What changed in this filing

/stocks — the workspaceLOADING

Item 9A. Controls and Procedures

2024-02-29 compared with 2023-03-01 · 418 added, 468 removed, 1990 unchanged (31% of the section changed)

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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, 2023, the end of the period covered by this report, and, based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our DCP is effective.

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Internal Control over Financial Reporting

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There have been no changes in our internal control over financial reporting during the fourth quarter of 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Certifications

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Other Information

There was no information that was required to be disclosed in a report on Form 8-K during the fourth quarter of 2022 that has not previously been reported.

During the quarter ended December 31, 2023, none of our directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted or terminated a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K).

Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

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Directors and Executive Officers of Our General Partner and Corporate Governance

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Kevin McCarthy (2)

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

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

Managing Partner, EnCap Investments L.P.

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The information required by this item will be set forth in the Proxy Statement for our 2024 Annual Meeting, which will be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2023, and is incorporated herein by reference thereto.

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Certain Relationships and Related Transactions, and Director Independence

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Exhibits and Financial Statement Schedules

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

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

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

3.14 — Amendment No.

3 dated August 17, 2023 to the Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P.

(incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed August 21, 2023).

3.15 — Certificate of Incorporation of PAA Finance Corp.

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

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

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

4.1 — Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp.

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

4.5 — Twenty-Second Supplemental Indenture (2.85% Senior Notes due 2023) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp.

Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed December 12, 2012).

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— Twenty-Third Supplemental Indenture (4.30% Senior Notes due 2043) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp.

Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 12, 2012).

4.7 — Twenty-Fourth Supplemental Indenture (3.85% Senior Notes due 2023) dated August 15, 2013, by and among Plains All American Pipeline, L.P., PAA Finance Corp.

Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed August 15, 2013).

4.6 — Twenty-Fifth Supplemental Indenture (4.70% Senior Notes due 2044) dated April 23, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp.

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

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

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

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

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1 to Third Amended and Restated Employment Agreement dated effective December 31, 2021 between Plains All American GP LLC and Greg L.

Armstrong (i ncorporated by reference to Exhibit 10.12 to o ur Annual Report on Form 1 0-K for the year ended December 31, 202 1) .

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

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

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

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

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

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

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

10.22** — First Amendment to Plains AAP, L.P.

Class B Restricted Units Agreement dated August 25, 2016 (Willie Chiang) (incorporated by reference to Exhibit 10.8 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2016).

10.23** — Second Amendment dated March 22, 2018 to Plains AAP, L.P.

Class B Restricted Units Agreement (Willie Chiang) (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).

— 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).

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

10.30** — Form of Plains AAP, L.P.

Class B Restricted Units Agreement (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed January 4, 2008).

10.31** — Form of Amendment to the Plains AAP, L.P.

Class B Restricted Units Agreement dated October 18, 2013 (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed October 25, 2013).

10.32** — Form of Amendment to Plains AAP, L.P.

Class B Restricted Units Agreement dated August 25, 2016 (incorporated by reference to Exhibit 10.6 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 filed November 8, 2016).

10.33** — Form of First Amendment dated March 22, 2018 to Amended and Restated Plains AAP, L.P.

Class B Restricted Units Agreement dated August 25, 2016 (Officers) (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).

— 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).

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10.35** — Form of LTIP Grant Letter dated August 15, 2019 (Directors) (incorporated by reference to E xhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).

10.36** — Director LTIP Grant Letter (January 2020) (incorporated by reference to Exhibit 10.72 to our Annual Report on Form 10-K for the year ended December 31, 2019).

10.37** — Form of LTIP Grant Letter dated August 13, 2020 (Officers) (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2020).

— 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).

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

10.40** — Form of LTIP Grant Letter dated August 19, 2021 (Named Executive Officers) (incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2021).

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

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— Form of LTIP Grant Letter dated August 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).

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

— Form of LTIP Grant Letter dated August 17, 2023 (Directors) (incorporated by reference to Exhibit 10.

2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2023).

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

23.1 † — Consent of PricewaterhouseCoopers LLP.

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

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

— Amended and Restated Clawback Policy .

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

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

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** Management compensatory plan or arrangement.

Form 10-K Summary

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

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February 28, 2024

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

Name Title Date

/s/ Willie Chiang Chairman of the Board of PAA GP Holdings LLC and Chief Executive Officer of Plains All American GP LLC (Principal Executive Officer) February 28, 2023

/s/ Willie Chiang

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

Willie Chiang

Pefanis Director of PAA GP Holdings LLC and President of Plains All American GP LLC February 28, 2023

/s/ Al Swanson Executive Vice President and Chief Financial Officer of Plains All American GP LLC (Principal Financial Officer) February 28, 2023

/s/ Chris Herbold Senior Vice President, Finance and Chief Accounting Officer of Plains All American GP LLC (Principal Accounting Officer) February 28, 2023

Director of PAA GP Holdings LLC and President of Plains All American GP LLC February 28, 2024

/s/ Al Swanson

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

/s/ Chris Herbold

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

Chris Herbold

Armstrong Director of PAA GP Holdings LLC February 28, 2023

/s/ Victor Burk Director of PAA GP Holdings LLC February 28, 2023

DeSanctis Director of PAA GP Holdings LLC February 28, 2023

/s/ Kevin McCarthy Director of PAA GP Holdings LLC February 28, 2023

Director of PAA GP Holdings LLC February 28, 2024

/s/ Victor Burk

Director of PAA GP Holdings LLC February 28, 2024

/s/ Kevin McCarthy

Director of PAA GP Holdings LLC February 28, 2024

Kevin McCarthy

Petersen Director of PAA GP Holdings LLC February 28, 2023

Director of PAA GP Holdings LLC February 28, 2024

/s/ Alexandra D.

Pruner Director of PAA GP Holdings LLC February 28, 2023

Raymond Director of PAA GP Holdings LLC February 28, 2023

Shackouls Director of PAA GP Holdings LLC February 28, 2023

Director of PAA GP Holdings LLC February 28, 2024

/s/ Christopher M.

Temple Director of PAA GP Holdings LLC February 28, 2023

Director of PAA GP Holdings LLC February 28, 2024

Christopher M.

/s/ Lawrence M.

Ziemba Director of PAA GP Holdings LLC February 28, 2023

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Director of PAA GP Holdings LLC February 28, 2024

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PLAINS ALL AMERICAN PIPELINE, L.P.

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Consolidated Statements of Operations for the years ended December 31, 2023, 2022 and 2021

Consolidated Statements of Comprehensive Income/(Loss) for the years ended December 31, 2022, 2021 and 2020

Consolidated Statements of Comprehensive Income for the years ended December 31, 2023, 2022 and 2021

Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss) for the years ended December 31, 2023, 2022 and 2021

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Revenues and Accounts Receivable

Net Income/(Loss) Per Common Unit

Net Income Per Common Unit

Inventory, Linefill and Long-term Inventory

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Segment Information

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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February 28, 2024

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Report of Independent Registered Public Accounting Firm

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We have audited the accompanying consolidated balance sheets of Plains All American Pipeline, L.P.

and its subsidiaries (the “Partnership”) as of December 31, 2022 and 2021, and the related consolidated statements of operations, of comprehensive income (loss), of changes in accumulated other comprehensive income (loss), of changes in partners' capital and of cash flows for each of the three years in the period ended December 31, 2022, including the related notes (collectively referred to as the “consolidated financial statements”).

and its subsidiaries (the “Partnership”) as of December 31, 2023 and 2022, and the related consolidated statements of operations, of comprehensive income, of changes in accumulated other comprehensive income (loss), of changes in partners’ capital and of cash flows for each of the three years in the period ended December 31, 2023, including the related notes (collectively referred to as the “consolidated financial statements”).

