10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________________________________

FORM 10-Q

________________________________________________________________________________________________________________________________

☑      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2022

or

☐      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 1-36132

________________________________________________________________

PLAINS GP HOLDINGS, L.P.

(Exact name of registrant as specified in its charter)

Delaware	90-1005472
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

333 Clay Street, Suite 1600

Houston, Texas 77002

(Address of principal executive offices) (Zip code)

(713) 646-4100

(Registrant’s telephone number, including area code)

________________________________________________________________

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class A Shares	PAGP	Nasdaq

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  ☑ Yes  ☐ No

 Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  ☑ Yes  ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☑	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

 If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ☐ Yes  ☑ No

As of April 29, 2022, there were 194,228,477 Class A Shares outstanding.

PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
Condensed Consolidated Balance Sheets: As of March 31, 2022 and December 31, 2021	3
Condensed Consolidated Statements of Operations: For the three months ended March 31, 2022 and 2021	4
Condensed Consolidated Statements of Comprehensive Income: For the three months ended March 31, 2022 and 2021	5
Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss): For the three months ended March 31, 2022 and 2021	5
Condensed Consolidated Statements of Cash Flows: For the three months ended March 31, 2022 and 2021	6
Condensed Consolidated Statements of Changes in Partners’ Capital: For the three months ended March 31, 2022 and 2021	7
Notes to the Condensed Consolidated Financial Statements:
1. Organization and Basis of Consolidation and Presentation	8
2. Summary of Significant Accounting Policies	10
3. Revenues and Accounts Receivable	11
4. Net Income Per Class A Share	14
5. Inventory, Linefill and Long-term Inventory	15
6. Debt	16
7. Partners’ Capital and Distributions	17
8. Derivatives and Risk Management Activities	19
9. Related Party Transactions	24
10. Commitments and Contingencies	25
11. Segment Information	30
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	34
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	51
Item 4. CONTROLS AND PROCEDURES	52
PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS	53
Item 1A. RISK FACTORS	53
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	53
Item 3. DEFAULTS UPON SENIOR SECURITIES	53
Item 4. MINE SAFETY DISCLOSURES	53
Item 5. OTHER INFORMATION	53
Item 6. EXHIBITS	54
SIGNATURES	57

2

PART I. FINANCIAL INFORMATION

Item 1.    UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except share data)

	March 31, 2022		December 31, 2021
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	117	$	452
Trade accounts receivable and other receivables, net	7,136		4,705
Inventory	527		783
Other current assets	320		200
Total current assets	8,100		6,140
PROPERTY AND EQUIPMENT	19,434		19,292
Accumulated depreciation	(4,565)		(4,383)
Property and equipment, net	14,869		14,909
OTHER ASSETS
Investments in unconsolidated entities	3,807		3,805
Intangible assets, net	1,901		1,960
Deferred tax asset	1,341		1,362
Linefill	919		907
Long-term operating lease right-of-use assets, net	387		393
Long-term inventory	374		253
Other long-term assets, net	293		249
Total assets	$	31,991	$	29,978
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES
Trade accounts payable	$	6,871	$	4,811
Short-term debt	900		822
Other current liabilities	801		601
Total current liabilities	8,572		6,234
LONG-TERM LIABILITIES
Senior notes, net	7,931		8,329
Other long-term debt, net	55		69
Long-term operating lease liabilities	331		339
Other long-term liabilities and deferred credits	901		830
Total long-term liabilities	9,218		9,567
COMMITMENTS AND CONTINGENCIES (NOTE 10)
PARTNERS’ CAPITAL
Class A shareholders (194,228,477 and 194,192,777 shares outstanding, respectively)	1,540		1,533
Noncontrolling interests	12,661		12,644
Total partners’ capital	14,201		14,177
Total liabilities and partners’ capital	$	31,991	$	29,978

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

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

	Three Months Ended March 31,
	2022		2021
	(unaudited)
REVENUES
Product sales revenues	$	13,381	$	8,083
Services revenues	313		300
Total revenues	13,694		8,383
COSTS AND EXPENSES
Purchases and related costs	12,785		7,392
Field operating costs	346		219
General and administrative expenses	83		68
Depreciation and amortization	231		178
(Gains)/losses on asset sales and asset impairments, net	(42)		2
Total costs and expenses	13,403		7,859
OPERATING INCOME	291		524
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	97		88
Interest expense (net of capitalized interest of $1 and $5, respectively)	(107)		(107)
Other expense, net	(37)		(60)
INCOME BEFORE TAX	244		445
Current income tax expense	(19)		(1)
Deferred income tax expense	(16)		(52)
NET INCOME	209		392
Net income attributable to noncontrolling interests	(187)		(322)
NET INCOME ATTRIBUTABLE TO PAGP	$	22	$	70
BASIC AND DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING	194		194
BASIC AND DILUTED NET INCOME PER CLASS A SHARE	$	0.11	$	0.36

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

4

PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

 

	Three Months Ended March 31,
	2022		2021
	(unaudited)
Net income	$	209	$	392
Other comprehensive income	74		108
Comprehensive income	283		500
Comprehensive income attributable to noncontrolling interests	(240)		(401)
Comprehensive income attributable to PAGP	$	43	$	99

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

PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

(in millions)

 

	Derivative Instruments		Translation Adjustments		Other		Total
	(unaudited)
Balance at December 31, 2021	$	(208)	$	(642)	$	(3)	$	(853)
Reclassification adjustments	3		—		—		3
Unrealized gain on hedges	32		—		—		32
Currency translation adjustments	—		40		—		40
Other	—		—		(1)		(1)
Total period activity	35		40		(1)		74
Balance at March 31, 2022	$	(173)	$	(602)	$	(4)	$	(779)

	Derivative Instruments		Translation Adjustments		Other		Total
	(unaudited)
Balance at December 31, 2020	$	(258)	$	(657)	$	(3)	$	(918)
Reclassification adjustments	3		—		—		3
Unrealized gain on hedges	68		—		—		68
Currency translation adjustments	—		37		—		37
Total period activity	71		37		—		108
Balance at March 31, 2021	$	(187)	$	(620)	$	(3)	$	(810)

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

5

PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Three Months Ended March 31,
	2022		2021
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	209	$	392
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	231		178
(Gains)/losses on asset sales and asset impairments, net	(42)		2
Deferred income tax expense	16		52
Change in fair value of Preferred Distribution Rate Reset Option (Note 8)	44		67
Equity earnings in unconsolidated entities	(97)		(88)
Distributions on earnings from unconsolidated entities	96		110
Other	4		6
Changes in assets and liabilities, net of acquisitions	(122)		70
Net cash provided by operating activities	339		789
CASH FLOWS FROM INVESTING ACTIVITIES
Investments in unconsolidated entities	(3)		(35)
Additions to property, equipment and other	(101)		(97)
Proceeds from sales of assets	53		21
Cash paid for purchases of linefill	(39)		—
Other investing activities	9		3
Net cash used in investing activities	(81)		(108)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) under PAA commercial paper program (Note 6)	382		(410)
Net repayments under PAA senior secured hedged inventory facility (Note 6)	—		(166)
Repayments of PAA senior notes	(750)		—
Repurchase of common units by a subsidiary (Note 7)	(25)		(3)
Distributions paid to Class A shareholders (Note 7)	(35)		(35)
Distributions paid to noncontrolling interests (Note 7)	(188)		(138)
Other financing activities	20		66
Net cash used in financing activities	(596)		(686)
Effect of translation adjustment	3		—
Net decrease in cash and cash equivalents and restricted cash	(335)		(5)
Cash and cash equivalents and restricted cash, beginning of period	456		63
Cash and cash equivalents and restricted cash, end of period	$	121	$	58
Cash paid for:
Interest, net of amounts capitalized	$	74	$	65
Income taxes, net of amounts refunded	$	23	$	24

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

6

PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(in millions)

	Class A Shareholders		Noncontrolling Interests		Total Partners’ Capital
	(unaudited)
Balance at December 31, 2021	$	1,533	$	12,644	$	14,177
Net income	22		187		209
Distributions (Note 7)	(35)		(200)		(235)
Deferred tax asset	(5)		—		(5)
Other comprehensive income	21		53		74
Repurchase of common units by a subsidiary (Note 7)	—		(25)		(25)
Other	4		2		6
Balance at March 31, 2022	$	1,540	$	12,661	$	14,201

	Class A Shareholders		Noncontrolling Interests		Total Partners’ Capital
	(unaudited)
Balance at December 31, 2020	$	1,464	$	9,726	$	11,190
Net income	70		322		392
Distributions	(35)		(150)		(185)
Deferred tax asset	(7)		—		(7)
Other comprehensive income	29		79		108
Repurchase of common units by a subsidiary (Note 7)	—		(3)		(3)
Contributions from noncontrolling interests	—		1		1
Other	2		1		3
Balance at March 31, 2021	$	1,523	$	9,976	$	11,499

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

7

PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Basis of Consolidation and Presentation

Organization

Plains GP Holdings, L.P. (“PAGP”) is a Delaware limited partnership formed in 2013 that has elected to be taxed as a corporation for United States federal income tax purposes. PAGP does not directly own any operating assets; as of March 31, 2022, its principal sources of cash flow are 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-Q 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 March 31, 2022, 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. AAP is a Delaware limited partnership that, as of March 31, 2022, directly owned a limited partner interest in PAA through its ownership of approximately 241.5 million PAA common units (approximately 31% of PAA’s total outstanding common units and Series A preferred units combined). AAP is the sole member of PAA GP LLC (“PAA GP”), a Delaware limited liability company that directly holds the non-economic general partner interest in PAA.

PAA’s business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals. As one of the largest midstream service providers in North America, PAA owns an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and natural gas liquids (“NGL”) producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. PAA’s assets and the services it provides are primarily focused on and conducted through two operating segments: Crude Oil and NGL. See Note 11 for further discussion of our operating segments.

PAA GP Holdings LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities and is responsible for exercising on our behalf any rights we have as the sole and managing member of GP LLC, including responsibility for conducting the business and managing the operations of AAP and PAA. GP LLC employs our domestic officers and personnel involved in the operation and management of AAP and PAA. PAA’s Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC.

References to the “Plains Entities” include us, our general partner, GP LLC, AAP, PAA GP and PAA and its subsidiaries.

8

PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Definitions

Additional defined terms are used in this Form 10-Q and shall have the meanings indicated below:

AOCI	=	Accumulated other comprehensive income/(loss)
ASC	=	Accounting Standards Codification
ASU	=	Accounting Standards Update
Bcf	=	Billion cubic feet
Btu	=	British thermal unit
CAD	=	Canadian dollar
CODM	=	Chief Operating Decision Maker
EBITDA	=	Earnings before interest, taxes, depreciation and amortization
EPA	=	United States Environmental Protection Agency
FASB	=	Financial Accounting Standards Board
GAAP	=	Generally accepted accounting principles in the United States
ICE	=	Intercontinental Exchange
ISDA	=	International Swaps and Derivatives Association
LIBOR	=	London Interbank Offered Rate
LTIP	=	Long-term incentive plan
Mcf	=	Thousand cubic feet
MMbls	=	Million barrels
NGL	=	Natural gas liquids, including ethane, propane and butane
NYMEX	=	New York Mercantile Exchange
SEC	=	United States Securities and Exchange Commission
TWh	=	Terawatt hour
USD	=	United States dollar
WTI	=	West Texas Intermediate

Basis of Consolidation and Presentation

The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our 2021 Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of PAGP and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. The condensed consolidated balance sheet data as of December 31, 2021 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three months ended March 31, 2022 should not be taken as indicative of results to be expected for the entire year. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. 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, including the reclassifications discussed further below.

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

9

PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Management judgment is required to evaluate whether PAGP controls an entity. Key areas of that evaluation include (i) determining whether an entity is a variable interest entity (“VIE”); (ii) determining whether PAGP is the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that PAGP and its related parties have over those activities through variable interests; and (iii) identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether PAGP is a VIE’s primary beneficiary.

We have determined that our subsidiaries, PAA and AAP, are VIEs and should be consolidated by PAGP because:

•The limited partners of PAA and AAP lack (i) substantive “kick-out rights” (i.e., the right to remove the general partner) based on a simple majority or lower vote and (ii) substantive participation rights and thus lack the ability to block actions of the general partner that most significantly impact the economic performance of PAA and AAP, respectively.

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

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

With the exception of a deferred tax asset of $1.341 billion and $1.362 billion as of March 31, 2022 and December 31, 2021, respectively, substantially all assets and liabilities presented on PAGP’s Condensed Consolidated Balance Sheets are those of PAA. Only the assets of each respective VIE can be used to settle the obligations of that individual VIE, and the creditors of each/either of those VIEs do not have recourse against the general credit of PAGP. PAGP did not provide any financial support to PAA or AAP during the three months ended March 31, 2022 or the year ended December 31, 2021. See Note 17 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K 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 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 11 for further discussion of our operating segments. In connection with this change, we changed the presentation of Revenues on our Condensed 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.”

Note 2—Summary of Significant Accounting Policies

Restricted Cash

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 Condensed Consolidated Balance Sheets that sum to the total of the amounts shown on our Condensed Consolidated Statements of Cash Flows (in millions):

	March 31, 2022		December 31, 2021
Cash and cash equivalents	$	117	$	452
Restricted cash (1)	4		4
Total cash and cash equivalents and restricted cash	$	121	$	456

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1)Included in “Other current assets” on our Condensed Consolidated Balance Sheets.

Recent Accounting Pronouncements

Except as discussed below and in our 2021 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the three months ended March 31, 2022 that are of significance or potential significance to us.

In August 2020, the FASB issued ASU 2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity, by eliminating two of the three models that require separate accounting for embedded conversion features and the settlement assessment that entities are required to perform to determine whether a contract qualifies for equity classification. This guidance is effective for interim and annual periods beginning after December 15, 2021, with early adoption permitted. We adopted this guidance effective January 1, 2022, and our adoption did not have a material impact on our financial position, results of operations or cash flows.

Note 3—Revenues and Accounts Receivable

Revenue Recognition

We disaggregate our revenues by segment and type of activity. These categories depict how the nature, amount, timing and uncertainty of revenues and cash flows are affected by economic factors. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for additional information regarding our types of revenues and policies for revenue recognition.

Revenues from Contracts with Customers. The following tables present our revenues from contracts with customers disaggregated by segment and type of activity (in millions):

	Three Months Ended March 31,
	2022		2021
Crude Oil segment revenues from contracts with customers
Sales	$	12,857	$	7,726
Transportation	155		90
Terminalling, Storage and Other	90		130
Total Crude Oil segment revenues from contracts with customers	$	13,102	$	7,946

	Three Months Ended March 31,
	2022		2021
NGL segment revenues from contracts with customers
Sales	$	845	$	772
Transportation	9		7
Terminalling, Storage and Other	25		22
Total NGL segment revenues from contracts with customers	$	879	$	801

Reconciliation to Total Revenues of Reportable Segments. The following disclosures only include information regarding revenues associated with consolidated entities; 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 to total revenues of reportable segments and total revenues as disclosed in our Condensed Consolidated Statements of Operations (in millions):

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended March 31, 2022	Crude Oil		NGL		Total
Revenues from contracts with customers	$	13,102	$	879	$	13,981
Other items in revenues	(23)		(144)		(167)
Total revenues of reportable segments	$	13,079	$	735	$	13,814
Intersegment revenue elimination					(120)
Total revenues					$	13,694
Three Months Ended March 31, 2021	Crude Oil		NGL		Total
Revenues from contracts with customers	$	7,946	$	801	$	8,747
Other items in revenues	(93)		(162)		(255)
Total revenues of reportable segments	$	7,853	$	639	$	8,492
Intersegment revenue elimination					(109)
Total revenues					$	8,383

Minimum Volume Commitments. We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. 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	March 31, 2022		December 31, 2021
Billed and collected	Liability	$	56	$	63
Unbilled (1)	N/A	16		16
Total		$	72	$	79

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

Contract Balances. Our contract balances consist of amounts received associated with services or sales for which we have not yet completed the related performance obligation. The following table presents the change in the liability balance associated with contracts with customers (in millions):

	Contract Liabilities
Balance at December 31, 2021	$	141
Amounts recognized as revenue	(20)
Additions	16
Balance at March 31, 2022	$	137

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Remaining Performance Obligations. The information below includes the amount of consideration allocated to partially and wholly unsatisfied remaining performance obligations under contracts that exist as of the end of the periods and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These arrangements include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of March 31, 2022 (in millions):

	Remainder of 2022		2023		2024		2025		2026		2027 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	132	$	174	$	158	$	134	$	87	$	379
Terminalling, storage and other agreement revenues	201		223		173		81		61		517
Total	$	333	$	397	$	331	$	215	$	148	$	896

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

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

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

•Acreage dedications;

•Buy/sell arrangements with future committed volumes;

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

•Contracts within the scope of ASC 842, Leases; and

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

Trade Accounts Receivable and Other Receivables, Net

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL. These purchasers include, but are not limited to, refiners, producers, marketing and trading companies and financial institutions. 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.

To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions and perform credit reviews of each customer to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit, credit insurance or parental guarantees. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. For a majority of these net-cash arrangements, we also enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet).

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Accounts receivable from the sale of crude oil are generally settled with counterparties on the industry settlement date, which is typically in the month following the month in which the title transfers. Otherwise, we generally invoice customers within 30 days of when the products or services were provided and generally require payment within 30 days of the invoice date. We review all outstanding accounts receivable balances on a monthly basis and record our receivables net of expected credit losses. We do not write-off accounts receivable balances until we have exhausted substantially all collection efforts. At March 31, 2022 and December 31, 2021, substantially all of our trade accounts receivable were less than 30 days past their invoice date. Our expected credit losses are immaterial. 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.

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 Condensed Consolidated Balance Sheets (in millions):

	March 31, 2022		December 31, 2021
Trade accounts receivable arising from revenues from contracts with customers	$	5,496	$	4,031
Other trade accounts receivables and other receivables (1)	9,620		5,126
Impact due to contractual rights of offset with counterparties	(7,980)		(4,452)
Trade accounts receivable and other receivables, net	$	7,136	$	4,705

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

Note 4—Net Income Per Class A Share

Basic net income per Class A share is determined by dividing net income attributable to PAGP by the weighted average number of Class A shares outstanding during the period. Our Class B and Class C shares do not share in the earnings of the Partnership; accordingly, basic and diluted net income per Class B and Class C share has not been presented.

Diluted net income per Class A share is determined by dividing net income attributable to PAGP by the diluted weighted average number of Class A shares outstanding during the period. For purposes of calculating diluted net income per Class A share, both the net income attributable to PAGP and the diluted weighted average number of Class A shares outstanding consider the impact of possible future exchanges of (i) AAP units and the associated Class B shares into our Class A shares and (ii) Class B units of AAP (referred to herein as “AAP Management Units”) into 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. 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. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for information regarding exchanges of AAP units and AAP Management Units. PAGP LTIP awards that are deemed to be dilutive are reduced by a hypothetical share repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 18 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for information regarding PAGP LTIP awards.

On a weighted-average basis, for the three months ended March 31, 2022 and 2021, the possible exchange of 47 million and 51 million AAP units, respectively, would not have had a dilutive effect on basic net income per Class A share. For each of the three months ended March 31, 2022 and 2021, the possible exchange of less than 1 million AAP Management Units would not have had a dilutive effect on basic net income per Class A share on a weighted-average basis. For the three months ended March 31, 2022 and 2021, our PAGP LTIP awards were dilutive; however, the LTIP awards 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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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	Three Months Ended March 31,
	2022		2021
Basic and Diluted Net Income per Class A Share
Net income attributable to PAGP	$	22	$	70
Basic and diluted weighted average Class A shares outstanding	194		194
Basic and diluted net income per Class A share	$	0.11	$	0.36

Note 5—Inventory, Linefill and Long-term Inventory

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

	March 31, 2022						December 31, 2021
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	4,711	barrels	$	420	$	89.15	8,041	barrels	$	544	$	67.65
NGL	2,329	barrels	102		$	43.80	6,982	barrels	234		$	33.51
Other	N/A		5		N/A		N/A		5		N/A
Inventory subtotal			527						783
Linefill
Crude oil	15,160	barrels	872		$	57.52	15,199	barrels	862		$	56.71
NGL	1,667	barrels	47		$	28.19	1,633	barrels	45		$	27.56
Linefill subtotal			919						907
Long-term inventory
Crude oil	3,289	barrels	325		$	98.81	2,973	barrels	209		$	70.30
NGL	1,071	barrels	49		$	45.75	1,135	barrels	44		$	38.77
Long-term inventory subtotal			374						253
Total			$	1,820					$	1,943

(1)Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 6—Debt

Debt consisted of the following (in millions):

	March 31, 2022		December 31, 2021
SHORT-TERM DEBT
PAA commercial paper notes, bearing a weighted-average interest rate of 0.8% (1)	$	382	$	—
PAA senior notes:
3.65% senior notes due June 2022 (2)	—		750
2.85% senior notes due January 2023	400		—
Other	118		72
Total short-term debt	900		822
LONG-TERM DEBT
PAA senior notes, net of unamortized discounts and debt issuance costs of $52 and $54, respectively	7,931		8,329
Other	55		69
Total long-term debt	7,986		8,398
Total debt (3)	$	8,886	$	9,220

(1)We classified these PAA commercial paper notes as short-term as of March 31, 2022, as these notes were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.

(2)These senior notes were redeemed on March 1, 2022.

(3)PAA’s fixed-rate senior notes had a face value of approximately $8.4 billion and $9.1 billion as of March 31, 2022 and December 31, 2021, respectively. We estimated the aggregate fair value of these notes as of March 31, 2022 and December 31, 2021 to be approximately $8.4 billion and $9.9 billion, respectively. PAA’s fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under PAA’s commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for PAA’s senior notes and commercial paper notes are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

Borrowings and Repayments

Total borrowings under the PAA credit facilities and commercial paper program for the three months ended March 31, 2022 and 2021 were approximately $5.6 billion and $14.2 billion, respectively. Total repayments under the PAA credit facilities and commercial paper program were approximately $5.2 billion and $14.8 billion for the three months ended March 31, 2022 and 2021, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.

During the three months ended March 31, 2022, PAA redeemed its 3.65%, $750 million senior notes due June 2022.

Letters of Credit

In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil and NGL. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At March 31, 2022 and December 31, 2021, we had outstanding letters of credit of $34 million and $98 million, respectively.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 7—Partners’ Capital and Distributions

Shares Outstanding

The following tables present the activity for our Class A shares, Class B shares and Class C shares:

	Class A Shares	Class B Shares	Class C Shares
Outstanding at December 31, 2021	194,192,777	46,645,514	534,596,831
Conversion of AAP Management Units (1)	—	205,024	—
Exchange Right exercises (1)	35,700	(35,700)	—
Redemption Right exercises (1)	—	(11,957)	11,957
Repurchase of common units by a subsidiary under the Common Equity Repurchase Program	—	—	(2,375,299)
Other	—	—	51,937
Outstanding at March 31, 2022	194,228,477	46,802,881	532,285,426

 

	Class A Shares	Class B Shares	Class C Shares
Outstanding at December 31, 2020	194,051,436	50,640,192	547,717,762
Conversion of AAP Management Units (1)	—	414,608	—
Exchange Right exercises (1)	46,879	(46,879)	—
Redemption Right exercises (1)	—	(229,931)	229,931
Repurchase of common units by a subsidiary under the Common Equity Repurchase Program	—	—	(350,000)
Other	—	—	25,431
Outstanding at March 31, 2021	194,098,315	50,777,990	547,623,124

(1)See Note 12 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for information regarding conversions of AAP Management Units, Exchange Rights and Redemption Rights.

Distributions

The following table details distributions to our Class A shareholders paid during or pertaining to the first three months of 2022 (in millions, except per share data):

Distribution Payment Date	Distributions to Class A Shareholders		Distributions per Class A Share
May 13, 2022 (1)	$	42	$	0.2175
February 14, 2022	$	35	$	0.1800

(1)Payable to shareholders of record at the close of business on April 29, 2022 for the period from January 1, 2022 through March 31, 2022.

Consolidated Subsidiaries

Noncontrolling Interests in Subsidiaries

As of March 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 Plains Oryx Permian Basin LLC (the “Permian JV”) and (iv) a 33% interest in Red River Pipeline Company LLC (“Red River LLC”).

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Common Equity Repurchase Program

PAA repurchased 2.4 million and 0.4 million common units under the Common Equity Repurchase Program (the “Program”) through open market purchases that settled during the three months ended March 31, 2022 and 2021, respectively, for a total purchase price of $25 million and $3 million, respectively, including commissions and fees. The repurchased PAA common units were canceled immediately upon acquisition, as were the Class C shares held by PAA associated with the repurchased common units. At March 31, 2022, the remaining available capacity under the Program was $247 million. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for additional information regarding the Program.

Subsidiary Distributions

PAA Series A Preferred Unit Distributions. The following table details distributions to PAA’s Series A preferred unitholders paid during or pertaining to the first three months of 2022 (in millions, except per unit data):

	Series A Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit
May 13, 2022 (1)	$	37	$	0.525
February 14, 2022	$	37	$	0.525

(1)Payable to unitholders of record at the close of business on April 29, 2022 for the period from January 1, 2022 through March 31, 2022. At March 31, 2022, such amount was accrued as distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

PAA Series B Preferred Unit Distributions. Distributions on PAA’s Series B preferred units are payable semi-annually in arrears on the 15th day of May and November. The following table details distributions paid to PAA’s Series B preferred unitholders (in millions, except per unit data):

	Series B Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit
May 16, 2022 (1)	$	24.5	$	30.625

(1)Payable to unitholders of record at the close of business on May 2, 2022 for the period from November 15, 2021 through May 14, 2022.

At March 31, 2022, approximately $18 million of accrued distributions payable to PAA’s Series B preferred unitholders was included in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

PAA Common Unit Distributions. The following table details distributions to PAA’s common unitholders paid during or pertaining to the first three months of 2022 (in millions, except per unit data):

	Distributions						Cash Distribution per Common Unit
	Common Unitholders				Total Cash Distribution
Distribution Payment Date	Public		AAP
May 13, 2022 (1)	$	100	$	53	$	153	$	0.2175
February 14, 2022	$	84	$	43	$	127	$	0.1800

(1)Payable to unitholders of record at the close of business on April 29, 2022 for the period from January 1, 2022 through March 31, 2022.

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AAP Distributions. The following table details the distributions to AAP’s partners paid during or pertaining to the first three months of 2022 from distributions received from PAA (in millions):

	Distributions to AAP’s Partners
Distribution Payment Date	Noncontrolling Interests		PAGP		Total Cash Distribution
May 13, 2022 (1)	$	11	$	42	$	53
February 14, 2022	$	8	$	35	$	43

(1)Payable to unitholders of record at the close of business on April 29, 2022 for the period from January 1, 2022 through March 31, 2022.

Other Distributions. During the three months ended March 31, 2022, we paid distributions of $54 million and $5 million to noncontrolling interests in the Permian JV and Red River LLC, respectively.

Note 8—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. 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. 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. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. At the inception of the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions. Throughout the hedging relationship, retrospective and prospective hedge effectiveness is assessed on a qualitative basis.

We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives designated as cash flow hedges, changes in fair value are deferred in AOCI and recognized in earnings in the periods during which the underlying hedged transactions are recognized in earnings. Derivatives that are not designated in a hedging relationship for accounting purposes are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Condensed Consolidated Statements of Cash Flows.

Our financial derivatives, used for hedging risk, are governed through ISDA master agreements and clearing brokerage agreements. These agreements include stipulations regarding the right of set off in the event that we or our counterparty default on performance obligations. If a default were to occur, both parties have the right to net amounts payable and receivable into a single net settlement between parties.

At March 31, 2022 and December 31, 2021, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our exchange-traded derivatives transacted through a clearing brokerage account, as described below, we do not require our non-cleared derivative counterparties to post collateral with us.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Commodity Price Risk Hedging

Our core business activities involve certain commodity price-related risks that we manage in various ways, including through the use of derivative instruments. 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. We use derivatives to manage the associated risks and to optimize profits. As of March 31, 2022, net derivative positions related to these activities included:

•A net long position of 6.6 million barrels associated with our crude oil purchases, which was unwound ratably during April 2022 to match monthly average pricing.

•A net short time spread position of 5.3 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through May 2023.

•A net crude oil basis spread position of 1.2 million barrels at multiple locations through November 2023. These derivatives allow us to lock in grade and location basis differentials.

•A net short position of 11.0 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. Additionally, we purchase NGL mix for fractionation and sell the resulting individual specification products (including ethane, propane, butane and condensate). In conjunction with these activities, we hedge the price risk associated with the purchase of the natural gas and the subsequent sale of the individual specification products. The following table summarizes our open derivative positions utilized to hedge the price risk associated with anticipated purchases and sales related to our natural gas processing and NGL fractionation activities as of March 31, 2022:

	Notional Volume
	(Short)/Long	Remaining Tenor
Natural gas purchases	82.6 Bcf	December 2024
Propane sales	(15.5) MMbls	December 2024
Butane sales	(3.8) MMbls	December 2024
Condensate sales	(1.5) MMbls	December 2024
Fuel gas requirements (1)	8.8 Bcf	December 2023
Power supply requirements (1)	0.5 TWh	December 2023

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

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

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Our commodity derivatives are not designated in a hedging relationship for accounting purposes; as such, changes in the fair value are reported in earnings. The following table summarizes the impact of our commodity derivatives recognized in earnings (in millions):

	Three Months Ended March 31,
	2022		2021
Product sales revenues	$	(213)	$	(314)
Field operating costs	13		39
Net loss from commodity derivative activity	$	(200)	$	(275)

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through clearing brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. The following table provides the components of our net broker receivable (in millions):

	March 31, 2022		December 31, 2021
Initial margin	$	102	$	133
Variation margin posted	296		173
Letters of credit	(25)		(47)
Net broker receivable	$	373	$	259

The following table reflects the Condensed Consolidated Balance Sheet line items that include the fair values of our commodity derivative assets and liabilities and the effect of the collateral netting. Such amounts are presented on a gross basis, before the effects of counterparty netting. However, we have elected to present our commodity derivative assets and liabilities with the same counterparty on a net basis on our Condensed Consolidated Balance Sheet when the legal right of offset exists. Amounts in the table below are presented in millions.

	March 31, 2022								December 31, 2021
					Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet						Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet
	Commodity Derivatives								Commodity Derivatives
	Assets		Liabilities						Assets		Liabilities
Derivative Assets
Other current assets	$	230	$	(331)	$	373	$	272	$	90	$	(210)	$	259	$	139
Other long-term assets, net	12		—		—		12		3		—		—		3
Derivative Liabilities
Other current liabilities	11		(51)		—		(40)		4		(24)		—		(20)
Other long-term liabilities and deferred credits	8		(28)		—		(20)		3		(9)		—		(6)
Total	$	261	$	(410)	$	373	$	224	$	100	$	(243)	$	259	$	116

Interest Rate Risk Hedging

We use interest rate derivatives to hedge the benchmark interest rate associated with interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist of forward starting interest rate swaps and treasury locks. These derivatives are designated as cash flow hedges. As such, changes in fair value are deferred in AOCI and are reclassified to interest expense as we incur the interest expense associated with the underlying debt.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the terms of our outstanding interest rate derivatives as of March 31, 2022 (notional amounts in millions):

Hedged Transaction	Number and Types of Derivatives Employed	Notional Amount		Expected Termination Date	Average Rate Locked		Accounting Treatment
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	6/15/2023	1.38	%	Cash flow hedge
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	6/14/2024	0.73	%	Cash flow hedge

As of March 31, 2022, there was a net loss of $173 million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with interest expense accruals associated with underlying debt instruments. We estimate that substantially all of the remaining deferred loss will be reclassified to earnings through 2054 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of March 31, 2022; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

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

	Three Months Ended March 31,
	2022		2021
Interest rate derivatives, net	$	32	$	68

At March 31, 2022, the net fair value of our interest rate hedges, which were included in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet, totaled $97 million. 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 Condensed 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 expense, net” in our Condensed Consolidated Statement of Operations. For the three months ended March 31, 2022 and 2021, we recognized losses of $44 million and $67 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 Condensed Consolidated Balance Sheets, totaled $44 million and less than $1 million at March 31, 2022 and December 31, 2021, respectively. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for additional information regarding the PAA Series A preferred units and the Preferred Distribution Rate Reset Option.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Recurring Fair Value Measurements

Derivative Financial Assets and Liabilities

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions):

	Fair Value as of March 31, 2022								Fair Value as of December 31, 2021
Recurring Fair Value Measures (1)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivatives	$	(76)	$	(73)	$	—	$	(149)	$	(17)	$	(124)	$	(2)	$	(143)
Interest rate derivatives	—		97		—		97		—		65		—		65
Preferred Distribution Rate Reset Option and Other	—		—		(44)		(44)		—		—		—		—
Total net derivative asset/(liability)	$	(76)	$	24	$	(44)	$	(96)	$	(17)	$	(59)	$	(2)	$	(78)

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

Level 1

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

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. In addition, it includes certain physical commodity contracts. The fair values of these derivatives are corroborated with market observable inputs.

Level 3

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 PAA’s 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 Condensed Consolidated Statements of Operations as Product sales revenues.

The fair value of the embedded derivative feature contained in PAA’s partnership agreement is based on a valuation model that estimates the fair value of the PAA Series A preferred units with and without the Preferred Distribution Rate Reset Option. This model contains inputs, including PAA’s 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.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Rollforward of Level 3 Net Asset/(Liability)

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

	Three Months Ended March 31,
	2022		2021
Beginning Balance	$	(2)	$	(29)
Net losses for the period included in earnings	(44)		(67)
Settlements	2		4
Ending Balance	$	(44)	$	(92)
Change in unrealized losses included in earnings relating to Level 3 derivatives still held at the end of the period	$	(44)	$	(67)

Note 9—Related Party Transactions

See Note 17 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for a complete discussion of related parties, including the determination of our related parties and nature of involvement with such related parties.

During the three months ended March 31, 2022 and 2021, we recognized sales and transportation revenues, purchased petroleum products and utilized transportation and storage services from our related parties. These transactions were conducted at posted tariff rates or prices that we believe approximate market.

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

	Three Months Ended March 31,
	2022		2021
Revenues from related parties	$	12	$	7
Purchases and related costs from related parties	$	97	$	90

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

	March 31, 2022		December 31, 2021
Trade accounts receivable and other receivables, net from related parties (1)	$	56	$	41
Trade accounts payable to related parties (1) (2)	$	75	$	72

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

(2)We have agreements to store crude oil at facilities and transport crude oil or utilize capacity on pipelines that are owned by equity method investees. 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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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 10—Commitments and Contingencies

Loss Contingencies — General

To the extent we are able to assess the likelihood of a negative outcome for a contingency, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred.

We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss.

Legal Proceedings — General

In the ordinary course of business, we are involved in various legal proceedings, including those arising from regulatory and environmental matters. In connection with determining the probability of loss associated with such legal proceedings and whether any potential losses associated therewith are estimable, we take into account what we believe to be all relevant known facts and circumstances, and what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing agreements, laws and regulations. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully protect us from losses arising from current or future legal proceedings. Accordingly, we can provide no assurance that the outcome of the various legal proceedings that we are currently involved in, or will become involved with in the future, will not, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

Environmental — General

We currently own or lease, and in the past have owned and leased, properties where hazardous liquids, including hydrocarbons, are or have been handled. These properties and the hazardous liquids or associated wastes disposed thereon may be subject to the U.S. federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, and the U.S. federal Resource Conservation and Recovery Act, as amended, as well as state and Canadian federal and provincial laws and regulations. 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.

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. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. We also may discover environmental impacts from past releases that were previously unidentified. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. We record receivables for amounts we believe are recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Environmental expenditures that pertain to current operations or to future revenues are expensed or capitalized consistent with our capitalization policy for property and equipment. Expenditures that result from the remediation of an existing condition caused by past operations and that do not contribute to current or future profitability are expensed.

At March 31, 2022, our estimated undiscounted reserve for environmental liabilities (excluding liabilities related to the Line 901 incident, as discussed further below) totaled $59 million, of which $9 million was classified as short-term and $50 million was classified as long-term. At December 31, 2021, our estimated undiscounted reserve for environmental liabilities (excluding liabilities related to the Line 901 incident) totaled $57 million, of which $11 million was classified as short-term and $46 million was classified as long-term. Such short-term liabilities are reflected in “Other current liabilities” and long-term liabilities are reflected in “Other long-term liabilities and deferred credits” on our Condensed Consolidated Balance Sheets. At both March 31, 2022 and December 31, 2021, we had recorded receivables (excluding receivables related to the Line 901 incident) totaling $11 million, for amounts probable of recovery under insurance and from third parties under indemnification agreements, $1 million of which for each period is reflected in “Other long-term assets, net” and the remainder is reflected in “Trade accounts receivable and other receivables, net” on our Condensed Consolidated Balance Sheets. 

In some cases, the actual cash expenditures associated with these liabilities may not occur for three years or longer. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing or future legal claims giving rise to additional liabilities. Therefore, although we believe that the reserve is adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of the reserve and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

Specific Legal, Environmental or Regulatory Matters

Line 901 Incident. In May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. A portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert. Following the release, we shut down the pipeline and initiated our emergency response plan. A Unified Command, which included the United States Coast Guard, the EPA, the State of California Department of Fish and Wildlife (“CDFW”), the California Office of Spill Prevention and Response and the Santa Barbara Office of Emergency Management, was established for the response effort. Clean-up and remediation operations with respect to impacted shoreline and other areas has been determined by the Unified Command to be complete, and the Unified Command has been dissolved. Our estimate of the amount of oil spilled, based on relevant facts, data and information, and as set forth in the Consent Decree described below, is approximately 2,934 barrels; of this amount, we estimate that 598 barrels reached the Pacific Ocean.

As a result of the Line 901 incident, several governmental agencies and regulators initiated investigations into the Line 901 incident, various claims have been made against us and a number of lawsuits have been filed against us, the majority of which have been resolved. Set forth below is a brief summary of actions and matters that are currently pending or recently resolved:

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As the “responsible party” for the Line 901 incident we are liable for various costs and for certain natural resource damages under the Oil Pollution Act. In this regard, following the Line 901 incident, we entered into a cooperative Natural Resource Damage Assessment (“NRDA”) process with the federal and state agencies designated or authorized by law to act as trustees for the natural resources of the United States and the State of California (collectively, the “Trustees”). Additionally, various government agencies sought to collect civil fines and penalties under applicable state and federal regulations. On March 13, 2020, the United States and the People of the State of California filed a civil complaint against Plains All American Pipeline, L.P. and Plains Pipeline L.P. along with a pre-negotiated settlement agreement in the form of a Consent Decree (the “Consent Decree”) that was signed by the United States Department of Justice, Environmental and Natural Resources Division, the United States Department of Transportation, Pipeline and Hazardous Materials Safety Administration, the EPA, CDFW, the California Department of Parks and Recreation, the California State Lands Commission, the California Department of Forestry and Fire Protection’s Office of the State Fire Marshal, Central Coast Regional Water Quality Control Board, and Regents of the University of California. The Consent Decree was approved and entered by the Federal District Court for the Central District of California on October 14, 2020. Pursuant to the terms of the Consent Decree, Plains paid $24 million in civil penalties and $22.325 million as compensation for injuries to, destruction of, loss of, or loss of use of natural resources resulting from the Line 901 incident. The Consent Decree 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.

Following an investigation and grand jury proceedings, in May of 2016, PAA was charged by a California state grand jury, pursuant to an indictment filed in California Superior Court, Santa Barbara County (the “May 2016 Indictment”), with alleged violations of California law in connection with the Line 901 incident. Fifteen charges from the May 2016 Indictment were the subject of a jury trial in California Superior Court in Santa Barbara County, and the jury returned a verdict on September 7, 2018, pursuant to which we were (i) found guilty on one felony discharge count and eight misdemeanor counts (which included one reporting count, one strict liability discharge count and six strict liability animal takings counts) and (ii) found not guilty on one strict liability animal takings count. The remaining counts were subsequently dismissed by the Court. On April 25, 2019, PAA was sentenced to pay fines and penalties in the aggregate amount of just under $3.35 million for the convictions covered by the September 2018 jury verdict (the “2019 Sentence”). The fines and penalties imposed in connection with the 2019 Sentence have been paid. In September 2021, the Superior Court concluded a series of hearings on the issue of whether there were any “direct victims” of the spill that are entitled to restitution under applicable criminal law. Through a series of final orders issued at the trial court level and without affecting any rights of the claimants under civil law, the Court dismissed the vast majority of the claims and ruled that the claimants were not entitled to restitution under applicable criminal laws. The Court did award an aggregate amount of less than $150,000 to a handful of claimants and we settled with approximately 40 claimants before the hearings for aggregate consideration that is not material. The prosecution and certain separately represented claimants have appealed the Court’s rulings.

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: (i) commercial fishermen who landed fish in certain specified fishing blocks in the waters off the coast of Southern California or persons or businesses who resold commercial seafood caught in those areas; and (ii) owners and lessees of residential beachfront properties, or properties with a private easement to a beach, where plaintiffs claim oil from the spill washed up. In order to fully and finally resolve all claims and litigation for both classes, we have reached an agreement in principle to settle this case in exchange for a payment of $230 million (the “Class Action Settlement”). The Class Action Settlement is subject to negotiation of final documentation and approval of the trial court. 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.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In addition, after various other unitholder derivative lawsuits were either dismissed or consolidated, one proceeding remains pending in Delaware Chancery Court. Generally, the plaintiffs in the remaining derivative lawsuit claim that our 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 court approval, we intend to effect notice to all PAA unitholders by filing a Current Report on Form 8-K with the SEC. The key terms of the Derivative Settlement include a payment of Plaintiff’s attorneys’ fees by our insurers in the amount of approximately $2.0 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.

We 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. The following lawsuits remain: (i) a lawsuit pending in the United States District Court for the Central District of California 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 cost 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.

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 March 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 $725 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 Condensed Consolidated Statements of Operations. This estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the resolution of certain third party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and excluding future claims and lawsuits and (ii) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. Our estimate does not include any lost revenue associated with the shutdown of Line 901 or 903 and does not include any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, with respect to potential losses that we regard as only reasonably possible or remote, we have made assumptions regarding the strength of our legal position based on our assessment of the relevant facts and applicable law and precedent; if our assumptions regarding such matters turn out to be inaccurate (i.e., we are found to be liable under circumstances where we regard the likelihood of loss as being only reasonably possible or remote), we could be responsible for significant costs and expenses that are not currently included in our estimates and accruals. In addition, for any potential losses that we regard as probable and for which we have accrued an estimate of the potential losses, our estimates regarding damages, legal fees, court costs and interest could turn out to be inaccurate and the actual losses we incur could be significantly higher than the amounts included in our estimates and accruals. Also, the amount of time it takes for us to resolve all of the current and future lawsuits and claims that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated. Accordingly, our assumptions and estimates may turn out to be inaccurate and our total costs could turn out to be materially higher; therefore, we can provide no assurance that we will not have to accrue significant additional costs in the future with respect to the Line 901 incident.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As of March 31, 2022, we had a remaining undiscounted gross liability of $335 million related to this event, which aggregate amount is reflected in “Trade accounts payable” and “Other current liabilities” on our Condensed Consolidated Balance Sheet. We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such environmental liabilities; however, after giving effect to the settlements described above and assuming full collection of costs that we believe are probable of recovery from insurance providers, net of deductibles, we will reach the limit of our $500 million 2015 insurance program applicable to the Line 901 incident. Through March 31, 2022, we had collected, subject to customary reservations, approximately $260 million out of the $500 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of March 31, 2022, we have recognized a receivable of approximately $240 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 Condensed 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. 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.

Insurance

Pipelines, terminals, trucks or other facilities or equipment may experience damage as a result of an accident, natural disaster, terrorist attack, cyber event or other event. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. Consistent with insurance coverage generally available in the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences. We maintain various types and varying levels of insurance coverage to cover our operations and properties, and we self-insure certain risks, including gradual pollution, cybersecurity and named windstorms. 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. While we strive to maintain adequate insurance coverage, our actual costs may exceed our coverage levels and insurance will not cover many types of interruptions that might occur, will not cover amounts up to applicable deductibles and will not cover all risks associated with certain of our assets and operations. With respect to our insurance coverage, our policies are subject to deductibles and retention levels that we consider reasonable and not excessive. Additionally, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable. As a result, we may elect to self-insure or utilize higher deductibles in certain other insurance programs. In addition, although we believe that we have established adequate reserves and liquidity to the extent such risks are not insured, costs incurred in excess of these reserves may be higher or we may not receive insurance proceeds in a timely manner, which may potentially have a material adverse effect on our financial conditions, results of operations or cash flows.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 11—Segment Information

During the fourth quarter of 2021, we effected changes in the primary financial information provided to our CODM 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. All segment data and related disclosures for earlier periods presented herein have been recast to reflect the new segment reporting structure. Our CODM evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below) and maintenance capital. During the fourth quarter of 2021, we modified our definition of Segment Adjusted EBITDA to exclude amounts attributable to noncontrolling interests in consolidated joint venture entities. 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 venture entities for earlier periods presented herein have been recast to reflect this modification. See Note 20 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for additional information regarding the modifications to our segment reporting and for a full discussion of our basis for segmentation and performance measures.

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 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”).

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	Crude Oil		NGL		Intersegment Revenues Elimination		Total
Three Months Ended March 31, 2022
Revenues (1):
Product sales	$	12,811	$	682	$	(112)	$	13,381
Services	268		53		(8)		313
Total revenues	$	13,079	$	735	$	(120)	$	13,694
Equity earnings in unconsolidated entities	$	97	$	—			$	97
Segment Adjusted EBITDA	$	453	$	161			$	614
Maintenance capital expenditures	$	19	$	8			$	27
Three Months Ended March 31, 2021
Revenues (1):
Product sales	$	7,586	$	600	$	(103)	$	8,083
Services	267		39		(6)		300
Total revenues	$	7,853	$	639	$	(109)	$	8,383
Equity earnings in unconsolidated entities	$	88	$	—			$	88
Segment Adjusted EBITDA	$	474	$	69			$	543
Maintenance capital expenditures	$	28	$	7			$	35

(1)Segment revenues include intersegment amounts that are eliminated in Purchases and related costs. Intersegment activities are conducted at posted tariff rates where applicable, or otherwise at rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Segment Adjusted EBITDA Reconciliation

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

 

	Three Months Ended March 31,
	2022		2021
Segment Adjusted EBITDA	$	614	$	543
Adjustments: (1)
Depreciation and amortization of unconsolidated entities (2)	(20)		(20)
Gains/(losses) from derivative activities and inventory valuation adjustments (3)	(88)		198
Long-term inventory costing adjustments (4)	92		41
Deficiencies under minimum volume commitments, net (5)	(6)		32
Equity-indexed compensation expense (6)	(7)		(5)
Net gain on foreign currency revaluation (7)	2		1
Line 901 incident (8)	(85)		—
Adjusted EBITDA attributable to noncontrolling interests in consolidated joint ventures (9)	76		3
Unallocated general and administrative expenses (10)	(1)		(1)
Depreciation and amortization	(231)		(178)
Gains/(losses) on asset sales and asset impairments, net	42		(2)
Interest expense, net	(107)		(107)
Other expense, net	(37)		(60)
Income before tax	244		445
Income tax expense	(35)		(53)
Net income	209		392
Net income attributable to noncontrolling interests	(187)		(322)
Net income attributable to PAGP	$	22	$	70

(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.

(3)We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify differences in the timing of earnings from the derivative instruments and the underlying transactions and exclude the related gains and losses in determining Segment Adjusted EBITDA such that the earnings from the derivative instruments and the underlying transactions impact Segment Adjusted EBITDA in the same period. In addition, we exclude gains and losses on derivatives that are related to (i) investing activities, such as the purchase of linefill, and (ii) purchases of long-term inventory. We also exclude the impact of corresponding inventory valuation adjustments, as applicable.

(4)We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). 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.

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(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. 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. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to Segment Adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.

(6)Our total equity-indexed compensation expense includes expense associated with awards that will be settled in PAA common units and awards that will be settled in cash. The awards that will be settled in PAA common units are included in PAA’s diluted net income per unit calculation when the applicable performance criteria have been met. We exclude compensation expense associated with these awards in determining Segment Adjusted EBITDA as the dilutive impact of the outstanding awards is included in PAA’s diluted net income per unit calculation, as applicable. The portion of compensation expense associated with awards that will settle in cash is not excluded in determining Segment Adjusted EBITDA. See Note 18 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for a discussion regarding our equity-indexed compensation plans.

(7)During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. These gains and losses are not integral to our core operating performance and were therefore excluded in determining Segment Adjusted EBITDA.

(8)Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. See Note 10 for additional information regarding the Line 901 incident.

(9)Reflects amounts attributable to noncontrolling interests in the Permian JV and Red River LLC.

(10)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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Item 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical Consolidated Financial Statements and accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations as presented in our 2021 Annual Report on Form 10-K. For more detailed information regarding the basis of presentation for the following financial information, see the Condensed Consolidated Financial Statements and related notes that are contained in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Our discussion and analysis includes the following:

•Executive Summary

•Results of Operations

•Liquidity and Capital Resources 

•Recent Accounting Pronouncements

•Forward-Looking Statements

Executive Summary

Company Overview

We are a Delaware limited partnership that has elected to be taxed as a corporation for United States federal income tax purposes. As of March 31, 2022, our sole cash-generating assets consisted of (i) a 100% managing member interest in GP LLC and (ii) an approximate 81% limited partner interest in AAP through our direct ownership of AAP units and indirect ownership of AAP units through GP LLC, which also holds the non-economic general partner interest in AAP. As of March 31, 2022, AAP directly owned a limited partner interest in PAA through its ownership of approximately 241.5 million PAA common units (approximately 31% of PAA’s total outstanding common units and Series A preferred units combined). AAP is the sole member of PAA GP, which holds the non-economic general partner interest in PAA.

PAA’s business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals. As one of the largest midstream service providers in North America, we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. PAA’s assets and the services it provides are primarily focused on crude oil and NGL.

Segment Changes

During the fourth quarter of 2021, we reorganized our historical operating segments into two operating segments: Crude Oil and NGL. Additionally, during the fourth quarter of 2021, we modified our definition of Segment Adjusted EBITDA to exclude amounts attributable to noncontrolling interests in consolidated joint venture entities. See Note 20 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for additional information. All segment data and related disclosures for earlier periods presented herein have been recast to reflect the new segment reporting structure and the modification to our definition of Segment Adjusted EBITDA.

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Overview of Operating Results

During the first three months of 2022, we recognized net income of $209 million compared to net income of $392 million recognized during the first three months of 2021. Results for the first three months of 2022 decreased from the comparable 2021 period driven primarily by the impact of the mark-to-market of certain derivative instruments, and, to a lesser extent, the sale of our natural gas storage facilities and higher field operating costs primarily from (i) an increase in estimated costs associated with the Line 901 incident and (ii) gains related to hedged power costs resulting from the extreme winter weather event that occurred in February 2021 (“Winter Storm Uri”) recognized in the first quarter of 2021. These items were partially offset by more favorable margins in our NGL segment and increased earnings from higher tariff volumes on our pipelines.

See the “Results of Operations” section below for further discussion.

Results of Operations

Consolidated Results

The following table sets forth an overview of our consolidated financial results calculated in accordance with GAAP (in millions, except per share data): 

	Three Months Ended March 31,				Variance
	2022		2021		$		%
Product sales revenues	$	13,381	$	8,083	$	5,298	66	%
Services revenues	313		300		13		4	%
Purchases and related costs	(12,785)		(7,392)		(5,393)		(73)	%
Field operating costs	(346)		(219)		(127)		(58)	%
General and administrative expenses	(83)		(68)		(15)		(22)	%
Depreciation and amortization	(231)		(178)		(53)		(30)	%
Gains/(losses) on asset sales and asset impairments, net	42		(2)		44		**
Equity earnings in unconsolidated entities	97		88		9		10	%
Interest expense, net	(107)		(107)		—		—	%
Other expense, net	(37)		(60)		23		38	%
Income tax expense	(35)		(53)		18		34	%
Net income	209		392		(183)		(47)	%
Net income attributable to noncontrolling interests	(187)		(322)		135		42	%
Net income attributable to PAGP	$	22	$	70	$	(48)	(69)	%
Basic and diluted net income per Class A share	$	0.11	$	0.36	$	(0.25)	(69)	%
Basic and diluted weighted average Class A shares outstanding	194		194		—		—	%

**    Indicates that variance as a percentage is not meaningful.

Revenues and Purchases

Fluctuations in our consolidated revenues and purchases and related costs are primarily associated with our merchant activities and generally explained in large part by changes in commodity prices. Our crude oil and NGL merchant activities are not directly affected by the absolute level of prices because the commodities that we buy and sell are generally indexed to the same pricing indices. Both product sales revenues and purchases and related costs will fluctuate with market prices; however, the absolute margins related to those sales and purchases will not necessarily have a corresponding increase or decrease.

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Additionally, product sales revenues include the impact of gains and losses related to derivative instruments used to manage our exposure to commodity price risk associated with such sales and purchases.

The following table presents the range of the NYMEX WTI benchmark price of crude oil (in dollars per barrel):    

	NYMEX WTI Crude Oil Price
	Low		High		Average
Three Months Ended March 31, 2022	$	76	$	124	$	95
Three Months Ended March 31, 2021	$	48	$	66	$	58

Product sales revenues and purchases increased for the three months ended March 31, 2022, compared to the same period in 2021 primarily due to higher prices and volumes in the 2022 period.

Revenues from services increased for the three months ended March 31, 2022, compared to the same period in 2021 primarily due to higher prices and volumes in the 2022 period, partially offset by the impact of the sale of our natural gas storage facilities in the third quarter of 2021.

See further discussion of our net revenues in the “—Analysis of Operating Segments” section below.

Field Operating Costs

See discussion of field operating costs in the “—Analysis of Operating Segments” section below.

General and Administrative Expenses

The increase in general and administrative expenses for the three months ended March 31, 2022 compared to the same period in 2021 was primarily due to (i) costs associated with the formation of the Permian JV, a portion of which are transition related, (ii) employee related costs, including an increase in equity-indexed compensation expense on equity-classified awards (which is excluded in the calculation of Adjusted EBITDA and Segment Adjusted EBITDA) due to changes in plan assumptions, and (iii) higher office rent due to a cost abatement in the prior year.

Gains/(Losses) on Asset Sales and Asset Impairments, Net

During the first quarter of 2022, we recognized a gain of $40 million related to the sale of land and buildings in California.

Depreciation and Amortization

The increase in depreciation and amortization expense for the three months ended March 31, 2022 compared to the same period in 2021 was driven by depreciation expense on the assets contributed by Oryx Midstream Holdings LLC (“Oryx Midstream”) upon formation of the Permian JV.

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Other Expense, Net

The following table summarizes the components impacting Other expense, net (in millions):

	Three Months Ended March 31,
	2022		2021
Loss related to mark-to-market adjustment of Preferred Distribution Rate Reset Option (1)	$	(44)	$	(67)
Net gain on foreign currency revaluation (2)	7		7
	$	(37)	$	(60)

(1)See Note 8 to our Condensed Consolidated Financial Statements for additional information.

(2)The activity during the periods presented was primarily related to the impact from the change in the United States dollar to Canadian dollar exchange rate on the portion of our intercompany net investment that is not long-term in nature.

Income Tax Expense

The net favorable income tax variance for the three months ended March 31, 2022 compared to the same period in 2021 was primarily due to the impact of lower earnings at PAA on income attributable to PAGP, partially offset by the impact of a change in our effective tax rate.

Non-GAAP Financial Measures

To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future. The primary additional measures used by management are Adjusted EBITDA and Adjusted EBITDA attributable to PAA.

Adjusted EBITDA is defined as earnings before interest, taxes, depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects, of unconsolidated entities), gains and losses on asset sales and asset impairments, goodwill impairment losses and gains on and impairments of investments in unconsolidated entities, adjusted for certain selected items impacting comparability. Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted EBITDA and Adjusted EBITDA attributable to PAA are reconciled to Net Income, the most directly comparable measure as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our Condensed Consolidated Financial Statements and accompanying notes.

Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance and results of operations because these measures, when used to supplement related GAAP financial measures, (i) provides additional information about our core operating performance, (ii) provides investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions and (iii) presents measures that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These non-GAAP measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) 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, (iii) long-term inventory costing adjustments, (iv) items that are not indicative of our core operating results and/or (v) other items that we believe should be excluded in understanding our core operating performance. These measures may further be adjusted to include amounts related to deficiencies associated with minimum volume commitments whereby we have billed the counterparties for their deficiency obligation and such amounts are recognized as deferred revenue in “Other current liabilities” in our Condensed Consolidated Financial Statements. We also adjust for amounts billed by our equity method investees related to deficiencies under minimum volume commitments. Such amounts are presented net of applicable amounts subsequently recognized into revenue. We have defined all such items as “selected items impacting comparability.” We do not necessarily consider all of our selected items impacting comparability to be non-recurring, infrequent or unusual, but we believe that an understanding of these selected items impacting comparability is material to the evaluation of our operating results and prospects.

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Although we present selected items impacting comparability that management considers in evaluating our performance, you should also be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions, divestitures, investment capital projects and numerous other factors as discussed, as applicable, in “—Analysis of Operating Segments.”

The following table sets forth the reconciliation of the non-GAAP financial performance measures Adjusted EBITDA and Adjusted EBITDA attributable to PAA from Net Income (in millions):

	Three Months Ended March 31,				Variance
	2022		2021		$		%
Net income	$	209	$	392	$	(183)	(47)	%
Interest expense, net	107		107		—		—	%
Income tax expense	35		53		(18)		(34)	%
Depreciation and amortization	231		178		53		30	%
(Gains)/losses on asset sales and asset impairments, net	(42)		2		(44)		**
Depreciation and amortization of unconsolidated entities (1)	20		20		—		—	%
Unallocated general and administrative expenses (2)	1		1		—		—	%
Selected Items Impacting Comparability:
(Gains)/losses from derivative activities and inventory valuation adjustments	88		(198)		286		**
Long-term inventory costing adjustments	(92)		(41)		(51)		**
Deficiencies under minimum volume commitments, net	6		(32)		38		**
Equity-indexed compensation expense	7		5		2		**
Net gain on foreign currency revaluation	(2)		(1)		(1)		**
Line 901 incident	85		—		85		**
Selected Items Impacting Comparability - Segment Adjusted EBITDA (3)	92		(267)		359		**
Losses from derivative activities (4)	44		67		(23)		**
Net gain on foreign currency revaluation (5)	(7)		(7)		—		**
Selected Items Impacting Comparability - Adjusted EBITDA (6)	129		(207)		336		**
Adjusted EBITDA (6)	$	690	$	546	$	144	26	%
Adjusted EBITDA attributable to noncontrolling interests in consolidated joint ventures (7)	(76)		(3)		(73)		**
Adjusted EBITDA attributable to PAA	$	614	$	543	$	71	13	%

**    Indicates that variance as a percentage is not meaningful.

(1)We exclude our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects) of such unconsolidated entities when reviewing Adjusted EBITDA, similar to our consolidated assets.

(2)Represents general and administrative expenses incremental to those of PAA, which are not allocated to our reporting segments in determining Segment Adjusted EBITDA and are excluded in the non-GAAP financial performance measures utilized by management.

(3)For a more detailed discussion of these selected items impacting comparability, see the footnotes to the Segment Adjusted EBITDA Reconciliation table in Note 11 to our Condensed Consolidated Financial Statements.

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(4)The Preferred Distribution Rate Reset Option of PAA’s Series A preferred units is accounted for as an embedded derivative and recorded at fair value in our Condensed Consolidated Financial Statements. The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability. See Note 8 to our Condensed Consolidated Financial Statements for additional information regarding the Preferred Distribution Rate Reset Option.

(5)During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability.

(6)Other expense, net per our Condensed Consolidated Statements of Operations, adjusted for selected items impacting comparability (“Adjusted Other income/(expense), net”) is included in Adjusted EBITDA and excluded from Segment Adjusted EBITDA.

(7)Reflects amounts attributable to noncontrolling interests in the Permian JV and Red River LLC.

Analysis of Operating Segments

We manage our operations through two operating segments: Crude Oil and NGL. Our CODM (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Adjusted EBITDA, segment volumes and maintenance capital investment. See Note 11 to our Condensed Consolidated Financial Statements for our definition of Segment Adjusted EBITDA and a reconciliation of Segment Adjusted EBITDA to Net income attributable to PAGP. See Note 20 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for our definition of maintenance capital.

Crude Oil Segment

Our Crude Oil segment operations generally consist of gathering and transporting crude oil using pipelines, gathering systems, trucks and at times on barges or railcars, in addition to providing terminalling, storage and other facilities-related services utilizing our integrated assets across the United States and Canada. Our assets serve third parties and are also supported by our merchant activities. Our merchant activities include the purchase of crude oil supply and the movement of this supply on primarily our assets to sales locations, including our terminals, third-party connecting carriers, regional hubs or to refineries. Our merchant activities are subject to our risk management policies and may include the use of derivative instruments to hedge our exposure.

Our Crude Oil segment generates revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees, month-to-month and multi-year storage and terminalling agreements and the sale of gathered and bulk-purchased crude oil. Tariffs and other fees on our pipeline systems are typically based on volumes transported and vary by receipt point and delivery point. Fees for our terminalling and storage services are based on capacity leases and throughput volumes. Generally, results from our merchant activities are impacted by (i) increases or decreases in our lease gathering crude oil purchases volumes and (ii) the overall strength, weakness and volatility of market conditions, including regional differentials and time spreads. In addition, the execution of our risk management strategies in conjunction with our assets can provide upside in certain markets. The segment results also include the direct fixed and variable field costs of operating the crude oil assets, as well as an allocation of indirect operating costs.

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

Operating Results (1)	Three Months Ended March 31,				Variance
(in millions)	2022		2021		$		%
Revenues	$	13,079	$	7,853	$	5,226	67	%
Purchases and related costs	(12,393)		(7,047)		(5,346)		(76)	%
Field operating costs	(282)		(165)		(117)		(71)	%
Segment general and administrative expenses (2)	(63)		(50)		(13)		(26)	%
Equity earnings in unconsolidated entities	97		88		9		10	%
Adjustments (3):
Depreciation and amortization of unconsolidated entities	20		20		—		—	%
(Gains)/losses from derivative activities and inventory valuation adjustments	59		(159)		218		137	%
Long-term inventory costing adjustments	(85)		(35)		(50)		(143)	%
Deficiencies under minimum volume commitments, net	6		(32)		38		119	%
Equity-indexed compensation expense	7		5		2		40	%
Net gain on foreign currency revaluation	(1)		(1)		—		—	%
Line 901 incident	85		—		85		N/A
Adjusted EBITDA attributable to noncontrolling interests in consolidated joint ventures	(76)		(3)		(73)		**
Segment Adjusted EBITDA	$	453	$	474	$	(21)	(4)	%
Maintenance capital	$	19	$	28	$	(9)	(32)	%

	Three Months Ended March 31,		Variance
Average Volumes	2022	2021	Volumes	%
Tariff activities volumes (4)
Crude oil pipelines tariff volumes (by region):
Permian Basin (5)	5,214	3,753	1,461	39	%
South Texas / Eagle Ford (5)	365	320	45	14	%
Mid-Continent (5)	472	373	99	27	%
Gulf Coast	196	145	51	35	%
Rocky Mountain (5)	346	287	59	21	%
Western	235	237	(2)	(1)	%
Canada	331	315	16	5	%
Crude oil pipelines tariff activities total volumes	7,159	5,430	1,729	32	%
Commercial crude oil storage capacity (5) (6)	72	73	(1)	(1)	%
Crude oil lease gathering purchases (4)	1,361	1,174	187	16	%

**    Indicates that variance as a percentage is not meaningful.

(1)Revenues and costs and expenses include intersegment amounts. 

(2)Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.

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(3)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 11 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.

(4)Average daily volumes in thousands of barrels per day calculated as the total volumes (attributable to our interest for pipelines owned by unconsolidated entities or undivided joint interests) for the year divided by the number of days in the year. Volumes associated with acquisitions represent total volumes for the number of days we actually owned the assets divided by the number of days in the period.  

(5)Includes volumes (attributable to our interest) from assets owned by unconsolidated entities.

(6)Average monthly capacity in millions of barrels per day calculated as total volumes for the period divided by the number of months in the period.

Segment Adjusted EBITDA

Crude Oil Segment Adjusted EBITDA decreased for the three months ended March 31, 2022 compared to the same period in 2021 primarily due to (i) the sale of our natural gas storage facilities in August of 2021 and (ii) gains related to hedged power costs resulting from Winter Storm Uri recognized in the first quarter of 2021. These items were partially offset by increased earnings in the first quarter of 2022 from higher tariff volumes on our pipelines.

Variances in the components impacting Segment Adjusted EBITDA are discussed in more detail below.

Revenues, Net of Purchases and Related Costs (“net revenues”) and Equity Earnings in Unconsolidated Entities. The following is a discussion of the significant factors impacting net revenues and equity earnings in unconsolidated entities that contributed to the variance in Segment Adjusted EBITDA for the first quarter of 2022 compared to the first quarter of 2021.

•Production and Market Impacts. Since the trough in demand for crude oil in 2020 related to the COVID-19 pandemic, we have seen steady growth in our volumes, commensurate with the growth in total U.S. crude oil production, resulting in a favorable impact on our earnings in the first quarter of 2022 compared to the first quarter of 2021. This was partially offset by the impact of less favorable crude oil differentials, including contango profits that benefited the 2021 period.

•Joint Venture Formation and Divestiture Transactions. In October of 2021, we closed on the transaction with Oryx Midstream to merge our respective Permian Basin assets, with the exception of our long-haul pipeline systems and certain of our intra-basin assets into the Permian JV. The pipelines contributed by Oryx Midstream upon formation of the Permian JV resulted in approximately 640 thousand barrels per day of additional tariff volumes in the Permian Basin in the first quarter of 2022. We deduct the portion of the financial results attributable to Oryx Midstream’s 35% interest in the Permian JV in determining Segment Adjusted EBITDA, which offset the favorable impact of the additional volumes for the first quarter of 2022.

We sold our natural gas storage facilities in August 2021, which was a significant driver of the decrease in our results for the first quarter of 2022 compared to the first quarter of 2021 as net revenues from our natural gas storage facilities in the first quarter of 2021 were approximately $42 million, which included the benefit of favorable margins from hub activities related to Winter Storm Uri, as mentioned below.

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•Winter Storm Uri. During the first quarter of 2021, Winter Storm Uri had a negative impact on our volumes; however, this impact was more than offset during the 2021 period by gains related to hedged power costs, which are reflected in equity earnings and field operating costs, and favorable margins from hub activities at our natural gas storage facilities resulting from Winter Storm Uri.

•Pipeline Loss Allowance Revenue. Pipeline loss allowance revenues increased for the three months ended March 31, 2022 compared to the three months ended March 31, 2021 primarily due to higher prices and volumes during the 2022 period.

•Minimum Volume Commitments. For the three months ended March 31, 2022 and 2021, Segment Adjusted EBITDA includes approximately $43 million and $26 million, respectively, associated with deficiencies under minimum volume commitments under contracts that have make-up rights. Although the payments have been received associated with the volume deficiencies, the revenues are not recognized until future periods when either the shortfall is made up or when the shipper’s make-up rights expire or it is determined that their ability to utilize the make-up right is remote. During the three months ended March 31, 2022 and 2021, we recognized approximately $37 million and $58 million, respectively, associated with deficiencies under minimum volume commitments that were previously deferred. The amount presented as an “Adjustment” in the table above reflects the net adjustment for revenues deferred during the period and the reversal of previously deferred revenues that were recognized during the period.

•Project Completions. The Capline pipeline reversal project and phase two of the Wink to Webster pipeline project have been completed and were placed in service in the first quarter of 2022, which favorably impacted equity earnings in unconsolidated entities and our tariff volumes for the 2022 period.

Field Operating Costs. The increase in field operating costs for the three months ended March 31, 2022 compared to the same period in 2021 was primarily due to (i) the impact of gains related to hedged power costs resulting from Winter Storm Uri recognized in the first quarter of 2021, (ii) additional estimated costs associated with the Line 901 incident (which impact field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above), and (iii) incremental operating costs from the Permian JV.

Segment General and Administrative Expenses. See the “—Consolidated Results” section above for a discussion of general and administrative expenses.

Maintenance Capital. The decrease in maintenance capital spending for the three months ended March 31, 2022 compared to the same period in 2021 was primarily due to timing.

NGL Segment

Our NGL segment operations involve natural gas processing and NGL fractionation, storage, transportation and terminalling. Our NGL revenues are primarily derived from a combination of (i) providing gathering, fractionation, storage, and/or terminalling services to third-party customers for a fee, and (ii) extracting NGL mix supply from the gas stream processed at our Empress straddle plant facility as well as acquiring NGL mix supply, which mix supply is then transported, stored and fractionated into finished products and sold to customers.

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The following tables set forth our operating results from our NGL segment:

Operating Results (1)	Three Months Ended March 31,				Variance
(in millions, except per barrel data)	2022		2021		$		%
Revenues	$	735	$	639	$	96	15	%
Purchases and related costs	(512)		(454)		(58)		(13)	%
Field operating costs	(64)		(54)		(10)		(19)	%
Segment general and administrative expenses (2)	(19)		(17)		(2)		(12)	%
Adjustments (3):
(Gains)/losses from derivative activities and inventory valuation adjustments	29		(39)		68		174	%
Long-term inventory costing adjustments	(7)		(6)		(1)		(17)	%
Net gain on foreign currency revaluation	(1)		—		(1)		N/A
Segment Adjusted EBITDA	$	161	$	69	$	92	133	%
Maintenance capital	$	8	$	7	$	1	14	%

	Three Months Ended March 31,		Variance
Average Volumes (in thousands of barrels per day) (4)	2022	2021	Volumes	%
NGL fractionation	134	144	(10)	(7)	%
NGL pipeline tariff	176	183	(7)	(4)	%
NGL sales	168	220	(52)	(24)	%

**    Indicates that variance as a percentage is not meaningful.

(1)Revenues and costs and expenses include intersegment amounts. 

(2)Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period. 

(3)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 11 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.

(4)Average daily volumes are calculated as total volumes (attributable to our interest for pipelines and facilities in which we have undivided joint interests) for the period divided by the number of days in the period. 

Segment Adjusted EBITDA

NGL Segment Adjusted EBITDA increased for the three months ended March 31, 2022 compared to the same period in 2021 primarily due to the favorable impact of higher realized fractionation spreads between the price of natural gas and the extracted NGL (“frac spreads”) and higher NGL sales prices, partially offset by lower NGL sales volumes.

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Significant variances in the components of Segment Adjusted EBITDA are discussed in more detail below.

Net Revenues. Net revenues from our NGL activities increased for the three months ended March 31, 2022 compared to the same period in 2021 due to higher realized frac spreads and higher NGL sales prices, partially offset by lower NGL sales volumes. Additionally, net revenues for the 2022 period compared to 2021 include the benefit of our increased ownership in the Empress straddle plants effective June 2021.

Field Operating Costs. The increase in field operating costs for the three months ended March 31, 2022 compared to the same period in 2021 was primarily due to (i) increased power costs related to our increased ownership in the Empress straddle plants and (ii) higher compensation costs including lower wage subsidies received by our Canadian subsidiary.

Liquidity and Capital Resources

General

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

As of March 31, 2022, although we had a working capital deficit of $472 million, we had approximately $2.4 billion of liquidity available to meet our ongoing operating, investing and financing needs, subject to continued covenant compliance, as noted below (in millions):

	As of March 31, 2022
Availability under PAA senior unsecured revolving credit facility (1) (2)	$	1,321
Availability under PAA senior secured hedged inventory facility (1) (2)	1,345
Amounts outstanding under PAA commercial paper program	(382)
Subtotal	2,284
Cash and cash equivalents	117
Total	$	2,401

(1)Represents availability prior to giving effect to borrowings outstanding under the PAA commercial paper program, which reduce available capacity under the facilities.

(2)Available capacity under the PAA senior unsecured revolving credit facility and the PAA senior secured hedged inventory facility was reduced by outstanding letters of credit of $29 million and $5 million, respectively.

Usage of PAA’s credit facilities, and, in turn, its commercial paper program, is subject to ongoing compliance with covenants. The credit agreements for PAA’s revolving credit facilities (which impact PAA’s ability to access its commercial paper program because they provide the financial backstop that supports its short-term credit ratings) and the indentures governing its senior notes contain cross-default provisions. A default under PAA’s credit agreements or indentures would permit the lenders to accelerate the maturity of the outstanding debt. Additionally, lack of compliance with the provisions in PAA’s credit agreements may restrict its ability to make distributions of available cash. PAA was in compliance with the covenants contained in its credit agreements and indentures as of March 31, 2022.

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We believe that we have, and will continue to have, the ability to access the PAA commercial paper program and credit facilities, which we use to meet our short-term cash needs. We believe that our financial position remains strong and we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under the credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow, including extended disruptions in the financial markets and/or energy price volatility resulting from current macroeconomic and geopolitical conditions associated with the COVID-19 pandemic and/or actions by Organization of Petroleum Exporting Countries (“OPEC”). A prolonged material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity and cost of borrowing. Our borrowing capacity and borrowing costs are also impacted by PAA’s credit rating. See Item 1A. “Risk Factors” included in our 2021 Annual Report on Form 10-K for further discussion regarding risks that may impact our liquidity and capital resources.

Cash Flow from Operating Activities

For a comprehensive discussion of the primary drivers of cash flow from operating activities, including the impact of varying market conditions and the timing of settlement of our derivatives, see Item 7. “Liquidity and Capital Resources—Cash Flow from Operating Activities” included in our 2021 Annual Report on Form 10-K.

Net cash provided by operating activities for the first three months of 2022 and 2021 was $339 million and $789 million, respectively, and primarily resulted from earnings from our operations. During the three months ended March 31, 2022, our cash provided by operating activities was negatively impacted by working capital changes. During the three months ended March 31, 2021, our cash provided by operating activities was positively impacted by working capital changes, including decreases in the volume of inventory that we held, primarily due to the sale of crude oil inventory that had been stored during the contango market and the sale of NGL inventory related to demand for heating during the winter season. The net proceeds from the liquidation of such inventory were used to repay borrowings under PAA’s commercial paper program and credit facilities.

Investing Activities

Capital Expenditures

In addition to our operating needs, we also use cash for our investment capital projects, maintenance capital activities and acquisition activities. We fund these expenditures with cash generated by operating activities, financing activities and/or proceeds from asset sales. In the near term, we do not plan to issue common equity to fund such expenditures. The following table summarizes our investment, maintenance and acquisition capital expenditures (in millions):

	Three Months Ended March 31,
	2022		2021
Investment capital (1) (2)	$	109	$	85
Maintenance capital (1)	27		35
	$	136	$	120

(1)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.”

(2)Includes contributions to unconsolidated entities, accounted for under the equity method of accounting, related to investment capital projects by such entities.

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2022 Investment and Maintenance Capital. Total investment capital for the year ended December 31, 2022 is projected to be approximately $330 million ($275 million net to our interest). Approximately half of our projected investment capital expenditures are expected to be invested in the Permian JV assets. Additionally, maintenance capital for the full year of 2022 is projected to be $220 million ($210 million net to our interest). We expect to fund our 2022 investment and maintenance capital expenditures primarily with retained cash flow.

Divestitures

Proceeds from the sale of assets have generally been used to fund our investment capital projects and reduce debt levels. The following table summarizes the proceeds received during the first three months of 2022 and 2021 from sales of assets (in millions):

	Three Months Ended March 31,
	2022		2021
Proceeds from divestitures (1)	$	53	$	21

(1)Represents proceeds, including working capital adjustments, net of transaction costs.

Ongoing Activities Related to Strategic Transactions

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

We typically do not announce a transaction until after we have executed a definitive agreement. In certain cases, in order to protect our business interests or for other reasons, we may defer public announcement of a transaction until closing or a later date. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future efforts with respect to any such transactions will be successful, and we can provide no assurance that our financial expectations with respect to such transactions will ultimately be realized. See Item 1A. “Risk Factors—Risks Related to PAA’s Business—Divestitures and acquisitions involve risks that may adversely affect our business” included in our 2021 Annual Report on Form 10-K.

Financing Activities

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

Borrowings and Repayments Under Credit Arrangements

During the three months ended March 31, 2022, we had net borrowings on the PAA credit facilities and commercial paper program of $382 million. The net borrowings resulted primarily from borrowings during the period related to funding needs for capital investments, inventory purchases, senior notes repayments and other general partnership purposes, partially offset by cash flow from operating activities and proceeds from asset sales.

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During the three months ended March 31, 2021, we had net repayments on the PAA credit facilities and commercial paper program of $576 million. The net repayments resulted primarily from cash flow from operating activities and proceeds from asset sales, which offset borrowings during the period related to funding needs for capital investments, inventory purchases and other general partnership purposes.

Repayment of Senior Notes

During the three months ended March 31, 2022, PAA redeemed its 3.65%, $750 million senior notes due June 2022. PAA utilized cash on hand and borrowings under its commercial paper program to repay these senior notes.

Common Equity Repurchase Program

PAA repurchased 2.4 million and 0.4 million common units under the Program through open market purchases that settled during the three months ended March 31, 2022 and 2021, respectively, for a total purchase price of $25 million and $3 million, respectively, including commissions and fees. At March 31, 2022, the remaining available capacity under the Program was $247 million.

Registration Statements

PAGP Registration Statements. We have filed with the SEC a shelf registration statement that, subject to effectiveness at the time of use, allows us to issue, in the aggregate, up to a specified amount of equity securities (the “PAGP Traditional Shelf”), under which we had approximately $939 million of unsold securities available at March 31, 2022. We also have access to a shelf registration statement (the “PAGP WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of equity securities, subject to market conditions and capital needs. We did not conduct any offerings under the PAGP Traditional Shelf or the PAGP WKSI Shelf during the three months ended March 31, 2022.

PAA Registration Statements. PAA periodically accesses the capital markets for both equity and debt financing. PAA has filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows PAA to issue, in the aggregate, up to a specified amount of debt or equity securities (the “PAA Traditional Shelf”), under which PAA had approximately $1.1 billion of unsold securities available at March 31, 2022. PAA also has access to a universal shelf registration statement (the “PAA WKSI Shelf”), which provides it with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and capital needs. PAA did not conduct any offerings under the PAA Traditional Shelf or the PAA WKSI Shelf during the three months ended March 31, 2022.

Distributions to Our Class A Shareholders

We distribute all of our available cash within 55 days following the end of each quarter to Class A shareholders of record. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. Our levels of financial reserves are established by our general partner and include reserves for the proper conduct of our business (including future capital expenditures and anticipated credit needs), compliance with legal or contractual obligations and funding of future distributions to our shareholders. See Item 5. “Market for Registrant’s Shares, Related Shareholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy” included in our 2021 Annual Report on Form 10-K for additional discussion.

On May 13, 2022, we will pay a quarterly cash distribution of $0.2175 per Class A share ($0.87 per share on an annualized basis) to shareholders of record at the close of business on April 29, 2022 for the period from January 1, 2022 through March 31, 2022, which represents a $0.0375 per share increase from the distribution paid in February 2022.

See Note 7 to our Condensed Consolidated Financial Statements for details of distributions paid during or pertaining to the first three months of 2022.

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Distributions to Noncontrolling Interests

Distributions to noncontrolling interests represent amounts paid on interests in consolidated entities that are not owned by us. As of March 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 and (iv) a 33% interest in Red River LLC.

On May 13, 2022, PAA will pay a quarterly cash distribution of $0.2175 per common unit ($0.87 per unit on an annualized basis) to unitholders of record at the close of business on April 29, 2022 for the period from January 1, 2022 through March 31, 2022, which represents a $0.0375 per unit increase from the distribution paid in February 2022.

See Note 7 to our Condensed Consolidated Financial Statements for details of distributions paid to noncontrolling interests during the three months ended March 31, 2022.

Contingencies

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

Commitments

Purchase Obligations. In the ordinary course of doing business, we purchase crude oil and NGL from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years, with a limited number of contracts with remaining terms extending up to 12 years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy or who have provided credit support we consider adequate.

The following table includes our best estimate of the amount and timing of these payments as well as other amounts due under the specified contractual obligations as of March 31, 2022 (in millions):

	Remainder of 2022		2023		2024		2025		2026		2027 and Thereafter		Total
Crude oil, NGL and other purchases (1)	$	23,259	$	26,253	$	25,271	$	24,414	$	23,148	$	72,905	$	195,250

(1)Amounts are primarily based on estimated volumes and market prices based on average activity during March 2022. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.

Letters of Credit. In connection with merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At March 31, 2022 and December 31, 2021, we had outstanding letters of credit of approximately $34 million and $98 million, respectively.

Recent Accounting Pronouncements

See Note 2 to our Condensed Consolidated Financial Statements.

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FORWARD-LOOKING STATEMENTS

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

•our ability to pay distributions to our Class A shareholders;

•our expected receipt of, and amounts of, distributions from Plains AAP, L.P.;

•declines in global crude oil demand and crude oil prices (whether due to the COVID-19 pandemic, future pandemics or other factors) that correspondingly lead to a significant reduction of North American crude oil and natural gas liquids (“NGL”) production (whether due to reduced producer cash flow to fund drilling activities or the inability of producers to access capital, or both, the unavailability of pipeline and/or storage capacity, the shutting-in of production by producers, government-mandated pro-ration orders, or other factors), which in turn could result in significant declines in the actual or expected volume of crude oil and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets and/or the reduction of commercial opportunities that might otherwise be available to us;

•the effects of competition and capacity overbuild in areas where we operate, including downward pressure on rates and margins, contract renewal risk and the risk of loss of business to other midstream operators who are willing or under pressure to aggressively reduce transportation rates in order to capture or preserve customers;

•negative societal sentiment regarding the hydrocarbon energy industry and the continued development and consumption of hydrocarbons, which could influence consumer preferences and governmental or regulatory actions that adversely impact our business;

•unanticipated changes in crude oil and NGL market structure, grade differentials and volatility (or lack thereof);

•general economic, market or business conditions in the United States and elsewhere (including the potential for a recession or significant slowdown in economic activity levels, the risk of persistently high inflation and continued supply chain issues, the impact of coronavirus variants on demand and growth, and the timing, pace and extent of economic recovery) that impact (i) demand for crude oil, drilling and production activities and therefore the demand for the midstream services we provide and (ii) commercial opportunities available to us;

•the impact of current and future laws, rulings, governmental regulations, executive orders, trade policies, accounting standards and statements, and related interpretations, including legislation, executive orders or regulatory initiatives that arise out of pandemic related concerns that prohibit, restrict or regulate hydraulic fracturing or that prohibit the development of oil and gas resources and the related infrastructure on lands dedicated to or served by our pipelines;

•environmental liabilities, litigation or other events that are not covered by an indemnity, insurance or existing reserves;

•loss of key personnel and inability to attract and retain new talent;

•fluctuations in refinery capacity in areas supplied by our mainlines and other factors affecting demand for various grades of crude oil and NGL and resulting changes in pricing conditions or transportation throughput requirements;

•the successful operation of joint ventures and joint operating arrangements we enter into from time to time, whether relating to assets operated by us or by third parties, and the successful integration and future performance of acquired assets or businesses;

•the availability of, and our ability to consummate, divestitures, joint ventures, acquisitions or other strategic opportunities;

•maintenance of PAA’s credit rating and ability to receive open credit from our suppliers and trade counterparties;

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•the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event that materially impacts our operations, including cyber or other attacks on our electronic and computer systems;

•weather interference with business operations or project construction, including the impact of extreme weather events or conditions;

•significant under-utilization of our assets and facilities;

•the refusal or inability of our customers or counterparties to perform their obligations under their contracts with us (including commercial contracts, asset sale agreements and other agreements), whether justified or not and whether due to financial constraints (such as reduced creditworthiness, liquidity issues or insolvency), market constraints, legal constraints (including governmental orders or guidance), the exercise of contractual or common law rights that allegedly excuse their performance (such as force majeure or similar claims) or other factors;

•our inability to perform our obligations under our contracts, whether due to non-performance by third parties, including our customers or counterparties, market constraints, third-party constraints, supply chain issues, legal constraints (including governmental orders or guidance), or other factors or events;

•the incurrence of costs and expenses related to unexpected or unplanned capital expenditures, third-party claims or other factors;

•disruptions to futures markets for crude oil, NGL and other petroleum products, which may impair our ability to execute our commercial or hedging strategies;

•failure to implement or capitalize, or delays in implementing or capitalizing, on investment capital projects, whether due to permitting delays, permitting withdrawals or other factors;

•shortages or cost increases of supplies, materials or labor;

•tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, investment capital projects, working capital requirements and the repayment or refinancing of indebtedness;

•the amplification of other risks caused by volatile financial markets, capital constraints, liquidity concerns and inflation;

•the use or availability of third-party assets upon which our operations depend and over which we have little or no control;

•the currency exchange rate of the Canadian dollar to the United States dollar;

•inability to recognize current revenue attributable to deficiency payments received from customers who fail to ship or move more than minimum contracted volumes until the related credits expire or are used;

•increased costs, or lack of availability, of insurance;

•the effectiveness of our risk management activities;

•fluctuations in the debt and equity markets, including the price of PAA’s units at the time of vesting under its long-term incentive plans;

•risks related to the development and operation of our assets; and

•other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, as well as in the processing, transportation, fractionation, storage and marketing of NGL.

Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read “Risk Factors” discussed in Item 1A of our 2021 Annual Report on Form 10-K. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various market risks, including (i) commodity price risk, (ii) interest rate risk and (iii) currency exchange rate risk. We use various derivative instruments to manage such risks and, in certain circumstances, to realize incremental margin during volatile market conditions. Our risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our exchange-cleared and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. We have a risk management function that has direct responsibility and authority for our risk policies, related controls around commercial activities and certain aspects of corporate risk management. Our risk management function also approves all new risk management strategies through a formal process. The following discussion addresses each category of risk.

Commodity Price Risk

We use derivative instruments to hedge price risk associated with the following commodities:

•Crude oil

We utilize crude oil derivatives to hedge commodity price risk inherent in our pipeline, terminalling and merchant activities. Our objectives for these derivatives include hedging anticipated purchases and sales, stored inventory and basis differentials. We manage these exposures with various instruments including futures, forwards, swaps and options.

•Natural gas

We utilize natural gas derivatives to hedge commodity price risk inherent in our natural gas processing assets (natural gas purchase component of the frac spread). Additionally, we utilize natural gas derivatives to hedge anticipated operational fuel gas requirements related to our natural gas processing and NGL fractionation plants. We manage these exposures with various instruments including futures, swaps and options.

•NGL and other

We utilize NGL derivatives, primarily propane and butane derivatives, to hedge commodity price risk inherent in our commercial activities, including the sale of the individual specification products extracted in our natural gas processing assets (sale of specification NGL products component of the frac spread), as well as other net sales of NGL inventory, held mainly at our owned NGL storage terminals. Our objectives for these derivatives include hedging anticipated purchases and sales and stored inventory. We manage these exposures with various instruments including futures, forwards, swaps and options.

See Note 8 to our Condensed Consolidated Financial Statements for further discussion regarding our hedging strategies and objectives.

The fair value of our commodity derivatives and the change in fair value as of March 31, 2022 that would be expected from a 10% price increase or decrease is shown in the table below (in millions): 

	Fair Value		Effect of 10% Price Increase		Effect of 10% Price Decrease
Crude oil	$	(62)	$	(40)	$	40
Natural gas	130		$	34	$	(34)
NGL and other	(217)		$	(95)	$	95
Total fair value	$	(149)

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The fair values presented in the table above reflect the sensitivity of the derivative instruments only and do not include the effect of the underlying hedged commodity. Price-risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in near-term commodity prices, the fair value of our derivative portfolio would typically change less than that shown in the table as changes in near-term prices are not typically mirrored in delivery months further out.

Interest Rate Risk

Our use of variable rate debt and any forecasted issuances of fixed rate debt expose us to interest rate risk. Therefore, from time to time, we use interest rate derivatives to hedge interest rate risk associated with anticipated interest payments and, in certain cases, outstanding debt instruments. All of PAA’s senior notes are fixed rate notes and thus are not subject to interest rate risk. Our variable rate debt outstanding at March 31, 2022, approximately $382 million, was subject to interest rate re-sets that generally range from one day to approximately one week. The average interest rate on variable rate debt that was outstanding during the three months ended March 31, 2022 was 1.0%, based upon rates in effect during such period. The fair value of our interest rate derivatives was a net asset of $97 million as of March 31, 2022. A 10% increase in the forward LIBOR curve as of March 31, 2022 would have resulted in an increase of $18 million to the fair value of our interest rate derivatives. A 10% decrease in the forward LIBOR curve as of March 31, 2022 would have resulted in a decrease of $18 million to the fair value of our interest rate derivatives. See Note 8 to our Condensed Consolidated Financial Statements for a discussion of our interest rate risk hedging activities.

Preferred Distribution Rate Reset Option

The Preferred Distribution Rate Reset Option of PAA’s Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, PAA’s partnership agreement, and recorded at fair value in our Condensed Consolidated Balance Sheets. The valuation model utilized for this embedded derivative contains inputs including PAA’s common unit price, ten-year United States treasury rates, default probabilities and timing estimates to ultimately calculate the fair value of PAA’s Series A preferred units with and without the Preferred Distribution Rate Reset Option. The fair value of this embedded derivative was a liability of $44 million as of March 31, 2022. A 10% increase or decrease in the fair value would have an impact of $4 million. See Note 8 to our Condensed Consolidated Financial Statements for a discussion of embedded derivatives.

Item 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We maintain written disclosure controls and procedures, which we refer to as our “DCP.” Our DCP is designed to ensure that information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 (the “Exchange Act”) is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.

Applicable SEC rules require an evaluation of the effectiveness of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our DCP as of March 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.

Changes in Internal Control over Financial Reporting

In addition to the information concerning our DCP, we are required to disclose certain changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting during the first quarter of 2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Certifications

The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a) are filed with this report as Exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350 are furnished with this report as Exhibits 32.1 and 32.2.

PART II. OTHER INFORMATION

Item 1.   LEGAL PROCEEDINGS

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

Item 1A. RISK FACTORS

For a discussion of our risk factors, see Item 1A. of our 2021 Annual Report on Form 10-K. Those risks and uncertainties are not the only ones facing us and there may be additional matters of which we are unaware or that we currently consider immaterial. All of those risks and uncertainties could adversely affect our business, financial condition and/or results of operations.

Item 2.   UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

In connection with our IPO and related transactions, the former owners of Plains All American GP LLC (the “Legacy Owners”) acquired the following interests (collectively, the “Stapled Interests”): (i) Class A units of AAP (“AAP units”) representing an economic limited partner interest in AAP; (ii) general partner units representing a non-economic membership interest in our general partner; and (iii) Class B shares representing a non-economic limited partner interest in us. The Legacy Owners and any permitted transferees of their Stapled Interests have the right to exchange (the “Exchange Right”) all or a portion of such Stapled Interests for an equivalent number of Class A shares. In connection with the exercise of the Exchange Right, the Stapled Interests are transferred to us and the applicable Class B shares are canceled. Although we issue one Class A share for each Stapled Interest that is exchanged, we also receive one AAP unit and one general partner unit. As a result, the exercise by Legacy Owners of the Exchange Right is not dilutive. During the three months ended March 31, 2022, certain Legacy Owners or their permitted transferees exercised the Exchange Right, which resulted in the issuance of 35,700 Class A shares. The issuance of Class A shares in connection with the exercise of the Exchange Right was exempt from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof.

Item 3.   DEFAULTS UPON SENIOR SECURITIES

None.

Item 4.   MINE SAFETY DISCLOSURES

Not applicable.

Item 5.   OTHER INFORMATION

None.

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Item 6.   EXHIBITS

Exhibit No.		Description
3.1	—	Certificate of Limited Partnership of Plains GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (333-190227) filed July 29, 2013).
3.2	—	Second Amended and Restated Agreement of Limited Partnership of Plains GP Holdings, L.P. dated as of November 15, 2016 (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K filed November 21, 2016).
3.3	—	Amendment No. 1 dated April 6, 2020 to the Second Amended and Restated Agreement of Limited Partnership of Plains GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed April 9, 2020).
3.4	—	Certificate of Formation of PAA GP Holdings LLC (incorporated by reference to Exhibit 3.3 to our Registration Statement on Form S-1 (333-190227) filed July 29, 2013).
3.5	—	Fourth Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC dated effective as of August 19, 2020 (incorporated by reference to Exhibit 3.11 to our Annual Report on Form 10-K for the year ended December 31, 2021).
3.6	—	Seventh Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P., dated as of October 10, 2017 (incorporated by reference to Exhibit 3.1 to PAA's Current Report on Form 8-K filed October 12, 2017).
3.7	—	Seventh Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated November 15, 2016 (incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K filed November 21, 2016).
3.8	—	Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. dated November 15, 2016 (incorporated by reference to Exhibit 3.4 to our Current Report on Form 8-K filed November 21, 2016).
3.9	—	Amendment No. 1 dated September 26, 2018 to the Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 2, 2018).
3.10	—	Amendment No. 2 dated May 23, 2019 to the Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed May 30, 2019).
3.11	—	Limited Liability Company Agreement of PAA GP LLC dated December 28, 2007 (incorporated by reference to Exhibit 3.3 to PAA’s Current Report on Form 8-K filed January 4, 2008).
4.1	—	Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).
4.2	—	Sixth Supplemental Indenture (Series A and Series B 6.70% Senior Notes due 2036) dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed May 12, 2006).
4.3	—	Tenth Supplemental Indenture (Series A and Series B 6.650% Senior Notes due 2037) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to PAA’s Current Report on Form 8-K filed October 30, 2006).
4.4	—	Twenty-First Supplemental Indenture (5.15% Senior Notes due 2042) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance Corp and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to PAA’s Current Report on Form 8-K filed March 26, 2012).

54

4.5	—	Twenty-Second Supplemental Indenture (2.85% Senior Notes due 2023) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed December 12, 2012).
4.6	—	Twenty-Third Supplemental Indenture (4.30% Senior Notes due 2043) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to PAA’s Current Report on Form 8-K filed December 12, 2012).
4.7	—	Twenty-Fourth Supplemental Indenture (3.85% Senior Notes due 2023) dated August 15, 2013, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed August 15, 2013).
4.8	—	Twenty-Fifth Supplemental Indenture (4.70% Senior Notes due 2044) dated April 23, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed April 29, 2014).
4.9	—	Twenty-Sixth Supplemental Indenture (3.60% Senior Notes due 2024) dated September 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed September 11, 2014).
4.10	—	Twenty-Eighth Supplemental Indenture (4.90% Senior Notes due 2045) dated December 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 11, 2014).
4.11	—	Twenty-Ninth Supplemental Indenture (4.65% Senior Notes due 2025) dated August 24, 2015, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed August 26, 2015).
4.12	—	Thirtieth Supplemental Indenture (4.50% Senior Notes due 2026) dated November 22, 2016, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed November 29, 2016).
4.13	—	Thirty-First Supplemental Indenture (3.55% Senior Notes due 2029) dated September 16, 2019, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed September 17, 2019).
4.14	—	Thirty-Second Supplemental Indenture (3.80% Senior Notes due 2030) dated June 11, 2020, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to PAA’s Current Report on Form 8-K filed June 11, 2020).
4.15	—	Shareholder and Registration Rights Agreement dated October 21, 2013 by and among Plains GP Holdings, L.P. and the other parties signatory thereto (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed October 25, 2013).
4.16	—	Description of Our Securities (incorporated by reference to Exhibit 4.17 to our Annual Report on Form 10-K for the year ended December 31, 2021).
10.1* †	—	Form of Amended and Restated Special Retention LTIP Grant Letter Dated February 24, 2022.
31.1 †	—	Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).
31.2 †	—	Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).
32.1 ††	—	Certification of Principal Executive Officer pursuant to 18 U.S.C. 1350.
32.2 ††	—	Certification of Principal Financial Officer pursuant to 18 U.S.C. 1350.

55

101.INS†	—	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH†	—	Inline XBRL Taxonomy Extension Schema Document
101.CAL†	—	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF†	—	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB†	—	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE†	—	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104†	—	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

†    Filed herewith.

††    Furnished herewith.

*    Management compensatory plan or arrangement.

56

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

	PLAINS GP HOLDINGS, L.P.
	By:	PAA GP HOLDINGS LLC,
		its general partner
	By:	/s/ Willie Chiang
		Willie Chiang,
		Chief Executive Officer and Director of PAA GP Holdings LLC
		(Principal Executive Officer)
May 9, 2022
	By:	/s/ Al Swanson
		Al Swanson,
		Executive Vice President and Chief Financial Officer of PAA GP Holdings LLC
		(Principal Financial Officer)
May 9, 2022
	By:	/s/ Chris Herbold
		Chris Herbold,
		Senior Vice President, Finance and Chief Accounting Officer of PAA GP Holdings LLC
		(Principal Accounting Officer)
May 9, 2022

57

EX-10.1

Exhibit 10.1

AMENDED AND RESTATED

SPECIAL RETENTION LTIP GRANT –

US Section 16 Officer

February 24, 2022

(Replaces and supersedes letter dated November 21, 2019)

[Name]

[Address]

Re:    Amended and Restated Grant of Phantom Units

Dear [Name]:

This letter replaces and supersedes the original grant letter dated November 21, 2019, pursuant to which you received an award of [•] Phantom Units under the Company’s 2013 Long-Term Incentive Plan (the “Plan”) and an equal number of distribution equivalent rights (“DERs”) representing the right to receive a cash payment equivalent to the amount, if any, paid in cash distributions on one Common Unit of Plains All American Pipeline, L.P. (“PAA” or the “Partnership”) to the holder of such Common Unit. The terms and conditions of this amended and restated grant are as set forth below.

1.Subject to the further provisions of this Agreement, your Phantom Units or applicable portion thereof shall vest (become payable in the form of one Common Unit of PAA for each Phantom Unit) as follows:

a.Tranche A, which shall consist of 50% of the total number of Phantom Units covered by this grant letter, shall vest on the August 2026 Distribution Date; and

b.Tranche B, which shall consist of up to 50% of the total number of Phantom Units covered by this grant letter, shall vest pursuant to the terms and conditions described in Exhibit A attached hereto. With respect to Tranche B, the actual number of Phantom Units that vest may be lower than the percentage of target Phantom Units associated with such Tranche.

2.Subject to the further provisions of this Agreement, your DERs have vested or will vest (become payable in cash) as follows: (i) one-fifth of your DERs vested upon and effective with the August 2020 Distribution Date; (ii) one-fifth of your DERs vested upon and effective with the August 2021 Distribution Date; (iii) one-fifth of your DERs shall vest upon and effective with the August 2022 Distribution Date; and (iv) two-fifths of your DERs will begin accruing with the first quarter 2022 distribution paid on the May 2022 Distribution Date and will continue to accrue until the associated Phantom Units vest or are forfeited pursuant to the terms hereof. Once the final payout percentages and the final number of Phantom Units vesting for Tranche B have been determined, such accrued amounts shall be adjusted so that they equal the total amount that would have been accrued in respect of the DERs associated with such vested Phantom Units had the accrual been based on such number of vested Phantom Units commencing on the May 2022 Distribution Date. All accrued and unpaid DERs associated with the number of vested Tranche B Phantom Units as finally determined, if any, shall be paid on the August 2026 Distribution Date or as soon thereafter as is administratively practicable.

333 Clay Street, Suite 1600 (77002)     ■ P.O. Box 4648 ■ Houston, Texas 77210-4648 ■ 713-646-4100

[Name]

February 24, 2022

Page 2

3.Except as set forth in paragraph 2(iv) above, your DERs shall not accrue payments prior to vesting.

4.The number of Phantom Units and DERs subject to this award shall be proportionately reduced or increased for any split or reverse split, respectively, of the Common Units, or any event or transaction having a similar effect.

5.Upon vesting of any Phantom Units, an equivalent number of DERs will expire. Any such DERs that are vested prior to, or that would vest as of, the Distribution Date on which the Phantom Units vest, shall be payable on such Distribution Date prior to their expiration.

6.In the event of the termination of your employment with the Company and its Affiliates for any reason (other than in connection with a Change in Status or by reason of your death or “disability,” as defined in paragraph 7 below), all of your then outstanding DERs (regardless of vesting) and Phantom Units shall automatically be forfeited as of the date of termination; provided, however, that if the Company or its Affiliates terminate your employment other than as a result of a Termination for Cause, the following provisions shall apply: (i) if such termination occurs prior to the third anniversary of the date of the original grant letter, 40% of your unvested Phantom Units (assuming a TSR Payout Percentage (as defined in Exhibit A) of 100% with respect to Tranche B) shall be deemed nonforfeitable on the date of termination, and shall vest on the next following Distribution Date; (ii) if such termination occurs on or after the third anniversary of the date of the original grant letter but prior to the fourth anniversary of the date of the original grant letter, 60% of your unvested Phantom Units (assuming a TSR Payout Percentage of 100% with respect to Tranche B) shall be deemed nonforfeitable on the date of termination, and shall vest on the next following Distribution Date; (iii) if such termination occurs on or after the fourth anniversary of the date of the original grant letter but prior to the fifth anniversary of the date of the original grant letter, 80% of your unvested Phantom Units (assuming a TSR Payout Percentage of 100% with respect to Tranche B) shall be deemed nonforfeitable on the date of termination, and shall vest on the next following Distribution Date; (iv) if such termination occurs on or after the fifth anniversary of the date of the original grant letter, 100% of your unvested Phantom Units (assuming a TSR Payout Percentage of 100% with respect to Tranche B) shall be deemed nonforfeitable on the date of termination, and shall vest on the next following Distribution Date; and (v) any DERs associated with such unvested, nonforfeitable Phantom Units described in clauses (i)-(iv) immediately preceding shall not be forfeited on the date of termination, but shall vest in accordance with paragraph 2 above and if vested shall be payable and shall expire in accordance with paragraph 1 or paragraph 5 above.

[Name]

February 24, 2022

Page 3

7.In the event of the termination of your employment with the Company and its Affiliates by reason of your death or your “disability” (a physical or mental infirmity that impairs your ability substantially to perform your duties for a period of eighteen months or that the Company otherwise determines constitutes a “disability”), 100% of the unvested Phantom Units covered by paragraphs 1(a) and 1(b) above (assuming a TSR Payout Percentage of 100% with respect to Tranche B) shall be deemed nonforfeitable on the date of termination and shall vest on the next following Distribution Date (and any DERs associated with such unvested, nonforfeitable Phantom Units shall not be forfeited on the date of termination, but shall vest in accordance with paragraph 2 above and if vested shall be payable and shall expire in accordance with paragraph 1 or paragraph 5 above). As soon as administratively practicable after the vesting of any Phantom Units pursuant to this paragraph 7, payment will be made in cash in an amount equal to the Market Value of the number of Phantom Units vesting.

8.In the event of a Change in Status, all of your then outstanding Phantom Units (assuming a TSR Payout Percentage of 100% with respect to Tranche B) and tandem DERs shall be deemed 100% nonforfeitable on such date, and such Phantom Units shall vest in full upon the next Distribution Date.

9.Upon payment pursuant to a DER, the Company will withhold any taxes due from your compensation as required by law. Upon vesting of a Phantom Unit, the Company will withhold any taxes due from your compensation as required by law, which (in the sole discretion of the Company) may include withholding a number of Common Units otherwise payable to you.

As used herein, (i) the “Company” refers to Plains All American GP LLC; (ii) “Distribution Date” means the day in February, May, August or November in any year (as context dictates) that is 45 days after the end of the most recently completed calendar quarter (or, if not a business day, the closest previous business day); (iii) “Market Value” means the average of the closing sales prices for a Common Unit on Nasdaq for the five trading days preceding the then most recent “ex dividend” date for payment of a distribution by the Partnership; and (iv) “Board” means the board of directors of PAGP GP (defined below).

The phrase “Change in Status” means (A) the termination of your employment by the Company other than a Termination for Cause, within two and a half months prior to or one year following a Change of Control (the “Protected Period”), (B) the termination of your employment by you due to the occurrence during the Protected Period, without your written consent, of (i) any material diminution in your authority, duties or responsibilities, (ii) any material reduction in your base salary or (iii) any other action or inaction that constitutes a material breach of this Agreement by the Company, or (C) the termination of your employment by you as a result of your retirement on terms and timing that are approved by the Chief Executive Officer of the Company (“CEO”). A termination by you pursuant to (B) above shall not be a Change in Status unless (1) you provide written notice to the Company of the condition in (B)(i), (ii) or (iii) that would constitute a Change in Status within 90 days of the initial existence of the condition and (2) the Company fails to remedy the condition within the 30-day period following such notice.

The phrase “Change of Control” means, and shall be deemed to have occurred upon the occurrence of, one or more of the following events:

[Name]

February 24, 2022

Page 4

(i)any Person (other than Plains GP Holdings, L.P. (“PAGP”) and any affiliate of PAGP that is controlled by PAGP) becomes the beneficial owner, directly or indirectly (in one transaction or a series of related transactions and whether by merger or otherwise), of 50% or more of the membership interest in PAA GP Holdings LLC, a Delaware limited liability company (“PAGP GP”);

(ii)any Person (other than PAGP GP, PAGP or any affiliate of PAGP that is controlled by PAGP) acquires (in one transaction or a series of related transactions and whether by merger or otherwise) direct or indirect control of the general partner interest of PAGP;

(iii)PAGP ceases to retain direct or indirect control (in one transaction or a series of related transactions and whether by merger or otherwise) of the general partner of the Partnership; or

(iv)the consummation of a reorganization, merger or consolidation with, or any direct or indirect sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Partnership to, one or more Persons (other than PAGP or any affiliates of PAGP that are controlled by PAGP).

As used in this definition, “Person” shall include any “partnership, limited partnership, syndicate or other group” constituting a “person” within the meaning of such terms pursuant to Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended.

The phrase “Termination for Cause” shall mean severance of your employment with the Company or its Affiliates based on your (i) failure to perform the duties and responsibilities of your position at an acceptable level as reasonably determined in good faith by the CEO, (ii) conviction of or guilty plea to the committing of an act or acts constituting a felony under the laws of the United States or any state thereof (or Canada or any province thereof) or any misdemeanor involving moral turpitude, or (iii) violation of the Company’s Code of Business Conduct (unless waived in accordance with the terms thereof), in the case of clauses (i) and (iii), with the specific failure or violation described to you in writing.

Terms used herein that are not defined herein shall have the meanings set forth in the Plan or, if not defined in the Plan, in the Seventh Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P., as amended (the “Partnership Agreement”).

This award is intended to either (i) qualify as a “short-term deferral” under Section 409A of the Internal Revenue Code of 1986, as amended, or (ii) comply with the provisions of Section 409A. If it is determined that any payments or benefits to be made or provided under this Agreement do not comply with Section 409A, the parties agree to amend this Agreement or take such other actions as reasonably necessary or appropriate to comply with Section 409A while preserving the economic agreement of the parties.

By signing below, you agree that the Phantom Units and DERs granted hereunder are governed by the terms of the Plan. You also acknowledge and agree that (i) Tranche B of this award constitutes performance-based compensation as defined in the Clawback Policy adopted by PAGP GP on November 12, 2020 and (ii) Tranche B of this award, as well as any other performance-based compensation previously paid or awarded to you, is subject to recovery or cancellation pursuant to such Policy. Copies of the Plan, the Partnership Agreement and the Clawback Policy are available upon request.

[Name]

February 24, 2022

Page 5

Please designate in the space provided below a beneficiary to receive benefits payable under this grant in the event of your death. Unless you indicate otherwise by checking the box below, the named beneficiaries on this form will serve as your beneficiaries for all previous LTIP grants. Please execute and return a copy of this grant letter to Richard McGee and retain a copy for your records.

PLAINS ALL AMERICAN PIPELINE, L.P.

By:    PAA GP LLC, its general partner

By:    PLAINS AAP, L.P., its sole member

By:    PLAINS ALL AMERICAN GP LLC,
its general partner

By:    ______________________________

Name:    Willie Chiang

Title:    Chief Executive Officer

[Name]
Units:	[•]
Dated:

Beneficiary Designation

Primary Beneficiary Name	Relationship	Percent (Must total 100%)
Secondary Beneficiary Name	Relationship	Percent (Must total 100%)

☐ Check this box only if designation does not apply to prior grants

Exhibit A

Tranche B Vesting Terms
(Total Shareholder Return)

1.General. Consistent with the Company’s pay for performance philosophy and in order to more closely align the interests of management with the interests of investors, a portion of your Phantom Units will vest based on PAA’s total shareholder return (“TSR”) compared to the TSR of a peer group as described below. TSR, which will be calculated using data from Bloomberg, is a primary long-term measure of PAA’s performance.

2.Vesting and Payout. As soon as administratively feasible following the close of the period beginning on January 1, 2022 and ending on June 30, 2026 (the “Performance Period”), the Compensation Committee shall determine and certify the TSR Payout Percentage (as defined below). The Compensation Committee shall make such determination based on a scaled payout range of between 0% and 100% as provided in the table below (the specific payout percentage is referred to as the “TSR Payout Percentage”) based on PAA’s TSR ranking at the end of the Performance Period compared to the TSR ranking of the various companies included in the PAA Peer Group described below. If PAA’s absolute TSR is within 50 basis points of the TSR of one or more peer group comparators (i.e., 50 basis points higher or lower), PAA and such comparator(s) shall be deemed to have the same rank and the TSR Payout Percentage shall be equal to the average of the TSR Payout Percentages associated with the relevant rankings as set forth in the table below. The number of Tranche B Phantom Units vesting will be determined by multiplying your target number of Tranche B Phantom Units by the TSR Payout Percentage as certified by the Compensation Committee. If the resulting amount includes a fraction, it will be rounded down to the nearest whole number.

PAA TSR Ranking vs. PAA Peer Group	TSR Payout Percentage
1	100.0%
2	100.0%
3	100.0%
4	100.0%
5	100.0%
6	100.0%
7	100.0%
8	100.0%
9	100.0%
10	87.5%
11	75.0%
12	62.5%
13	50.0%
14	37.5%
15	25.0%
16	12.5%
17	0%

Illustrative Examples (based on an assumed target number of Tranche B Phantom Units of 1,000):

PAA TSR Ranking vs. PAA Peer Group	TSR Payout Percentage / Number of Units Vesting
#1 through #9	100% / 1,000 units
#13	50% / 500 units
#17	0% / 0 units

A-1

3.PAA Peer Group (2022-2026 Performance Period):

Company Name	Ticker
Enterprise Products Partners LP	EPD
Kinder Morgan Inc.	KMI
The Williams Companies Inc.	WMB
MPLX LP	MPLX
Energy Transfer LP	ET
ONEOK Inc.	OKE
Magellan Midstream Partners LP	MMP
Phillips 66 Partners LP	PSXP
Targa Resources Corp.	TRGP
DCP Midstream LP	DCP
Western Midstream Partners LP	WES
Holly Energy Partners LP	HEP
NuStar Energy LP	NS
EnLink Midstream LLC	ENLC
Alerian Midstream Energy Index	AMNA
S&P 500 Index	SPX

In the event any member of the PAA Peer Group files for bankruptcy, liquidates or reorganizes under the United States Bankruptcy Code or other applicable bankruptcy law, such entity shall remain in the PAA Peer Group but shall be deemed to have a TSR of -100% for purposes of calculating the TSR Payout Percentage. If any member of the PAA Peer Group is acquired by an unrelated entity before the end of the Performance Period, such member shall be removed from the PAA Peer Group for purposes of calculating the TSR Payout Percentage. The Compensation Committee shall have discretionary authority to replace such member for purposes of calculating the TSR Payout Percentage. In all other cases involving merger, reorganization or other material change in ownership, legal structure or business operations of any member of the PAA Peer Group, including acquisition by a related entity before the end of the Performance Period, the Compensation Committee shall have authority to retain, remove or replace such member for purposes of calculating the TSR Payout Percentage. In connection with any change to the PAA Peer Group, the Compensation Committee shall also have authority to make related adjustments to the rankings and TSR Payout Percentages.

A-2

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Willie Chiang, certify that:

1.  I have reviewed this quarterly report on Form 10-Q of Plains GP Holdings, L.P. (the “registrant”);

2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.  The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)           Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)           Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)           Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)           Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.  The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)           All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)           Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 9, 2022

/s/ Willie Chiang

Willie Chiang

Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Al Swanson, certify that:

1.  I have reviewed this quarterly report on Form 10-Q of Plains GP Holdings, L.P. (the “registrant”);

2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.  The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)           Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)           Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)           Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)           Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.  The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)           All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)           Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 9, 2022

/s/ Al Swanson

Al Swanson

Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

OF PLAINS GP HOLDINGS, L.P.

PURSUANT TO 18 U.S.C. 1350

I, Willie Chiang, Chief Executive Officer of Plains GP Holdings, L.P. (the “Company”), hereby certify that:

(i)            the accompanying report on Form 10-Q for the period ended March 31, 2022 and filed with the Securities and Exchange Commission on the date hereof (the “Report”) by the Company fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(ii)           the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Willie Chiang

Name: Willie Chiang

Date: May 9, 2022

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

OF PLAINS GP HOLDINGS, L.P.

PURSUANT TO 18 U.S.C. 1350

I, Al Swanson, Chief Financial Officer of Plains GP Holdings, L.P. (the “Company”), hereby certify that:

(i)            the accompanying report on Form 10-Q for the period ended March 31, 2022 and filed with the Securities and Exchange Commission on the date hereof (the “Report”) by the Company fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(ii)           the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Al Swanson

Name: Al Swanson

Date: May 9, 2022

XML

Cover Page - shares	3 Months Ended
	Mar. 31, 2022	Apr. 29, 2022
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2022
Document Transition Report	false
Entity File Number	1-36132
Entity Registrant Name	PLAINS GP HOLDINGS LP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	90-1005472
Entity Address, Address Line One	333 Clay Street
Entity Address, Address Line Two	Suite 1600
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	646-4100
Title of 12(b) Security	Class A Shares
Trading Symbol	PAGP
Security Exchange Name	NASDAQ
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Small Business Entity	false
Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (shares)		194,228,477
Entity Central Index Key	0001581990
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	Q1

XML

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
CURRENT ASSETS
Cash and cash equivalents	$ 117	$ 452
Trade accounts receivable and other receivables, net	7,136	4,705
Inventory	527	783
Other current assets	320	200
Total current assets	8,100	6,140
PROPERTY AND EQUIPMENT	19,434	19,292
Accumulated depreciation	(4,565)	(4,383)
Property and equipment, net	14,869	14,909
OTHER ASSETS
Investments in unconsolidated entities	3,807	3,805
Intangible assets, net	1,901	1,960
Deferred tax asset	1,341	1,362
Linefill	919	907
Long-term operating lease right-of-use assets, net	387	393
Long-term inventory	374	253
Other long-term assets, net	293	249
Total assets	31,991	29,978
CURRENT LIABILITIES
Trade accounts payable	6,871	4,811
Short-term debt	900	822
Other current liabilities	801	601
Total current liabilities	8,572	6,234
LONG-TERM LIABILITIES
Senior notes, net	7,931	8,329
Other long-term debt, net	55	69
Long-term operating lease liabilities	331	339
Other long-term liabilities and deferred credits	901	830
Total long-term liabilities	9,218	9,567
Commitments and Contingencies
PARTNERS’ CAPITAL
Noncontrolling interests	12,661	12,644
Total partners’ capital	14,201	14,177
Total liabilities and partners’ capital	31,991	29,978
Class A Shares
PARTNERS’ CAPITAL
Class A shareholders (194,228,477 and 194,192,777 shares outstanding, respectively)	$ 1,540	$ 1,533

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Mar. 31, 2022	Dec. 31, 2021	Mar. 31, 2021	Dec. 31, 2020
Class A Shares
Shares outstanding
Shares outstanding (shares)	194,228,477	194,192,777	194,098,315	194,051,436

XML

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
REVENUES
Total revenues	$ 13,694	$ 8,383
COSTS AND EXPENSES
Purchases and related costs	12,785	7,392
Field operating costs	346	219
General and administrative expenses	83	68
Depreciation and amortization	231	178
(Gains)/losses on asset sales and asset impairments, net	(42)	2
Total costs and expenses	13,403	7,859
OPERATING INCOME	291	524
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	97	88
Interest expense (net of capitalized interest of $1 and $5, respectively)	(107)	(107)
Other expense, net	(37)	(60)
INCOME BEFORE TAX	244	445
Current income tax expense	(19)	(1)
Deferred income tax expense	(16)	(52)
NET INCOME	209	392
Net income attributable to noncontrolling interests	(187)	(322)
NET INCOME ATTRIBUTABLE TO PAGP	$ 22	$ 70
Class A Shares
OTHER INCOME/(EXPENSE)
BASIC WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING (shares)	194	194
DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING (shares)	194	194
BASIC NET INCOME PER CLASS A SHARE (usd per share)	$ 0.11	$ 0.36
DILUTED NET INCOME PER CLASS A SHARE (usd per share)	$ 0.11	$ 0.36
Product sales revenues
REVENUES
Total revenues	$ 13,381	$ 8,083
Services revenues
REVENUES
Total revenues	$ 313	$ 300

XML

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Income Statement [Abstract]
Interest expense, capitalized interest	$ 1	$ 5

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Statement of Comprehensive Income [Abstract]
Net income	$ 209	$ 392
Other comprehensive income	74	108
Comprehensive income	283	500
Comprehensive income attributable to noncontrolling interests	(240)	(401)
Comprehensive income attributable to PAGP	$ 43	$ 99

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CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance	$ 14,177	$ 11,190
Total period activity	74	108
Ending balance	14,201	11,499
Derivative Instruments
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance	(208)	(258)
Reclassification adjustments	3	3
Unrealized gain on hedges	32	68
Total period activity	35	71
Ending balance	(173)	(187)
Translation Adjustments
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance	(642)	(657)
Currency translation adjustments	40	37
Total period activity	40	37
Ending balance	(602)	(620)
Other
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance	(3)	(3)
Other	(1)
Total period activity	(1)	0
Ending balance	(4)	(3)
Total
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance	(853)	(918)
Reclassification adjustments	3	3
Unrealized gain on hedges	32	68
Currency translation adjustments	40	37
Other	(1)
Total period activity	74	108
Ending balance	$ (779)	$ (810)

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 209	$ 392
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	231	178
(Gains)/losses on asset sales and asset impairments, net	(42)	2
Deferred income tax expense	16	52
Change in fair value of Preferred Distribution Rate Reset Option (Note 8)	44	67
Equity earnings in unconsolidated entities	(97)	(88)
Distributions on earnings from unconsolidated entities	96	110
Other	4	6
Changes in assets and liabilities, net of acquisitions	(122)	70
Net cash provided by operating activities	339	789
CASH FLOWS FROM INVESTING ACTIVITIES
Investments in unconsolidated entities	(3)	(35)
Additions to property, equipment and other	(101)	(97)
Proceeds from sales of assets	53	21
Cash paid for purchases of linefill	(39)	0
Other investing activities	9	3
Net cash used in investing activities	(81)	(108)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) under PAA commercial paper program (Note 6)	382	(410)
Net repayments under PAA senior secured hedged inventory facility (Note 6)	0	(166)
Repayments of PAA senior notes	(750)	0
Repurchase of common units by a subsidiary (Note 7)	(25)	(3)
Distributions paid to Class A shareholders (Note 7)	(35)	(35)
Distributions paid to noncontrolling interests (Note 7)	(188)	(138)
Other financing activities	20	66
Net cash used in financing activities	(596)	(686)
Effect of translation adjustment	3	0
Net decrease in cash and cash equivalents and restricted cash	(335)	(5)
Cash and cash equivalents and restricted cash, beginning of period	456	63
Cash and cash equivalents and restricted cash, end of period	121	58
Cash paid for:
Interest, net of amounts capitalized	74	65
Income taxes, net of amounts refunded	$ 23	$ 24

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CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions	Total	Noncontrolling Interests	Limited Partners Class A Shares
Beginning balance at Dec. 31, 2020	$ 11,190	$ 9,726	$ 1,464
Increase (Decrease) in Partners' Capital
Net income	392	322	70
Distributions (Note 7)	(185)	(150)	(35)
Deferred tax asset	(7)	0	(7)
Other comprehensive income	108	79	29
Repurchase of common units by a subsidiary (Note 7)	(3)	(3)	0
Contributions from noncontrolling interests	1	1	0
Other	3	1	2
Ending balance at Mar. 31, 2021	11,499	9,976	1,523
Beginning balance at Dec. 31, 2021	14,177	12,644	1,533
Increase (Decrease) in Partners' Capital
Net income	209	187	22
Distributions (Note 7)	(235)	(200)	(35)
Deferred tax asset	(5)	0	(5)
Other comprehensive income	74	53	21
Repurchase of common units by a subsidiary (Note 7)	(25)	(25)	0
Other	6	2	4
Ending balance at Mar. 31, 2022	$ 14,201	$ 12,661	$ 1,540

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Organization and Basis of Consolidation and Presentation

3 Months Ended

Mar. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Basis of Consolidation and Presentation

Organization and Basis of Consolidation and Presentation

Organization

Plains GP Holdings, L.P. (“PAGP”) is a Delaware limited partnership formed in 2013 that has elected to be taxed as a corporation for United States federal income tax purposes. PAGP does not directly own any operating assets; as of March 31, 2022, its principal sources of cash flow are 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-Q 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 March 31, 2022, 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. AAP is a Delaware limited partnership that, as of March 31, 2022, directly owned a limited partner interest in PAA through its ownership of approximately 241.5 million PAA common units (approximately 31% of PAA’s total outstanding common units and Series A preferred units combined). AAP is the sole member of PAA GP LLC (“PAA GP”), a Delaware limited liability company that directly holds the non-economic general partner interest in PAA.

PAA’s business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals. As one of the largest midstream service providers in North America, PAA owns an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and natural gas liquids (“NGL”) producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. PAA’s assets and the services it provides are primarily focused on and conducted through two operating segments: Crude Oil and NGL. See Note 11 for further discussion of our operating segments.

PAA GP Holdings LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities and is responsible for exercising on our behalf any rights we have as the sole and managing member of GP LLC, including responsibility for conducting the business and managing the operations of AAP and PAA. GP LLC employs our domestic officers and personnel involved in the operation and management of AAP and PAA. PAA’s Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC.

References to the “Plains Entities” include us, our general partner, GP LLC, AAP, PAA GP and PAA and its subsidiaries.

Definitions

Additional defined terms are used in this Form 10-Q and shall have the meanings indicated below:

AOCI	=	Accumulated other comprehensive income/(loss)
ASC	=	Accounting Standards Codification
ASU	=	Accounting Standards Update
Bcf	=	Billion cubic feet
Btu	=	British thermal unit
CAD	=	Canadian dollar
CODM	=	Chief Operating Decision Maker
EBITDA	=	Earnings before interest, taxes, depreciation and amortization
EPA	=	United States Environmental Protection Agency
FASB	=	Financial Accounting Standards Board
GAAP	=	Generally accepted accounting principles in the United States
ICE	=	Intercontinental Exchange
ISDA	=	International Swaps and Derivatives Association
LIBOR	=	London Interbank Offered Rate
LTIP	=	Long-term incentive plan
Mcf	=	Thousand cubic feet
MMbls	=	Million barrels
NGL	=	Natural gas liquids, including ethane, propane and butane
NYMEX	=	New York Mercantile Exchange
SEC	=	United States Securities and Exchange Commission
TWh	=	Terawatt hour
USD	=	United States dollar
WTI	=	West Texas Intermediate

Basis of Consolidation and Presentation

The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our 2021 Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of PAGP and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. The condensed consolidated balance sheet data as of December 31, 2021 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three months ended March 31, 2022 should not be taken as indicative of results to be expected for the entire year. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. 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, including the reclassifications discussed further below.

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

Management judgment is required to evaluate whether PAGP controls an entity. Key areas of that evaluation include (i) determining whether an entity is a variable interest entity (“VIE”); (ii) determining whether PAGP is the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that PAGP and its related parties have over those activities through variable interests; and (iii) identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether PAGP is a VIE’s primary beneficiary.

We have determined that our subsidiaries, PAA and AAP, are VIEs and should be consolidated by PAGP because:

•The limited partners of PAA and AAP lack (i) substantive “kick-out rights” (i.e., the right to remove the general partner) based on a simple majority or lower vote and (ii) substantive participation rights and thus lack the ability to block actions of the general partner that most significantly impact the economic performance of PAA and AAP, respectively.

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

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

With the exception of a deferred tax asset of $1.341 billion and $1.362 billion as of March 31, 2022 and December 31, 2021, respectively, substantially all assets and liabilities presented on PAGP’s Condensed Consolidated Balance Sheets are those of PAA. Only the assets of each respective VIE can be used to settle the obligations of that individual VIE, and the creditors of each/either of those VIEs do not have recourse against the general credit of PAGP. PAGP did not provide any financial support to PAA or AAP during the three months ended March 31, 2022 or the year ended December 31, 2021. See Note 17 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K 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 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 11 for further discussion of our operating segments. In connection with this change, we changed the presentation of Revenues on our Condensed 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.”

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Restricted Cash

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 Condensed Consolidated Balance Sheets that sum to the total of the amounts shown on our Condensed Consolidated Statements of Cash Flows (in millions):

	March 31, 2022		December 31, 2021
Cash and cash equivalents	$	117	$	452
Restricted cash (1)	4		4
Total cash and cash equivalents and restricted cash	$	121	$	456

(1)Included in “Other current assets” on our Condensed Consolidated Balance Sheets.

Recent Accounting Pronouncements

Except as discussed below and in our 2021 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the three months ended March 31, 2022 that are of significance or potential significance to us.

In August 2020, the FASB issued ASU 2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity, by eliminating two of the three models that require separate accounting for embedded conversion features and the settlement assessment that entities are required to perform to determine whether a contract qualifies for equity classification. This guidance is effective for interim and annual periods beginning after December 15, 2021, with early adoption permitted. We adopted this guidance effective January 1, 2022, and our adoption did not have a material impact on our financial position, results of operations or cash flows.

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Revenues and Accounts Receivable

3 Months Ended

Mar. 31, 2022

Revenue from Contract with Customer [Abstract]

Revenues and Accounts Receivable

Revenues and Accounts Receivable

Revenue Recognition

We disaggregate our revenues by segment and type of activity. These categories depict how the nature, amount, timing and uncertainty of revenues and cash flows are affected by economic factors. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for additional information regarding our types of revenues and policies for revenue recognition.

Revenues from Contracts with Customers. The following tables present our revenues from contracts with customers disaggregated by segment and type of activity (in millions):

	Three Months Ended March 31,
	2022		2021
Crude Oil segment revenues from contracts with customers
Sales	$	12,857	$	7,726
Transportation	155		90
Terminalling, Storage and Other	90		130
Total Crude Oil segment revenues from contracts with customers	$	13,102	$	7,946

	Three Months Ended March 31,
	2022		2021
NGL segment revenues from contracts with customers
Sales	$	845	$	772
Transportation	9		7
Terminalling, Storage and Other	25		22
Total NGL segment revenues from contracts with customers	$	879	$	801

Reconciliation to Total Revenues of Reportable Segments. The following disclosures only include information regarding revenues associated with consolidated entities; 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 to total revenues of reportable segments and total revenues as disclosed in our Condensed Consolidated Statements of Operations (in millions):

Three Months Ended March 31, 2022	Crude Oil		NGL		Total
Revenues from contracts with customers	$	13,102	$	879	$	13,981
Other items in revenues	(23)		(144)		(167)
Total revenues of reportable segments	$	13,079	$	735	$	13,814
Intersegment revenue elimination					(120)
Total revenues					$	13,694
Three Months Ended March 31, 2021	Crude Oil		NGL		Total
Revenues from contracts with customers	$	7,946	$	801	$	8,747
Other items in revenues	(93)		(162)		(255)
Total revenues of reportable segments	$	7,853	$	639	$	8,492
Intersegment revenue elimination					(109)
Total revenues					$	8,383

Minimum Volume Commitments. We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. 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	March 31, 2022		December 31, 2021
Billed and collected	Liability	$	56	$	63
Unbilled (1)	N/A	16		16
Total		$	72	$	79

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

Contract Balances. Our contract balances consist of amounts received associated with services or sales for which we have not yet completed the related performance obligation. The following table presents the change in the liability balance associated with contracts with customers (in millions):

	Contract Liabilities
Balance at December 31, 2021	$	141
Amounts recognized as revenue	(20)
Additions	16
Balance at March 31, 2022	$	137

Remaining Performance Obligations. The information below includes the amount of consideration allocated to partially and wholly unsatisfied remaining performance obligations under contracts that exist as of the end of the periods and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These arrangements include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of March 31, 2022 (in millions):

	Remainder of 2022		2023		2024		2025		2026		2027 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	132	$	174	$	158	$	134	$	87	$	379
Terminalling, storage and other agreement revenues	201		223		173		81		61		517
Total	$	333	$	397	$	331	$	215	$	148	$	896

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

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

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

•Acreage dedications;

•Buy/sell arrangements with future committed volumes;

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

•Contracts within the scope of ASC 842, Leases; and

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

Trade Accounts Receivable and Other Receivables, Net

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL. These purchasers include, but are not limited to, refiners, producers, marketing and trading companies and financial institutions. 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.

To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions and perform credit reviews of each customer to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit, credit insurance or parental guarantees. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. For a majority of these net-cash arrangements, we also enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet).

Accounts receivable from the sale of crude oil are generally settled with counterparties on the industry settlement date, which is typically in the month following the month in which the title transfers. Otherwise, we generally invoice customers within 30 days of when the products or services were provided and generally require payment within 30 days of the invoice date. We review all outstanding accounts receivable balances on a monthly basis and record our receivables net of expected credit losses. We do not write-off accounts receivable balances until we have exhausted substantially all collection efforts. At March 31, 2022 and December 31, 2021, substantially all of our trade accounts receivable were less than 30 days past their invoice date. Our expected credit losses are immaterial. 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.

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 Condensed Consolidated Balance Sheets (in millions):

	March 31, 2022		December 31, 2021
Trade accounts receivable arising from revenues from contracts with customers	$	5,496	$	4,031
Other trade accounts receivables and other receivables (1)	9,620		5,126
Impact due to contractual rights of offset with counterparties	(7,980)		(4,452)
Trade accounts receivable and other receivables, net	$	7,136	$	4,705

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

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Net Income Per Class A Share

3 Months Ended

Mar. 31, 2022

Earnings Per Share [Abstract]

Net Income Per Class A Share

Net Income Per Class A Share

Basic net income per Class A share is determined by dividing net income attributable to PAGP by the weighted average number of Class A shares outstanding during the period. Our Class B and Class C shares do not share in the earnings of the Partnership; accordingly, basic and diluted net income per Class B and Class C share has not been presented.

Diluted net income per Class A share is determined by dividing net income attributable to PAGP by the diluted weighted average number of Class A shares outstanding during the period. For purposes of calculating diluted net income per Class A share, both the net income attributable to PAGP and the diluted weighted average number of Class A shares outstanding consider the impact of possible future exchanges of (i) AAP units and the associated Class B shares into our Class A shares and (ii) Class B units of AAP (referred to herein as “AAP Management Units”) into 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. 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. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for information regarding exchanges of AAP units and AAP Management Units. PAGP LTIP awards that are deemed to be dilutive are reduced by a hypothetical share repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 18 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for information regarding PAGP LTIP awards.

On a weighted-average basis, for the three months ended March 31, 2022 and 2021, the possible exchange of 47 million and 51 million AAP units, respectively, would not have had a dilutive effect on basic net income per Class A share. For each of the three months ended March 31, 2022 and 2021, the possible exchange of less than 1 million AAP Management Units would not have had a dilutive effect on basic net income per Class A share on a weighted-average basis. For the three months ended March 31, 2022 and 2021, our PAGP LTIP awards were dilutive; however, the LTIP awards did not change the presentation of diluted weighted average Class A shares outstanding or diluted net income per Class A share.

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

	Three Months Ended March 31,
	2022		2021
Basic and Diluted Net Income per Class A Share
Net income attributable to PAGP	$	22	$	70
Basic and diluted weighted average Class A shares outstanding	194		194
Basic and diluted net income per Class A share	$	0.11	$	0.36

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Inventory, Linefill and Long-term Inventory

3 Months Ended

Mar. 31, 2022

Inventory Disclosure [Abstract]

Inventory, Linefill and Long-term Inventory

Inventory, Linefill and Long-term Inventory

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

	March 31, 2022						December 31, 2021
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	4,711	barrels	$	420	$	89.15	8,041	barrels	$	544	$	67.65
NGL	2,329	barrels	102		$	43.80	6,982	barrels	234		$	33.51
Other	N/A		5		N/A		N/A		5		N/A
Inventory subtotal			527						783
Linefill
Crude oil	15,160	barrels	872		$	57.52	15,199	barrels	862		$	56.71
NGL	1,667	barrels	47		$	28.19	1,633	barrels	45		$	27.56
Linefill subtotal			919						907
Long-term inventory
Crude oil	3,289	barrels	325		$	98.81	2,973	barrels	209		$	70.30
NGL	1,071	barrels	49		$	45.75	1,135	barrels	44		$	38.77
Long-term inventory subtotal			374						253
Total			$	1,820					$	1,943

(1)Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products.

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Debt

3 Months Ended

Mar. 31, 2022

Debt Disclosure [Abstract]

Debt

Debt

Debt consisted of the following (in millions):

	March 31, 2022		December 31, 2021
SHORT-TERM DEBT
PAA commercial paper notes, bearing a weighted-average interest rate of 0.8% (1)	$	382	$	—
PAA senior notes:
3.65% senior notes due June 2022 (2)	—		750
2.85% senior notes due January 2023	400		—
Other	118		72
Total short-term debt	900		822
LONG-TERM DEBT
PAA senior notes, net of unamortized discounts and debt issuance costs of $52 and $54, respectively	7,931		8,329
Other	55		69
Total long-term debt	7,986		8,398
Total debt (3)	$	8,886	$	9,220

(1)We classified these PAA commercial paper notes as short-term as of March 31, 2022, as these notes were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.

(2)These senior notes were redeemed on March 1, 2022.

(3)PAA’s fixed-rate senior notes had a face value of approximately $8.4 billion and $9.1 billion as of March 31, 2022 and December 31, 2021, respectively. We estimated the aggregate fair value of these notes as of March 31, 2022 and December 31, 2021 to be approximately $8.4 billion and $9.9 billion, respectively. PAA’s fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under PAA’s commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for PAA’s senior notes and commercial paper notes are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

Borrowings and Repayments

Total borrowings under the PAA credit facilities and commercial paper program for the three months ended March 31, 2022 and 2021 were approximately $5.6 billion and $14.2 billion, respectively. Total repayments under the PAA credit facilities and commercial paper program were approximately $5.2 billion and $14.8 billion for the three months ended March 31, 2022 and 2021, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.

During the three months ended March 31, 2022, PAA redeemed its 3.65%, $750 million senior notes due June 2022.

Letters of Credit

In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil and NGL. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At March 31, 2022 and December 31, 2021, we had outstanding letters of credit of $34 million and $98 million, respectively.

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Partners' Capital and Distributions

3 Months Ended

Mar. 31, 2022

Partners' Capital Notes [Abstract]

Partners' Capital and Distributions

Partners’ Capital and Distributions

Shares Outstanding

The following tables present the activity for our Class A shares, Class B shares and Class C shares:

	Class A Shares	Class B Shares	Class C Shares
Outstanding at December 31, 2021	194,192,777	46,645,514	534,596,831
Conversion of AAP Management Units (1)	—	205,024	—
Exchange Right exercises (1)	35,700	(35,700)	—
Redemption Right exercises (1)	—	(11,957)	11,957
Repurchase of common units by a subsidiary under the Common Equity Repurchase Program	—	—	(2,375,299)
Other	—	—	51,937
Outstanding at March 31, 2022	194,228,477	46,802,881	532,285,426

 

	Class A Shares	Class B Shares	Class C Shares
Outstanding at December 31, 2020	194,051,436	50,640,192	547,717,762
Conversion of AAP Management Units (1)	—	414,608	—
Exchange Right exercises (1)	46,879	(46,879)	—
Redemption Right exercises (1)	—	(229,931)	229,931
Repurchase of common units by a subsidiary under the Common Equity Repurchase Program	—	—	(350,000)
Other	—	—	25,431
Outstanding at March 31, 2021	194,098,315	50,777,990	547,623,124

(1)See Note 12 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for information regarding conversions of AAP Management Units, Exchange Rights and Redemption Rights.

Distributions

The following table details distributions to our Class A shareholders paid during or pertaining to the first three months of 2022 (in millions, except per share data):

Distribution Payment Date	Distributions to Class A Shareholders		Distributions per Class A Share
May 13, 2022 (1)	$	42	$	0.2175
February 14, 2022	$	35	$	0.1800

(1)Payable to shareholders of record at the close of business on April 29, 2022 for the period from January 1, 2022 through March 31, 2022.

Consolidated Subsidiaries

Noncontrolling Interests in Subsidiaries

As of March 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 Plains Oryx Permian Basin LLC (the “Permian JV”) and (iv) a 33% interest in Red River Pipeline Company LLC (“Red River LLC”).

Common Equity Repurchase Program

PAA repurchased 2.4 million and 0.4 million common units under the Common Equity Repurchase Program (the “Program”) through open market purchases that settled during the three months ended March 31, 2022 and 2021, respectively, for a total purchase price of $25 million and $3 million, respectively, including commissions and fees. The repurchased PAA common units were canceled immediately upon acquisition, as were the Class C shares held by PAA associated with the repurchased common units. At March 31, 2022, the remaining available capacity under the Program was $247 million. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for additional information regarding the Program.

Subsidiary Distributions

PAA Series A Preferred Unit Distributions. The following table details distributions to PAA’s Series A preferred unitholders paid during or pertaining to the first three months of 2022 (in millions, except per unit data):

	Series A Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit
May 13, 2022 (1)	$	37	$	0.525
February 14, 2022	$	37	$	0.525

(1)Payable to unitholders of record at the close of business on April 29, 2022 for the period from January 1, 2022 through March 31, 2022. At March 31, 2022, such amount was accrued as distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

PAA Series B Preferred Unit Distributions. Distributions on PAA’s Series B preferred units are payable semi-annually in arrears on the 15th day of May and November. The following table details distributions paid to PAA’s Series B preferred unitholders (in millions, except per unit data):

	Series B Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit
May 16, 2022 (1)	$	24.5	$	30.625

(1)Payable to unitholders of record at the close of business on May 2, 2022 for the period from November 15, 2021 through May 14, 2022.

At March 31, 2022, approximately $18 million of accrued distributions payable to PAA’s Series B preferred unitholders was included in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

PAA Common Unit Distributions. The following table details distributions to PAA’s common unitholders paid during or pertaining to the first three months of 2022 (in millions, except per unit data):

	Distributions						Cash Distribution per Common Unit
	Common Unitholders				Total Cash Distribution
Distribution Payment Date	Public		AAP
May 13, 2022 (1)	$	100	$	53	$	153	$	0.2175
February 14, 2022	$	84	$	43	$	127	$	0.1800

(1)Payable to unitholders of record at the close of business on April 29, 2022 for the period from January 1, 2022 through March 31, 2022.

AAP Distributions. The following table details the distributions to AAP’s partners paid during or pertaining to the first three months of 2022 from distributions received from PAA (in millions):

	Distributions to AAP’s Partners
Distribution Payment Date	Noncontrolling Interests		PAGP		Total Cash Distribution
May 13, 2022 (1)	$	11	$	42	$	53
February 14, 2022	$	8	$	35	$	43

(1)Payable to unitholders of record at the close of business on April 29, 2022 for the period from January 1, 2022 through March 31, 2022.

Other Distributions. During the three months ended March 31, 2022, we paid distributions of $54 million and $5 million to noncontrolling interests in the Permian JV and Red River LLC, respectively.

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Derivatives and Risk Management Activities

3 Months Ended

Mar. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives and Risk Management Activities

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. 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. 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. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. At the inception of the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions. Throughout the hedging relationship, retrospective and prospective hedge effectiveness is assessed on a qualitative basis.

We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives designated as cash flow hedges, changes in fair value are deferred in AOCI and recognized in earnings in the periods during which the underlying hedged transactions are recognized in earnings. Derivatives that are not designated in a hedging relationship for accounting purposes are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Condensed Consolidated Statements of Cash Flows.

Our financial derivatives, used for hedging risk, are governed through ISDA master agreements and clearing brokerage agreements. These agreements include stipulations regarding the right of set off in the event that we or our counterparty default on performance obligations. If a default were to occur, both parties have the right to net amounts payable and receivable into a single net settlement between parties.

At March 31, 2022 and December 31, 2021, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our exchange-traded derivatives transacted through a clearing brokerage account, as described below, we do not require our non-cleared derivative counterparties to post collateral with us.

Commodity Price Risk Hedging

Our core business activities involve certain commodity price-related risks that we manage in various ways, including through the use of derivative instruments. 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. We use derivatives to manage the associated risks and to optimize profits. As of March 31, 2022, net derivative positions related to these activities included:

•A net long position of 6.6 million barrels associated with our crude oil purchases, which was unwound ratably during April 2022 to match monthly average pricing.

•A net short time spread position of 5.3 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through May 2023.

•A net crude oil basis spread position of 1.2 million barrels at multiple locations through November 2023. These derivatives allow us to lock in grade and location basis differentials.

•A net short position of 11.0 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. Additionally, we purchase NGL mix for fractionation and sell the resulting individual specification products (including ethane, propane, butane and condensate). In conjunction with these activities, we hedge the price risk associated with the purchase of the natural gas and the subsequent sale of the individual specification products. The following table summarizes our open derivative positions utilized to hedge the price risk associated with anticipated purchases and sales related to our natural gas processing and NGL fractionation activities as of March 31, 2022:

	Notional Volume
	(Short)/Long	Remaining Tenor
Natural gas purchases	82.6 Bcf	December 2024
Propane sales	(15.5) MMbls	December 2024
Butane sales	(3.8) MMbls	December 2024
Condensate sales	(1.5) MMbls	December 2024
Fuel gas requirements (1)	8.8 Bcf	December 2023
Power supply requirements (1)	0.5 TWh	December 2023

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

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

Our commodity derivatives are not designated in a hedging relationship for accounting purposes; as such, changes in the fair value are reported in earnings. The following table summarizes the impact of our commodity derivatives recognized in earnings (in millions):

	Three Months Ended March 31,
	2022		2021
Product sales revenues	$	(213)	$	(314)
Field operating costs	13		39
Net loss from commodity derivative activity	$	(200)	$	(275)

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through clearing brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. The following table provides the components of our net broker receivable (in millions):

	March 31, 2022		December 31, 2021
Initial margin	$	102	$	133
Variation margin posted	296		173
Letters of credit	(25)		(47)
Net broker receivable	$	373	$	259

The following table reflects the Condensed Consolidated Balance Sheet line items that include the fair values of our commodity derivative assets and liabilities and the effect of the collateral netting. Such amounts are presented on a gross basis, before the effects of counterparty netting. However, we have elected to present our commodity derivative assets and liabilities with the same counterparty on a net basis on our Condensed Consolidated Balance Sheet when the legal right of offset exists. Amounts in the table below are presented in millions.

	March 31, 2022								December 31, 2021
					Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet						Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet
	Commodity Derivatives								Commodity Derivatives
	Assets		Liabilities						Assets		Liabilities
Derivative Assets
Other current assets	$	230	$	(331)	$	373	$	272	$	90	$	(210)	$	259	$	139
Other long-term assets, net	12		—		—		12		3		—		—		3
Derivative Liabilities
Other current liabilities	11		(51)		—		(40)		4		(24)		—		(20)
Other long-term liabilities and deferred credits	8		(28)		—		(20)		3		(9)		—		(6)
Total	$	261	$	(410)	$	373	$	224	$	100	$	(243)	$	259	$	116

Interest Rate Risk Hedging

We use interest rate derivatives to hedge the benchmark interest rate associated with interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist of forward starting interest rate swaps and treasury locks. These derivatives are designated as cash flow hedges. As such, changes in fair value are deferred in AOCI and are reclassified to interest expense as we incur the interest expense associated with the underlying debt.

The following table summarizes the terms of our outstanding interest rate derivatives as of March 31, 2022 (notional amounts in millions):

Hedged Transaction	Number and Types of Derivatives Employed	Notional Amount		Expected Termination Date	Average Rate Locked		Accounting Treatment
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	6/15/2023	1.38	%	Cash flow hedge
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	6/14/2024	0.73	%	Cash flow hedge

As of March 31, 2022, there was a net loss of $173 million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with interest expense accruals associated with underlying debt instruments. We estimate that substantially all of the remaining deferred loss will be reclassified to earnings through 2054 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of March 31, 2022; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

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

	Three Months Ended March 31,
	2022		2021
Interest rate derivatives, net	$	32	$	68

At March 31, 2022, the net fair value of our interest rate hedges, which were included in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet, totaled $97 million. 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 Condensed 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 expense, net” in our Condensed Consolidated Statement of Operations. For the three months ended March 31, 2022 and 2021, we recognized losses of $44 million and $67 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 Condensed Consolidated Balance Sheets, totaled $44 million and less than $1 million at March 31, 2022 and December 31, 2021, respectively. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for additional information regarding the PAA Series A preferred units and the Preferred Distribution Rate Reset Option.

Recurring Fair Value Measurements

Derivative Financial Assets and Liabilities

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions):

	Fair Value as of March 31, 2022								Fair Value as of December 31, 2021
Recurring Fair Value Measures (1)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivatives	$	(76)	$	(73)	$	—	$	(149)	$	(17)	$	(124)	$	(2)	$	(143)
Interest rate derivatives	—		97		—		97		—		65		—		65
Preferred Distribution Rate Reset Option and Other	—		—		(44)		(44)		—		—		—		—
Total net derivative asset/(liability)	$	(76)	$	24	$	(44)	$	(96)	$	(17)	$	(59)	$	(2)	$	(78)

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

Level 1

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

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. In addition, it includes certain physical commodity contracts. The fair values of these derivatives are corroborated with market observable inputs.

Level 3

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 PAA’s 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 Condensed Consolidated Statements of Operations as Product sales revenues.

The fair value of the embedded derivative feature contained in PAA’s partnership agreement is based on a valuation model that estimates the fair value of the PAA Series A preferred units with and without the Preferred Distribution Rate Reset Option. This model contains inputs, including PAA’s 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.

Rollforward of Level 3 Net Asset/(Liability)

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

	Three Months Ended March 31,
	2022		2021
Beginning Balance	$	(2)	$	(29)
Net losses for the period included in earnings	(44)		(67)
Settlements	2		4
Ending Balance	$	(44)	$	(92)
Change in unrealized losses included in earnings relating to Level 3 derivatives still held at the end of the period	$	(44)	$	(67)

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Related Party Transactions

3 Months Ended

Mar. 31, 2022

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

See Note 17 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for a complete discussion of related parties, including the determination of our related parties and nature of involvement with such related parties.

During the three months ended March 31, 2022 and 2021, we recognized sales and transportation revenues, purchased petroleum products and utilized transportation and storage services from our related parties. These transactions were conducted at posted tariff rates or prices that we believe approximate market.

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

	Three Months Ended March 31,
	2022		2021
Revenues from related parties	$	12	$	7
Purchases and related costs from related parties	$	97	$	90

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

	March 31, 2022		December 31, 2021
Trade accounts receivable and other receivables, net from related parties (1)	$	56	$	41
Trade accounts payable to related parties (1) (2)	$	75	$	72

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

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

3 Months Ended

Mar. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Loss Contingencies — General

To the extent we are able to assess the likelihood of a negative outcome for a contingency, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred.

We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss.

Legal Proceedings — General

In the ordinary course of business, we are involved in various legal proceedings, including those arising from regulatory and environmental matters. In connection with determining the probability of loss associated with such legal proceedings and whether any potential losses associated therewith are estimable, we take into account what we believe to be all relevant known facts and circumstances, and what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing agreements, laws and regulations. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully protect us from losses arising from current or future legal proceedings. Accordingly, we can provide no assurance that the outcome of the various legal proceedings that we are currently involved in, or will become involved with in the future, will not, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

Environmental — General

We currently own or lease, and in the past have owned and leased, properties where hazardous liquids, including hydrocarbons, are or have been handled. These properties and the hazardous liquids or associated wastes disposed thereon may be subject to the U.S. federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, and the U.S. federal Resource Conservation and Recovery Act, as amended, as well as state and Canadian federal and provincial laws and regulations. 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.

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. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. We also may discover environmental impacts from past releases that were previously unidentified. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. We record receivables for amounts we believe are recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery.

Environmental expenditures that pertain to current operations or to future revenues are expensed or capitalized consistent with our capitalization policy for property and equipment. Expenditures that result from the remediation of an existing condition caused by past operations and that do not contribute to current or future profitability are expensed.

At March 31, 2022, our estimated undiscounted reserve for environmental liabilities (excluding liabilities related to the Line 901 incident, as discussed further below) totaled $59 million, of which $9 million was classified as short-term and $50 million was classified as long-term. At December 31, 2021, our estimated undiscounted reserve for environmental liabilities (excluding liabilities related to the Line 901 incident) totaled $57 million, of which $11 million was classified as short-term and $46 million was classified as long-term. Such short-term liabilities are reflected in “Other current liabilities” and long-term liabilities are reflected in “Other long-term liabilities and deferred credits” on our Condensed Consolidated Balance Sheets. At both March 31, 2022 and December 31, 2021, we had recorded receivables (excluding receivables related to the Line 901 incident) totaling $11 million, for amounts probable of recovery under insurance and from third parties under indemnification agreements, $1 million of which for each period is reflected in “Other long-term assets, net” and the remainder is reflected in “Trade accounts receivable and other receivables, net” on our Condensed Consolidated Balance Sheets. 

In some cases, the actual cash expenditures associated with these liabilities may not occur for three years or longer. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing or future legal claims giving rise to additional liabilities. Therefore, although we believe that the reserve is adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of the reserve and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

Specific Legal, Environmental or Regulatory Matters

Line 901 Incident. In May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. A portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert. Following the release, we shut down the pipeline and initiated our emergency response plan. A Unified Command, which included the United States Coast Guard, the EPA, the State of California Department of Fish and Wildlife (“CDFW”), the California Office of Spill Prevention and Response and the Santa Barbara Office of Emergency Management, was established for the response effort. Clean-up and remediation operations with respect to impacted shoreline and other areas has been determined by the Unified Command to be complete, and the Unified Command has been dissolved. Our estimate of the amount of oil spilled, based on relevant facts, data and information, and as set forth in the Consent Decree described below, is approximately 2,934 barrels; of this amount, we estimate that 598 barrels reached the Pacific Ocean.

As a result of the Line 901 incident, several governmental agencies and regulators initiated investigations into the Line 901 incident, various claims have been made against us and a number of lawsuits have been filed against us, the majority of which have been resolved. Set forth below is a brief summary of actions and matters that are currently pending or recently resolved:

As the “responsible party” for the Line 901 incident we are liable for various costs and for certain natural resource damages under the Oil Pollution Act. In this regard, following the Line 901 incident, we entered into a cooperative Natural Resource Damage Assessment (“NRDA”) process with the federal and state agencies designated or authorized by law to act as trustees for the natural resources of the United States and the State of California (collectively, the “Trustees”). Additionally, various government agencies sought to collect civil fines and penalties under applicable state and federal regulations. On March 13, 2020, the United States and the People of the State of California filed a civil complaint against Plains All American Pipeline, L.P. and Plains Pipeline L.P. along with a pre-negotiated settlement agreement in the form of a Consent Decree (the “Consent Decree”) that was signed by the United States Department of Justice, Environmental and Natural Resources Division, the United States Department of Transportation, Pipeline and Hazardous Materials Safety Administration, the EPA, CDFW, the California Department of Parks and Recreation, the California State Lands Commission, the California Department of Forestry and Fire Protection’s Office of the State Fire Marshal, Central Coast Regional Water Quality Control Board, and Regents of the University of California. The Consent Decree was approved and entered by the Federal District Court for the Central District of California on October 14, 2020. Pursuant to the terms of the Consent Decree, Plains paid $24 million in civil penalties and $22.325 million as compensation for injuries to, destruction of, loss of, or loss of use of natural resources resulting from the Line 901 incident. The Consent Decree 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.

Following an investigation and grand jury proceedings, in May of 2016, PAA was charged by a California state grand jury, pursuant to an indictment filed in California Superior Court, Santa Barbara County (the “May 2016 Indictment”), with alleged violations of California law in connection with the Line 901 incident. Fifteen charges from the May 2016 Indictment were the subject of a jury trial in California Superior Court in Santa Barbara County, and the jury returned a verdict on September 7, 2018, pursuant to which we were (i) found guilty on one felony discharge count and eight misdemeanor counts (which included one reporting count, one strict liability discharge count and six strict liability animal takings counts) and (ii) found not guilty on one strict liability animal takings count. The remaining counts were subsequently dismissed by the Court. On April 25, 2019, PAA was sentenced to pay fines and penalties in the aggregate amount of just under $3.35 million for the convictions covered by the September 2018 jury verdict (the “2019 Sentence”). The fines and penalties imposed in connection with the 2019 Sentence have been paid. In September 2021, the Superior Court concluded a series of hearings on the issue of whether there were any “direct victims” of the spill that are entitled to restitution under applicable criminal law. Through a series of final orders issued at the trial court level and without affecting any rights of the claimants under civil law, the Court dismissed the vast majority of the claims and ruled that the claimants were not entitled to restitution under applicable criminal laws. The Court did award an aggregate amount of less than $150,000 to a handful of claimants and we settled with approximately 40 claimants before the hearings for aggregate consideration that is not material. The prosecution and certain separately represented claimants have appealed the Court’s rulings.

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: (i) commercial fishermen who landed fish in certain specified fishing blocks in the waters off the coast of Southern California or persons or businesses who resold commercial seafood caught in those areas; and (ii) owners and lessees of residential beachfront properties, or properties with a private easement to a beach, where plaintiffs claim oil from the spill washed up. In order to fully and finally resolve all claims and litigation for both classes, we have reached an agreement in principle to settle this case in exchange for a payment of $230 million (the “Class Action Settlement”). The Class Action Settlement is subject to negotiation of final documentation and approval of the trial court. 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, after various other unitholder derivative lawsuits were either dismissed or consolidated, one proceeding remains pending in Delaware Chancery Court. Generally, the plaintiffs in the remaining derivative lawsuit claim that our 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 court approval, we intend to effect notice to all PAA unitholders by filing a Current Report on Form 8-K with the SEC. The key terms of the Derivative Settlement include a payment of Plaintiff’s attorneys’ fees by our insurers in the amount of approximately $2.0 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.

We 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. The following lawsuits remain: (i) a lawsuit pending in the United States District Court for the Central District of California 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 cost 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.

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 March 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 $725 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 Condensed Consolidated Statements of Operations. This estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the resolution of certain third party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and excluding future claims and lawsuits and (ii) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. Our estimate does not include any lost revenue associated with the shutdown of Line 901 or 903 and does not include any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, with respect to potential losses that we regard as only reasonably possible or remote, we have made assumptions regarding the strength of our legal position based on our assessment of the relevant facts and applicable law and precedent; if our assumptions regarding such matters turn out to be inaccurate (i.e., we are found to be liable under circumstances where we regard the likelihood of loss as being only reasonably possible or remote), we could be responsible for significant costs and expenses that are not currently included in our estimates and accruals. In addition, for any potential losses that we regard as probable and for which we have accrued an estimate of the potential losses, our estimates regarding damages, legal fees, court costs and interest could turn out to be inaccurate and the actual losses we incur could be significantly higher than the amounts included in our estimates and accruals. Also, the amount of time it takes for us to resolve all of the current and future lawsuits and claims that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated. Accordingly, our assumptions and estimates may turn out to be inaccurate and our total costs could turn out to be materially higher; therefore, we can provide no assurance that we will not have to accrue significant additional costs in the future with respect to the Line 901 incident.

As of March 31, 2022, we had a remaining undiscounted gross liability of $335 million related to this event, which aggregate amount is reflected in “Trade accounts payable” and “Other current liabilities” on our Condensed Consolidated Balance Sheet. We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such environmental liabilities; however, after giving effect to the settlements described above and assuming full collection of costs that we believe are probable of recovery from insurance providers, net of deductibles, we will reach the limit of our $500 million 2015 insurance program applicable to the Line 901 incident. Through March 31, 2022, we had collected, subject to customary reservations, approximately $260 million out of the $500 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of March 31, 2022, we have recognized a receivable of approximately $240 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 Condensed 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. 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.

Insurance

Pipelines, terminals, trucks or other facilities or equipment may experience damage as a result of an accident, natural disaster, terrorist attack, cyber event or other event. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. Consistent with insurance coverage generally available in the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences. We maintain various types and varying levels of insurance coverage to cover our operations and properties, and we self-insure certain risks, including gradual pollution, cybersecurity and named windstorms. 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. While we strive to maintain adequate insurance coverage, our actual costs may exceed our coverage levels and insurance will not cover many types of interruptions that might occur, will not cover amounts up to applicable deductibles and will not cover all risks associated with certain of our assets and operations. With respect to our insurance coverage, our policies are subject to deductibles and retention levels that we consider reasonable and not excessive. Additionally, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable. As a result, we may elect to self-insure or utilize higher deductibles in certain other insurance programs. In addition, although we believe that we have established adequate reserves and liquidity to the extent such risks are not insured, costs incurred in excess of these reserves may be higher or we may not receive insurance proceeds in a timely manner, which may potentially have a material adverse effect on our financial conditions, results of operations or cash flows.

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Segment Information

3 Months Ended

Mar. 31, 2022

Segment Reporting [Abstract]

Segment Information

Segment Information

During the fourth quarter of 2021, we effected changes in the primary financial information provided to our CODM 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. All segment data and related disclosures for earlier periods presented herein have been recast to reflect the new segment reporting structure. Our CODM evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below) and maintenance capital. During the fourth quarter of 2021, we modified our definition of Segment Adjusted EBITDA to exclude amounts attributable to noncontrolling interests in consolidated joint venture entities. 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 venture entities for earlier periods presented herein have been recast to reflect this modification. See Note 20 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for additional information regarding the modifications to our segment reporting and for a full discussion of our basis for segmentation and performance measures.

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 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”).

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

	Crude Oil		NGL		Intersegment Revenues Elimination		Total
Three Months Ended March 31, 2022
Revenues (1):
Product sales	$	12,811	$	682	$	(112)	$	13,381
Services	268		53		(8)		313
Total revenues	$	13,079	$	735	$	(120)	$	13,694
Equity earnings in unconsolidated entities	$	97	$	—			$	97
Segment Adjusted EBITDA	$	453	$	161			$	614
Maintenance capital expenditures	$	19	$	8			$	27
Three Months Ended March 31, 2021
Revenues (1):
Product sales	$	7,586	$	600	$	(103)	$	8,083
Services	267		39		(6)		300
Total revenues	$	7,853	$	639	$	(109)	$	8,383
Equity earnings in unconsolidated entities	$	88	$	—			$	88
Segment Adjusted EBITDA	$	474	$	69			$	543
Maintenance capital expenditures	$	28	$	7			$	35

(1)Segment revenues include intersegment amounts that are eliminated in Purchases and related costs. Intersegment activities are conducted at posted tariff rates where applicable, or otherwise at rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated.

Segment Adjusted EBITDA Reconciliation

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

 

	Three Months Ended March 31,
	2022		2021
Segment Adjusted EBITDA	$	614	$	543
Adjustments: (1)
Depreciation and amortization of unconsolidated entities (2)	(20)		(20)
Gains/(losses) from derivative activities and inventory valuation adjustments (3)	(88)		198
Long-term inventory costing adjustments (4)	92		41
Deficiencies under minimum volume commitments, net (5)	(6)		32
Equity-indexed compensation expense (6)	(7)		(5)
Net gain on foreign currency revaluation (7)	2		1
Line 901 incident (8)	(85)		—
Adjusted EBITDA attributable to noncontrolling interests in consolidated joint ventures (9)	76		3
Unallocated general and administrative expenses (10)	(1)		(1)
Depreciation and amortization	(231)		(178)
Gains/(losses) on asset sales and asset impairments, net	42		(2)
Interest expense, net	(107)		(107)
Other expense, net	(37)		(60)
Income before tax	244		445
Income tax expense	(35)		(53)
Net income	209		392
Net income attributable to noncontrolling interests	(187)		(322)
Net income attributable to PAGP	$	22	$	70

(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.

(3)We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify differences in the timing of earnings from the derivative instruments and the underlying transactions and exclude the related gains and losses in determining Segment Adjusted EBITDA such that the earnings from the derivative instruments and the underlying transactions impact Segment Adjusted EBITDA in the same period. In addition, we exclude gains and losses on derivatives that are related to (i) investing activities, such as the purchase of linefill, and (ii) purchases of long-term inventory. We also exclude the impact of corresponding inventory valuation adjustments, as applicable.

(4)We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). 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. 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. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to Segment Adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.

(6)Our total equity-indexed compensation expense includes expense associated with awards that will be settled in PAA common units and awards that will be settled in cash. The awards that will be settled in PAA common units are included in PAA’s diluted net income per unit calculation when the applicable performance criteria have been met. We exclude compensation expense associated with these awards in determining Segment Adjusted EBITDA as the dilutive impact of the outstanding awards is included in PAA’s diluted net income per unit calculation, as applicable. The portion of compensation expense associated with awards that will settle in cash is not excluded in determining Segment Adjusted EBITDA. See Note 18 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for a discussion regarding our equity-indexed compensation plans.

(7)During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. These gains and losses are not integral to our core operating performance and were therefore excluded in determining Segment Adjusted EBITDA.

(8)Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. See Note 10 for additional information regarding the Line 901 incident.

(9)Reflects amounts attributable to noncontrolling interests in the Permian JV and Red River LLC.

(10)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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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

Restricted Cash

Restricted CashRestricted 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.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

Except as discussed below and in our 2021 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the three months ended March 31, 2022 that are of significance or potential significance to us.

In August 2020, the FASB issued ASU 2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity, by eliminating two of the three models that require separate accounting for embedded conversion features and the settlement assessment that entities are required to perform to determine whether a contract qualifies for equity classification. This guidance is effective for interim and annual periods beginning after December 15, 2021, with early adoption permitted. We adopted this guidance effective January 1, 2022, and our adoption did not have a material impact on our financial position, results of operations or cash flows.

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Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

Reconciliation of cash and cash equivalents and restricted cash

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

	March 31, 2022		December 31, 2021
Cash and cash equivalents	$	117	$	452
Restricted cash (1)	4		4
Total cash and cash equivalents and restricted cash	$	121	$	456

(1)Included in “Other current assets” on our Condensed Consolidated Balance Sheets.

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Revenues and Accounts Receivable (Tables)

3 Months Ended

Mar. 31, 2022

Revenue from Contract with Customer [Abstract]

Disaggregation of revenue

The following tables present our revenues from contracts with customers disaggregated by segment and type of activity (in millions):

	Three Months Ended March 31,
	2022		2021
Crude Oil segment revenues from contracts with customers
Sales	$	12,857	$	7,726
Transportation	155		90
Terminalling, Storage and Other	90		130
Total Crude Oil segment revenues from contracts with customers	$	13,102	$	7,946

	Three Months Ended March 31,
	2022		2021
NGL segment revenues from contracts with customers
Sales	$	845	$	772
Transportation	9		7
Terminalling, Storage and Other	25		22
Total NGL segment revenues from contracts with customers	$	879	$	801

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

Three Months Ended March 31, 2022	Crude Oil		NGL		Total
Revenues from contracts with customers	$	13,102	$	879	$	13,981
Other items in revenues	(23)		(144)		(167)
Total revenues of reportable segments	$	13,079	$	735	$	13,814
Intersegment revenue elimination					(120)
Total revenues					$	13,694
Three Months Ended March 31, 2021	Crude Oil		NGL		Total
Revenues from contracts with customers	$	7,946	$	801	$	8,747
Other items in revenues	(93)		(162)		(255)
Total revenues of reportable segments	$	7,853	$	639	$	8,492
Intersegment revenue elimination					(109)
Total revenues					$	8,383

Contract with customer, counterparty deficiencies

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	March 31, 2022		December 31, 2021
Billed and collected	Liability	$	56	$	63
Unbilled (1)	N/A	16		16
Total		$	72	$	79

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

Contracts with customers, change in asset and liability balance

The following table presents the change in the liability balance associated with contracts with customers (in millions):

	Contract Liabilities
Balance at December 31, 2021	$	141
Amounts recognized as revenue	(20)
Additions	16
Balance at March 31, 2022	$	137

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 Condensed Consolidated Balance Sheets (in millions):

	March 31, 2022		December 31, 2021
Trade accounts receivable arising from revenues from contracts with customers	$	5,496	$	4,031
Other trade accounts receivables and other receivables (1)	9,620		5,126
Impact due to contractual rights of offset with counterparties	(7,980)		(4,452)
Trade accounts receivable and other receivables, net	$	7,136	$	4,705

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

Remaining performance obligations

The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of March 31, 2022 (in millions):

	Remainder of 2022		2023		2024		2025		2026		2027 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	132	$	174	$	158	$	134	$	87	$	379
Terminalling, storage and other agreement revenues	201		223		173		81		61		517
Total	$	333	$	397	$	331	$	215	$	148	$	896

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

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Net Income Per Class A Share (Tables)

3 Months Ended

Mar. 31, 2022

Earnings Per Share [Abstract]

Calculation of basic and diluted net income per Class A share

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

	Three Months Ended March 31,
	2022		2021
Basic and Diluted Net Income per Class A Share
Net income attributable to PAGP	$	22	$	70
Basic and diluted weighted average Class A shares outstanding	194		194
Basic and diluted net income per Class A share	$	0.11	$	0.36

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Inventory, Linefill and Long-term Inventory (Tables)

3 Months Ended

Mar. 31, 2022

Inventory Disclosure [Abstract]

Schedule of inventory

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

	March 31, 2022						December 31, 2021
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	4,711	barrels	$	420	$	89.15	8,041	barrels	$	544	$	67.65
NGL	2,329	barrels	102		$	43.80	6,982	barrels	234		$	33.51
Other	N/A		5		N/A		N/A		5		N/A
Inventory subtotal			527						783
Linefill
Crude oil	15,160	barrels	872		$	57.52	15,199	barrels	862		$	56.71
NGL	1,667	barrels	47		$	28.19	1,633	barrels	45		$	27.56
Linefill subtotal			919						907
Long-term inventory
Crude oil	3,289	barrels	325		$	98.81	2,973	barrels	209		$	70.30
NGL	1,071	barrels	49		$	45.75	1,135	barrels	44		$	38.77
Long-term inventory subtotal			374						253
Total			$	1,820					$	1,943

(1)Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products.

Schedule of linefill and long-term inventory

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

	March 31, 2022						December 31, 2021
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	4,711	barrels	$	420	$	89.15	8,041	barrels	$	544	$	67.65
NGL	2,329	barrels	102		$	43.80	6,982	barrels	234		$	33.51
Other	N/A		5		N/A		N/A		5		N/A
Inventory subtotal			527						783
Linefill
Crude oil	15,160	barrels	872		$	57.52	15,199	barrels	862		$	56.71
NGL	1,667	barrels	47		$	28.19	1,633	barrels	45		$	27.56
Linefill subtotal			919						907
Long-term inventory
Crude oil	3,289	barrels	325		$	98.81	2,973	barrels	209		$	70.30
NGL	1,071	barrels	49		$	45.75	1,135	barrels	44		$	38.77
Long-term inventory subtotal			374						253
Total			$	1,820					$	1,943

(1)Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products.

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Debt (Tables)

3 Months Ended

Mar. 31, 2022

Debt Disclosure [Abstract]

Schedule of debt

Debt consisted of the following (in millions):

	March 31, 2022		December 31, 2021
SHORT-TERM DEBT
PAA commercial paper notes, bearing a weighted-average interest rate of 0.8% (1)	$	382	$	—
PAA senior notes:
3.65% senior notes due June 2022 (2)	—		750
2.85% senior notes due January 2023	400		—
Other	118		72
Total short-term debt	900		822
LONG-TERM DEBT
PAA senior notes, net of unamortized discounts and debt issuance costs of $52 and $54, respectively	7,931		8,329
Other	55		69
Total long-term debt	7,986		8,398
Total debt (3)	$	8,886	$	9,220

(1)We classified these PAA commercial paper notes as short-term as of March 31, 2022, as these notes were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.

(2)These senior notes were redeemed on March 1, 2022.

(3)PAA’s fixed-rate senior notes had a face value of approximately $8.4 billion and $9.1 billion as of March 31, 2022 and December 31, 2021, respectively. We estimated the aggregate fair value of these notes as of March 31, 2022 and December 31, 2021 to be approximately $8.4 billion and $9.9 billion, respectively. PAA’s fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under PAA’s commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for PAA’s senior notes and commercial paper notes are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

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Partners' Capital and Distributions (Tables)

3 Months Ended

Mar. 31, 2022

Partners' Capital and Distributions

Schedule of activity for Class A shares, Class B shares and Class C shares

The following tables present the activity for our Class A shares, Class B shares and Class C shares:

	Class A Shares	Class B Shares	Class C Shares
Outstanding at December 31, 2021	194,192,777	46,645,514	534,596,831
Conversion of AAP Management Units (1)	—	205,024	—
Exchange Right exercises (1)	35,700	(35,700)	—
Redemption Right exercises (1)	—	(11,957)	11,957
Repurchase of common units by a subsidiary under the Common Equity Repurchase Program	—	—	(2,375,299)
Other	—	—	51,937
Outstanding at March 31, 2022	194,228,477	46,802,881	532,285,426

 

	Class A Shares	Class B Shares	Class C Shares
Outstanding at December 31, 2020	194,051,436	50,640,192	547,717,762
Conversion of AAP Management Units (1)	—	414,608	—
Exchange Right exercises (1)	46,879	(46,879)	—
Redemption Right exercises (1)	—	(229,931)	229,931
Repurchase of common units by a subsidiary under the Common Equity Repurchase Program	—	—	(350,000)
Other	—	—	25,431
Outstanding at March 31, 2021	194,098,315	50,777,990	547,623,124

(1)See Note 12 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for information regarding conversions of AAP Management Units, Exchange Rights and Redemption Rights.

AAP

Partners' Capital and Distributions

Schedule of distributions

The following table details the distributions to AAP’s partners paid during or pertaining to the first three months of 2022 from distributions received from PAA (in millions):

	Distributions to AAP’s Partners
Distribution Payment Date	Noncontrolling Interests		PAGP		Total Cash Distribution
May 13, 2022 (1)	$	11	$	42	$	53
February 14, 2022	$	8	$	35	$	43

(1)Payable to unitholders of record at the close of business on April 29, 2022 for the period from January 1, 2022 through March 31, 2022.

Class A Shares

Partners' Capital and Distributions

Schedule of distributions

The following table details distributions to our Class A shareholders paid during or pertaining to the first three months of 2022 (in millions, except per share data):

Distribution Payment Date	Distributions to Class A Shareholders		Distributions per Class A Share
May 13, 2022 (1)	$	42	$	0.2175
February 14, 2022	$	35	$	0.1800

(1)Payable to shareholders of record at the close of business on April 29, 2022 for the period from January 1, 2022 through March 31, 2022.

Series A Preferred Units | PAA

Partners' Capital and Distributions

Schedule of distributions

The following table details distributions to PAA’s Series A preferred unitholders paid during or pertaining to the first three months of 2022 (in millions, except per unit data):

	Series A Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit
May 13, 2022 (1)	$	37	$	0.525
February 14, 2022	$	37	$	0.525

(1)Payable to unitholders of record at the close of business on April 29, 2022 for the period from January 1, 2022 through March 31, 2022. At March 31, 2022, such amount was accrued as distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

Series B Preferred Units | PAA

Partners' Capital and Distributions

Schedule of distributions

The following table details distributions paid to PAA’s Series B preferred unitholders (in millions, except per unit data):

	Series B Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit
May 16, 2022 (1)	$	24.5	$	30.625

(1)Payable to unitholders of record at the close of business on May 2, 2022 for the period from November 15, 2021 through May 14, 2022.

Common Units | PAA

Partners' Capital and Distributions

Schedule of distributions

The following table details distributions to PAA’s common unitholders paid during or pertaining to the first three months of 2022 (in millions, except per unit data):

	Distributions						Cash Distribution per Common Unit
	Common Unitholders				Total Cash Distribution
Distribution Payment Date	Public		AAP
May 13, 2022 (1)	$	100	$	53	$	153	$	0.2175
February 14, 2022	$	84	$	43	$	127	$	0.1800

(1)Payable to unitholders of record at the close of business on April 29, 2022 for the period from January 1, 2022 through March 31, 2022.

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Derivatives and Risk Management Activities (Tables)

3 Months Ended

Mar. 31, 2022

Derivatives and Risk Management Activities

Impact of derivatives recognized in earnings

The following table summarizes the impact of our commodity derivatives recognized in earnings (in millions):

	Three Months Ended March 31,
	2022		2021
Product sales revenues	$	(213)	$	(314)
Field operating costs	13		39
Net loss from commodity derivative activity	$	(200)	$	(275)

Schedule of net broker receivable/(payable)

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

	March 31, 2022		December 31, 2021
Initial margin	$	102	$	133
Variation margin posted	296		173
Letters of credit	(25)		(47)
Net broker receivable	$	373	$	259

Summary of derivative assets and liabilities on condensed consolidated balance sheets on a gross basis

The following table reflects the Condensed Consolidated Balance Sheet line items that include the fair values of our commodity derivative assets and liabilities and the effect of the collateral netting. Such amounts are presented on a gross basis, before the effects of counterparty netting. However, we have elected to present our commodity derivative assets and liabilities with the same counterparty on a net basis on our Condensed Consolidated Balance Sheet when the legal right of offset exists. Amounts in the table below are presented in millions.

	March 31, 2022								December 31, 2021
					Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet						Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet
	Commodity Derivatives								Commodity Derivatives
	Assets		Liabilities						Assets		Liabilities
Derivative Assets
Other current assets	$	230	$	(331)	$	373	$	272	$	90	$	(210)	$	259	$	139
Other long-term assets, net	12		—		—		12		3		—		—		3
Derivative Liabilities
Other current liabilities	11		(51)		—		(40)		4		(24)		—		(20)
Other long-term liabilities and deferred credits	8		(28)		—		(20)		3		(9)		—		(6)
Total	$	261	$	(410)	$	373	$	224	$	100	$	(243)	$	259	$	116

Net unrealized gain/(loss) recognized in AOCI for derivatives

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

	Three Months Ended March 31,
	2022		2021
Interest rate derivatives, net	$	32	$	68

Schedule of derivative financial assets and liabilities accounted for at fair value on a recurring basis, by level within the fair value hierarchy

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions):

	Fair Value as of March 31, 2022								Fair Value as of December 31, 2021
Recurring Fair Value Measures (1)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivatives	$	(76)	$	(73)	$	—	$	(149)	$	(17)	$	(124)	$	(2)	$	(143)
Interest rate derivatives	—		97		—		97		—		65		—		65
Preferred Distribution Rate Reset Option and Other	—		—		(44)		(44)		—		—		—		—
Total net derivative asset/(liability)	$	(76)	$	24	$	(44)	$	(96)	$	(17)	$	(59)	$	(2)	$	(78)

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

Reconciliation of changes in fair value of derivatives classified as Level 3

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

	Three Months Ended March 31,
	2022		2021
Beginning Balance	$	(2)	$	(29)
Net losses for the period included in earnings	(44)		(67)
Settlements	2		4
Ending Balance	$	(44)	$	(92)
Change in unrealized losses included in earnings relating to Level 3 derivatives still held at the end of the period	$	(44)	$	(67)

Commodity derivatives

Derivatives and Risk Management Activities

Summary of open derivative positions

The following table summarizes our open derivative positions utilized to hedge the price risk associated with anticipated purchases and sales related to our natural gas processing and NGL fractionation activities as of March 31, 2022:

	Notional Volume
	(Short)/Long	Remaining Tenor
Natural gas purchases	82.6 Bcf	December 2024
Propane sales	(15.5) MMbls	December 2024
Butane sales	(3.8) MMbls	December 2024
Condensate sales	(1.5) MMbls	December 2024
Fuel gas requirements (1)	8.8 Bcf	December 2023
Power supply requirements (1)	0.5 TWh	December 2023

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

Interest rate derivatives

Derivatives and Risk Management Activities

Schedule of terms of outstanding interest rate derivatives

The following table summarizes the terms of our outstanding interest rate derivatives as of March 31, 2022 (notional amounts in millions):

Hedged Transaction	Number and Types of Derivatives Employed	Notional Amount		Expected Termination Date	Average Rate Locked		Accounting Treatment
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	6/15/2023	1.38	%	Cash flow hedge
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	6/14/2024	0.73	%	Cash flow hedge

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Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2022

Related Party Transactions [Abstract]

Schedule of related party transactions

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

	Three Months Ended March 31,
	2022		2021
Revenues from related parties	$	12	$	7
Purchases and related costs from related parties	$	97	$	90

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

	March 31, 2022		December 31, 2021
Trade accounts receivable and other receivables, net from related parties (1)	$	56	$	41
Trade accounts payable to related parties (1) (2)	$	75	$	72

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

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

3 Months Ended

Mar. 31, 2022

Segment Reporting [Abstract]

Segment financial data

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

	Crude Oil		NGL		Intersegment Revenues Elimination		Total
Three Months Ended March 31, 2022
Revenues (1):
Product sales	$	12,811	$	682	$	(112)	$	13,381
Services	268		53		(8)		313
Total revenues	$	13,079	$	735	$	(120)	$	13,694
Equity earnings in unconsolidated entities	$	97	$	—			$	97
Segment Adjusted EBITDA	$	453	$	161			$	614
Maintenance capital expenditures	$	19	$	8			$	27
Three Months Ended March 31, 2021
Revenues (1):
Product sales	$	7,586	$	600	$	(103)	$	8,083
Services	267		39		(6)		300
Total revenues	$	7,853	$	639	$	(109)	$	8,383
Equity earnings in unconsolidated entities	$	88	$	—			$	88
Segment Adjusted EBITDA	$	474	$	69			$	543
Maintenance capital expenditures	$	28	$	7			$	35

(1)Segment revenues include intersegment amounts that are eliminated in Purchases and related costs. Intersegment activities are conducted at posted tariff rates where applicable, or otherwise at rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated.

Reconciliation of Segment Adjusted EBITDA to Net income attributable to PAGP

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

 

	Three Months Ended March 31,
	2022		2021
Segment Adjusted EBITDA	$	614	$	543
Adjustments: (1)
Depreciation and amortization of unconsolidated entities (2)	(20)		(20)
Gains/(losses) from derivative activities and inventory valuation adjustments (3)	(88)		198
Long-term inventory costing adjustments (4)	92		41
Deficiencies under minimum volume commitments, net (5)	(6)		32
Equity-indexed compensation expense (6)	(7)		(5)
Net gain on foreign currency revaluation (7)	2		1
Line 901 incident (8)	(85)		—
Adjusted EBITDA attributable to noncontrolling interests in consolidated joint ventures (9)	76		3
Unallocated general and administrative expenses (10)	(1)		(1)
Depreciation and amortization	(231)		(178)
Gains/(losses) on asset sales and asset impairments, net	42		(2)
Interest expense, net	(107)		(107)
Other expense, net	(37)		(60)
Income before tax	244		445
Income tax expense	(35)		(53)
Net income	209		392
Net income attributable to noncontrolling interests	(187)		(322)
Net income attributable to PAGP	$	22	$	70

(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.

(3)We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify differences in the timing of earnings from the derivative instruments and the underlying transactions and exclude the related gains and losses in determining Segment Adjusted EBITDA such that the earnings from the derivative instruments and the underlying transactions impact Segment Adjusted EBITDA in the same period. In addition, we exclude gains and losses on derivatives that are related to (i) investing activities, such as the purchase of linefill, and (ii) purchases of long-term inventory. We also exclude the impact of corresponding inventory valuation adjustments, as applicable.

(4)We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). 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. 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. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to Segment Adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.

(6)Our total equity-indexed compensation expense includes expense associated with awards that will be settled in PAA common units and awards that will be settled in cash. The awards that will be settled in PAA common units are included in PAA’s diluted net income per unit calculation when the applicable performance criteria have been met. We exclude compensation expense associated with these awards in determining Segment Adjusted EBITDA as the dilutive impact of the outstanding awards is included in PAA’s diluted net income per unit calculation, as applicable. The portion of compensation expense associated with awards that will settle in cash is not excluded in determining Segment Adjusted EBITDA. See Note 18 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for a discussion regarding our equity-indexed compensation plans.

(7)During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. These gains and losses are not integral to our core operating performance and were therefore excluded in determining Segment Adjusted EBITDA.

(8)Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. See Note 10 for additional information regarding the Line 901 incident.

(9)Reflects amounts attributable to noncontrolling interests in the Permian JV and Red River LLC.

(10)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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Organization and Basis of Consolidation and Presentation - Additional Information (Details) shares in Millions, $ in Millions	3 Months Ended	6 Months Ended	9 Months Ended
	Mar. 31, 2022 USD ($) segment shares	Mar. 31, 2022 USD ($) segment	Sep. 30, 2021 segment	Dec. 31, 2021 USD ($)
Organization and basis of presentation
Operating segments number | segment	2	2	3
Deferred tax asset | $	$ 1,341	$ 1,341		$ 1,362
Consolidated Entity Excluding VIE
Organization and basis of presentation
Deferred tax asset | $	$ 1,341	$ 1,341		$ 1,362
GP LLC
Organization and basis of presentation
Ownership interest	100.00%
AAP
Organization and basis of presentation
Ownership interest	81.00%
Ownership interest (units)	193.2
AAP | GP LLC
Organization and basis of presentation
Ownership interest (units)	1.0
PAA | AAP
Organization and basis of presentation
Ownership interest	31.00%
Ownership interest (units)	241.5

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Summary of Significant Accounting Policies - Cash and Restricted Cash (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021	Mar. 31, 2021	Dec. 31, 2020
Accounting Policies [Abstract]
Cash and cash equivalents	$ 117	$ 452
Restricted cash	4	4
Total cash and cash equivalents and restricted cash	$ 121	$ 456	$ 58	$ 63

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Revenues and Accounts Receivable - Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Crude Oil
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 13,102	$ 7,946
Crude Oil | Sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	12,857	7,726
Crude Oil | Transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	155	90
Crude Oil | Terminalling, Storage and Other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	90	130
NGL
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	879	801
NGL | Sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	845	772
NGL | Transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	9	7
NGL | Terminalling, Storage and Other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 25	$ 22

XML

Revenues and Accounts Receivable - Segment Revenue (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Disaggregation of Revenue [Line Items]
Total revenues	$ 13,694	$ 8,383
Crude Oil
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	13,102	7,946
NGL
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	879	801
Operating Segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	13,981	8,747
Other items in revenues	(167)	(255)
Total revenues	13,814	8,492
Operating Segments | Crude Oil
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	13,102	7,946
Other items in revenues	(23)	(93)
Total revenues	13,079	7,853
Operating Segments | NGL
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	879	801
Other items in revenues	(144)	(162)
Total revenues	735	639
Intersegment revenue elimination
Disaggregation of Revenue [Line Items]
Total revenues	$ (120)	$ (109)

XML

Revenues and Accounts Receivable - Counterparty Deficiencies (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Minimum Volume Commitments [Line Items]
Contract liability, deferred revenue	$ 137	$ 141
Minimum Volume Commitments
Minimum Volume Commitments [Line Items]
Contract liability, deferred revenue	56	63
Counterparty deficiencies unbilled	16	16
Counterparty deficiencies	$ 72	$ 79

XML

Revenues and Accounts Receivable - Contract Balances (Details) $ in Millions	3 Months Ended
	Mar. 31, 2022 USD ($)
Change in Contract with Customer, Liability [Roll Forward]
Beginning balance	$ 141
Amounts recognized as revenue	(20)
Additions	16
Ending balance	$ 137

XML

Revenues and Accounts Receivable - Performance Obligations (Details) $ in Millions	Mar. 31, 2022 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 333
Remaining performance obligations, expected timing of satisfaction, period	9 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 397
Remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 331
Remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 215
Remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 148
Remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 896
Remaining performance obligations, expected timing of satisfaction, period
Pipeline revenues supported by minimum volume commitments and capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 132
Remaining performance obligations, expected timing of satisfaction, period	9 months
Pipeline revenues supported by minimum volume commitments and capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 174
Remaining performance obligations, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 158
Remaining performance obligations, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 134
Remaining performance obligations, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 87
Remaining performance obligations, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 379
Remaining performance obligations, expected timing of satisfaction, period
Terminalling, storage and other agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 201
Remaining performance obligations, expected timing of satisfaction, period	9 months
Terminalling, storage and other agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 223
Remaining performance obligations, expected timing of satisfaction, period	1 year
Terminalling, storage and other agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 173
Remaining performance obligations, expected timing of satisfaction, period	1 year
Terminalling, storage and other agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 81
Remaining performance obligations, expected timing of satisfaction, period	1 year
Terminalling, storage and other agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 61
Remaining performance obligations, expected timing of satisfaction, period	1 year
Terminalling, storage and other agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 517
Remaining performance obligations, expected timing of satisfaction, period

XML

Revenues and Accounts Receivable - Narrative (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2022	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
General payment terms	30 days
Substantially all trade accounts receivable, net, maximum age of balances past their invoice date	30 days	30 days

XML

Revenues and Accounts Receivable - Trade Accounts Receivable and Other Receivables (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Trade accounts receivable arising from revenues from contracts with customers	$ 5,496	$ 4,031
Other trade accounts receivables and other receivables	9,620	5,126
Impact due to contractual rights of offset with counterparties	(7,980)	(4,452)
Trade accounts receivable and other receivables, net	$ 7,136	$ 4,705

XML

Net Income Per Class A Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Basic and Diluted Net Income per Class A Share
Net income attributable to PAGP	$ 22	$ 70
AAP Units
Net Income Per Class A Share
Antidilutive securities excluded from computation of earnings per share (shares)	47	51
AAP Management Units | Maximum
Net Income Per Class A Share
Antidilutive securities excluded from computation of earnings per share (shares)	1	1
Class A Shares
Basic and Diluted Net Income per Class A Share
Basic weighted average Class A shares outstanding (shares)	194	194
Diluted weighted average Class A shares outstanding (shares)	194	194
Basic net income per Class A share (usd per share)	$ 0.11	$ 0.36
Diluted net income per Class A share (usd per share)	$ 0.11	$ 0.36

XML

Inventory, Linefill and Long-term Inventory (Details) bbl in Thousands, $ in Millions	Mar. 31, 2022 USD ($) $ / bbl bbl	Dec. 31, 2021 USD ($) $ / bbl bbl
Inventory by category
Inventory	$ 527	$ 783
Linefill	919	907
Long-term inventory	374	253
Total	$ 1,820	$ 1,943
Crude oil
Inventory by category
Inventory, Volumes (in barrels) | bbl	4,711	8,041
Linefill, Volumes (in barrels) | bbl	15,160	15,199
Long-term inventory, Volumes (in barrels) | bbl	3,289	2,973
Inventory	$ 420	$ 544
Linefill	872	862
Long-term inventory	$ 325	$ 209
Inventory (Price/Unit of measure) (in dollars per units) | $ / bbl	89.15	67.65
Linefill (Price/Unit of measure) (in dollars per units) | $ / bbl	57.52	56.71
Long-term inventory (Price/Unit of measure) (in dollars per units) | $ / bbl	98.81	70.30
NGL
Inventory by category
Inventory, Volumes (in barrels) | bbl	2,329	6,982
Linefill, Volumes (in barrels) | bbl	1,667	1,633
Long-term inventory, Volumes (in barrels) | bbl	1,071	1,135
Inventory	$ 102	$ 234
Linefill	47	45
Long-term inventory	$ 49	$ 44
Inventory (Price/Unit of measure) (in dollars per units) | $ / bbl	43.80	33.51
Linefill (Price/Unit of measure) (in dollars per units) | $ / bbl	28.19	27.56
Long-term inventory (Price/Unit of measure) (in dollars per units) | $ / bbl	45.75	38.77
Other
Inventory by category
Inventory	$ 5	$ 5

XML

Debt - Components (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Short-term debt:
Total short-term debt	$ 900	$ 822
Long-term debt:
Senior notes, net	7,931	8,329
Other long-term debt, net	55	69
Total long-term debt	7,986	8,398
Total debt	8,886	9,220
Senior notes
Long-term debt:
Senior notes, net	7,931	8,329
Unamortized discounts and debt issuance costs	52	54
Debt instrument face value	8,400	9,100
Other
Long-term debt:
Other long-term debt, net	55	69
Level 2 | Senior notes
Long-term debt:
Debt instrument fair value	8,400	9,900
Other
Short-term debt:
Total short-term debt	118	72
Commercial Paper | Line of Credit
Short-term debt:
Short-term debt	$ 382	0
Weighted average interest rate, short-term	0.80%
3.65% senior notes due June 2022 | Senior notes
Short-term debt:
Total short-term debt	$ 0	$ 750
Stated percentage	3.65%	3.65%
2.85% senior notes due January 2023 | Senior notes
Short-term debt:
Total short-term debt	$ 400	$ 0
Stated percentage	2.85%

XML

Debt - Borrowings and Repayments, Letters of Credit (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Debt
Outstanding letters of credit	$ 34		$ 98
3.65% senior notes due June 2022 | Senior notes
Debt
Stated percentage	3.65%		3.65%
Senior notes redeemed	$ 750
Credit facilities and PAA commercial paper program
Debt
Total borrowings	5,600	$ 14,200
Total repayments	$ 5,200	$ 14,800

XML

Partners' Capital and Distributions - Exchange Rights and Shares Activity (Details) - shares	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Class A Shares
Activity for Class A shares, Class B shares and Class C shares
Balance, beginning of period (shares)	194,192,777	194,051,436
Exchange Right exercises (shares)	35,700	46,879
Balance, end of period (shares)	194,228,477	194,098,315
Class B Shares
Activity for Class A shares, Class B shares and Class C shares
Balance, beginning of period (shares)	46,645,514	50,640,192
Conversion of AAP Management Units (shares)	205,024	414,608
Exchange Right exercises (shares)	(35,700)	(46,879)
Redemption Right exercises (shares)	(11,957)	(229,931)
Balance, end of period (shares)	46,802,881	50,777,990
Class C Shares
Activity for Class A shares, Class B shares and Class C shares
Balance, beginning of period (shares)	534,596,831	547,717,762
Redemption Right exercises (shares)	11,957	229,931
Repurchase of common units by a subsidiary under the Common Equity Repurchase Program (shares)	(2,375,299)	(350,000)
Other (shares)	51,937	25,431
Balance, end of period (shares)	532,285,426	547,623,124

XML

Partners' Capital and Distributions - Distributions, Class A (Details) - Cash Distribution - Class A Shares - USD ($) $ / shares in Units, $ in Millions	May 13, 2022	Feb. 14, 2022
Partners' Capital and Distributions
Distributions to Class A shareholders		$ 35
Distribution per Class A share, paid (usd per share)		$ 0.1800
Forecast
Partners' Capital and Distributions
Distributions to Class A shareholders	$ 42
Distribution per Class A share, paid (usd per share)	$ 0.2175

XML

Partners' Capital and Distributions - Noncontrolling Interests in Subsidiaries (Details)	Mar. 31, 2022
AAP
Partners' Capital and Distributions
Noncontrolling interests in subsidiaries (percent)	19.00%
Permian JV
Partners' Capital and Distributions
Noncontrolling interests in subsidiaries (percent)	35.00%
Red River LLC
Partners' Capital and Distributions
Noncontrolling interests in subsidiaries (percent)	33.00%
Common Units and Series A Preferred Units | PAA
Partners' Capital and Distributions
Noncontrolling interests in subsidiaries (percent)	69.00%
Series B Preferred Units | PAA
Partners' Capital and Distributions
Noncontrolling interests in subsidiaries (percent)	100.00%

XML

Partners' Capital and Distributions - Common Equity Repurchase Program (Details) - Common Equity Repurchase Program - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Partners Capital and Distribution [Line Items]
Common equity repurchase program, remaining amount	$ 247
PAA
Partners Capital and Distribution [Line Items]
Common equity repurchase program, repurchased amount	$ 25	$ 3
PAA | Common Units
Partners Capital and Distribution [Line Items]
Repurchase and cancellation of common units by a subsidiary under the Common Equity Repurchase Program (units)	2.4	0.4

XML

Partners' Capital and Distributions - Subsidiary Distributions (Details) - USD ($) $ / shares in Units, $ in Millions				3 Months Ended
	May 16, 2022	May 13, 2022	Feb. 14, 2022	Mar. 31, 2022	Mar. 31, 2021
Partners' Capital and Distributions
Total distributions paid				$ 235.0	$ 185.0
PAA | Series A Preferred Units | Cash Distribution
Partners' Capital and Distributions
Preferred unit distribution amount			$ 37.0
Preferred unit distribution amount (usd per unit)			$ 0.525
PAA | Series A Preferred Units | Cash Distribution | Forecast
Partners' Capital and Distributions
Preferred unit distribution amount		$ 37.0
Preferred unit distribution amount (usd per unit)		$ 0.525
PAA | Series B Preferred Units | Cash Distribution | Forecast
Partners' Capital and Distributions
Preferred unit distribution amount	$ 24.5
Preferred unit distribution amount (usd per unit)	$ 30.625
PAA | Common Units | Cash Distribution
Partners' Capital and Distributions
Total distributions paid			$ 127.0
Distributions per common unit, paid (usd per unit)			$ 0.1800
PAA | Common Units | Cash Distribution | Forecast
Partners' Capital and Distributions
Total distributions paid		$ 153.0
Distributions per common unit, paid (usd per unit)		$ 0.2175
AAP | Cash Distribution
Partners' Capital and Distributions
Total distributions paid			$ 43.0
Distributions to noncontrolling interests			8.0
Distributions to PAGP			35.0
AAP | Cash Distribution | Forecast
Partners' Capital and Distributions
Total distributions paid		$ 53.0
Distributions to noncontrolling interests		11.0
Distributions to PAGP		42.0
Public | PAA | Common Units | Cash Distribution
Partners' Capital and Distributions
Total distributions paid			84.0
Public | PAA | Common Units | Cash Distribution | Forecast
Partners' Capital and Distributions
Total distributions paid		100.0
AAP | PAA | Common Units | Cash Distribution
Partners' Capital and Distributions
Total distributions paid			$ 43.0
AAP | PAA | Common Units | Cash Distribution | Forecast
Partners' Capital and Distributions
Total distributions paid		$ 53.0
Other current liabilities | PAA | Series B Preferred Units
Partners' Capital and Distributions
Amount accrued to distributions payable				18.0
Noncontrolling Interests
Partners' Capital and Distributions
Total distributions paid				200.0	$ 150.0
Noncontrolling Interests | Permian JV
Partners' Capital and Distributions
Total distributions paid				54.0
Noncontrolling Interests | Red River LLC
Partners' Capital and Distributions
Total distributions paid				$ 5.0

XML

Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions	3 Months Ended
	Mar. 31, 2022 TWh Bcf bbl MMBbls
Crude oil purchases | Long
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf)	6.6
Time spread on hedging anticipated crude oil lease gathering purchases | Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf)	5.3
Crude oil basis spread position
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf)	1.2
Anticipated net sales of crude oil and NGL inventory | Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf)	11.0
Natural gas purchases for processing and operational needs | Long
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf) | Bcf	82.6
Propane contracts related to subsequent sale of products | Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf) | MMBbls	15.5
Butane contracts related to subsequent sale of products | Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf) | MMBbls	3.8
Condensate sales contracts related to subsequent sale of products | Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf) | MMBbls	1.5
Fuel gas requirements | Long
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf) | Bcf	8.8
Power supply requirements | Long
Commodity Price Risk Hedging:
Derivative position notional amount (in Terawatt hours) | TWh	0.5

XML

Derivatives and Risk Management Activities - Financial Impact (Details) - Derivatives Not Designated as a Hedge - Commodity derivatives - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Impact of derivative activities recognized in earnings
Net loss from commodity derivative activity	$ (200)	$ (275)
Product sales revenues
Impact of derivative activities recognized in earnings
Net loss from commodity derivative activity	(213)	(314)
Field operating costs
Impact of derivative activities recognized in earnings
Net loss from commodity derivative activity	$ 13	$ 39

XML

Derivatives and Risk Management Activities - Broker Receivable/Payable (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Offsetting Assets, Liabilities [Line Items]
Initial margin	$ 102	$ 133
Variation margin posted	296	173
Letters of credit	(34)	(98)
Net broker receivable	373	259
Exchange traded
Offsetting Assets, Liabilities [Line Items]
Letters of credit	$ (25)	$ (47)

XML

Derivatives and Risk Management Activities - Offsetting Asset and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Derivative Asset Positions
Effect of Collateral Netting	$ 373	$ 259
Commodity derivatives
Derivative Asset Positions
Effect of Collateral Netting	373	259
Derivative Liability Positions
Gross Position - Asset	261	100
Gross Position - Liability	(410)	(243)
Net Carrying Value Presented on the Balance Sheet, Total	224	116
Other current assets | Commodity derivatives
Derivative Asset Positions
Gross Position - Asset	230	90
Gross Position - Liability	(331)	(210)
Effect of Collateral Netting	373	259
Net Carrying Value Presented on the Balance Sheet	272	139
Other long-term assets, net | Commodity derivatives
Derivative Asset Positions
Gross Position - Asset	12	3
Net Carrying Value Presented on the Balance Sheet	12	3
Other current liabilities | Commodity derivatives
Derivative Liability Positions
Gross Position - Asset	11	4
Gross Position - Liability	(51)	(24)
Net Carrying Value Presented on the Balance Sheet	(40)	(20)
Other long-term liabilities and deferred credits | Commodity derivatives
Derivative Liability Positions
Gross Position - Asset	8	3
Gross Position - Liability	(28)	(9)
Net Carrying Value Presented on the Balance Sheet	$ (20)	$ (6)

XML

Derivatives and Risk Management Activities - Interest Rate Risk Hedging (Details) - Cash flow hedge $ in Millions	3 Months Ended
	Mar. 31, 2022 USD ($) contract
8 forward starting interest rate swaps (30-year), 1.38%
Interest Rate Risk Hedging
Number of interest rate derivatives | contract	8
Term of derivative contract	30 years
Notional amount of derivatives | $	$ 200
Average rate locked (percent)	1.38%
8 forward starting interest rate swaps (30-year), 0.73%
Interest Rate Risk Hedging
Number of interest rate derivatives | contract	8
Term of derivative contract	30 years
Notional amount of derivatives | $	$ 200
Average rate locked (percent)	0.73%

XML

Derivatives and Risk Management Activities - Net Unrealized Gain/(Loss) Recognized in AOCI (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Other long-term assets, net
Derivative assets and liabilities
Net fair value of interest rate hedges	$ 97		$ 65
AOCI cash flow hedge
Derivative assets and liabilities
Net loss deferred in AOCI	173
Interest rate derivatives
Derivative assets and liabilities
Net unrealized gain/(loss) recognized in AOCI	$ 32	$ 68

XML

Derivatives and Risk Management Activities - Preferred Distribution Rate (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Derivatives and Risk Management Activities
Loss recognized	$ 44	$ 67
Preferred Distribution Rate Reset Option and Other | Derivatives Not Designated as a Hedge | Other long-term liabilities and deferred credits
Derivatives and Risk Management Activities
Derivative liability	44
Preferred Distribution Rate Reset Option and Other | Derivatives Not Designated as a Hedge | Other long-term liabilities and deferred credits | Maximum
Derivatives and Risk Management Activities
Derivative liability			$ 1
Preferred Distribution Rate Reset Option and Other | Derivatives Not Designated as a Hedge | Other expense, net
Derivatives and Risk Management Activities
Loss recognized	$ 44	$ 67

XML

Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Level 3
Rollforward of Level 3 Net Asset/(Liability)
Beginning Balance	$ (2)	$ (29)
Net losses for the period included in earnings	(44)	(67)
Settlements	2	4
Ending Balance	(44)	(92)
Change in unrealized losses included in earnings relating to Level 3 derivatives still held at the end of the period	(44)	$ (67)
Recurring Fair Value Measures
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(96)		$ (78)
Recurring Fair Value Measures | Commodity derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(149)		(143)
Recurring Fair Value Measures | Interest rate derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	97		65
Recurring Fair Value Measures | Preferred Distribution Rate Reset Option and Other
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(44)		0
Recurring Fair Value Measures | Level 1
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(76)		(17)
Recurring Fair Value Measures | Level 1 | Commodity derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(76)		(17)
Recurring Fair Value Measures | Level 1 | Interest rate derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	0		0
Recurring Fair Value Measures | Level 1 | Preferred Distribution Rate Reset Option and Other
Recurring Fair Value Measurements
Total net derivative asset/(liability)	0		0
Recurring Fair Value Measures | Level 2
Recurring Fair Value Measurements
Total net derivative asset/(liability)	24		(59)
Recurring Fair Value Measures | Level 2 | Commodity derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(73)		(124)
Recurring Fair Value Measures | Level 2 | Interest rate derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	97		65
Recurring Fair Value Measures | Level 2 | Preferred Distribution Rate Reset Option and Other
Recurring Fair Value Measurements
Total net derivative asset/(liability)	0		0
Recurring Fair Value Measures | Level 3
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(44)		(2)
Recurring Fair Value Measures | Level 3 | Commodity derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	0		(2)
Recurring Fair Value Measures | Level 3 | Interest rate derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	0		0
Recurring Fair Value Measures | Level 3 | Preferred Distribution Rate Reset Option and Other
Recurring Fair Value Measurements
Total net derivative asset/(liability)	$ (44)		$ 0

XML

Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Related Party Transactions [Abstract]
Revenues from related parties	$ 12	$ 7
Purchases and related costs from related parties	97	$ 90
Trade accounts receivable and other receivables, net from related parties	56		$ 41
Trade accounts payable to related parties	$ 75		$ 72

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Commitments and Contingencies - Legal, Environmental or Regulatory (Details)	1 Months Ended			12 Months Ended	83 Months Ended
	Apr. 30, 2022 USD ($)	Sep. 30, 2021 USD ($)	May 31, 2015 bbl	Sep. 30, 2021 USD ($)	Mar. 31, 2022 USD ($) lawsuit	Dec. 31, 2021 USD ($)	Apr. 25, 2019 USD ($)	Sep. 07, 2018 count
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities					$ 59,000,000	$ 57,000,000
Amounts probable of recovery under insurance and from third parties under indemnification agreements					11,000,000	11,000,000
Other current liabilities
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities, short-term					9,000,000	11,000,000
Other long-term liabilities and deferred credits
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities, long-term					50,000,000	46,000,000
Other long-term assets, net
Legal, Environmental or Regulatory Matters
Amounts probable of recovery under insurance and from third parties under indemnification agreements					1,000,000	$ 1,000,000
Line 901 Incident
Legal, Environmental or Regulatory Matters
Estimated size of release (in bbl) | bbl			2,934
Estimated size of release to reach Pacific Ocean (in bbl) | bbl			598
Aggregate total estimated costs					725,000,000
Coverage limit under insurance program					500,000,000
Recoveries from insurance carriers					260,000,000
Total release costs probable of recovery					500,000,000
Line 901 Incident | Trade accounts payable and Other current liabilities
Legal, Environmental or Regulatory Matters
Remaining undiscounted liability					335,000,000
Line 901 Incident | Trade accounts receivable and other receivables, net
Legal, Environmental or Regulatory Matters
Receivable for remaining portion of release costs probable of recovery from insurance					$ 240,000,000
Line 901 Incident | Civil Penalties | Judicial Ruling
Legal, Environmental or Regulatory Matters
Penalties or compensation paid				$ 24,000,000
Line 901 Incident | Consent Decree, Compensation for Injuries to, Destruction of, Loss of Use of, Natural Resources | Judicial Ruling
Legal, Environmental or Regulatory Matters
Penalties or compensation paid				$ 22,325,000
Line 901 Incident | May 2016 Indictment
Legal, Environmental or Regulatory Matters
Number of felony discharges found guilty | count								1
Number of misdemeanor charges found guilty | count								8
Number of misdemeanor charges found guilty, reporting | count								1
Number of misdemeanor charges found guilty, strict liability discharge | count								1
Number of misdemeanor charges found guilty, strict liability animal takings | count								6
Number of misdemeanor charges found not guilty, strict liability animal takings | count								1
Line 901 Incident | May 2016 Indictment | Judicial Ruling
Legal, Environmental or Regulatory Matters
Fines or penalties assessed							$ 3,350,000
Line 901 Incident | May 2016 Indictment | Maximum | Judicial Ruling
Legal, Environmental or Regulatory Matters
Amount awarded to claimants by Court		$ 150,000
Line 901 Incident | Class Action Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed | lawsuit					9
Line 901 Incident | Class Action Lawsuits | Pending Litigation
Legal, Environmental or Regulatory Matters
Number of proceedings pending | lawsuit					2
Line 901 Incident | Class Action Lawsuit Claim of Damages | Subsequent Event | Pending Litigation
Legal, Environmental or Regulatory Matters
Litigation settlement agreement amount, subject to approval	$ 230,000,000
Line 901 Incident | Unitholder Derivative Lawsuits | Pending Litigation
Legal, Environmental or Regulatory Matters
Number of proceedings pending | lawsuit					1
Line 901 Incident | Unitholder Derivative Lawsuits | Subsequent Event | Pending Litigation
Legal, Environmental or Regulatory Matters
Litigation settlement agreement amount, subject to approval	$ 2,000,000

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Segment Information - Segment Financial Data (Details) $ in Millions	3 Months Ended		6 Months Ended	9 Months Ended
	Mar. 31, 2022 USD ($) segment	Mar. 31, 2021 USD ($)	Mar. 31, 2022 segment	Sep. 30, 2021 segment
Segment Reporting Information [Line Items]
Operating segments number | segment	2		2	3
Revenues:
Revenues	$ 13,694	$ 8,383
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	97	88
Segment Adjusted EBITDA	614	543
Maintenance capital expenditures	27	35
Operating Segments
Revenues:
Revenues	13,814	8,492
Intersegment Revenues Elimination
Revenues:
Revenues	(120)	(109)
Product sales revenues
Revenues:
Revenues	13,381	8,083
Product sales revenues | Intersegment Revenues Elimination
Revenues:
Revenues	(112)	(103)
Services revenues
Revenues:
Revenues	313	300
Services revenues | Intersegment Revenues Elimination
Revenues:
Revenues	(8)	(6)
Crude Oil
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	97	88
Segment Adjusted EBITDA	453	474
Maintenance capital expenditures	19	28
Crude Oil | Operating Segments
Revenues:
Revenues	13,079	7,853
Crude Oil | Product sales revenues | Operating Segments
Revenues:
Revenues	12,811	7,586
Crude Oil | Services revenues | