of $ 1.140 billion based upon a valuation of the acquired business, as of the date of acquisition.

We considered multiple factors in determining the fair value of the previously held equity method investment, including, (i) the price negotiated with WES for its 15 % interest in Cactus II and (ii) a discounted cash flow approach.

amortized to earnings under the declining balance method of amortization.

Amortization expense was approximately $ 4 million for the year ended December 31, 2025, and the future amortization expense through 2030 is estimated as follows (in millions):

Rattler Permian Transaction

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

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

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

The transaction was accounted for as a business combination using the acquisition method of accounting.

The discounted cash flow approach utilized a discount rate of approximately 11 %, based on the estimate of the risk that a theoretical market participant would assign to the business.

Prior to the acquisition, we had a preexisting relationship with Cactus II, through one of our consolidated joint ventures, for certain capacity lease agreements.

The portion of the fair value of Cactus II associated with these agreements is eliminated in consolidation.

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

The remeasurement of the Permian JV’s investment in OMOG to fair value resulted in a gain of $ 29 million.

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

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.

The consideration transferred of $ 1.556 billion excludes the value associated with the capacity lease agreements described above as such value is eliminated for our Consolidated Financial Statements.

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

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

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

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

The following table reflects our determination of the fair value of the assets acquired and liabilities assumed in connection with the transaction (in millions):

Identifiable Assets Acquired and Liabilities Assumed:

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Working capital and other assets and liabilities N/A 14

The fair value of the tangible assets is a Level 3 measurement in the fair value hierarchy and was determined using a market approach for rights-of-way and a cost approach for other tangible assets, which were based on costs incurred on similar recent construction projects.

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The fair value of the tangible assets is a Level 3 measurement in the fair value hierarchy and was determined using the cost approach based on costs incurred on similar recent construction projects.

The fair value of the intangible assets is also a Level 3 measurement in the fair value hierarchy and was determined by applying a discounted cash flow approach.

Such approach utilized a discount rate of approximately 18 %, based on our estimate of the risk that a theoretical market participant would assign to the respective intangible assets.

The projection of future crude oil volumes transported and the estimated tariff rates for transportation were also key assumptions in the valuation of the intangible assets.

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Amortization expense was approximately $ 10 million, $ 8 million and $ 4 million during the years ended December 31, 2025, 2024 and 2023, respectively, and the future amortization expense through 2028 is estimated as follows (in millions):

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 our general partner.

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.

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

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

See Note 9 for additional information about our investments in unconsolidated entities.

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

The Black Knight Midstream assets are accounted for in our Crude Oil segment.

• the acquisition in February 2025, through a non-monetary transaction, of the remaining 50 % interest in Cheyenne Pipeline LLC (“Cheyenne”) in exchange for the termination of certain obligations.

As a result of this transaction, we now own 100 % of Cheyenne and reflect such entity as a consolidated subsidiary in our Consolidated Financial Statements within our Crude Oil segment.

The transaction resulted in a net gain of approximately $ 31 million, which represents the difference between the fair value of the entity and the historical book value of our investment.

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

• the acquisition in January 2025 of EMG Medallion 2 Holdings, LLC and its subsidiaries, which own a crude oil gathering and transportation business in the Delaware Basin, for $ 163 million (approximately $ 106 million net to our 65 % interest in the Permian JV), subject to certain adjustments.

A cash deposit of approximately $ 16 million was paid upon signing in December 2024.

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

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• the acquisition in December 2024 of the remaining 50 % interest in Midway Pipeline LLC (“Midway”) for approximately $ 90 million.

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This transaction was accounted for as an asset acquisition since substantially all of the value of the assets acquired was concentrated in a single asset.

During the year ended December 31, 2022, we also completed the following acquisitions:

• the acquisition in July 2022 of the remaining 50 % interest in Advantage Pipeline Holdings LLC (“Advantage”) for $ 74 million (approximately $ 48 million net to our 65 % interest in the Permian JV), including cash paid for working capital.

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.

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• 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.

During the year ended December 31, 2025, we received cash proceeds of $ 81 million, primarily from the sale of non-core assets, which were previously included in our Crude Oil segment.

We recognized gains of approximately $ 44 million related to these asset sales, which is included in “(Gains)/losses on asset sales, asset impairments and other, net” on our Consolidated Statement of Operations.

In February 2023, we sold our 21 % non-operated/undivided joint interest in the Keyera Fort Saskatchewan facility to Keyera Corporation for approximately $ 270 million.

As of December 31, 2022, we classified the assets related to this transaction (primarily “Property and equipment” in our NGL segment), valued at the lower of the carrying amount or fair value less costs to sell, of approximately $ 130 million as assets held for sale on our Consolidated Balance Sheet (in “Other current assets”).

At the time of this transaction, we concluded that this disposition did not meet the criteria for discontinued operations.

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

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

The assets sold primarily consisted of land and related assets in Long Beach, California, as well as Line 901 and the Sisquoc to Pentland portion of Line 903.

These assets were previously reported in our Crude Oil segment.

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, asset impairments and other, net” on our Consolidated Statement of Operations.

Note 9— Investments in Unconsolidated Entities

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An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature.

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

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

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(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.

(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.

During 2025, we acquired the remaining 50 % interest in Cheyenne (which was previously presented in “Other investments” in the table above).

Prior to our acquisition, our 50 % interest in Cheyenne was accounted for as an equity method investment.

In addition, during 2025, we acquired an additional interest in BridgeTex, which we continue to account for as an equity method investment.

See Note 8 for additional information regarding these transactions.

During 2024, we acquired the remaining 50 % interest in Midway (which was previously presented in “Other investments” in the table above).

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See Note 8 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.

After the transaction, our ownership interest in OMOG increased to 57 % from 40 %.

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 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.

We now reflect OMOG and its subsidiaries as consolidated subsidiaries in our Consolidated Financial Statements.

See Note 7 for additional information.

In July 2022, we acquired the remaining 50 % interest in Advantage.

Prior to the acquisition, our 50 % interest in Advantage was accounted for as an equity method investment.

See Note 7 for additional information.

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 now reflect Cactus II as a consolidated subsidiary in our Consolidated Financial Statements.

See Note 7 for additional information.

See “Rattler Permian Transaction” in Note 8 for additional information.

Distributions

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Other distributions received from unconsolidated entities are considered a return of investment and classified as cash flows from investing activities on the Consolidated Statement of Cash Flows.

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Contributions

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The majority of the basis difference at both December 31, 2025 and 2024 was attributable to goodwill related to our ownership interest in BridgeTex with the remaining basis difference primarily related to capitalized interest incurred during construction of the assets of our unconsolidated entities.

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Summarized Financial Information of Unconsolidated Entities

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See Note 7 for a discussion of property and equipment.

(2) The increase in intangible assets in 2025 is associated with the assets acquired during the period.

See Note 8 for additional information.

Intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable.

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PAA senior notes:

3.60 % senior notes due November 2024 (2)

4.65 % senior notes due October 2025 (2)

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3.80 % senior notes due September 2030

4.70 % senior notes due January 2031

5.70 % senior notes due September 2034

5.95 % senior notes due June 2035

5.60 % senior notes due January 2036

6.70 % senior notes due May 2036

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Other long-term debt:

PAA commercial paper notes, bearing a weighted-average interest rate of 3.9 % (3)

PAA term loan, net of debt issuance costs of $ 1 , bearing a weighted-average interest rate of 5.0 %

Total long-term debt 10,696 7,211

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(1) PAA classified these commercial paper notes as short-term as of December 31, 2025 and 2024, as these notes were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.

(2) As of December 31, 2023, PAA classified its $ 750 million, 3.60 % senior notes due November 2024 as long-term based on its ability and intent to refinance these notes on a long-term basis at that time.

PAA redeemed these senior notes on November 1, 2024.

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

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

We estimated the aggregate fair value of these notes to be approximately $ 6.7 billion and $ 6.9 billion at December 31, 2024 and 2023, respectively.

PAA’s fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service.

Our determination of fair value is based on reported trading activity near the end of the reporting period.

We estimate that the carrying value of outstanding borrowings under PAA’s commercial paper program approximates fair value as interest rates reflect current market rates.

The fair value estimates for the PAA senior notes and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

(2) As of December 31, 2024, PAA classified its $ 1.0 billion, 4.65 % senior notes due October 2025 as long-term based on its ability and intent to refinance these notes on a long-term basis at that time.

PAA redeemed these senior notes on October 3, 2025.

(3) As of December 31, 2025, PAA classified its $ 750 million, 4.50 % senior notes due December 2026 as long-term based on its ability and intent to refinance the notes on a long-term basis.

(4) As of December 31, 2025, we classified a portion of our commercial paper notes as long-term based on our ability and intent to refinance such amounts on a long-term basis.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(5) PAA’s fixed-rate senior notes had a face value of approximately $ 9.2 billion and $ 7.2 billion as of December 31, 2025 and 2024, respectively.

We estimated the aggregate fair value of these notes as of December 31, 2025 and 2024 to be approximately $ 9.0 billion and $ 6.7 billion, respectively.

PAA’s fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service.

Our determination of fair value is based on reported trading activity near the end of the reporting period.

We estimate that the carrying value of outstanding borrowings under PAA’s commercial paper program and term loan approximate fair value as interest rates reflect current market rates.

The fair value estimates for the PAA senior notes, commercial paper program and term loan are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

PAA Commercial Paper Program

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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 2024, PAA 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.

The maturity date of the facility is August 2027 with respect to all extending lenders under the facility, except for a non-extending lender (which represents a commitment of approximately $ 64 million out of total commitments of $ 1.35 billion from all lenders), which has a maturity date of August 2026.

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

The maturity date of the facility is August 2029 with respect to all extending lenders under the facility, except for a non-extending lender (which represents a commitment of approximately $ 64 million out of total commitments of $ 1.35 billion from all lenders), which has a maturity date of August 2027.

EPIC credit agreement .

In connection with the EPIC Acquisition, completed on November 1, 2025, PAA assumed the EPIC credit agreement, which provided for a $ 1.2 billion term loan and a $ 125 million revolving credit facility.

Borrowings under the EPIC credit agreement accrued interest based, at our election, on certain floating rate indices as defined in the EPIC credit agreement, in each case, plus an applicable margin.

On December 1, 2025, PAA terminated the EPIC credit agreement and repaid the $ 1.1 billion of borrowings outstanding under the EPIC term loan.

Term Loan Agreement

On November 26, 2025, PAA entered into a term loan agreement that provides for a $ 1.1 billion senior unsecured term loan, which was funded on December 1, 2025.

The term loan will mature in November 2027.

PAA may at any time prepay amounts outstanding under the term loan agreement, in whole or in part, without premium or penalty.

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

Borrowings accrue interest based, at its election, on either Term SOFR or the Base Rate, in each case, plus an applicable rate.

From the closing date to (but excluding) the first anniversary of the closing date, the applicable rate is 1.125 % for Term SOFR Loans and 0.125 % for Base Rate Loans;

on and after the first anniversary, the applicable rate increases to 1.250 % for Term SOFR Loans and 0.250 % for Base Rate Loans.