We also have audited the Partnership’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

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

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

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Fair Value of the Preferred Distribution Rate Reset Option

As described in Note 13 to the consolidated financial statements, the Preferred Distribution Rate Reset Option of the Partnership’s Series A preferred units is an embedded derivative that is bifurcated from the related host contract and recorded at fair value.

The fair value, as of December 31, 2022, was $189 million, and is recorded in other long-term liabilities and deferred credits.

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

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

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

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

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

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

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

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

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

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

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PLAINS ALL AMERICAN PIPELINE, L.P.

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

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PLAINS ALL AMERICAN PIPELINE, L.P.

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

Goodwill impairment loss (Note 8) — — 2,515

Total costs and expenses 47,202 56,050 41,227

OPERATING INCOME/(LOSS) 1,292 851 ( 2,375 )

OPERATING INCOME 1,510 1,292 851

OTHER INCOME/(EXPENSE)

Equity earnings in unconsolidated entities 369 403 274

Gains (losses) on/(impairment of) investments in unconsolidated entities, net (Note 7, Note 9) 346 2 ( 182 )

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

Interest expense (net of capitalized interest of $ 10 , $ 5 and $ 18 , respectively)

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

INCOME/(LOSS) BEFORE TAX 1,417 721 ( 2,599 )

INCOME BEFORE TAX 1,623 1,417 721

Current income tax expense ( 145 ) ( 84 ) ( 50 )

Deferred income tax (expense)/benefit 24 ( 105 ) ( 23 )

NET INCOME/(LOSS) 1,228 648 ( 2,580 )

NET INCOME 1,502 1,228 648

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

NET INCOME/(LOSS) ATTRIBUTABLE TO PAA $ 1,037 $ 593 $ ( 2,590 )

NET INCOME/(LOSS) PER COMMON UNIT (NOTE 4):

Net income/(loss) allocated to common unitholders — Basic and Diluted $ 831 $ 393 $ ( 2,790 )

NET INCOME ATTRIBUTABLE TO PAA $ 1,230 $ 1,037 $ 593

NET INCOME PER COMMON UNIT (NOTE 4):

Net income allocated to common unitholders — Basic and Diluted $ 976 $ 831 $ 393

Basic and diluted weighted average common units outstanding 699 701 716

Basic and diluted net income/(loss) per common unit $ 1.19 $ 0.55 $ ( 3.83 )

Basic and diluted net income per common unit $ 1.40 $ 1.19 $ 0.55

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

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PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

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2023 2022 2021

Net income/(loss) $ 1,228 $ 648 $ ( 2,580 )

Net income $ 1,502 $ 1,228 $ 648

Other comprehensive income/(loss) 118 ( 101 ) 65

Comprehensive income/(loss) 1,127 713 ( 2,565 )

Comprehensive income 1,620 1,127 713

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

Comprehensive income/(loss) attributable to PAA $ 936 $ 658 $ ( 2,575 )

Comprehensive income attributable to PAA $ 1,348 $ 936 $ 658

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

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Reclassification adjustments 31 — — 31

Unrealized loss on hedges ( 10 ) — — ( 10 )

Unrealized gain on hedges 19 — — 19

Currency translation adjustments — 15 — 15

Other — — ( 3 ) ( 3 )

2021 Activity 50 15 — 65

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Currency translation adjustments — ( 204 ) — ( 204 )

Other — — 2 2

2022 Activity 101 ( 204 ) 2 ( 101 )

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

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PLAINS ALL AMERICAN PIPELINE, L.P.

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CASH FLOWS FROM OPERATING ACTIVITIES

Net income/(loss) $ 1,228 $ 648 $ ( 2,580 )

Reconciliation of net income/(loss) to net cash provided by operating activities:

Net income $ 1,502 $ 1,228 $ 648

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

Depreciation and amortization 1,048 965 774

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

Goodwill impairment loss (Note 8) — — 2,515

Equity-indexed compensation expense 50 40 23

Inventory valuation adjustments (Note 5) — — 233

Deferred income tax expense/(benefit) ( 24 ) 105 23

(Gains)/losses on sales of linefill ( 35 ) — 1

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

(Gain)/loss on foreign currency revaluation 8 41 ( 7 )

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Distributions on earnings from unconsolidated entities 458 488 431

(Gains) losses on/impairment of investments in unconsolidated entities, net (Note 7, Note 9) ( 346 ) ( 2 ) 182

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

Other 20 16 29

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Additions to property, equipment and other ( 559 ) ( 455 ) ( 336 )

Cash paid for purchases of linefill ( 23 ) ( 84 ) ( 37 )

Proceeds from sales of assets (Note 7) 328 60 881

Cash received from sales of linefill 9 72 3

Cash paid for purchases of linefill ( 84 ) ( 37 ) ( 14 )

Other investing activities 1 44 1

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Net borrowings/(repayments) under commercial paper program (Note 10) 433 — ( 545 )

Net borrowings/(repayments) under senior secured hedged inventory facility (Note 11) — ( 167 ) ( 160 )

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

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

Proceeds from the issuance of senior notes (Note 11) — — 748

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

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Distributions paid to noncontrolling interests (Note 11) ( 333 ) ( 298 ) ( 14 )

Contributions from noncontrolling interests (Note 12) 26 1 12

Contributions from noncontrolling interests 106 26 1

Other financing activities ( 93 ) ( 53 ) ( 166 )

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

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PLAINS ALL AMERICAN PIPELINE, L.P.

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Balance at December 31, 2020 $ 1,505 $ 787 $ 7,301 $ 9,593 $ 145 $ 9,738

Net income/(loss) 149 49 ( 2,788 ) ( 2,590 ) 10 ( 2,580 )

Net income 149 49 395 593 55 648

Distributions (Note 11) ( 149 ) ( 49 ) ( 517 ) ( 715 ) ( 14 ) ( 729 )

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Repurchase of common units (Note 11) — — ( 178 ) ( 178 ) — ( 178 )

Contributions from noncontrolling interests (Note 12) — — — — 12 12

Contributions from noncontrolling interests — — — — 1 1

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

Other — — ( 10 ) ( 10 ) — ( 10 )

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

Other comprehensive income — — 65 65 — 65

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

Equity-indexed compensation expense — — 32 32 — 32

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

Contributions from noncontrolling interests (Note 12) — — — — 1 1

Contributions from noncontrolling interests — — — — 26 26

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

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

Other — — ( 14 ) ( 14 ) 1 ( 13 )

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

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

Other comprehensive income — — 118 118 — 118

Equity-indexed compensation expense — — 36 36 — 36

Repurchase of common units (Note 12) — — ( 74 ) ( 74 ) — ( 74 )

Contributions from noncontrolling interests (Note 12) — — — — 26 26

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

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

Contributions from noncontrolling interests — — — — 106 106

Other 4 — ( 26 ) ( 22 ) ( 3 ) ( 25 )

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SEC = United States Securities and Exchange Commission

= Secured Overnight Financing Rate

TWh = Terawatt hour

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

For the years ended December 31, 2022, 2021 and 2020, the revaluation of foreign currency transactions and monetary assets and liabilities resulted in the recognition of a net loss of $ 41 million, a net gain of $ 7 million and a net gain of $ 16 million, respectively, in our Consolidated Statements of Operations.

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

Cash and Cash Equivalents

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(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 Notes 7 and 19 for additional information.

See Note 7 and Note 18 for additional information.

