What changed in this filing

/stocks — the workspaceLOADING

Item 9A. Controls and Procedures

2023-03-01 compared with 2022-03-01 · 488 added, 478 removed, 1989 unchanged (33% of the section changed)

4 unchanged sentences

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, 2022, the end of the period covered by this report, and, based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our DCP is effective.

Index to Financial Statements

Internal Control over Financial Reporting

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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.

Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

Index to Financial Statements

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Victor Burk (2)

Managing Director, Alvarez and Marsal

Senior Advisor, Alvarez and Marsal

DeSanctis (2)

Former Senior Vice President, ConocoPhillips

Kevin McCarthy (2)

49 unchanged sentences

Index to Financial Statements

3.11 † — Fourth Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC dated effective as of August 19, 2021.

3.11 — 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 3.11 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 4.2 to PAA’s Current Report on Form 8-K filed October 30, 2006).

4.4 — Twentieth Supplemental Indenture (3.65% Senior Notes due 2022) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance Corp.

Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed March 26, 2012).

4.4 — Twenty-First Supplemental Indenture (5.15% Senior Notes due 2042) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance Corp.

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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).

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

and Plains Midstream Canada ULC, as Borrowers;

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

from time to time party thereto, as Designated Borrowers;

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

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

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

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

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

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and the other Lenders party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed August 26, 2021).

10.4 — First Amendment to Fourth Amended and Restated Credit Agreement dated as of August 22, 2022, among Plains Marketing, L.P.

and Plains Midstream Canada ULC, as Borrowers;

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

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

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

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

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

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

8 unchanged sentences

Armstrong (incorporated by reference to Exhibit 10.31 to PAA’s Annual Report on Form 10-K for the year ended December 31, 2010).

Index to Financial Statements

10.11** — Waiver Agreement dated October 21, 2013 to the Amended and Restated Employment Agreement dated June 30, 2001 of Greg L.

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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.

Index to Financial Statements

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.

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

Index to Financial Statements

10.28** — PAA Natural Gas Storage, L.P.

8 unchanged sentences

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

Index to Financial Statements

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).

10.32** — Form of Director LTIP Grant Letter (August 2018) (incorporated by reference to Exhibit 10.66 to our Annual Report on Form 10-K for the year ended December 31, 2018).

10.33** — Director LTIP Grant Letter (December 2018) (incorporated by reference to Exhibit 10.66 to our Annual Report on Form 10-K for the year ended December 31, 2018).

10.34** — 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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10.40** — Form of Special Retention LTIP Grant Letter dated November 20, 2019 (incorporated by reference to Exhibit 10.54 to our Annual Report on Form 10-K for the year ended December 31, 2020).

10.41** — Form of LTIP Grant Letter dated December 21, 2017 (Goebel) (incorporated by reference to Exhibit 10.55 to our Annual Report on Form 10-K for the year ended December 31, 2020).

10.42** — Form of LTIP Grant Letter dated May 1, 2018 (Chandler) (incorporated by reference to Exhibit 10.57 to our Annual Report on Form 10-K for the year ended December 31, 2020).

10.41** — 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).

10.42** — 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).

10.43** — 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).

10.44** — 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).

10.45** — Form of LTIP Grant Letter dated August 18, 2022 (Directors) (incorporated by reference to Exhibit 10.5 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2022).

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

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

Index to Financial Statements

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

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

Index to Financial Statements

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

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/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

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Net Income/(Loss) Per Class A Share

Inventory, Linefill and Base Gas and Long-term Inventory

Inventory, Linefill and Long-term Inventory

Property and Equipment

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We believe that our audits provide a reasonable basis for our opinions.

Index to Financial Statements

Definition and Limitations of Internal Control over Financial Reporting

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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.

Index to Financial Statements

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

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

Accounting for the Oryx Midstream Holdings LLC Business Combination

As described in Note 7 to the consolidated financial statements, in October 2021, the Partnership and Oryx Midstream Holdings LLC (“Oryx Midstream”), completed the merger, in a cashless, debt-free transaction, of their respective Permian Basin assets, operations and commercial activities into a newly formed strategic joint venture, Plains Oryx Permian Basin LLC (the “Permian JV”).

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

The Partnership owns 65% of Permian JV, operates the combined assets and reflects Permian JV as a consolidated subsidiary in the consolidated financial statements.

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

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

In accordance with applicable accounting guidance, the fair value of Oryx Midstream’s ownership interest in the joint venture following the formation of $3.256 billion is utilized as the consideration transferred for the purchase price allocation.

The fair value of the $3.256 billion consideration is a Level 3 measurement in the fair value hierarchy and was determined by valuing both the enterprise value of Oryx Midstream’s Permian Basin business and the enterprise value of the Partnership’s Permian Basin assets that were contributed to the joint venture.

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

The DCF approach utilized a discount rate based on the estimate of the risk that a theoretical market participant would assign to the business.

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

The fair value of the intangible assets was determined by applying a discounted cash flow approach.

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

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

The fair value of intangible assets is comprised of customer relationships with an assigned value of $1.247 billion.

The principal considerations for our determination that performing procedures relating to the accounting for the Oryx Midstream business combination is a critical audit matter are (i) the significant judgment by management when determining the fair value of the consideration transferred for the Oryx Midstream Permian Basin business and the customer relationships, which in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to future crude volumes gathered and transported and the discount rates used in the valuation of the consideration transferred for the Oryx Midstream Permian Basin business and the customer relationships;

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

Index to Financial Statements

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 Plains All American Pipeline L.P.

(PAA) 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 PAA common unit price, and default probabilities which impact timing estimates as to when the option will be exercised.

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

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

Treasury rate.

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

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

These procedures included testing the effectiveness of controls relating to acquisition accounting, including controls over management’s valuation of the consideration transferred and the customer relationships, and controls over the determination of the significant assumptions.

These procedures also included, among others (i) reading the transaction agreement and (ii) testing management’s process for determining the fair value of the consideration transferred for the Oryx Midstream Permian Basin business and the customer relationships.

Testing management’s process included evaluating the appropriateness of the valuation methods, testing the completeness and accuracy of data provided by management, and evaluating the reasonableness of the significant assumptions related to future crude volumes gathered and transported and the discount rates used in the valuation of the consideration transferred for the Oryx Midstream Permian Basin business and the customer relationships.

Evaluating the reasonableness of the future crude volumes gathered and transported involved considering (i) the consistency with external market and industry data and (ii) the past performance of the Oryx Midstream Permian Basin business.

Professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of the valuation methods and the reasonableness of the discount rate significant assumption.

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

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

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

/s/ PricewaterhouseCoopers LLP

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Cash and cash equivalents $ 404 $ 452

Restricted cash 4 38

Trade accounts receivable and other receivables, net 3,907 4,705

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Deferred tax asset 1,309 1,362

Linefill and base gas 907 982

Linefill 961 907

Long-term operating lease right-of-use assets, net 349 393

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(Gains)/losses on asset sales and asset impairments, net (Note 6, Note 7) 269 592 719

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

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

Total costs and expenses 56,058 41,236 25,673

2 unchanged sentences

Equity earnings in unconsolidated entities 403 274 355

Gain on/(impairment of) investments in unconsolidated entities, net (Note 9) 2 ( 182 ) 271

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

Interest expense (net of capitalized interest of $ 5 , $ 18 and $ 24 , respectively)

( 405 ) ( 425 ) ( 436 )

Other income, net 19 39 24

Other income/(expense), net ( 219 ) 19 39

INCOME/(LOSS) BEFORE TAX 1,409 712 ( 2,607 )

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Net income/(loss) $ 1,163 $ 600 $ ( 2,440 )

Other comprehensive income 65 15 97

Other comprehensive income/(loss) ( 101 ) 65 15

Comprehensive income/(loss) 1,062 665 ( 2,425 )

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Currency translation adjustments — 17 — 17

Other — — ( 3 ) ( 3 )

2020 Activity 1 17 ( 3 ) 15

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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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(Gains)/losses on asset sales and asset impairments, net (Note 6, Note 7) 269 592 719

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

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

Equity-indexed compensation expense 41 24 16

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Deferred income tax expense/(benefit) 162 62 ( 218 )

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

(Gain)/loss on foreign currency revaluation 41 ( 7 ) ( 16 )

Settlement of terminated interest rate hedging instruments 42 — ( 100 )