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PAA Senior Notes

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PAA Senior Notes Issuances.

The table below summarizes PAA’s 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

The table below summarizes PAA’s issuances of senior unsecured notes during the three years ended December 31, 2025 (face value in millions):

Issuance Date

Description Maturity Face Value Interest Payment Dates

November 14, 2025 4.70 % senior notes issued at 99.872 % of face value

$ 300 January 15 and July 15

November 14, 2025 5.60 % senior notes issued at 100.518 % of face value

$ 450 January 15 and July 15

September 8, 2025 4.70 % senior notes issued at 99.865 % of face value

January 2031 $ 700 January 15 and July 15

September 8, 2025 5.60 % senior notes issued at 99.798 % of face value

$ 550 January 15 and July 15

January 15, 2025 5.95 % senior notes issued at 99.761 % of face value

$ 1,000 June 15 and December 15

June 27, 2024 5.70 % senior notes issued at 99.953 % of face value

September 2034

$ 650 March 15 and September 15

In January 2025, PAA 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.

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

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

PAA Senior Notes Repayments.

During the three years ended December 31, 2025, PAA repaid the following senior unsecured notes in full:

Repayment Date

Description Maturity

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

November 1, 2024 $ 750 million 3.60 % senior notes

November 2024

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

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

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PAA Senior Notes Repayments.

During the three years ended December 31, 2024, PAA repaid the following senior unsecured notes in full (in millions):

Year Description Repayment Date

2024 $ 750 million 3.60 % Senior Notes due November 2024

November 2024

2023 $ 700 million 3.85 % Senior Notes due October 2023

2023 $ 400 million 2.85 % Senior Notes due January 2023

2022 $ 750 million 3.65 % Senior Notes due June 2022

March 2022 (2)

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

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

The weighted average maturity of PAA’s senior notes outstanding at December 31, 2025 was approximately 10 years.

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Covenants and Compliance

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

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

PAA’s credit agreements prohibit declaration or payments of distributions on, or purchases or redemptions of, units if any default or event of default is continuing.

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• enter into certain burdensome agreements.

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The credit agreements for the PAA senior unsecured revolving credit facility and senior secured hedged inventory facility treat a change of control as an event of default and also require PAA 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)).

The credit agreements for the PAA senior unsecured revolving credit facility and senior secured hedged inventory facility and the term loan agreement treat a change of control as an event of default and also require PAA to maintain a debt-to-EBITDA coverage ratio that, on a trailing four-quarter basis, will not be greater than 5.00 to 1.00 (or 5.50 to 1.00 on all outstanding debt during an acquisition period (generally, the period consisting of three fiscal quarters following an acquisition greater than $ 150 million)).

For covenant compliance purposes, Consolidated EBITDA may include certain adjustments, including those for material projects and certain non-recurring expenses.

Additionally, letters of credit and borrowings to fund hedged inventory and margin requirements are excluded when calculating the debt coverage ratio.

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

As long as PAA is in compliance with the provisions contained in its credit agreements, PAA’s ability to make distributions of available cash is not restricted.

As of December 31, 2024, PAA was in compliance with the covenants contained in its credit agreements and indentures.

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

As long as PAA is in compliance with the provisions contained in its credit agreements and term loan agreement, PAA’s ability to make distributions of available cash is not restricted.

As of December 31, 2025, PAA was in compliance with the covenants contained in its credit agreements, term loan agreement and indentures.

Borrowings and Repayments

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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.

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Letters of Credit

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Use of the straight-line method does not differ materially from the “effective interest” method of amortization.

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Note 12— Partners’ Capital and Distributions

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Thus, the Class C shares function as a “pass-through” voting mechanism through which PAA votes at the direction of and as proxy for the PAA common unitholders (other than AAP) and Series A preferred unitholders in such director elections.

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Exchange and Redemption Rights

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Redemption Right exercises — ( 8,487,850 ) 8,487,850

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

Other 139,350 — 2,514,901

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196,416,760 36,237,168 539,445,289

Conversion of AAP Management Units — 388,839 —

Exchange Right exercises 846,937 ( 846,937 ) —

Redemption Right exercises — ( 8,487,850 ) 8,487,850

Other 202,002 — 2,559,549

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Exchange Right exercises 293,925 ( 293,925 ) —

Repurchase and cancellation of common units by a subsidiary under the Common Equity Repurchase Program

— — ( 476,695 )

Repurchase of Series A preferred units by a subsidiary

— — ( 12,678,560 )

Other 144,500 2,082,592

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197,904,124 35,096,306 530,932,175

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Distributions to Our Shareholders

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2023 $ 209 $ 1.0700

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On January 5, 2026, we declared a cash distribution of $ 0.4175 per outstanding Class A share.

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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.

Common Equity Repurchase Program

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Class C shares held by PAA associated with any publicly held common units that are repurchased will also be canceled.

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

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

During the year ended December 31, 2025, PAA repurchased common units under the Program through open market purchases for a total purchase price of $ 8 million, including commissions and fees.

The repurchased common units were canceled immediately upon acquisition, as were the Class C shares held by PAA associated with the repurchased common units.

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

At December 31, 2025, the remaining available capacity under the Program was $ 190 million.

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The quarterly distribution paid in May 2023 reflected a pro-rated amount of approximately $ 0.585 per unit.

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

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

EnCap Flatrock Midstream is affiliated with EnCap Investments, L.P., an entity that is associated with a member of our board of directors.

The repurchase also resulted in a reduction to the related Preferred Distribution Rate Reset Option liability.

The following table details distributions paid to PAA’s Series A preferred unitholders during the years presented (in millions, except unit data):

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2023 $ 166 $ 2.34

2022 $ 149 $ 2.10

(1) Includes distribution of approximately $ 10 million associated with PAA’s repurchase of Series A preferred units in January 2025.

On February 13, 2026, PAA paid a cash distribution of $ 36 million to its Series A preferred unitholders outstanding as of January 30, 2026.

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At December 31, 2025, approximately $ 9 million of accrued distributions payable to PAA’s Series B preferred unitholders was included in “Other current liabilities” on our Consolidated Balance Sheet.

PAA Common Unit Distributions.

After making distributions to its outstanding preferred units, PAA distributes the remainder of its available cash within 45 days following the end of each quarter to common unitholders of record, including AAP.

Available cash is generally defined as all of PAA’s cash and cash equivalents on hand at the end of each quarter, less reserves established in the discretion of its general partner for future requirements.

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

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

PAA Common Unit Distributions.

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

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

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2025 2024 2023

Permian JV (1)

$ 360 $ 322 $ 249

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$ 447 $ 425 $ 333

(1) The initial distribution from the Permian JV was paid during the first quarter of 2022, with approximately $ 54 million paid to noncontrolling interests.

Index to Financial Statements

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We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so.

We use various derivative instruments to optimize our profits while managing our exposure to commodity price risk and interest rate risk.

We use various derivative instruments to manage our exposure to commodity price risk, interest rate risk, and currency exchange rate risk.

Our commodity price risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity.

Our interest rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies.

Our interest rate risk and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies.

Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on changes in commodity prices or interest rates.

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In the normal course of our operations, we purchase and sell commodities.

We use derivatives to manage the associated risks and to optimize profits.

We use derivatives to manage the associated risks and, in certain circumstances, to optimize profits.

As of December 31, 2025, net derivative positions related to these activities included:

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

• A net long position of 5.8 million barrels associated with our crude oil purchases, which will be unwound ratably through March 2026 to match monthly average pricing.

• A net short time spread position of 1.9 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through April 2026.

• A net crude oil basis spread position of 1.5 million barrels at multiple locations through December 2026.

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

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

• A net short position of 6.9 million barrels through December 2029 related to anticipated net sales of crude oil inventory.

• A net long position of 0.5 TWh through December 2030 related to anticipated power supply requirements.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

We purchase natural gas for processing and operational needs.

Additionally, we purchase NGL mix for fractionation and sell the resulting individual specification products (including ethane, propane, butane and condensate).

In conjunction with these activities, we hedge the price risk associated with the purchase of the natural gas and the subsequent sale of the individual specification products.

The following table summarizes our open derivative positions utilized to hedge the price risk associated with anticipated purchases and sales related to our natural gas processing and NGL fractionation activities as of December 31, 2024.

Notional Volume

(Short)/Long Remaining Tenor

Natural gas purchases 49.3 Bcf

Propane sales ( 8.8 ) MMbls

Butane sales ( 1.3 ) MMbls

December 2025

Condensate sales ( 2.3 ) MMbls

December 2025

Fuel gas requirements (1)

December 2025

Power supply requirements (1)

December 2030

(1) Positions to hedge a portion of our power supply and fuel gas requirements at our Canadian natural gas processing and fractionation plants.

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

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On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin.

The following table provides the components of our net broker receivable/(payable) (in millions):

The following table provides the components of our net broker receivable (in millions):

Initial margin $ 16 $ 16

Variation margin posted/(returned)

Variation margin posted

Letters of credit ( 1 ) ( 9 )

Net broker receivable/(payable)

$ 72 $ ( 13 )

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PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Net broker receivable

The following table reflects the Consolidated Balance Sheet line items that include the fair values of our commodity derivative assets and liabilities and the effect of the collateral netting.

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Total $ 28 $ ( 32 ) $ 19 $ 15 $ 22 $ ( 25 ) $ 22 $ 19

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AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Interest Rate Risk Hedging

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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.

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

Hedged Transaction Number and Types of

Derivatives Employed

Termination Date

Average Rate Locked Accounting

Anticipated interest payments 8 forward starting swaps

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

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.

During the year ended December 31, 2025, we terminated $ 200 million of notional interest hedging instruments previously expected to terminate in October 2025 for proceeds of $ 7 million and $ 200 million of notional interest hedging instruments previously expected to terminate in June 2026 for proceeds of $ 30 million which were recorded in AOCI.

As of December 31, 2025, there was a net loss of $ 29 million deferred in AOCI.

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thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

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

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

Year Ended December 31,

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Interest rate derivatives, net $ 10 $ 29 $ 15

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.

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AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2025, we did not have any interest rate hedges recorded on our Consolidated Balance Sheet.

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

Currency Exchange Rate Risk Hedging

In connection with the pending sale of the Canadian NGL Business, we entered into a forward currency instrument (CAD$ 4.5 billion notional amount) to hedge currency exchange risk.

The instrument is contingent upon the sale occurring and will settle at closing.

The cost of the deal-contingent structure is embedded in the hedge rate.

As of December 31, 2025, the sale of the Canadian NGL Business is probable and the fair value of the instrument is an $ 8 million asset, presented in “Other current assets” on our Consolidated Balance Sheet.

For the year ended December 31, 2025, we recognized the gains of $ 8 million, which was included in “(Gains)/losses on asset sales, asset impairments and other, net” on our Consolidated Statements of Operations.

As of December 31, 2025, for the periods covered by the instrument, the average fixed USD to CAD rate of the instrument is $ 1.37 and the average forward USD to CAD rate is $ 1.37 .

See Note 1 for additional information regarding the pending sale of the Canadian NGL Business.

Preferred Distribution Rate Reset Option

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The Preferred Distribution Rate Reset Option embedded derivative was required to be bifurcated from the related host contract, the PAA partnership agreement, and recorded at fair value on our Consolidated Balance Sheet.

The fair value of the Preferred Distribution Rate Reset Option, which was included in “ Other long-term liabilities and deferred credits ” on our Consolidated Balance Sheet, totaled $ 189 million at December 31, 2022.

The Preferred Distribution Rate Reset Option was settled when we received notice that the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option.

The fair value of the Preferred Distribution Rate Reset Option on the settlement date was $ 131 million.

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 and 2022, we recognized a gain of $ 58 million, and a net loss of $ 189 million, respectively.

The Preferred Distribution Rate Reset Option embedded derivative was not designated in a hedging relationship for accounting purposes and corresponding changes in fair value were recognized in “Other income, net” in our Consolidated Statements of Operations.

The Preferred Distribution Rate Reset Option was settled at a fair value of $ 131 million when we received notice that the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option, which resulted in a gain of $ 58 million, for the year ended December 31, 2023.

See Note 12 for additional information regarding the Preferred Distribution Rate Reset Option.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Recurring Fair Value Measurements

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Interest rate derivatives — — — — 27 27

Foreign currency derivatives — 8 8 — — —

Total net derivative asset/(liability) $ ( 2 ) $ 6 $ 4 $ 11 $ 13 $ 24

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The fair value of exchange-traded commodity derivatives and over-the-counter commodity contracts is based on unadjusted quoted prices in active markets.

Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives and over-the-counter commodity and interest rate derivatives that are traded in observable markets with less volume and transaction frequency than active markets.

Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives, over-the-counter commodity, foreign exchange and interest rate derivatives that are traded in observable markets with less volume and transaction frequency than active markets.

In addition, it includes certain physical commodity contracts.

The fair values of these derivatives are corroborated with market observable inputs.

Level 3 of the fair value hierarchy includes the Preferred Distribution Rate Reset Option contained in our partnership agreement which was classified as an embedded derivative.

As discussed above, the Preferred Distribution Rate Reset Option was settled on January 31, 2023.

The fair value of the Preferred Distribution Rate Reset Option was 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, PAA’s common unit price, and default probabilities which impacted timing estimates as to when the option would be exercised.

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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 the Preferred Distribution Rate Reset Option embedded derivative, which was classified as Level 3 in the fair value hierarchy (in millions):

Beginning Balance $ ( 189 )

Gain for the period included in earnings 58

Settlements 131

Ending Balance $ —

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

Note 14— 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, storage tanks, land and vehicles.

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

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

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Our lease agreements do not contain any material restrictive covenants.

For determining the present value of lease payments, we use the discount rate implicit in the lease when readily determinable;

however, such rate is not readily determinable for most of our leases.

For those leases for which the discount rate is not readily determinable, we utilize incremental borrowing rates that reflect collateralized borrowing with payments and terms that mirror our lease portfolio to discount the lease payments based on information available at the lease commencement date.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For determining the present value of lease payments, we use the discount rate implicit in the lease when readily determinable;

however, such rate is not readily determinable for most of our leases.

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

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We have elected the non-lease component separation practical expedient for all classes of assets where we are the lessor.

We enter into agreements to conduct activities associated with (i) providing storage services primarily for crude oil and NGL and (ii) transporting crude oil and NGL.

We enter into agreements to conduct activities associated with (i) providing storage services primarily for crude oil and (ii) transporting crude oil.

Certain of these agreements convey counterparties the right to direct the operation of physically distinct assets.

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All of our Canadian operations are conducted by entities that are treated as corporations for Canadian tax purposes (flow through for U.S.

income tax purposes) and that are subject to Canadian federal and provincial taxes.

income tax purposes) and thus are subject to Canadian federal and provincial taxes.

Additionally, payments of interest and dividends from our Canadian entities to other Plains entities are subject to Canadian withholding tax that is treated as income tax expense.

Tax Components

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

Year Ended December 31,

2025 2024 2023

United States

$ 1,350 $ 832 $ 1,130

Total pre-tax book income

$ 1,395 $ 963 $ 1,362

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

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2025 2024 2023

Current income tax expense:

Current income tax expense/(benefit):

State income tax $ 2 $ 2 $ 2

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federal income tax

$ 71 $ 31 $ 55

State income tax 6 6 13

Canadian federal and provincial income tax ( 28 ) ( 24 ) 105

Canadian federal and provincial income and withholding taxes

Total deferred income tax expense

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$ 92 $ 124 $ 129

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

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

Year Ended December 31,

2025 2024 2023

Income before tax

Amount Percent

federal statutory tax rate

$ 293 21.00 % $ 202 21.00 % $ 286 21.00 %

Net income attributable to noncontrolling interests

State and local income taxes (1)

8 0.57 % 8 0.87 % 15 1.08 %

Income taxes attributable to noncontrolling interests ( 167 ) ( 121 ) ( 189 )

Foreign tax effects:

Foreign rate differential ( 3 ) ( 0.22 ) % ( 8 ) ( 0.81 ) % ( 14 ) ( 1.02 ) %

Provincial taxes 5 0.36 % 13 1.22 % 20 1.50 %

Foreign withholding taxes

3 0.22 % 52 5.43 % — — %

Federal statutory income tax rate 21 % 21 % 21 %

Income tax expense at statutory rate

Other ( 2 ) ( 0.14 ) % — — % 4 0.32 %

Nontaxable or nondeductible items:

Nontaxable income attributable to noncontrolling interests

( 212 ) ( 15.20 ) % ( 143 ) ( 14.97 ) % ( 180 ) ( 13.25 ) %

Deferred tax rate adjustment 6 9 7

State income tax, net of federal benefit 2 3 3

Income taxes attributable to noncontrolling interests:

Canadian federal and provincial income tax 113 119 188

Canadian withholding tax 52 — —

State income tax 2 2 1

Total income tax expense

Other permanent book tax differences

— — % — — % ( 2 ) ( 0.14 ) %

Effective tax rate (2)

$ 92 6.59 % $ 124 12.84 % $ 129 9.48 %

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

(2) Consolidated pretax income includes amounts attributable to non-controlling interests.

Income attributable to non-controlling interests does not result in income tax expense of the reporting entity because the related taxes are incurred by the noncontrolling owners.

Accordingly, the effective tax rate reconciliation includes a reconciling item for income attributable to non-controlling interests.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Disclosures

Cash taxes paid were as follows (in millions):

Year Ended December 31,

2025 2024 2023

State income tax:

Total state income tax paid

Canadian federal and provincial income and withholding taxes

Total cash tax paid

$ 98 $ 269 $ 69

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

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Property and equipment in excess of tax values ( 204 ) ( 188 )

Derivative instruments — ( 6 )

Lease assets ( 9 ) ( 10 )

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Other long-term liabilities and deferred credits ( 197 ) ( 176 )

$ 939 $ 1,044

As a result of the exchange of the ownership interest in AAP in connection with our IPO and all subsequent exchanges, a deferred tax asset was created.

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The deferred tax asset is amortized to deferred income tax expense as the associated basis step-up is realized on our tax returns.

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PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2025, our federal and state net operating loss carryforwards for income tax purposes were approximately $ 4,482 million and $ 1,134 million, respectively.

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and state tax years are generally open to examination from 2022 to 2025.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2025, in reference to tax years 2012 to 2019, we had received notices of reassessment (“notices”) from the Canada Revenue Agency and the Alberta Tax and Revenue Administration (the “Canadian Tax Authorities”) related primarily to transfer pricing associated with cross-border intercompany financing transactions.

These notices include assessments, including penalties and interest, associated with these transfer pricing matters totaling approximately $ 177 million (based on the exchange rate as of December 31, 2024).

The notices include assessments, including penalties and interest, associated with these transfer pricing matters totaling approximately $ 189 million (based on the exchange rate as of December 31, 2025).

Payment of a portion of the assessment is required in order to file a notice of objection to dispute the reassessment.

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Note 16— Major Customers and Concentration of Credit Risk

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 year ended December 31, 2023.

ExxonMobil Corporation and its subsidiaries accounted for approximately 31 %, 31 % and 27 % of our revenues for the years ended December 31, 2025, 2024 and 2023, respectively.

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

No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2025.

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Omnibus Agreement

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

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

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

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PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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These transactions were conducted at posted tariff rates or prices that we believe approximate market.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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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.

(1) Primarily includes amounts related to transportation and storage services.

(2) We have agreements to store crude oil at facilities and transport crude oil or utilize capacity on pipelines that are owned by equity method investees.

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We have elected to recognize forfeitures of awards when they occur.

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PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Our LTIP awards contain (i) time-based vesting criteria, (ii) performance conditions, (iii) market conditions or (iv) a combination of time-based vesting criteria and performance conditions.

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For awards with market conditions, the probable outcomes are determined on the respective dates that the fair values are calculated, and the resulting expense is accrued over the service period.

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PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The following is a summary of the awards authorized under our LTIPs as of December 31, 2024 (in millions):

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

Awards Authorized

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The remaining balance has already vested or is currently outstanding.

As of December 31, 2024, 10.5 million PAA LTIP awards and 0.1 million PAGP LTIP awards were outstanding.

As of December 31, 2025, 10.5 million PAA LTIP awards and 0.1 million PAGP LTIP awards were outstanding (including those associated with discontinued operations).

Of the awards outstanding, 8.9 million PAA LTIP awards and 0.1 million PAGP LTIP awards include associated DERs.

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We have commitments (some of which are leases) related to real property, equipment and operating facilities.

We also incur costs associated with leased land, rights-of-way, permits and regulatory fees.

Future noncancelable commitments related to these items at December 31, 2025 are summarized below (in millions):

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(1) Includes both operating and finance leases as defined by FASB guidance.

Leases are primarily for (i) railcars, (ii) office space, (iii) land, (iv) vehicles, (v) storage tanks and (vi) tractor trailers.

Leases are primarily for (i) office space, (ii) land, (iii) vehicles, (iv) storage tanks and (v) tractor trailers.

See Note 14 for additional information.

(2) Primarily includes storage, transportation and pipeline throughput agreements, as well as certain rights-of-way easements.

Expense associated with our storage, transportation and pipeline throughput agreements was approximately $ 387 million, $ 396 million and $ 336 million for 2024, 2023 and 2022, respectively.

(2) Primarily includes storage, transportation and pipeline throughput agreements.

Expense associated with such agreements was approximately $ 363 million, $ 341 million and $ 348 million for 2025, 2024 and 2023, respectively.

A majority of the storage, transportation and pipeline throughput commitments are associated with agreements to store crude oil at facilities and transport crude oil on pipelines owned by equity method investees at posted tariff rates or prices that we believe approximate market.

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

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.

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PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Loss Contingencies — General

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In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred.

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PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote.

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We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated.

Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action.

Generally, our recording of these liabilities coincides with our completion of a feasibility study or our commitment to a formal plan of action.

We do not discount our environmental remediation liabilities to present value.

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We record receivables for amounts we believe are recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery.

Environmental expenditures that pertain to current operations or to future revenues are expensed or capitalized consistent with our capitalization policy for property and equipment.

Expenditures that result from the remediation of an existing condition caused by past operations and that do not contribute to current or future profitability are expensed.

Our estimated undiscounted 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):

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Environmental expenditures that pertain to current operations or to future revenues are expensed or capitalized consistent with our capitalization policy for property and equipment.

Expenditures that result from the remediation of an existing condition caused by past operations and that do not contribute to current or future profitability are expensed.

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

2025 December 31,

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Total $ 83 $ 80

(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.

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Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing or future legal claims giving rise to additional liabilities.

Therefore, although we believe that the reserve is adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of the reserve and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

Therefore, although we believe that our reserves are adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of such reserves and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

Specific Legal, Environmental or Regulatory Matters

Line 901 Incident .

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

A portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert.

Following the release, we shut down the pipeline and initiated our emergency response plan.

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 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, most of which have been resolved.

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

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.

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.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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.

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.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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.

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

Effective as of December 31, 2025, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $ 870 million, which includes actual emergency response and clean-up costs, natural resource damage assessments, fines and penalties incurred, certain third-party claims settlements, and estimated costs associated with our remaining Line 901 lawsuits and claims as described below, as well as estimates for certain legal fees and statutory interest where applicable.

We accrue such estimates of aggregate total costs to “Field operating costs” in our Consolidated Statements of Operations.

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Also, the amount of time it takes for us to resolve all of the current and future lawsuits and claims that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated.

Accordingly, our assumptions and estimates may turn out to be inaccurate and our total costs could turn out to be materially higher;

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, 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, 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.

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.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Other Litigation Matters.

During the year ended December 31, 2025, we did not recognize any costs related to the Line 901 incident.

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

As of December 31, 2025 and 2024, we had a remaining undiscounted gross liability of approximately $ 22 million and $ 5 million, respectively, related to the Line 901 incident, which aggregate amounts are reflected in “Current liabilities” on our Consolidated Balance Sheet.

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

To date, we have collected approximately $ 295 million of the $ 500 million available under our 2015 insurance program.

With respect to the Line 901 incident, we do not have any amounts recorded as receivables that are recognized on our Consolidated Balance Sheets as of December 31, 2025 and 2024.

We have completed the required clean-up and remediation work with respect to the Line 901 incident;

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

During the second quarter of 2025, we agreed to confidential settlement terms for various lawsuits filed in California Superior Court in Santa Barbara County by companies and individuals who provided labor, goods, or services associated with oil production activities they claim were disrupted following the Line 901 incident, the agreed aggregate settlement amount has been factored into our Line 901 total cost estimate.

The only other remaining Line 901 lawsuit is pending in California Superior Court in Santa Barbara County, in which a landowner on an adjacent pipeline is alleging property damage from the “stigma” of the Line 901 incident.

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

Taking into account the costs that we have included in our total estimate of costs for the Line 901 incident and considering what we regard as very strong defenses to the claims made in our remaining Line 901 lawsuits, we do not believe the ultimate resolution of such remaining lawsuit will have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

L48 Pipeline Release.

In March of 2025, our subsidiary, Pacific Pipeline System LLC, experienced a crude oil release of approximately 125 barrels on a segment of the Line 48 pipeline in Carson, California.

Clean-up and remediation activities were conducted in cooperation with applicable state and federal regulatory agencies.

An investigation by the California Office of the State Fire Marshall is not complete.

To date no charges, fines or penalties have been assessed against us with respect to this release;

however, it is possible that charges, fines or penalties may be assessed against us in the future.

We provided notification to our applicable insurance carriers and intend to pursue reimbursement of any costs incurred in excess of our $ 10 million self-insured retention.

We estimate that the aggregate cost to clean-up and remediate the site will be approximately $ 20 million.

Through December 31, 2025, we incurred $ 12 million in connection with clean-up and remediation activities.

On July 19, 2022, Hartree Natural Gas Storage, LLC (“Hartree”) filed a lawsuit under seal in the Superior Court for the State of Delaware asserting claims against PAA Natural Gas Storage, L.P.

and PAA arising out of a Membership Interest Purchase Agreement relating to the 2021 sale of the Pine Prairie Energy Center natural gas storage facility to Hartree.

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.

In early 2025, w e entered into a settlement agreement with Hartree;

the terms of the settlement are confidential and the amount paid is not material to our operations.

All of Hartree’s claims were dismissed with prejudice and without any admission of wrongdoing by Plains.

Louisiana Coastal Erosion Lawsuit.

Various coastal parishes, the State of Louisiana and some of its departments have filed lawsuits in Louisiana against a number of energy companies seeking damages for coastal erosion in connection with oil and gas operations in Louisiana.

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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.

LADWF alleges that the Defendants breached the terms of the ROWs by failing to prevent erosion and seeks restoration of the Wildlife Refuge or alternatively monetary compensatory damages including restoration costs, legal fees and disgorgement of profits derived from the alleged trespass.

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

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.

We settled this lawsuit in January 2026 for a payment from Plains of $ 1.5 million.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 20— Segment Information

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The Crude Oil segment includes our crude oil pipelines, crude oil storage and marine terminals and related crude oil marketing activities.

The NGL segment includes our NGL pipelines, NGL storage, natural gas processing and NGL fractionation facilities and related NGL marketing activities.

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 crude oil marketing activities are included in our Crude Oil reporting segment as its primary purpose is to support the utilization of our assets by entering into transactions that facilitate increased volumes handled by our assets, resulting in additional earnings for the segment.

The NGL segment includes our NGL assets primarily located in the Southwestern United States.

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

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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 GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Segment Adjusted EBITDA excludes depreciation and amortization.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

Crude Oil NGL Intersegment

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Foreign currency revaluation (8)

Line 901 incident (9)

Transaction-related expenses (9)

Segment amounts attributable to noncontrolling interests in consolidated joint ventures (10)

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Line 901 incident (13)

Transaction-related expenses (13)

Segment amounts attributable to noncontrolling interests in consolidated joint ventures (10)

27 unchanged sentences

Derivative activities and inventory valuation adjustments (4)

( 11 ) ( 269 )

Long-term inventory costing adjustments (5)

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Line 901 incident (13)

Transaction-related expenses (9)

Segment amounts attributable to noncontrolling interests in consolidated joint ventures (10)

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(3) Includes our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities.

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

Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Segment Adjusted EBITDA such that the earnings from the derivative instruments and the underlying transactions impact Segment Adjusted EBITDA in the same period.

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

Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction.

In the course of evaluating our results, we identify differences in the timing of earnings from the derivative instruments and the underlying transactions and exclude the related gains and losses in determining Segment Adjusted EBITDA such that the earnings from the derivative instruments and the underlying transactions impact Segment Adjusted EBITDA in the same period.

In addition, we exclude gains and losses on derivatives that are related to (i) investing activities, such as the purchase of linefill, and (ii) purchases of long-term inventory.

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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.

(9) Primarily related to deal-specific costs incurred during the years presented.

See Note 8 for additional discussion.

An adjustment for these non-recurring expenses is included in the calculation of Segment Adjusted EBITDA for the years ended December 31, 2025 and 2023 as our CODM does not view such expenses as integral to understanding our core segment operating performance.

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

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

(12) These amounts combined represent total capital expenditures.

(13) Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance (as applicable).

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See Note 19 for additional information regarding the Line 901 incident.

(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 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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Segment Adjusted EBITDA Reconciliation

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

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

Year Ended December 31,

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( 467 ) ( 382 ) ( 386 )

Other income/(expense), net

17 102 ( 219 )

Income before tax

1,274 1,614 1,409

Income tax expense

( 204 ) ( 189 ) ( 246 )

Other income, net

Income from continuing operations before tax

1,395 963 1,362

Net income attributable to noncontrolling interests

Income tax expense from continuing operations

( 92 ) ( 124 ) ( 129 )

Net income attributable to PAGP

Income from continuing operations, net of tax

$ 1,303 $ 839 $ 1,233

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

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 21— Selected Quarterly Financial Data (Unaudited)

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

See Note 1 for additional information.

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

First Quarter

Second Quarter

Third Quarter

Fourth Quarter

Year Ended December 31, 2025

Total revenues

$ 11,477 $ 10,642 $ 11,578 $ 10,565 $ 44,262

Gross margin (2)

$ 440 $ 321 $ 567 $ 447 $ 1,776

Operating income

$ 353 $ 237 $ 483 $ 354 $ 1,428

Income from continuing operations, net of tax

$ 356 $ 213 $ 428 $ 306 $ 1,303

Income from discontinued operations, net of tax

$ 136 $ 70 $ 76 $ 102 $ 383

$ 492 $ 283 $ 504 $ 408 $ 1,686

Net income attributable to PAGP

$ 84 $ 30 $ 83 $ 62 $ 260

Basic net income per Class A share:

Continuing operations

$ 0.23 $ 0.05 $ 0.31 $ 0.17 $ 0.77

Discontinued operations

0.19 0.10 0.11 0.14 0.54

Basic net income per Class A share

$ 0.42 $ 0.15 $ 0.42 $ 0.31 $ 1.31

Diluted net income per Class A share:

Continuing operations

$ 0.23 $ 0.05 $ 0.31 $ 0.17 $ 0.77

Discontinued operations

0.19 0.10 0.10 0.14 0.53

Diluted net income per Class A share

$ 0.42 $ 0.15 $ 0.41 $ 0.31 $ 1.30

Year Ended December 31, 2024

Total revenues

$ 11,639 $ 12,757 $ 12,456 $ 12,035 $ 48,889

Gross margin (2)

$ 437 $ 411 $ 282 $ 67 $ 1,196

Operating income/(loss)

$ 355 $ 330 $ 195 $ ( 17 ) $ 862

Income from continuing operations, net of tax

$ 326 $ 284 $ 187 $ 42 $ 839

Income from discontinued operations, net of tax

$ 10 $ 32 $ 114 $ 74 $ 231

$ 336 $ 316 $ 301 $ 116 $ 1,070

Net income/(loss) attributable to PAGP

$ 42 $ 39 $ 33 $ ( 11 ) $ 103

Basic net income/(loss) per Class A share:

Continuing operations

$ 0.20 $ 0.15 $ 0.01 $ ( 0.16 ) $ 0.19

Discontinued operations

0.01 0.05 0.16 0.11 0.33

Basic net income/(loss) per Class A share

$ 0.21 $ 0.20 $ 0.17 $ ( 0.05 ) $ 0.52

Diluted net income/(loss) per Class A share:

Continuing operations

$ 0.20 $ 0.15 $ 0.01 $ ( 0.16 ) $ 0.19

Discontinued operations

0.01 0.04 0.16 0.11 0.32

Diluted net income/(loss) per Class A share

$ 0.21 $ 0.19 $ 0.17 $ ( 0.05 ) $ 0.51

(1) The sum of the four quarters may not equal the year due to rounding.

(2) Gross margin is calculated as Total revenues less (i) Purchases and related costs, (ii) Field operating costs, (iii) Depreciation and amortization and (iv) (Gains)/losses on asset sales, asset impairments and other, net.

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

What changed 10-K

Item 9A. Controls and Procedures