Fair Value Measurements

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Other Significant Accounting Policies

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

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

Recent Accounting Pronouncements

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

Improvements to Income Tax Disclosures , which requires, among other things, disaggregated information about effective tax rate reconciliation and income taxes paid (net of refunds received) on an annual basis.

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

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

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

Improvements to Reportable Segment Disclosures, which requires disaggregated disclosure of significant segment expenses and other amounts included within the reported measure of segment profit or loss for each reportable segment on an annual and interim basis.

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

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

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

Recognition and Initial Measurement , which requires a newly-formed joint venture to apply a new basis of accounting to its contributed net assets, resulting in the joint venture initially measuring its contributed net assets at fair value on the formation date.

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

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

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

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

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

In July 2021, the FASB issued ASU 2021-05, Lessors - Certain Leases with Variable Lease Payments (Topic 842) w hich modifies the lease classification requirements for lessors in Topic 842, which we adopted on the effective date of January 1, 2019.

The amendments require lessors to classify and account for a lease with variable lease payments that do not depend on a reference index or a rate as an operating lease at lease commencement if another classification (i.e., sales-type or direct financing) would result in the recognition of a day-one loss.

For entities that have adopted Topic 842, the guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2021, with early adoption permitted.

We have elected to early adopt the guidance on a prospective basis as of July 1, 2021.

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

In August 2020, the FASB issued ASU 2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40):

Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity , which simplifies accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity, by eliminating two of the three models that require separate accounting for embedded conversion features and the settlement assessment that entities are required to perform to determine whether a contract qualifies for equity classification.

This guidance is effective for interim and annual periods beginning after December 15, 2021, with early adoption permitted.

We adopted this guidance effective January 1, 2022, and our adoption did not have a material impact on our financial position, results of operations or cash flows.

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

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

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

In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740):

Simplifying the Accounting for Income Taxes , to simplify the accounting for income taxes based on changes suggested by stakeholders as part of the FASB’s simplification initiative.

This guidance is effective for interim and annual periods beginning after December 15, 2020, with early adoption permitted.

We adopted this guidance effective January 1, 2021, and our adoption did not have a material impact on our financial position, results of operations or cash flows.

Index to Financial Statements

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Year Ended December 31,

2022 2021 2020

Crude Oil segment revenues from contracts with customers

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Year Ended December 31,

2022 2021 2020

NGL segment revenues from contracts with customers

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Revenues from contracts with customers $ 47,146 $ 1,853 $ 48,999

Other items in revenues 151 217 368

Other revenues

Total revenues of reportable segments $ 47,174 $ 1,935 $ 49,109

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Revenues from contracts with customers $ 54,929 $ 2,544 $ 57,473

Other items in revenues ( 80 ) ( 431 ) ( 511 )

Other revenues

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

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Revenues from contracts with customers $ 40,550 $ 2,399 $ 42,949

Other items in revenues ( 128 ) ( 115 ) ( 243 )

Other revenues

( 80 ) ( 431 ) ( 511 )

Total revenues of reportable segments $ 40,470 $ 1,968 $ 42,438

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If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right as a contract liability and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote.

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

Counterparty Deficiencies Financial Statement Classification 2023 2022

Billed and collected Other current liabilities $ 77 $ 104

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Counterparty Deficiencies Financial Statement Classification 2022 2021

Billed and collected Other current liabilities $ 104 $ 63

Total $ 105 $ 79

(1) Amounts were related to deficiencies for which the counterparties had not met their contractual minimum commitments and are not reflected in our Consolidated Financial Statements as we had not yet billed or collected such amounts.

Contract Balances .

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Amounts recognized as revenue

Additions (1)

Balance at December 31, 2022 $ 229

Amounts recognized as revenue ( 42 )

Additions (2)

Balance at December 31, 2023 $ 228

(1) Includes approximately $ 361 million associated with crude oil sales agreements that were entered into in conjunction with storage arrangements and future inventory exchanges.

Such amount was recognized as revenue in the first quarter of 2021.

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

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Remaining Performance Obligations .

The information below includes the amount of consideration allocated to partially and wholly unsatisfied remaining performance obligations under contracts that exist as of the end of the periods and the timing of revenue recognition of those remaining performance obligations.

The information below includes the amount of consideration allocated to partially and wholly unsatisfied remaining performance obligations under contracts that existed as of the end of the periods and the timing of revenue recognition of those remaining performance obligations.

Certain contracts meet the requirements for the presentation as remaining performance obligations.

These arrangements include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range.

These contracts include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range.

The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of December 31, 2023 (in millions):

2024 2025 2026 2027 2028

2029 and Thereafter

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The presentation above does not include (i) expected revenues from legacy shippers not underpinned by minimum volume commitments, including pipelines where there are no or limited alternative pipeline transportation options, (ii) intersegment revenues and (iii) the amount of consideration associated with certain income generating contracts, which include a fixed minimum level of service, that are either not within the scope of ASC 606 or do not meet the requirements for presentation as remaining performance obligations.

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

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PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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Although we consider our credit procedures to be adequate to mitigate any significant credit losses, the actual amount of current and future credit losses could vary significantly from estimated amounts.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

Note 4— Net Income/(Loss) Per Common Unit

After consideration of distributions to preferred unitholders, basic and diluted net income/(loss) per common unit is determined pursuant to the two-class method as prescribed in FASB guidance.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 4— Net Income Per Common Unit

After consideration of distributions to preferred unitholders, basic and diluted net income per common unit is determined pursuant to the two-class method as prescribed in FASB guidance.

This method is an earnings allocation formula that is used to determine allocations to our limited partners and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings or distributions in excess of earnings.

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Participating securities include equity-indexed compensation plan awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units.

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

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

The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units and (ii) our equity-indexed compensation plan awards.

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See Note 17 for a complete discussion of our equity-indexed compensation plan awards.

When applying the if-converted method prescribed by FASB guidance, the possible conversion of approximately 71 million Series A preferred units, on a weighted-average basis, were excluded from the calculation of diluted net income/(loss) per common unit for the years ended December 31, 2022, 2021 and 2020 as the effect was antidilutive for all periods.

When applying the if-converted method prescribed by FASB guidance, the possible conversion of approximately 71 million Series A preferred units, on a weighted-average basis, were excluded from the calculation of diluted net income per common unit for the years ended December 31, 2023, 2022 and 2021 as the effect was antidilutive for all periods.

Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied.

Equity-indexed compensation plan awards that were deemed to be dilutive during the year were reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.

For the years ended December 31, 2022, 2021 and 2020, approximately 2.0 million, 0.5 million and 0.3 million equity-indexed compensation plan awards, respectively, on a weighted-average basis, were excluded from the computation of diluted net income/(loss) per common unit as the effect did not change the presentation of diluted net income/(loss) per common unit or the effect was antidilutive.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

Equity-indexed compensation plan awards that are deemed to be dilutive during the year are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.

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

Year Ended December 31,

2023 2022 2021

Basic and Diluted Net Income/(Loss) per Common Unit

Net income/(loss) attributable to PAA $ 1,037 $ 593 $ ( 2,590 )

Basic and Diluted Net Income per Common Unit

Net income attributable to PAA $ 1,230 $ 1,037 $ 593

Distributions to Series A preferred unitholders ( 173 ) ( 149 ) ( 149 )

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Amounts allocated to participating securities ( 10 ) ( 5 ) ( 2 )

Net income/(loss) allocated to common unitholders (1)

Net income allocated to common unitholders (1)

$ 976 $ 831 $ 393

Basic and diluted weighted average common units outstanding 699 701 716

Basic and diluted net income/(loss) per common unit $ 1.19 $ 0.55 $ ( 3.83 )

(1) We calculate net income/(loss) allocated to common unitholders based on the distributions pertaining to the current period’s net income.

Basic and diluted net income per common unit $ 1.40 $ 1.19 $ 0.55

(1) We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income.

After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (i.e., undistributed loss), if any, are allocated to the common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 5— Inventory, Linefill and Long-term Inventory

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No adjustments were recorded during the years ended December 31, 2023, 2022 or 2021.

During the year ended December 31, 2020, we recorded charges of $ 233 million (of which $ 40 million was associated with our long-term inventory) related to the write down of our crude oil and NGL inventory due to declines in prices.

A portion of these inventory valuation adjustments was offset by the recognition of gains on derivative instruments being utilized to hedge future sales of our crude oil and NGL inventory.

Such gains were recorded to “Product sales revenues” in our accompanying Consolidated Statements of Operations.

See Note 13 for discussion of our derivative and risk management activities.

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

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At the end of each period, we reclassify the inventory not expected to be liquidated within the succeeding twelve months out of “Inventory,” at the average cost of the applicable inventory pools, and into “Long-term inventory,” which is reflected as a separate line item under “Other assets” on our Consolidated Balance Sheets.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 6— Property and Equipment

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Lives (Years)

Pipelines and related facilities (1)

Crude oil pipeline systems

$ 14,265 $ 13,303

Storage, terminal and rail facilities 10 - 50

Trucking equipment and other 2 - 15

Crude oil storage and terminal facilities

NGL storage, terminal, fractionation and processing facilities

NGL pipeline systems

Office property and equipment and rolling stock

Construction in progress N/A 257 201

Office property and equipment 2 - 50

Land and other N/A 341 326

Property and equipment, gross (1)

21,143 20,020

Accumulated depreciation ( 5,361 ) ( 4,770 )

Property and equipment, net $ 15,782 $ 15,250

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(1) We include rights-of-way, which are intangible assets, in our Pipelines and related facilities amounts within property and equipment.

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

We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets.

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• if an impairment exists, the fair value of the asset or asset group.

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

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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Our estimated fair value (which we consider a Level 3 measurement in the fair value hierarchy) was primarily based upon an assumption for the amount for which the relevant assets and land could be sold.

During the year ended December 31, 2020, we recognized approximately $ 541 million of non-cash impairment losses, reflected in “ (Gains)/losses on asset sales and asset impairments, net ” on our Consolidated Statement of Operations.

Of our 2020 impairment losses, approximately $ 415 million was associated with certain pipeline assets in our Crude Oil segment located in the Mid-Continent region.

The macroeconomic and geopolitical conditions that occurred in 2020, including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply, as well as changing market conditions and expected lower crude oil production in certain regions, resulted in expected decreases in future cash flows for certain of our assets, which was a triggering event that required us to assess the recoverability of our carrying value of such long-lived assets.

As a result of our impairment review, we wrote off the portion of the carrying amount of these long-lived assets that exceeded their fair value.

Our estimated fair 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 14 %, which represents our estimate of the cost of capital of a theoretical market participant.

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) future commodity prices (based on relevant indices and applicable quality and location differentials), and (iv) estimated fixed and variable costs.

The remaining 2020 impairment losses were associated with idled or underutilized assets, primarily in our Crude Oil segment, including certain pipelines located in the Western region and other long-lived assets, for which it has been determined that it is unlikely that opportunities will exist in the future to recover our investment in these assets.

We wrote off substantially all of the carrying value of these assets.

Note 7— 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 “Gains/(losses) on investments in unconsolidated entities, net” on our Consolidated Statement of Operations.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 7— Acquisitions, Divestitures and Other Transactions

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

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

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

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

Identifiable Assets Acquired and Liabilities Assumed:

Estimated Useful Lives

(in years) Recognized Amount

Property and equipment 3 - 30

Intangible assets 10 34

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 the cost approach based on costs incurred on similar recent construction projects.

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

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

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

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

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

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

Amortization expense was approximately $ 4 million during the year ended December 31, 2023, 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.

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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.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

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.

The discounted cash flow approach utilized a discount rate of 13.8 %, based on the estimate of the risk that a theoretical market participant would assign to the business.

The discounted cash flow approach utilized a discount rate of approximately 14 %, 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.

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

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

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

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

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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 20 years.

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

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

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.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The fair value of intangible assets is comprised of customer relationships that will be amortized over their useful lives, which have a remaining weighted average life of approximately 20 years.

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

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

Other Acquisitions

In November 2023, we acquired a crude oil gathering system in the Northern Delaware Basin from a subsidiary of LM Energy Partners for approximately $ 135 million (approximately $ 88 million net to our 65 % interest in the Permian JV), subject to certain adjustments.

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

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, including cash paid for working capital.

• 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 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.

In February 2020, we acquired Felix Midstream LLC, now known as FM Gathering LLC (“FM Gathering”) from Felix Energy Holdings II, LLC for approximately $ 300 million, net of working capital and other adjustments.

FM Gathering owns and operates a newly constructed crude oil gathering system in the Delaware Basin, with associated crude oil storage and truck offloading capacity, and is supported by a long-term acreage dedication.

The assets acquired are included in our Crude Oil segment.

This acquisition was accounted for using the acquisition method of accounting and the determination of the fair value of the assets acquired and liabilities assumed was determined in accordance with the applicable accounting guidance.

The assets acquired primarily consisted of property and equipment with a fair value of $ 115 million and intangible assets with a fair value of $ 187 million.

The fair value of the tangible assets is a Level 3 measurement in the fair value hierarchy and was determined using a cost approach.

The cost approach was based on costs incurred on similar recent construction projects.

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

Such approach utilized discount rates varying from 18 % to 19 %, based on our estimate of the risk that a theoretical market participant would assign to the respective intangible assets.

Asset Exchange

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Joint Venture Transaction

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

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PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

Such approach utilized a discount rate of approximately 16 %, 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 16 %, based on our estimate of the risk that a theoretical market participant would assign to the respective intangible assets.

The projection of future crude oil volumes gathered and transported was also a key assumption in the valuation of the intangible assets and was based on projected rig activity on the associated acreage.

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

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

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

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

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

December 31, 2021

Total revenues $ 42,359

Net income attributable to PAA

Net income allocated to common unitholders

Basic and diluted net income per common unit

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

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

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

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Year ended December 31,

Total revenues $ 42,359 $ 23,536

Net income/(loss) attributable to PAA $ 524 $ ( 2,898 )

Net income/(loss) allocated to common unitholders $ 324 $ ( 3,098 )

Basic and diluted net income/(loss) per common unit $ 0.45 $ ( 4.26 )

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

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

During the year ended December 31, 2020, we received cash proceeds of $ 451 million, primarily from the sale of:

• certain Los Angeles Basin crude oil terminals previously included in our Crude Oil segment for proceeds of approximately $ 200 million, subject to certain adjustments;

• certain NGL terminals previously included in our NGL segment for proceeds of approximately $ 163 million (including $ 22 million related to a multi-year supply agreement related to the sale), subject to certain adjustments;

• a 10 % ownership interest in Saddlehorn Pipeline Company, LLC (“Saddlehorn”) for proceeds of approximately $ 78 million, including working capital adjustments (see Note 9 for additional information).

We recognized a loss related to these asset sales of $ 178 million, including non-cash impairments recognized upon classification to assets held for sale, for the year ended December 31, 2020.

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

Assets Held for Sale

In December 2022, we entered into a definitive agreement to sell our 21 % non-operated/undivided joint interest in the Keyera Fort Saskatchewan facility to Keyera Corporation for approximately CAD$ 365 million.

This transaction closed in February 2023.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 8— Goodwill

During the first quarter of 2020, we recorded impairment losses of $ 2.515 billion related to goodwill.

Our market capitalization declined significantly during the first quarter driven by macroeconomic and geopolitical conditions that occurred in 2020, including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply, as well as changing market conditions and expected lower crude oil production in certain regions, that resulted in expected decreases in future cash flows for certain of our assets, which we concluded was a triggering event that required us to perform a quantitative impairment test as of March 31, 2020, utilizing a discounted cash flow approach.

We applied a discount rate of approximately 14 % in the determination of the fair value of each of our reporting units, which represented our estimate of the cost of capital of a theoretical market participant as of March 31, 2020.

As a result of the impairment test, we concluded that the carrying value of each of our reporting units exceeded their respective fair values, resulting in an impairment charge for the entire goodwill balance for each reporting unit.

Note 8— Investments in Unconsolidated Entities

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BridgeTex Pipeline Company, LLC (“BridgeTex”) Crude Oil Pipeline 20 % $ 363 $ 403

Cactus II (2)

Capline Pipeline Company LLC (“Capline”)

Crude Oil Pipeline 54 % 535 539

Capline Pipeline Company LLC Crude Oil Pipeline 54 % 539 531

Diamond Pipeline LLC (“Diamond”) Crude Oil Pipeline 50 % 460 464

Eagle Ford Pipeline LLC (“Eagle Ford Pipeline”) Crude Oil Pipeline 50 % 371 363

Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”)

Diamond Pipeline LLC

Crude Oil Pipeline 50 % 450 460

Eagle Ford Pipeline LLC

Crude Oil Pipeline 50 % 370 371

Eagle Ford Terminals Corpus Christi LLC

Crude Oil Terminal and Dock 50 % 116 118

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Crude Oil Pipeline —% — 211

Saddlehorn Crude Oil Pipeline 30 % 197 209

Saddlehorn Pipeline Company, LLC

Crude Oil Pipeline 30 % 192 197

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

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

(2) 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.

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

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

See Note 7 for additional information.

(3) In November 2022, we acquired an additional interest in OMOG.

Although we own greater than 50% of OMOG, we use the equity method to account for the investment because the joint venture partner still retains 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.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 represents the difference between the fair value and historical book value of the assets contributed.

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

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.

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See Note 7 for additional information.

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.

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

We continue to account for OMOG as an equity method investment.

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

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

During the year ended December 31, 2020, we recognized losses as a result of the write-down of certain of our investments in unconsolidated entities, as discussed further below.

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

During the third quarter of 2020, we determined that there was an other-than-temporary impairment of our investment in STACK Pipeline LLC as a result of a continued decline of drilling activity and related volumes of crude oil in its area of operation.

We recognized a loss of $ 91 million related to the write-down of the portion of the carrying amount of our investment that exceeded its fair value.

The estimated fair value (which we consider a Level 3 measurement in the fair value hierarchy) was based on a discounted cash flow approach utilizing various assumptions and the application of a discount rate of approximately 14 %, which represented our estimate of the cost of capital of a theoretical market participant.

Such assumptions included (but were not limited to) (i) volumes (consistent with historical information and estimates of future drilling and completion activity), (ii) tariff rates, (iii) future commodity prices (based on relevant indices and applicable quality and location differentials), and (iv) estimated fixed and variable costs.

In June 2019, we formed Red Oak Pipeline LLC (“Red Oak”), a joint venture with a subsidiary of Phillips 66 and in which we own a 50 % interest, to develop a new crude oil pipeline project.

In 2020, the partners of Red Oak determined that the project would not proceed as previously contemplated.

We determined that there was an other-than-temporary impairment of our investment in Red Oak, and we recognized a loss of $ 69 million related to the write-down of our investment in Red Oak to the estimated residual value of our share of the net assets during the second quarter of 2020.

Other investments.

During the first quarter of 2020, we also recognized a loss of $ 43 million related to the write-down of certain of our investments included in “Other investments” in the table above due to an other-than-temporary impairment related to a decline in market conditions.

In February 2020, we sold a 10 % ownership interest in Saddlehorn for proceeds of approximately $ 78 million.

We recorded a gain of approximately $ 21 million related to this sale, which is included in “Gains (losses) on/(impairment of) investments in unconsolidated entities, net” on our Consolidated Statement of Operations.

We continue to account for our remaining 30 % interest in Saddlehorn under the equity method of accounting.

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.

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.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Contributions

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

The majority of the basis difference at both December 31, 2022 and 2021 was attributable to goodwill related to our ownership interest in BridgeTex and Capline LLC with the remaining basis difference primarily related to capitalized interest incurred during construction of the assets of our unconsolidated entities.

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Summarized Financial Information of Unconsolidated Entities

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Net income $ 947 $ 1,011 $ 506

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 9— Intangible Assets, Net

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$ 2,819 $ ( 944 ) $ 1,875 $ 2,852 $ ( 707 ) $ 2,145

(1) The increase in intangible assets related to Customer contracts and relationships in 2022 is primarily associated with the assets recognized upon consolidation of Cactus II.

See Note 7 for additional information.

(2) We include rights-of-way, which are intangible assets, in our pipeline and related facilities amounts within property and equipment.

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

See Note 6 for a discussion of property and equipment.

12 unchanged sentences

SHORT-TERM DEBT

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

Senior notes:

3.65 % senior notes due June 2022

2.85 % senior notes due January 2023

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Senior notes:

2.85 % senior notes due January 2023

3.85 % senior notes due October 2023

3.60 % senior notes due November 2024 (2)

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$ 7,751 $ 8,446

(1) We classified these commercial paper notes as short-term as of December 31, 2023, as these notes were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.

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

(3) Our fixed-rate senior notes had a face value of approximately $ 7.3 billion and $ 8.4 billion at December 31, 2023 and 2022, respectively.

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

We estimate that the carrying value of outstanding borrowings under our credit facilities and commercial paper program approximates fair value as interest rates reflect current market rates.

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

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

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

Index to Financial Statements

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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 2022, we amended this agreement to, among other things, extend the maturity date of the facility to August 2025 for each existing lender.

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

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 2022, we amended this agreement to, among other things, extend the maturity date of the facility to August 2027 for each existing lender.

In August 2023, we extended the maturity date of the facility to August 2028 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 2027.

GO Zone term loans .

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Our senior notes are not guaranteed by any of our subsidiaries.

Senior Notes Issuances.

The table below summarizes our issuances of senior unsecured notes during the three years ended December 31, 2022 (in millions):

Year Description Maturity Face Value Interest Payment Dates

2020 3.80 % Senior Notes issued at 99.794 % of face value

September 2030 $ 750 March 15 and September 15

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Senior Notes Repayments.

1 unchanged sentence

Year Description Repayment Date

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 (1)

2020 $ 600 million 5.00 % Senior Notes due February 2021

November 2020 (2)

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

(2) We repaid these senior notes with proceeds from our 3.80 % senior notes issued in June 2020 and cash on hand.

On January 31, 2023, we redeemed our 2.85 %, $ 400 million senior notes.

We utilized a combination of cash on hand and borrowings under our commercial paper program to repay these senior notes.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The weighted average maturity of our senior notes outstanding at December 31, 2023 was approximately 10 years.

16 unchanged sentences

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Letters of Credit

In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil and NGL.

These letters of credit are issued under our senior unsecured revolving credit facility and our senior secured hedged inventory facility, and our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil or NGL is purchased.

Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil or NGL is purchased.

Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction.

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The holders of the Series A preferred units receive cumulative quarterly distributions, subject to customary antidilution adjustments, to unitholders of record within 45 days following the end of each quarter.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

For a period of 30 days following (a) the fifth anniversary of the January 28, 2016 issuance date (the “Issuance Date”) of the Series A preferred units and (b) each subsequent anniversary of the Issuance Date, the holders of the Series A preferred units, acting by majority vote, may make a one -time election to reset the Series A preferred unit distribution rate to equal the then applicable rate of ten-year U.S.

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

After the fifth anniversary of the January 28, 2016 issuance date (the “Issuance Date”) of the Series A preferred units, the holders of the Series A preferred units, acting by majority vote, had the option to make a one-time election to reset the Series A preferred unit distribution rate to equal the then applicable rate of ten-year U.S.

Treasury Securities plus 5.85 % (the “Preferred Distribution Rate Reset Option”).

The Preferred Distribution Rate Reset Option is accounted for as an embedded derivative.

The Preferred Distribution Rate Reset Option was accounted for as an embedded derivative.

See Note 12 for additional information.

If the holders of the Series A preferred units have exercised the Preferred Distribution Rate Reset Option, then, at any time following 30 days after the sixth anniversary of the Issuance Date, we may redeem all or any portion of the outstanding Series A preferred units in exchange for cash, common units (valued at 95 % of the volume-weighted average price of our common units for a trading day period specified in our partnership agreement) or a combination of cash and common units at a redemption price equal to 110 % of the Issue Price, plus any accrued and unpaid distributions.

In January 2023, we received notice that the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option.

Effective January 31, 2023, the new Series A preferred unit distribution rate is equal to 9.375 % per annum on the original Issue Price (approximately $ 2.46 per unit annualized).

The quarterly distribution to be paid in May 2023 will reflect a pro-rated amount of $ 0.58516 per unit.

In January 2023, the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option.

Effective January 31, 2023, the new Series A preferred unit distribution rate is equal to 9.375 % per annum of the original Issue Price (approximately $ 2.46 per unit annualized).

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

We may redeem all or any portion of the outstanding Series A preferred units (subject to certain redemption size limitations and limited to two redemption transactions) in exchange for cash, common units (valued at 95 % of the volume-weighted average price of our common units for a trading period specified in our partnership agreement) or a combination of cash and common units at a redemption price equal to 110 % of the Issue Price, plus any accrued and unpaid distributions.

The holders may convert their Series A preferred units into common units, generally on a one -for-one basis and subject to customary anti-dilution adjustments, at any time, in whole or in part, subject to certain minimum conversion amounts (and not more often than once per quarter).

We may convert the Series A preferred units into common units at any time (but not more often than once per quarter), in whole or in part, subject to certain minimum conversion amounts, if the closing price of our common units is greater than 150 % of the Issue Price for the preceding 20 trading days.

The Series A preferred units vote on an as-converted basis with our common units on the election of directors and have certain other class voting rights with respect to any amendment to our partnership agreement that would adversely affect any rights, preferences or privileges of the Series A preferred units.

In addition, upon certain events involving a change of control, the holders of the Series A preferred units may elect, among other potential elections, to convert the Series A preferred units into common units at the then applicable conversion rate.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Series B Preferred Units

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The initial distribution rate for the Series B preferred units from and including October 10, 2017 to, but not including, November 15, 2022 was 6.125 % per year of the liquidation preference per unit (equal to $ 61.25 per unit per year).

On and after November 15, 2022, distributions on the Series B preferred units accumulate for each distribution period at a percentage of the liquidation preference equal to the applicable three-month LIBOR (or, if discontinued, a substitute or successor rate determined by the calculation agent) plus a spread of 4.11 %.

The distribution rate for the quarterly distribution paid on February 15, 2023 was 8.71614 % ($ 22.27 per Series B preferred unit).

From November 15, 2022 through August 14, 2023, distributions on the Series B preferred units accumulated for each distribution period at a percentage of the liquidation preference equal to the applicable three-month LIBOR plus a spread of 4.11 % per annum.

Beginning August 15, 2023, distributions on the Series B preferred units accumulate based on the applicable three-month SOFR, plus a credit spread adjustment of 0.26121 %, plus 4.11 % per annum.

The distribution rate for the quarterly distribution paid on February 15, 2024 was 9.75093 % per annum ($ 24.92 per Series B preferred unit).

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

13 unchanged sentences

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

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

Issuances of common units under equity-indexed compensation plans

— — 2,654,251

Outstanding at December 31, 2023

71,090,468 800,000 701,008,749

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Common Equity Repurchase Program.

6 unchanged sentences

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

During the years ended December 31, 2022, 2021 and 2020, we repurchased common units under the Program through open market purchases for a total purchase price of $ 74 million, $ 178 million and $ 50 million, respectively, including commissions and fees.

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

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

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

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

Preferred Unit Distributions

Series A Preferred Unit Distributions.

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

Series A Preferred Unitholders

Year Cash Distribution

Distribution per Unit

2023 $ 166 $ 2.34

2022 $ 149 $ 2.10

2021 $ 149 $ 2.10

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

At December 31, 2023, such amount was accrued as distributions payable in “Other current liabilities” on our Consolidated Balance Sheet.

Index to Financial Statements

2 unchanged sentences

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Preferred Unit Distributions

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

Cash Distributions

Year Series A Preferred Unitholders Series B Preferred Unitholders

Series B Preferred Unit Distributions.

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

Series B Preferred Unitholders

Year Cash Distribution

Distribution per Unit

2023 $ 75 $ 93.43

1 unchanged sentence

2021 $ 49 $ 61.25

On February 14, 2023, we paid a cash distribution of $ 37 million to our Series A preferred unitholders.

At December 31, 2022, such amount was accrued as distributions payable in “Other current liabilities” on our Consolidated Balance Sheet.

On February 15, 2023, we paid a cash distribution of $ 18 million to our Series B preferred unitholders.

On February 15, 2024, we paid a cash distribution of $ 20 million ($ 24.92 per unit) to our Series B preferred unitholders.

At December 31, 2023, approximately $ 10 million of accrued distributions payable to our Series B preferred unitholders was included in “Other current liabilities” on our Consolidated Balance Sheet.

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

Contributions from Noncontrolling Interests

During the year ended December 31, 2022, we received a contribution of $ 26 million from noncontrolling interests in the Permian JV associated with the acquisition of the remaining 50 % interest in Advantage.

See Note 7 for additional information.

During the year ended December 31, 2020, we received contributions from noncontrolling interests in Red River of $ 12 million related to a pipeline capacity expansion.

Note 12— Derivatives and Risk Management Activities

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If a default were to occur, both parties have the right to net amounts payable and receivable into a single net settlement between parties.

At December 31, 2023 and 2022, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings.

Although we may be required to post margin on our exchange-traded derivatives transacted through a clearing brokerage account, as described below, we do not require our non-cleared derivative counterparties to post collateral with us.

Index to Financial Statements

2 unchanged sentences

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2022 and 2021, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings.

Commodity Price Risk Hedging

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• A net long position of 6.3 million barrels associated with our crude oil purchases, which was unwound ratably during January 2024 to match monthly average pricing.

• A net short time spread position of 6.4 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through December 2024.

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

• A net crude oil basis spread position of 2.3 million barrels at multiple locations through December 2024.

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

• A net short position of 18.4 million barrels through June 2024 related to anticipated net sales of crude oil and NGL inventory.

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

We purchase natural gas for processing and operational needs.

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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Net gain/(loss) from commodity derivative activity $ ( 32 ) $ 238 $ ( 639 )

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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Initial margin $ 77 $ 93

Variation margin posted/(returned) ( 236 ) 173

Variation margin returned

( 65 ) ( 236 )

Letters of credit ( 25 ) ( 25 )

Net broker receivable/(payable) $ ( 168 ) $ 259

Net broker payable

$ ( 13 ) $ ( 168 )

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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As such, changes in fair value are deferred in AOCI and are reclassified to interest expense as we incur the interest expense associated with the underlying debt.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the terms of our outstanding interest rate derivatives as of December 31, 2023 (notional amounts in millions):

7 unchanged sentences

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

As of December 31, 2023, there was a net loss of $ 81 million deferred in AOCI.

The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with interest expense accruals associated with underlying debt instruments.

During the year ended December 31, 2022, we terminated $ 100 million of notional interest hedging instruments previously expected to terminate in June 2024 for proceeds of $ 42 million.

The early termination did not result in an impact to the relationship between the hedging instrument and hedged item.

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

At December 31, 2021, the net fair value of these hedges totaled $ 65 million and was included in “Other long-term assets, net.”

At December 31, 2022, the net fair value of these hedges totaled $ 75 million and $ 45 million, which were included in “Other current assets” and “Other long-term assets, net”, respectively.

Preferred Distribution Rate Reset Option

In January 2023, we received notice that the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option.

Prior to this election, the Preferred Distribution Rate Reset Option was accounted for as an embedded derivative.

A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract.

The Preferred Distribution Rate Reset Option of our Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, our partnership agreement, and recorded at fair value on our Consolidated Balance Sheet.

This embedded derivative is not designated in a hedging relationship for accounting purposes and corresponding changes in fair value are recognized in “Other income/(expense), net” in our Consolidated Statement of Operations.

For the years ended December 31, 2022, 2021 and 2020 we recognized a net loss of $ 189 million, a net gain of $ 14 million and a net gain of $ 20 million, respectively.

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 Sheets, totaled $ 189 million and less than $ 1 million at December 31, 2022 and 2021, respectively.

In January 2023, we received notice that the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option, which will be effective for the distribution paid in May 2023.

See Note 12 for additional information regarding our Series A preferred units and the Preferred Distribution Rate Reset Option.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

The 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, 2022 and 2021, we recognized a gain of $ 58 million, a net loss of $ 189 million, and a net gain of $ 14 million, respectively.

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

Recurring Fair Value Measurements

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

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PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

Level 3 of the fair value hierarchy includes certain physical commodity and other contracts, over-the-counter options and the Preferred Distribution Rate Reset Option contained in our partnership agreement which is classified as an embedded derivative.

The fair values of our Level 3 physical commodity and other contracts and over-the-counter options are based on valuation models utilizing significant timing estimates, which involve management judgment, and pricing inputs from observable and unobservable markets with less volume and transaction frequency than active markets.

Significant deviations from these estimates and inputs could result in a material change in fair value.

We report unrealized gains and losses associated with these contracts in our Consolidated Statements of Operations as Product sales revenues .

The fair value of the Preferred Distribution Rate Reset Option of our Series A preferred units contained in our partnership agreement is based on a Monte Carlo valuation model that estimates the fair value of the Series A preferred units with and without the Preferred Distribution Rate Reset Option.

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

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

In general, an increase in ten-year U.S.

Treasury rates would increase the fair value of the feature and our liability and expense.

The future impact on “ Other income/(expense), net ” depends on how inputs change in relation to one another.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

Rollforward of Level 3 Net Asset/(Liability)

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$ — $ ( 189 )

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 13— Leases

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Short-term lease cost 15 18 19

Other (1) (2)

Total lease cost $ 109 $ 124 $ 129

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

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

(2) Includes approximately $ 8 million, $ 8 million, and $ 6 million for the years ended December 31, 2022, 2021 and 2020, respectively, associated with leased storage tanks owned by an equity method investee, in which we own a 50 % interest.

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

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Finance leases

(1) Includes $ 25 million for the year ended December 31, 2020 associated with leased storage tanks owned by an equity method investee, in which we own a 50 % interest.

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

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Total deferred income tax expense/(benefit) $ ( 24 ) $ 105 $ 23

Total income tax expense/(benefit) $ 189 $ 73 $ ( 19 )

Total income tax expense

$ 121 $ 189 $ 73

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):

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2023 2022 2021

Income/(loss) before tax $ 1,417 $ 721 $ ( 2,599 )

Partnership (earnings)/loss not subject to current Canadian tax ( 686 ) ( 370 ) 2,221

Income before tax

$ 1,623 $ 1,417 $ 721

Partnership earnings not subject to Canadian tax

( 1,136 ) ( 686 ) ( 370 )

$ 487 $ 731 $ 351

Canadian federal and provincial corporate tax rate 24 % 24 % 24 %

Income tax expense/(benefit) at statutory rate $ 175 $ 84 $ ( 91 )

Canadian permanent differences and rate changes $ 13 $ ( 13 ) $ 72

Income tax expense at statutory rate

$ 117 $ 175 $ 84

Canadian permanent differences

$ 2 $ 13 $ ( 13 )

State income tax 2 1 2

Total income tax expense/(benefit) $ 189 $ 73 $ ( 19 )

The Canadian permanent differences and rate changes for the year ended December 31, 2020 primarily related to an impairment of goodwill that was recognized during the year.

A portion of the goodwill that was impaired had no basis for Canadian income tax purposes and thus was not a deductible expense in determining taxable income, resulting in a permanent difference for Canadian tax purposes.

See Note 8 for additional information regarding this impairment.

Total income tax expense

$ 121 $ 189 $ 73

Index to Financial Statements

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Deferred tax assets:

Derivative instruments $ — $ 39

Lease liabilities $ 40 $ 45

Net operating losses — 2

Total deferred tax assets 85 61

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

Other long-term assets, net $ — $ 2

Other long-term liabilities and deferred credits $ ( 535 ) $ ( 545 )

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ExxonMobil Corporation and its subsidiaries accounted for 26 %, 20 % and 15 % of our revenues for the years ended December 31, 2023, 2022 and 2021, respectively.

Marathon Petroleum Corporation and its subsidiaries accounted for 12 % and 13 % of our revenues for the years ended December 31, 2021 and 2020, respectively.

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

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

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

No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2023.

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Each Class C share represents a non-economic limited partner interest in PAGP.

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

The number of Class C shares that we own is equal to the number of outstanding common units and Series A preferred units that are entitled to vote, pro rata with the holders of PAGP Class A and Class B shares, for the election of eligible PAGP GP directors.

The Class C shares function as a “pass-through” voting mechanism through which we vote at the direction of and as proxy for our common unitholders and Series A preferred unitholders in such director elections.

Common units held by AAP and Series B preferred units are not entitled to vote in the election of directors.

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

Promissory Notes with our General Partner

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

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

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

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

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

Related party note receivable (1)

Related party note payable (1)

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

Transactions with Other Related Parties

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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$ 404 $ 365 $ 385

(1) Crude oil purchases that are part of inventory exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Consolidated Statements of Operations.

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

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

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(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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The DERs terminate with the vesting or forfeiture of the underlying LTIP award.

Plains All American 2021 Long-Term Incentive Plan.

In May 2021, PAA unitholders approved the Plains All American 2021 Long-Term Incentive Plan, which amends, restates, and renames the Plains All American 2013 Long-Term Incentive Plan and authorizes an incremental 20 million PAA common units deliverable upon vesting of awards granted under the plan.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Our LTIP awards include both liability-classified and equity-classified awards.

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Of the awards outstanding, 9.6 million include associated DERs.

At December 31, 2022, certain of the outstanding LTIP awards were considered probable of vesting and such awards are expected to vest at various dates between January 2023 and August 2026.

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

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 18— Commitments and Contingencies

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See Note 13 for additional information.

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PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Environmental — General

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Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

At December 31, 2022 and 2021, we had recorded receivables (excluding receivables related to the Line 901 incident) totaling $ 4 million and $ 11 million, respectively, for amounts probable of recovery under insurance and from third parties under indemnification agreements, $ 1 million of which for each period is reflected in “Other long-term assets, net” and the remainder is reflected in “Trade accounts receivable and other receivables, net” on our Consolidated Balance Sheets.

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

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

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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.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Specific Legal, Environmental or Regulatory Matters

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

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

In addition, after various other unitholder derivative lawsuits were either dismissed or consolidated, one derivative suit proceeded in Delaware Chancery Court.

Generally, the plaintiffs in the derivative lawsuit claimed that PAGP’s Board of Directors failed to exercise proper oversight over PAA’s pipeline integrity efforts.

In April 2022, Plains entered into a settlement agreement to settle this lawsuit, subject to court approval and notice to all PAA unitholders (the “Derivative Settlement”).

Following preliminary court approval, on May 23, 2022 we filed a Current Report on Form 8-K with the SEC.

We also posted notice on our website and mailed copies of the notice to all record holders of PAA common units as of August 10, 2022.

The key terms of the Derivative Settlement include a payment of Plaintiff’s attorneys’ fees by our insurers in the amount of approximately $ 1.0 million and the agreement of Plains to comply with various covenants regarding the implementation or continuation of certain Board oversight practices with respect to pipeline integrity.

At a settlement hearing held on November 1, 2022, the Delaware Chancery Court approved the terms of the Derivative Settlement.

Index to Financial Statements

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

We are vigorously defending these remaining lawsuits and believe we have strong defenses, including a lack of duty owed to the claimants to keep Line 901 in service.

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

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

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

Nine class action lawsuits were filed against us;

however, after various claims were either dismissed or consolidated, two proceedings remained pending in the United States District Court for the Central District of California.

In the first proceeding, the plaintiffs seek a declaratory judgment that Plains’ right-of-way agreements would not allow Plains to lay a new pipeline to replace Line 901 and/or the non-operating segment of Line 903 without paying additional compensation.

No trial date has been set in that action and the purchaser of Line 901 and the Sisquoc to Pentland portion of Line 903 will be joining this proceeding as a co-defendant with respect to its interest in such acquired pipelines.

In the second proceeding, the plaintiffs claimed two different classes of claimants were damaged by the release:

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

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

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

We are vigorously defending against these stigma damages claims.

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

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

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

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

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

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

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

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

We intend to vigorously pursue recovery from our insurers of all amounts for which we have claimed reimbursement.

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

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

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

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

Effective as of December 31, 2022, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $ 740 million, which includes actual and projected emergency response and clean-up costs, natural resource damage assessments, fines and penalties payable pursuant to the Consent Decree, certain third-party claims settlements (including the Class Action Settlement and the Derivative Settlement), and estimated costs associated with our remaining Line 901 lawsuits and claims as described above, as well as estimates for certain legal fees and statutory interest where applicable.

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

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

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

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

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

We did not recognize any such costs during the year ended December 31, 2020.

As of December 31, 2022, we had a remaining undiscounted gross liability of approximately $ 105 million related to the Line 901 incident, which aggregate amount is reflected in “Current liabilities” on our Consolidated Balance Sheet.

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

As of December 31, 2023 and 2022, we had a remaining undiscounted gross liability of approximately $ 94 million and $ 105 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.

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

Pipelines, terminals, trucks or other facilities or equipment may experience damage as a result of an accident, natural disaster, terrorist attack, cyber event or other event.

These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations.

Consistent with insurance coverage generally available in the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences.

We maintain various types and varying levels of insurance coverage to cover our operations and properties, and we self-insure certain risks, including gradual pollution, cybersecurity and named windstorms.

To the extent we do maintain insurance coverage, such insurance does not cover every potential risk that might occur, associated with operating pipelines, terminals and other facilities and equipment, including the potential loss of significant revenues and cash flows.

The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its insurance or indemnification obligations, could materially and adversely affect our operations and financial condition.

While we strive to maintain adequate insurance coverage, our actual costs may exceed our coverage levels and insurance will not cover many types of interruptions that might occur, will not cover amounts up to applicable deductibles and will not cover all risks associated with certain of our assets and operations.

With respect to our insurance coverage, our policies are subject to deductibles and retention levels that we consider reasonable and not excessive.

Additionally, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable.

As a result, we may elect to self-insure or utilize higher deductibles in certain other insurance programs.

In addition, although we believe that we have established adequate reserves and liquidity to the extent such risks are not insured, costs incurred in excess of these reserves may be higher or we may not receive insurance proceeds in a timely manner, which may potentially have a material adverse effect on our financial conditions, results of operations or cash flows.

Index to Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 19— Segment Information

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The measure of Segment Adjusted EBITDA forms the basis of our internal financial reporting and is the primary performance measure used by our CODM in assessing performance and allocating resources among our operating segments.

We define Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus (d) our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities, further adjusted (e) for certain selected items including (i) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance and (f) to exclude the portion of all preceding items that is attributable to noncontrolling interests (“Adjusted EBITDA attributable to noncontrolling interests”).

We define Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus (d) our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities, further adjusted (e) for certain selected items including (i) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance and (f) to exclude the portion of all preceding items that is attributable to noncontrolling interests (“Segment amounts attributable to noncontrolling interests”).

Segment Adjusted EBITDA excludes depreciation and amortization.

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Segment Adjusted EBITDA Reconciliation

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

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

Year Ended December 31,

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Foreign currency revaluation (7)

( 24 ) ( 4 ) 4

Line 901 incident (8)

( 10 ) ( 95 ) ( 15 )

Significant transaction-related expenses (9)

Transaction-related expenses (9)

( 1 ) — ( 16 )

Adjusted EBITDA attributable to noncontrolling interests (10)

Segment amounts attributable to noncontrolling interests (10)

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

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

Goodwill impairment loss — — ( 2,515 )

Gains (losses) on/(impairment of) investments in unconsolidated entities, net 346 2 ( 182 )

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

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

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

Income/(loss) before tax 1,417 721 ( 2,599 )

Income tax (expense)/benefit ( 189 ) ( 73 ) 19

Net income/(loss) 1,228 648 ( 2,580 )

Income before tax

1,623 1,417 721

Income tax expense

( 121 ) ( 189 ) ( 73 )

1,502 1,228 648

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

Net income/(loss) attributable to PAA $ 1,037 $ 593 $ ( 2,590 )

Net income attributable to PAA

$ 1,230 $ 1,037 $ 593

(1) Represents adjustments utilized by our CODM in the evaluation of segment results.

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(5) We, and certain of our equity method investees, have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period.

Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset.

Substantially all of such agreements were entered into with counterparties to economically support the return on capital expenditure necessary to construct the related asset.

Some of these agreements include make-up rights if the minimum volume is not met.

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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 and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote.

We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability.

We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue or equity earnings, as a selected item impacting comparability.

Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to Segment Adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.

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We exclude compensation expense associated with these awards in determining Segment Adjusted EBITDA as the dilutive impact of the outstanding awards is included in our diluted net income per unit calculation, as applicable.

The portion of compensation expense associated with awards that will settle in cash is not excluded in determining Segment Adjusted EBITDA.

The portion of compensation expense associated with awards that will be settled in cash is not excluded in determining Segment Adjusted EBITDA.

See Note 17 for information regarding our equity-indexed compensation plans.

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See Note 18 for additional information regarding the Line 901 incident.

(9) Includes expenses associated with the Permian JV transaction in 2021 and the Felix Midstream LLC acquisition in 2020.

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

See Note 7 for additional discussion.

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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