Change in fair value of Preferred Distribution Rate Reset Option (Note 13) 189 ( 14 ) ( 20 )

Equity earnings in unconsolidated entities ( 403 ) ( 274 ) ( 355 )

Distributions on earnings from unconsolidated entities 488 431 472

(Gain on)/impairment of investments in unconsolidated entities, net (Note 9) ( 2 ) 182 ( 271 )

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

Other 16 29 23

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Proceeds from sales of assets (Note 7) 60 881 429

Cash received from sales of linefill 72 3 3

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

Other investing activities 44 1 ( 2 )

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Distributions paid to noncontrolling interests (Note 12) ( 918 ) ( 589 ) ( 697 )

Sale of noncontrolling interest in a subsidiary (Note 12) — — 128

Contributions from noncontrolling interests (Note 12) 26 1 12

Other financing activities ( 49 ) ( 161 ) 44

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Balance at December 31, 2019 $ 2,155 $ 12,330 $ 14,485

Net income 331 1,731 2,062

Net loss ( 568 ) ( 1,872 ) ( 2,440 )

Distributions (Note 12) ( 166 ) ( 697 ) ( 863 )

Deferred tax asset (Note 15) 16 — 16

Change in ownership interest in connection with Exchange Right exercises (Note 12) 101 ( 101 ) —

Other comprehensive income (Note 12) 6 9 15

Equity-indexed compensation expense 6 14 20

Sale of noncontrolling interest in a subsidiary (Note 12) — 128 128

Repurchase of common units by a subsidiary (Note 12) 4 ( 54 ) ( 50 )

Contributions from noncontrolling interests (Note 12) — 12 12

Other 11 ( 16 ) ( 5 )

Balance at December 31, 2020 $ 1,464 $ 9,726 $ 11,190

Net loss ( 568 ) ( 1,872 ) ( 2,440 )

Net income 60 540 600

Distributions (Note 12) ( 140 ) ( 589 ) ( 729 )

Deferred tax asset (Note 15) ( 42 ) — ( 42 )

Change in ownership interest in connection with Exchange Right exercises (Note 12) 10 ( 10 ) —

Other comprehensive income (Note 12) 17 48 65

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Contributions from noncontrolling interests (Note 12) — 1 1

Plains Oryx Permian Basin LLC joint venture formation (Note 7) 166 3,090 3,256

Other — ( 6 ) ( 6 )

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Deferred tax asset (Note 15) 5 — 5

Other comprehensive income (Note 12) 17 48 65

Other comprehensive loss (Note 12) ( 28 ) ( 73 ) ( 101 )

Equity-indexed compensation expense 10 23 33

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Plains Oryx Permian Basin LLC joint venture formation (Note 7) ( 3 ) ( 23 ) ( 26 )

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

Other ( 1 ) ( 7 ) ( 8 )

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PAGP does not directly own any operating assets;

as of December 31, 2021, its principal sources of cash flow are derived from an indirect investment in Plains All American Pipeline, L.P.

as of December 31, 2022, its principal source of cash flow is derived from an indirect investment in Plains All American Pipeline, L.P.

(“PAA”), a publicly traded Delaware limited partnership.

As used in this Form 10-K and unless the context indicates otherwise (taking into account the fact that PAGP has no operating activities apart from those conducted by PAA and its subsidiaries), the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAGP and its subsidiaries.

As of December 31, 2021, PAGP owned (i) a 100 % managing member interest in Plains All American GP LLC (“GP LLC”), an entity that has also elected to be taxed as a corporation for United States federal income tax purposes and (ii) an approximate 81 % limited partner interest in Plains AAP, L.P.

(“AAP”) through our direct ownership of approximately 193.2 million Class A units of AAP (“AAP units”) and indirect ownership of approximately 1.0 million AAP units through GP LLC.

GP LLC is a Delaware limited liability company that also holds the non-economic general partner interest in AAP.

As of December 31, 2022, we owned an approximate 81 % limited partner interest in Plains AAP, L.P.

(“AAP”) through our ownership of approximately 194.4 million Class A units of AAP (“AAP units”).

We also own a 100 % managing member interest in Plains All American GP LLC (“GP LLC”), an entity that formerly elected to be taxed as a corporation for United States federal income tax purposes in 2013 and has elected to return to a disregarded entity effective December 31, 2022.

GP LLC also previously held 1.0 million AAP units, which were assigned to us in a deemed liquidation upon the election.

GP LLC is a Delaware limited liability company that holds the non-economic general partner interest in AAP.

AAP is a Delaware limited partnership that, as of December 31, 2022, directly owned a limited partner interest in PAA through its ownership of approximately 241.0 million PAA common units (approximately 31 % of PAA’s total outstanding common units and Series A preferred units combined).

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FASB = Financial Accounting Standards Board

GAAP = Generally accepted accounting principles in the United States

Index to Financial Statements

2 unchanged sentences

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

GAAP = Generally accepted accounting principles in the United States

ICE = Intercontinental Exchange

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The accompanying financial statements and related notes present and discuss our consolidated financial position as of December 31, 2022 and 2021, and the consolidated results of our operations, cash flows, changes in partners’ capital, comprehensive income and changes in accumulated other comprehensive income/(loss) for the years ended December 31, 2022, 2021 and 2020.

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

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

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

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

Reclassification of Prior Period Information

During the fourth quarter of 2021, we effected changes in the primary financial information provided to our Chief Operating Decision Maker (“CODM”) (our Chief Executive Officer) for assessing performance and allocating resources to present two operating segments, Crude Oil and NGL.

Prior to the fourth quarter of 2021, this information was organized into three operating segments:

Transportation, Facilities and Supply and Logistics.

See Note 20 for further discussion of our operating segments.

In connection with this change, we changed the presentation of Revenues on our Consolidated Statements of Operations.

“Product sales revenues” include amounts that were previously presented as “Supply and Logistics segment revenues,” while “Services revenues” includes amounts previously presented as “Transportation segment revenues” and “Facilities segment revenues.”

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

See Note 7 for more details regarding this transaction.

Due to the increase in intangible assets associated with this transaction, we present “Intangible assets, net” as a separate line item on our Consolidated Balance Sheets.

Such amounts were previously reported in “Other long-term assets, net” on our Consolidated Balance Sheets.

Many uncertainties remain with respect to the novel coronavirus (“COVID-19”) pandemic, including uncertainty regarding the length of time the pandemic will continue, as well as the timing, pace and extent of an economic recovery in the United States, Canada and elsewhere, and how such uncertainties will impact the energy industry and our business.

As a result, these matters may affect our estimates and assumptions on amounts reported in the financial statements and accompanying notes in the near term.

Subsequent Events

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

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Purchases and Related Costs

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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, 2021, 2020 and 2019, the revaluation of foreign currency transactions and monetary assets and liabilities resulted in the recognitions of net gains of $ 7 million, $ 16 million and $ 1 million, respectively, in our Consolidated Statements of Operations.

Cash and Cash Equivalents and Restricted Cash

Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits.

We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal.

In accordance with our policy, unless they may be covered by funds on deposit, outstanding checks are classified as trade accounts payable rather than negative cash.

As of December 31, 2021 and 2020, trade accounts payable included $ 19 million and $ 27 million, respectively, of outstanding checks that were reclassified from cash and cash equivalents.

Restricted cash includes cash held by us that is unavailable for general use and is comprised of amounts advanced to us by certain equity method investees related to the construction of fixed assets where we serve as construction manager.

The following table presents a reconciliation of cash and cash equivalents and restricted cash reported on our Consolidated Balance Sheets that sum to the total of the amounts shown on our Consolidated Statements of Cash Flows (in millions):

Cash and cash equivalents $ 452 $ 25

Restricted cash 4 38

Total cash and cash equivalents and restricted cash $ 456 $ 63

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.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Cash and Cash Equivalents

We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal.

In accordance with our policy, unless they may be covered by funds on deposit, outstanding checks are classified as trade accounts payable rather than negative cash.

As of December 31, 2022 and 2021, trade accounts payable included $ 25 million and $ 19 million, respectively, of outstanding checks that were reclassified from cash and cash equivalents.

Noncontrolling Interests

18 unchanged sentences

Liabilities settled (1)

( 26 ) ( 1 ) ( 1 )

Accretion expense 4 4 5

1 unchanged sentence

Ending balance $ 122 $ 143 $ 135

(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.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Measurements

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

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

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

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

1 unchanged sentence

See Note 13 for further discussion.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Other Significant Accounting Policies

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

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

Recent Accounting Pronouncements

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

We have not adopted this guidance as of December 31, 2021, but do not anticipate that our adoption will have a material impact on our financial position, results of operations or cash flows.

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.

9 unchanged sentences

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

This guidance is effective prospectively upon issuance through December 31, 2022 and may be applied from the beginning of an interim period that includes the issuance date of this ASU.

We will apply applicable expedients and exceptions to contract modifications through December 31, 2022.

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.

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

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

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

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

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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.

Note 3— Revenues and Accounts Receivable

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Inventory exchanges under buy/sell transactions are excluded from sales revenues in our Consolidated Statements of Operations.

In addition, we have certain crude oil sales agreements that are entered into in conjunction with storage arrangements and future inventory exchanges.

The revenues under these agreements are deferred until all performance obligations associated with the related agreements are completed.

The inventory that has been sold under these crude oil sales agreements is reflected in “Other current assets” on our Consolidated Balance Sheet until all of our performance obligations are complete.

At that time, the inventory that has been sold is removed from our Consolidated Balance Sheet and recorded as “Purchases and related costs” in our Consolidated Statement of Operations.

See “ Contract Balances ” below for further discussion of contract liabilities associated with these agreements.

The following table presents amounts in Other current assets and deferred revenue associated with these agreements (in millions):

Other current assets $ — $ 229

Deferred revenue (1)

(1) Included in “Other current liabilities” on our Consolidated Balance Sheet.

We may also utilize derivatives in connection with the transactions described above.

Derivative revenue is not included as a component of revenue from contracts with customers, but is included in other items in revenue.

The change in the fair value of derivatives that are not designated or do not qualify for hedge accounting is recognized in revenues each period.

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Transportation Revenues.

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

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

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

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We recognize the allowance volumes collected as part of the transaction price and record this non-cash consideration at fair value, measured as of the contract inception date .

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Terminalling, Storage and Other Revenues.

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revenues from entities accounted for by the equity method are not included.

The following tables present the reconciliation of our revenues from contracts with customers (as described above for each segment) to segment revenues and total revenues as disclosed in our Consolidated Statements of Operations (in millions):

The following tables present the reconciliation of our revenues from contracts with customers (as described above for each segment) to total revenues of reportable segments and total revenues as disclosed in our Consolidated Statements of Operations (in millions):

Year Ended December 31, 2022 Crude Oil NGL Total

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Total revenues $ 23,290

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Minimum Volume Commitments.

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

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

Counterparty Deficiencies Financial Statement Classification 2022 2021

Billed and collected Liability $ 63 $ 73

Billed and collected Other current liabilities $ 104 $ 63

Total $ 105 $ 79

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Amounts recognized as revenue (1)

Additions (2)

Balance at December 31, 2021 $ 141

Amounts recognized as revenue ( 26 )

Additions (2)

Balance at December 31, 2022 $ 229

(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 agreements were entered into in 2019 and recognized as revenue in the first quarter of 2020.

(2) 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.

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

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

See Note 7 for additional information.

Remaining Performance Obligations .

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Total $ 583 $ 532 $ 491 $ 224 $ 178 $ 932

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

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Certain contracts do not meet the requirements for presentation of remaining performance obligations due to variability in amount of performance obligation remaining, variability in the timing of recognition or variability in consideration.

Acreage dedications do require us to perform future services but do not contain a minimum level of services and are therefore excluded from this presentation.

Acreage dedications require us to perform future services but do not contain a minimum level of services and are therefore excluded from this presentation.

Long-term merchant arrangements contain variable timing, volumes and/or consideration and are excluded from this presentation.

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The majority of our accounts receivable relate to our crude oil merchant activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes.

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To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process.

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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.

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

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

For purposes of calculating diluted net income/(loss) per Class A share, both the net income/(loss) attributable to PAGP and the diluted weighted average number of Class A shares outstanding consider the impact of possible future exchanges of (i) AAP units and the associated Class B shares into our Class A shares and (ii) certain Class B units of AAP (referred to herein as “AAP Management Units”) into our Class A shares.

For purposes of calculating diluted net income/(loss) per Class A share, both the net income/(loss) attributable to PAGP and the diluted weighted average number of Class A shares outstanding consider the impact of possible future (i) exchanges of AAP units and the associated Class B shares into our Class A shares and (ii) conversions of vested Class B units of AAP (referred to herein as “AAP Management Units”) into AAP units and the subsequent exchange of those AAP units for our Class A shares.

In addition, the calculation of the diluted weighted average number of Class A shares outstanding considers the effect of potentially dilutive awards under the Plains GP Holdings, L.P.

Long-Term Incentive Plan (the “PAGP LTIP”).

All AAP Management Units that have satisfied the applicable performance conditions are considered potentially dilutive.

All AAP Management Units have satisfied the applicable performance conditions and are considered potentially dilutive.

Exchanges of potentially dilutive AAP units and AAP Management Units are assumed to have occurred at the beginning of the period and the incremental income attributable to PAGP resulting from the assumed exchanges is representative of the incremental income that would have been attributable to PAGP if the assumed exchanges occurred on that date.

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See Note 18 for information regarding PAGP LTIP awards.

On a weighted-average basis, for the years ended December 31, 2022 and 2021, the possible exchange of 47 million and 50 million AAP units, respectively, would not have had a dilutive effect on basic net income per Class A share.

The possible exchange of less than 1 million AAP Management Units for each of the years ended December 31, 2022 and 2021 and 1 million AAP Management Units for the year ended December 31, 2020 would not have had a dilutive effect on basic net income/(loss) per Class A share on a weighted-average basis.

For the year ended December 31, 2020, our PAGP LTIP awards were antidilutive.

For the years ended December 31, 2022 and 2021, our PAGP LTIP awards were dilutive;

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

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On a weighted-average basis, for the years ended December 31, 2021 and 2019, the possible exchange of 50 million and 99 million AAP units, respectively, would not have had a dilutive effect on basic net income per Class A share.

For each of the years ended December 31, 2021 and 2020, the possible exchange of 1 million AAP Management Units would not have had a dilutive effect on basic net income/(loss) per Class A share on a weighted-average basis.

For the year ended December 31, 2020, our PAGP LTIP awards were antidilutive.

For the years ended December 31, 2021 and 2019 our PAGP LTIP awards were dilutive;

however, there were less than 0.1 million dilutive LTIP awards for each period, which did not change the presentation of weighted average Class A shares outstanding or net income per Class A share.

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

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Net income/(loss) attributable to PAGP $ 168 $ 60 $ ( 568 )

Incremental net income/(loss) attributable to PAGP resulting from assumed exchange of AAP units and AAP Management Units

Net income/(loss) attributable to PAGP including incremental net income/(loss) from assumed exchange of AAP units and AAP Management Units

Incremental net income/(loss) attributable to PAGP resulting from assumed exchange of AAP units

Net income/(loss) attributable to PAGP including incremental net income/(loss) from assumed exchange of AAP units

$ 168 $ 60 $ ( 757 )

Basic weighted average Class A shares outstanding

Dilutive shares resulting from assumed exchange of AAP units and AAP Management Units

Dilutive shares resulting from assumed exchange of AAP units

Diluted weighted average Class A shares outstanding

Diluted net income/(loss) per Class A share $ 0.86 $ 0.31 $ ( 3.07 )

Note 5— Inventory, Linefill and Base Gas and Long-term Inventory

Note 5— Inventory, Linefill and Long-term Inventory

Inventory, including long-term inventory, primarily consists of crude oil and NGL in pipelines, storage facilities and railcars that are valued at the lower of cost or net realizable value, with cost determined using an average cost method within specific inventory pools.

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Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Consolidated Statements of Operations.

During the year ended December 31, 2021, no adjustments were recorded.

During the years ended December 31, 2020 and 2019, we recorded charges of $ 233 million (of which $ 40 million was associated with our long-term inventory) and $ 11 million, respectively, related to the write down of our crude oil and NGL inventory due to declines in prices.

No adjustments were recorded during the years ended December 31, 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.

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

Linefill and base gas in assets we own are recorded at historical cost and consist of crude oil, NGL and natural gas.

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

Following the sale of our Pine Prairie and Southern Pines natural gas storage facilities in August of 2021, we no longer own natural gas storage facilities.

See Note 7 for additional information.

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Linefill and base gas carrying amounts are reviewed for impairment in accordance with FASB guidance with respect to accounting for the impairment or disposal of long-lived assets.

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

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

Linefill carrying amounts are reviewed for impairment in accordance with FASB guidance with respect to accounting for the impairment or disposal of long-lived assets.

Carrying amounts that are not expected to be recoverable through future cash flows are written down to estimated fair value.

See Note 6 for further discussion regarding impairment of long-lived assets.

During 2021, 2020 and 2019, we did not recognize any material impairments of linefill and base gas.

During 2022, 2021 and 2020, we did not recognize any material impairments of linefill.

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

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

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

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

December 31, 2022 December 31, 2021

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Inventory subtotal 729 783

Linefill and base gas

Crude oil 15,480 barrels 906 $ 58.53 15,199 barrels 862 $ 56.71

NGL 1,876 barrels 55 $ 29.32 1,633 barrels 45 $ 27.56

Natural gas (2)

— Mcf — $ — 25,576 Mcf 110 $ 4.30

Linefill and base gas subtotal 907 982

Linefill subtotal 961 907

Long-term inventory

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

(2) Base gas with a carrying value of $ 110 million was included in the sale of our natural gas storage facilities, which closed in August 2021.

See Note 7 for additional information.

Note 6— Property and Equipment

In accordance with our capitalization policy, expenditures made to expand the existing operating and/or earnings capacity of our assets are capitalized.

We also capitalize certain costs directly related to the construction of such assets, including related internal labor costs, engineering costs and interest costs.

For the years ended December 31, 2021, 2020 and 2019, capitalized interest recorded to property and equipment was $ 6 million, $ 8 million and $ 14 million, respectively.

In addition, we capitalize interest related to investments in certain unconsolidated entities.

See Note 9 for additional information.

In accordance with our capitalization policy, expenditures made to expand the existing operating and/or earnings capacity of our assets are capitalized, as are certain costs directly related to the construction of such assets, including related internal labor costs, engineering costs and interest costs.

We also capitalize expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets.

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

(2) Useful lives changed to 10 to 50 years in 2021 See below for additional information.

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

Depreciation expense for the years ended December 31, 2022, 2021 and 2020 was $ 710 million, $ 655 million and $ 566 million, respectively.

During the first quarter of 2021, we modified the useful lives of our Pipelines and related facilities and Storage, terminal and rail facilities to useful lives of 10 to 50 years from useful lives of 10 to 70 years to reflect current expectations given our future operating and commercial outlook.

These depreciable life adjustments will prospectively increase depreciation expense.

For the year ended December 31, 2021, these reductions in useful lives increased depreciation expense by approximately $ 72 million, which resulted in a decrease in net income attributable to PAGP of approximately $ 15 million and to both basic and diluted net income per Class A share of approximately $ 0.08 from what these amounts would have been absent the change in useful lives.

As of December 31, 2021, 2020 and 2019, we incurred liabilities for construction in progress that had not been paid of $ 48 million, $ 51 million and $ 120 million, respectively.

As of December 31, 2022, 2021 and 2020, we incurred liabilities of $ 46 million, $ 48 million and $ 51 million, respectively, for construction in progress that had not been paid.

Impairment of Long-Lived Assets (Held and Used)

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

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

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

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

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

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

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

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

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

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

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

We did not recognize any material impairments during the year ended December 31, 2019.

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Note 7— Acquisitions, Divestitures and Other Transactions

In November 2022, we and Enbridge Inc.

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

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

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

We will continue to serve as operator.

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

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

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

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

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

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.

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

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

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

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

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

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

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

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

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

Identifiable Assets Acquired and Liabilities Assumed:

Estimated Useful Lives

(in years) Recognized Amount

Property and equipment 3 - 50

Intangible assets 20 428

Working capital and other assets and liabilities N/A ( 46 )

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

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

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

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

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

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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):

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.

Other Acquisitions

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.

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

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

This transaction was accounted for as an asset acquisition.

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

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

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

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

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Joint Venture Transaction

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

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

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

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

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

The DCF approach utilized a discount rate of 11.75 %, based on our estimate of the risk that a theoretical market participant would assign to the business.

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

The discounted cash flow approach utilized a discount rate of 11.75 %, based on our estimate of the risk that a theoretical market participant would assign to the business.

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

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

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

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

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

The determination of these values is preliminary, pending finalization of working capital balances, and we expect to finalize our fair value determination in 2022.

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

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

Identifiable Assets Acquired and Liabilities Assumed Estimated Useful Lives

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Investment in unconsolidated entities N/A 103

Linefill N/A 5

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

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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.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

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 $ 28 million during the year ended December 31, 2021, and the future amortization expense through 2026 is estimated as follows (in millions):

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):

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.

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

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

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

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

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

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

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

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4 $815 and above 70 % 30 %

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PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Year ended December 31,

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Diluted net income/(loss) per Class A Share $ 0.19 $ ( 3.41 )

Asset Exchange

The assets acquired are included in our Crude Oil segment.

The assets acquired primarily consisted of property and equipment of $ 115 million and intangible assets 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.

During the second quarter of 2019, we acquired a crude oil terminal, including tank bottoms and linefill, in Cushing, Oklahoma for cash consideration of $ 44 million, which was accounted for as an asset acquisition.

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

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

These assets were previously reported in our Crude Oil segment.

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

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

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

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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.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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• 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 assets sales of $ 178 million, including non-cash impairments recognized upon classification to assets held for sale, for the year ended December 31, 2020.

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.

During the year ended December 31, 2019, we sold certain non-core assets for total proceeds of $ 77 million that primarily consisted of a storage terminal in North Dakota, which is reflected in our Crude Oil segment for the period prior to the sale.

For the year ended December 31, 2019, we recognized a net loss related to these asset sales of $ 16 million, which is comprised of gains of $ 31 million and losses of $ 47 million.

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

Note 8— Goodwill

Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized.

In accordance with FASB guidance, we test goodwill to determine whether an impairment has occurred at least annually (as of June 30) and on an interim basis if it is more likely than not that a reporting unit’s fair value is less than its carrying value.

Goodwill is tested for impairment at a level of reporting referred to as a reporting unit.

A reporting unit is an operating segment or one level below an operating segment for which discrete financial information is available and regularly reviewed by segment management.

Our reporting units are our operating segments.

FASB guidance provides for a quantitative approach to testing goodwill for impairment;

however, we may first assess certain qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment test.

In the quantitative test, we compare the fair value of the reporting unit with the respective book values, including goodwill, by using an income approach based on a discounted cash flow model.

This approach requires us to make long-term forecasts of future revenues, expenses and other expenditures.

Those forecasts require the use of various assumptions and estimates, the most significant of which are net revenues (total revenues less purchases and related costs), operating expenses, general and administrative expenses and the weighted average cost of capital.

Fair value of the reporting units is determined using significant unobservable inputs, or Level 3 inputs in the fair value hierarchy.

When the fair value is greater than book value, then the reporting unit’s goodwill is not considered impaired.

If the book value is greater than fair value, then goodwill is impaired by the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value of goodwill.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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.

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”).

This transaction closed in February 2023.

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 represents our estimate of the cost of capital of a theoretical market participant as of March 31, 2020.

The fair values of the reporting units are Level 3 measurements in the fair value hierarchy and were based on various inputs, as discussed below.

The discounted cash flows for each reporting unit were based on six years of projected cash flows and terminal values that we believe would be applied by a theoretical market participant in similar market transactions.

The discounted cash flows for the respective reporting units utilized various other assumptions, including, but not limited to (i) volumes (based on historical information and estimates of future drilling and completion activity, as well as expectations of future demand recovery), (ii) tariff and storage rates, (iii) future commodity prices (based on relevant indices and applicable quality and location differentials), and (iv) estimated fixed and variable costs.

We used a range of cash flows for the discounted cash flow calculations based on differing potential market scenarios, but for each of the reporting units, the ultimate outcome of the impairment test was unchanged by the various points within the range of cash flows.

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 a goodwill impairment charge for the entire goodwill balance for each reporting unit.

Prior to the year ended December 31, 2020, we did not recognize any impairments of goodwill.

Goodwill by segment and changes in goodwill is reflected in the following table (in millions):

Crude Oil NGL Total

Balance at December 31, 2019 $ 2,300 $ 240 $ 2,540

Acquisitions 2 — 2

Goodwill, gross $ 2,302 $ 240 $ 2,542

Impairments ( 2,287 ) ( 228 ) ( 2,515 )

Foreign currency translation adjustments ( 15 ) ( 12 ) ( 27 )

Accumulated impairment losses ( 2,302 ) ( 240 ) ( 2,542 )

Balance at December 31, 2020 $ — $ — $ —

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 9— Investments in Unconsolidated Entities

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

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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BridgeTex Pipeline Company, LLC (“BridgeTex”) Crude Oil Pipeline 20 % $ 403 $ 406

Cactus II Pipeline LLC (“Cactus II”) Crude Oil Pipeline 65 % 737 752

Cactus II (2)

Crude Oil Pipeline — % — 737

Capline Pipeline Company LLC Crude Oil Pipeline 54 % 539 531

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Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”) Crude Oil Terminal and Dock 50 % 118 120

OMOG JV LLC (3)

OMOG JV LLC (“OMOG”) (3)

Crude Oil Pipeline 57 % 211 102

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

(2) The Capline pipeline was out of service during 2020 and a majority of 2021 pending the reversal of the pipeline system.

The pipeline reversal project was completed with interim service beginning in mid-December 2021 and full service beginning in January 2022.

(3) Our ownership in this entity was acquired as part of the assets contributed by Oryx Midstream in the formation of the Permian JV in October 2021.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(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.

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.

(4) 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.

(5) The pipeline system was in partial service during 2021 and another phase of the pipeline construction project was completed in the first quarter of 2022.

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

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

See Note 7 for additional information.

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

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 represents our estimate of the cost of capital of a theoretical market participant.

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.

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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.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Other investments.

Capline LLC .

During the first quarter of 2019, the owners of the Capline pipeline system contributed their undivided joint interests in the system to a newly formed entity, Capline Pipeline Company LLC (“Capline LLC”), in exchange for equity interests in such entity.

After the contribution, Capline LLC owns 100 % of the pipeline system.

Each owner’s undivided joint interest in the Capline pipeline system prior to the transaction is equal to each owner’s equity interest in Capline LLC.

Although we own a majority of Capline LLC’s equity, we do not have a controlling financial interest in Capline LLC because the other members have substantive participating rights.

Therefore, we account for our ownership interest in Capline LLC as an equity method investment.

Under applicable accounting rules, the transaction resulted in a “loss of control” of our undivided joint interest, which was derecognized and contributed to Capline LLC.

The “loss of control” required us to measure our equity interest in Capline LLC at fair value.

At the time of the transaction, our 54 % undivided joint interest in the Capline pipeline system had a carrying value of $ 175 million, which primarily related to property and equipment included in our Crude Oil segment.

We determined the fair value of our investment in Capline LLC to be approximately $ 444 million, resulting in the recognition of a gain of $ 269 million during the year ended December 31, 2019.

Such gain is included in “Gain on/(impairment of) investment in unconsolidated entities, net” on our Consolidated Statement of Operations.

The fair value of our investment in Capline LLC was based on an income approach utilizing a discounted cash flow analysis.

The cash flow forecasts require the use of various assumptions and estimates which include those related to the timing and amount of capital expenditures, the expected tariff rates and volumes of crude oil, and the terminal value.

We probability-weighted various forecasted cash flow scenarios utilized in the analysis when we considered the possible outcomes.

We used a discount rate representing our estimate of the risk adjusted discount rate that would be used by market participants.

If shipper interest varies from the levels assumed in our model, the related cash flows, and thus the fair value of our investment, could be materially impacted.

The fair value of our investment was determined using significant unobservable inputs, or Level 3 inputs in the fair value hierarchy.

In February 2020, we sold a 10 % ownership interest in Saddlehorn for proceeds of approximately $ 78 million and have retained a 30 % ownership interest.

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

We continue to account for our remaining interest under the equity method of accounting.

Distributions

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We generally fund our portion of development, construction or capital investment projects of our equity method investees through capital contributions.

Our contributions to these entities increase the carrying value of our investments and are reflected in our Consolidated Statements of Cash Flows as cash used in investing activities.

During the years ended December 31, 2022, 2021 and 2020, we made cash contributions of $ 13 million, $ 82 million and $ 445 million, respectively, to certain of our equity method investees.

In addition, we capitalized interest of $ 12 million, $ 16 million and $ 20 million during the years ended December 31, 2021, 2020 and 2019, respectively, related to contributions to unconsolidated entities for projects under development and construction.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

We capitalize interest costs associated with contributions to unconsolidated entities for projects under development and construction.

Our contributions to these entities (including capitalized interest costs) increase the carrying value of our investments and are reflected in our Consolidated Statements of Cash Flows as cash used in investing activities.

Basis Differences

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$ 2,852 $ ( 707 ) $ 2,145 $ 2,481 $ ( 521 ) $ 1,960

(1) The increase in intangible assets related to Customer contracts and relationships in 2021 is associated with the assets acquired in the formation of the Permian JV.

(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.

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We did not recognize any impairments of finite-lived intangible assets during the three years ended December 31, 2022.

The majority of our finite-lived intangible assets are amortized under the declining balance method.

Amortization expense for finite-lived intangible assets for the years ended December 31, 2022, 2021 and 2020 was $ 254 million, $ 122 million and $ 90 million, respectively.

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SHORT-TERM DEBT

PAA commercial paper notes, bearing a weighted-average interest rate of 0.7 % (1)

PAA senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.2 % (1)

PAA senior notes:

3.65 % senior notes due June 2022

2.85 % senior notes due January 2023

3.85 % senior notes due October 2023

Total short-term debt 1,159 822

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PAA senior notes:

3.65 % senior notes due June 2022

2.85 % senior notes due January 2023

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Other long-term debt:

PAA GO Zone term loans, net of debt issuance costs of $ 1 , bearing a weighted-average interest rate of 1.3 % (4)

Total long-term debt 7,287 8,398

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$ 8,446 $ 9,220

(1) We classified these PAA commercial paper notes and credit facility borrowings as short-term as of December 31, 2020, as these notes and borrowings 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) In January 2022, PAA provided notice of its intention to redeem these senior notes on March 1, 2022.

(3) During the year ended December 31, 2020, we repurchased $ 17 million of our outstanding senior notes on the open market and recognized a gain of $ 3 million on these transactions, which is included in “Other income/(expense), net” on our Consolidated Statement of Operations.

(1) PAA’s fixed-rate senior notes had a face value of approximately $ 8.4 billion and $ 9.1 billion at December 31, 2022 and 2021, respectively.

We estimated the aggregate fair value of these notes to be approximately $ 7.6 billion and $ 9.9 billion at December 31, 2022 and 2021, respectively.

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

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

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

The fair value estimates for the PAA 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.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(4) The GO Zone term loans were initially assumed by a subsidiary of PAA in connection with the acquisition of the Southern Pines natural gas storage facility.

The loans were repaid in August 2021 in connection with the sale of that facility.

See Note 7 for additional information.

(5) PAA’s fixed-rate senior notes had a face value of approximately $ 9.1 billion at both December 31, 2021 and 2020.

We estimated the aggregate fair value of these notes to be approximately $ 9.9 billion at both December 31, 2021 and 2020.

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

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

We estimate that the carrying value of outstanding borrowings under PAA’s credit facilities, commercial paper program and GO Zone term loans approximates fair value as interest rates reflect current market rates.

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

PAA Commercial Paper Program

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PAA senior secured hedged inventory facility .

In August 2021, PAA entered into an amended credit agreement which replaced its $ 1.4 billion senior secured hedged inventory facility scheduled to mature in August 2022 with a $ 1.35 billion senior secured hedged inventory facility with an initial maturity date of August 2024.

PAA has a credit agreement that provides for a senior secured hedged inventory facility with a committed borrowing capacity of $ 1.35 billion.

Subject to obtaining additional or increased lender commitments and other terms and conditions, the committed capacity of the facility may be increased to $ 1.9 billion.

The amended credit agreement provides for the issuance of letters of credit of up to $ 400 million.

The credit agreement provides for the issuance of letters of credit of up to $ 400 million.

Proceeds from the facility are primarily used to finance purchased or stored hedged inventory, including NYMEX and ICE margin deposits.

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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.

PAA senior unsecured revolving credit facility.

In August 2021, PAA entered into a new unsecured credit agreement that provides for a senior unsecured revolving credit facility with a committed borrowing capacity of $ 1.35 billion, of which $ 400 million is available for the issuance of letters of credit.

The new credit agreement replaced its previous credit agreement that provided for a $ 1.6 billion senior unsecured revolving credit facility and was scheduled to mature in August 2024.

PAA has a credit agreement that provides for a senior unsecured revolving credit facility with a committed borrowing capacity of $ 1.35 billion, of which $ 400 million is available for the issuance of letters of credit.

Subject to obtaining additional or increased lender commitments and other terms and conditions, the committed capacity may be increased to $ 2.1 billion.

Borrowings accrue interest based, at our election, on certain floating rate indices as defined in the credit agreement, in each case plus a margin based on our credit rating at the applicable time.

The new credit agreement has an initial maturity date of August 2026 and provides for one or more one-year extensions, subject to applicable approval and other terms and conditions.

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.

PAA GO Zone term loans .

In August 2018, PAA entered into an agreement for two $ 100 million term loans (the “GO Zone term loans”) from the remarketing of its $ 100 million Mississippi Business Finance Corporation Gulf Opportunity Zone Industrial Development Revenue Bonds (PAA Natural Gas Storage, L.P.

Project), Series 2009 and its $ 100 million Mississippi Business Finance Corporation Gulf Opportunity Zone Industrial Development Revenue Bonds (PAA Natural Gas Storage, L.P.

Project), Series 2010 (collectively, the “GO Bonds”).

The GO Zone term loans accrued interest, based on certain floating rate indices, in accordance with the interest payable on the related GO Bonds as provided in the GO Bonds Indenture pursuant to which such GO Bonds are issued and governed.

The GO Zone term loans were repaid in August 2021 in connection with the sale of the Southern Pines natural gas storage facility.

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

See Note 7 for additional information.

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PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

PAA Senior Notes

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September 2030 $ 750 March 15 and September 15

2019 3.55 % Senior Notes issued at 99.801 % of face value

December 2029 $ 1,000 June 15 and December 15

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PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

PAA Senior Notes Repayments.

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Year Description Repayment Date

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)

2019 $ 500 million 2.60 % Senior Notes due December 2019

November 2019 (2)

2019 $ 500 million 5.75 % Senior Notes due January 2020

December 2019 (2)

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

(2) These senior notes were repaid with proceeds from PAA’s 3.80 % senior notes issued in June 2020 and cash on hand.

(2) These senior notes were repaid with proceeds from PAA’s 3.55 % senior notes issued in September 2019 and cash on hand.

On January 31, 2023, PAA redeemed its 2.85 %, $ 400 million senior notes.

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

The weighted average maturity of PAA’s senior notes outstanding at December 31, 2022 was approximately 9 years.

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Thereafter $ 4,783

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PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Covenants and Compliance

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

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PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

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PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 12— Partners’ Capital and Distributions

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

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PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Exchange and Redemption Rights

Holders of AAP units and their permitted transferees each have the right to exchange all or a portion of their AAP units for Class A shares at an exchange ratio of one Class A share for each AAP unit exchanged (referred to herein as their “Exchange Right”).

This Exchange Right may be exercised only if, simultaneously therewith, an equal number of our Class B shares and general partner units are transferred by the exercising party to us.

This Exchange Right may be exercised only if, simultaneously therewith, an equal number of our Class B shares and general partner units (if any) are transferred by the exercising party to us.

Additionally, a holder of vested AAP Management Units is entitled to convert his or her AAP Management Units into AAP units and a like number of our Class B shares based on a conversion ratio of approximately 0.941 AAP units for each AAP Management Unit.

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See Note 15 for information regarding the recognition of deferred tax assets associated the transfer of ownership resulting from Exchange Right exercises.

Additionally, subject to certain limitations, a holder of AAP units (other than us and GP LLC) has the right (a “Redemption Right”) to cause AAP to redeem any or all of such holder’s AAP units in exchange for the distribution of an equivalent number of PAA common units held by AAP (“AAP Unit Redemption”).

Additionally, subject to certain limitations, a holder of AAP units (other than us) has the right (a “Redemption Right”) to cause AAP to redeem any or all of such holder’s AAP units in exchange for the distribution of an equivalent number of PAA common units held by AAP (“AAP Unit Redemption”).

In connection with any AAP Unit Redemption, the redeeming holder will transfer the AAP units to AAP and a corresponding number of our Class B shares and general partner units (if any), in each case, to us.

The AAP units transferred to AAP will be canceled, the Class B shares transferred to us will be canceled and the general partner units transferred to us will remain outstanding and increase our ownership percentage in our general partner.

The AAP units transferred to AAP will be canceled, the Class B shares transferred to us will be canceled and any general partner units transferred to us will remain outstanding and increase our ownership percentage in our general partner.

Additionally, we will issue a corresponding number of Class C shares to PAA.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Shares Outstanding

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182,138,592 65,785,702 549,538,139

Conversion of AAP Management Units — 595,117 —

Exchange Right exercises 11,858,457 ( 11,858,457 ) —

22,637,818 ( 22,637,818 ) —

Redemption Right exercises — ( 3,882,170 ) 3,882,170

— ( 31,180,818 ) 31,180,818

Repurchase and cancellation of common units by a subsidiary under the Common Equity Repurchase Program — — ( 6,222,748 )

Other 54,387 — 520,201

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Redemption Right exercises — ( 4,286,491 ) 4,286,491

Repurchase and cancellation of common units by a subsidiary — — ( 6,222,748 )

Repurchase and cancellation of common units by a subsidiary under the Common Equity Repurchase Program — — ( 18,061,583 )

Other 18,546 — 654,161

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Redemption Right exercises — ( 518,464 ) 518,464

Repurchase and cancellation of common units by a subsidiary — — ( 18,061,583 )

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

Other 35,715 — 578,604

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194,407,642 46,205,947 528,442,538

(1) Includes exercises by Occidental Petroleum Corporation or its subsidiaries (“Oxy”) and an affiliate of The Energy & Minerals Group (“EMG”).

See Note 17 for additional information.

Distributions

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Distributions to Our Shareholders

We distribute 100 % of our available cash within 55 days following the end of each quarter to Class A shareholders of record.

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This distribution of $ 52 million was paid on February 14, 2023 to shareholders of record at the close of business on January 31, 2023, for the period October 1, 2022 through December 31, 2022.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Other Comprehensive Income/(Loss)

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Noncontrolling Interests in Subsidiaries

As of December 31, 2021, noncontrolling interests in our subsidiaries consisted of (i) limited partner interests in PAA including a 69 % interest in PAA’s common units and PAA’s Series A preferred units combined and 100 % of PAA’s Series B preferred units, (ii) an approximate 19 % limited partner interest in AAP, (iii) a 35 % interest in the Permian JV, as discussed further below, and (iv) a 33 % interest in Red River Pipeline Company LLC (“Red River LLC”), as discussed further below.

As of December 31, 2022, noncontrolling interests in our subsidiaries consisted of (i) limited partner interests in PAA including a 69 % interest in PAA’s common units and PAA’s Series A preferred units combined and 100 % of PAA’s Series B preferred units, (ii) an approximate 19 % limited partner interest in AAP, (iii) a 35 % interest in the Permian JV, (iv) a 30 % interest in Cactus II and (v) a 33 % interest in Red River Pipeline Company LLC (“Red River”).

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

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

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

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

See Note 7 for more details regarding this transaction.

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

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See Note 7 for more details regarding this transaction.

In May 2019, we formed a joint venture, Red River LLC, with Delek Logistics Partners, LP (“Delek”) on our Red River pipeline system.

We received approximately $ 128 million for Delek’s 33 % interest in Red River LLC.

We consolidate Red River LLC based on control, with Delek’s 33 % interest accounted for as a noncontrolling interest.

During the years ended December 31, 2021 and 2020, we received contributions from noncontrolling interests in Red River LLC of $ 1 million and $ 12 million, respectively, related to the Red River pipeline capacity expansion.

Repurchases of Units by Subsidiary

Common Equity Repurchase Program

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

PAA repurchased 18,061,583 and 6,222,748 common units under the Program through open market purchases that settled during the years ended December 31, 2021 and 2020, respectively.

The total purchase price of these PAA common units was $ 178 million and $ 50 million, respectively, including commissions and fees.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

During the years ended December 31, 2022, 2021, and 2020, PAA 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.

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

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See Note 15 for additional information regarding the associated impact to the deferred tax asset.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Subsidiary Distributions

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

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

At December 31, 2022, approximately $ 9 million of accrued distributions payable to PAA’s Series B preferred unitholders was included in “Other current liabilities” on our Consolidated Balance Sheet.

PAA Common Unit Distributions.

PAA distributes 100 % of its available cash within 45 days following the end of each quarter to common unitholders of record, including AAP.

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

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

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

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

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

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

Distributions Paid Distributions per

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Of this amount, approximately $ 65 million was paid to AAP.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

AAP Distributions.

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Of this amount, $ 13 million was distributed to noncontrolling interests and $ 52 million was distributed to us.

Other Distributions.

During the years ended December 31, 2021, 2020 and 2019, we paid distributions of $ 14 million, $ 10 million and $ 6 million, respectively, to noncontrolling interests in Red River LLC.

Consolidated Joint Venture Distributions.

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

See Note 7 for additional information.

Cash available for distribution is cash on hand less the amount of cash required to fund normal operations and capital projects.

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

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

2022 2021 2020

Permian JV (1)

$ 273 $ — $ —

Cactus II 4 — —

Red River 21 14 10

$ 298 $ 14 $ 10

(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.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

Subsequent distributions will be allocated based on the MSA.

See Note 7 for additional information .

Note 13— Derivatives and Risk Management Activities

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

We use various derivative instruments to optimize our profits while managing our exposure to (i) commodity price risk, (ii) interest rate risk and (iii) currency exchange rate risk.

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

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

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

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

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

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

When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge.

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Our policy is to (i) only purchase inventory for which we have a sales market, (ii) structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold material physical inventory or derivatives for the purpose of speculating on commodity price changes.

The material commodity-related risks inherent in our business activities can be divided into the following general categories:

Commodity Purchases and Sales — In the normal course of our operations, we purchase and sell commodities.

The material commodity-related risks inherent in our business activities are described below.

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

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

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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.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

• A net short position of 19.2 million barrels through December 2023 related to anticipated net sales of crude oil and NGL inventory.

Natural Gas Processing/NGL Fractionation — We purchase natural gas for processing and operational needs.

We purchase natural gas for processing and operational needs.

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

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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.

We estimate that substantially all of the remaining deferred loss will be reclassified to earnings through 2054 as the underlying hedged transactions impact earnings.

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Interest rate derivatives, net $ 94 $ 19 $ ( 10 )

At December 31, 2021, the net fair value of our interest rate hedges, which were included in “Other long-term assets, net” on our Consolidated Balance Sheet, totaled $ 65 million.

At December 31, 2020, the net fair value of these hedges totaled $ 46 million and was included in “Other long-term assets, net.”

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2022, 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 $ 75 million and $ 45 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.”

Preferred Distribution Rate Reset Option

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 the PAA Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, the PAA partnership agreement, and recorded at fair value on our Consolidated Balance Sheets.

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, 2021, 2020 and 2019 we recognized net gains of $ 14 million, $ 20 million and $ 2 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 less than $ 1 million and $ 14 million at December 31, 2021 and 2020, respectively.

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, PAA 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.

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Interest rate derivatives — 120 — 120 — 65 — 65

Preferred Distribution Rate Reset Option and Other — — — — — 2 ( 14 ) ( 12 )

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

Total net derivative asset/(liability) $ ( 7 ) $ 349 $ ( 189 ) $ 153 $ ( 17 ) $ ( 59 ) $ ( 2 ) $ ( 78 )

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

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

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

In addition, it includes certain physical commodity contracts.

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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.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

This model contains inputs, including our common unit price, ten-year U.S.

Treasury rates, default probabilities and timing estimates, some of which involve management judgment.

A significant change in these inputs could result in a material change in fair value to this embedded derivative feature.

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 PAA’s Series A preferred units contained in PAA’s 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, PAA’s 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.

Rollforward of Level 3 Net Asset/(Liability)

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Our lease agreements do not contain any material restrictive covenants.

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

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

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

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

(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)

$ 1 $ 32 $ 27

(1) Includes $ 25 million and $ 12 million for the years ended December 31, 2020 and 2019, respectively, associated with leased storage tanks owned by an equity method investee, in which we own a 50 % interest.

(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 income tax expense/(benefit) $ 246 $ 112 $ ( 167 )

The Canadian federal and provincial income tax for the year ended December 31, 2020 reflects the impact of permanent differences primarily related to an impairment of goodwill that was recognized during the year.

A portion of the

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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.

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.

During the second quarter of 2019, the Alberta government enacted legislation that reduces the Alberta provincial corporate income tax rate from 12 % to 8 % over the period from July 1, 2019 through January 1, 2022.

As a result, during the second quarter of 2019, we recognized a reduction of our deferred income tax liability of approximately $ 60 million and a corresponding deferred tax benefit.

In the fourth quarter of 2020, the Alberta government changed the timing of the rate reduction to decrease the corporate income tax rate to 8 % starting July 1, 2020.

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

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Property and equipment in excess of tax values ( 515 ) ( 531 )

Derivative instruments ( 46 ) —

Lease assets ( 42 ) ( 47 )

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Other long-term liabilities and deferred credits ( 545 ) ( 477 )

$ 885 $ 1,028

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

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

As of December 31, 2021, our federal, state, and foreign net operating loss carryforwards for income tax purposes were approximately $ 2,832 million, $ 797 million and $ 9 million, respectively.

If not utilized, the state and foreign net operating losses will begin to expire in 2022 and 2034, respectively, and a portion of our federal net operating losses will begin to expire in 2033.

As of December 31, 2022, our federal and state net operating loss carryforwards for income tax purposes were approximately $ 3,082 million and $ 855 million, respectively.

If not utilized, the state net operating losses will begin to expire in 2023 and a portion of our federal net operating losses will begin to expire in 2033.

Under the Tax Act, U.S.

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federal NOLs generated prior to 2018 will not be subject to the taxable income limitation and will remain subject to a 20 year carryforward period.

Generally, tax returns for our Canadian entities are open to audit from 2016 through 2022.

and state tax years are generally open to examination from 2019 to 2022.

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Generally, tax returns for our Canadian entities are open to audit from 2017 through 2021.

and state tax years are generally open to examination from 2018 to 2021.

As of December 31, 2022, in reference to tax years 2008 to 2017, we had received notices of reassessment (“notices”) from the Canada Revenue Agency and the Alberta Tax and Revenue Administration (the “Canadian Tax Authorities”) related primarily to transfer pricing associated with cross-border intercompany financing transactions.

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

Phillips 66 Company and its subsidiaries accounted for 11 % of our revenues for the year ended December 31, 2019.

No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2022.

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Transactions with Other Related Parties

Our other related parties include (i) principal owners and their affiliated entities and (ii) entities in which we hold investments and account for under the equity method of accounting (see Note 9 for information regarding such entities).

Our other related parties include (i) entities in which we hold investments and account for under the equity method of accounting (see Note 9 for information regarding such entities) and (ii) principal owners and their affiliated entities.

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

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As of December 31, 2022, no entities met the criteria to be recognized as a principal owner in PAA.

Through various transactions by an affiliate of EMG in May 2019, EMG’s limited partner interest in AAP was significantly reduced, which caused EMG to lose its right to designate a representative on the board of directors of our general partner (the “Board”).

Additionally, as a result of various transactions by Oxy in September 2019, Oxy no longer holds a limited partner interest in AAP and lost its right to designate a representative on the Board.

Following these transactions, we no longer recognize EMG or Oxy as a principal owner.

In August 2021, the Board approved and adopted an amendment to our general partner’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 Board without being subject to public election.

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Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan 13.4

(1) Of the 47.3 million total awards authorized, 26.0 million awards are currently available.

(1) Of the 47.3 million total awards authorized, 23.0 million awards are currently available for future grant.

The remaining balance has already vested or is currently outstanding.

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Expense associated with our storage, transportation and pipeline throughput agreements was approximately $ 336 million, $ 270 million and $ 265 million for 2022, 2021 and 2020, respectively.

A majority of the storage, transportation and pipeline throughput commitments are associated with agreements to store crude oil at facilities and transport crude oil on pipelines owned by equity method investees, in which we own a 50 % interest, at posted tariff rates or prices that we believe approximate market.

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

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

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Under such laws and regulations, we could be required to remove or remediate hazardous liquids or associated wastes (including wastes disposed of or released by prior owners or operators) and to clean up contaminated property (including contaminated groundwater).

Assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified.

Assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified or insured.

Although we have made significant investments in our maintenance and integrity programs, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail, storage and other facility operations.

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

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

The Consent Decree resolved all regulatory claims related to the incident.

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

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

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

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

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

The prosecution has appealed the Court’s rulings.

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

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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.

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.

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

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

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

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

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

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

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

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 remain pending in the United States District Court for the Central District of California.

In the first proceeding, the plaintiffs claim two different classes of claimants were damaged by the release:

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.

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

We are vigorously defending against those claims.

This case is set for trial to begin in June of 2022.

In the second 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.

In addition, four unitholder derivative lawsuits were filed by certain purported investors in PAA against PAGP and certain of PAA’s affiliates, officers and directors.

After various claims were either dismissed or consolidated, one proceeding against PAGP remains pending in Delaware Chancery Court.

Generally, the plaintiffs claim that PAGP failed to exercise proper oversight over the Partnership’s pipeline integrity efforts.

We will continue to vigorously defend against the claim.

No trial date has been set in this action.

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

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

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

Remaining claims include claims for lost revenue or profit asserted by a former oil producer that declared bankruptcy and shut in its offshore production platform following the Line 901 incident, a state agency that received royalties on oil produced from that platform until it was abandoned by its owner, and 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 suits.

We may be subject to additional claims and lawsuits, which could materially impact the liabilities and costs we currently expect to incur as a result of the Line 901 incident.

Taking the foregoing into account, as of December 31, 2021, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $ 495 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 and certain third-party claims settlements, as well as estimates for certain legal fees.

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.

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

To date, we have received payment of approximately $ 3.6 million from one insurer, which represents the final payment obligation of such insurer and brings the total amount collected from all insurers under such program to $ 275 million of the $ 500 million policy limits as of December 31, 2022.

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.

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

Our belief is based on:

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

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

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

Index to Financial Statements

PLAINS GP HOLDINGS, L.P.

AND SUBSIDIARIES

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.

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.

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

As of December 31, 2022, our incurred costs for the Line 901 incident have exceeded our insurance coverage limit of $ 500 million related to our 2015 insurance program applicable to the Line 901 incident by $ 240 million.

Through December 31, 2022, we had collected, subject to customary reservations, approximately $ 280 million out of the $ 505 million of release costs that we believe are probable of recovery from insurance carriers (including the 2015 insurance program and our directors and officers (D&O) insurance policies), net of deductibles.

Therefore, as of December 31, 2022, we have recognized a long-term receivable of approximately $ 225 million for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected.

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

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

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

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

Index to Financial Statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2021, we had a remaining undiscounted gross liability of $ 103 million related to this event, which is reflected in “Trade accounts payable” and “Other current liabilities” on our Consolidated Balance Sheet.

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

Subject to such exclusions and deductibles, we believe that our coverage is adequate to cover the current estimated total emergency response and clean-up costs, claims settlement costs and remediation costs and we believe that this coverage is also adequate to cover any potential increase in the estimates for these costs that exceed the amounts currently identified.

Through December 31, 2021, we had collected, subject to customary reservations, $ 250 million out of the approximate $ 355 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles.

Therefore, as of December 31, 2021, we have recognized a receivable of approximately $ 105 million for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected.

Such amount is recognized as a current asset in “Trade accounts receivable and other receivables, net” on our Consolidated Balance Sheet.

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

however, we expect to make payments for additional costs associated with restoration of the impacted areas, as well as legal, professional and regulatory costs during future periods.

Other Litigation Matters.

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

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

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

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

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.

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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.

However, 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 indemnification obligations, could materially and adversely affect our operations and financial condition.

We believe that we maintain adequate insurance coverage, although 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.

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.

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Note 20— Segment Information

During the fourth quarter of 2021, we effected changes in the primary financial information provided to our CODM (our Chief Executive Officer) for assessing performance and allocating resources to present two operating segments, Crude Oil and NGL.

Prior to the fourth quarter of 2021, this information was organized into three operating segments:

Transportation, Facilities and Supply and Logistics.

The change in our segments is reflective of a change in how our CODM views our business and stems primarily from (i) a multi-year transition in the midstream energy industry driven by increased competition that has reduced the stand alone earnings opportunities of our supply and logistics activities such that those activities now primarily support our effort to increase the utilization of our Crude Oil and NGL assets and (ii) internal changes regarding the oversight and reporting of our assets and related results of operations.

All segment data and related disclosures for earlier periods presented herein have been recast to reflect the new segment reporting structure.

Our operating segments, which are also our reportable segments, are organized by product as our Crude Oil and NGL businesses are generally impacted by different market fundamentals and require the use of different assets and business strategies.

Our operating segments, Crude Oil and NGL, which are also our reportable segments, are organized by product as our Crude Oil and NGL businesses are generally impacted by different market fundamentals and require the use of different assets and business strategies.

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

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

In our historical segment reporting, our marketing activities were presented separately from our other operating activities.

Our crude oil and NGL marketing activities are now included in the respective reporting segments as their primary purpose is to support the utilization of our assets by entering into transactions that facilitate increased volumes handled by our assets, resulting in additional earnings for each of our segments.

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

Our crude oil and NGL marketing activities are included in the respective reporting segments as their primary purpose is to support the utilization of our assets by entering into transactions that facilitate increased volumes handled by our assets, resulting in additional earnings for each of our segments.

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

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

We define Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus (d) our proportionate share of the depreciation and amortization expense 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 related to investing activities (such as the purchase of linefill) 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 in consolidated joint venture entities (“Adjusted EBITDA attributable to noncontrolling interests in consolidated joint ventures”).

During the fourth quarter of 2021, we modified our definition of Segment Adjusted EBITDA to exclude amounts attributable to noncontrolling interests in consolidated joint ventures.

In connection with the Permian JV formation in October 2021, our CODM determined this modification resulted in amounts that were more meaningful to evaluate segment performance.

Amounts attributable to noncontrolling interests in consolidated joint ventures for periods prior have been recast to reflect this modification.

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 in consolidated joint venture entities (“Adjusted EBITDA attributable to noncontrolling interests in consolidated joint ventures”).

Segment Adjusted EBITDA excludes depreciation and amortization.

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

Capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as maintenance capital, which is deducted in determining “available cash.” Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are charged to expense as incurred.

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

Assets are not reviewed by our CODM on a segmented basis;

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( 85 ) ( 123 ) ( 73 )

Gains/(losses) from derivative activities and inventory valuation adjustments (3)

Derivative activities and inventory valuation adjustments (3)

280 271 ( 480 )

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Deficiencies under minimum volume commitments, net (5)

( 7 ) 7 ( 74 )

Equity-indexed compensation expense (6)

( 32 ) ( 19 ) ( 19 )

Net gain/(loss) on foreign currency revaluation (7)

Foreign currency revaluation (7)

Line 901 incident (8)

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Gains/(losses) on asset sales and asset impairments, net ( 269 ) ( 592 ) ( 719 )

Goodwill impairment losses — ( 2,515 ) —

Gain on/(impairment of) investments in unconsolidated entities, net 2 ( 182 ) 271

Goodwill impairment loss — — ( 2,515 )

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

Interest expense, net

( 405 ) ( 425 ) ( 436 )

Other income, net

Other income/(expense), net

( 219 ) 19 39

Income/(loss) before tax

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

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

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

Index to Financial Statements

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

In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill.

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

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

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We exclude the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and write-downs of such inventory that result from price declines from Segment Adjusted EBITDA.

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

(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.

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An adjustment for these non-recurring expenses is included in the calculation of Segment Adjusted EBITDA for the years ended December 31, 2021 and 2020 as our CODM does not view such expenses as integral to understanding our core segment operating performance.

(10) Reflects amounts attributable to noncontrolling interests in the Permian JV (beginning October 2021) and Red River LLC.

See Note 12 for additional information regarding these noncontrolling interests.

(10) Reflects amounts attributable to noncontrolling interests in the Permian JV (beginning October 2021), Cactus II (beginning November 2022) and Red River.

(11) Represents general and administrative expenses incremental to those of PAA, which are not allocated to our reporting segments in determining Segment Adjusted EBITDA.

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$ 22,460 $ 22,373

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

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

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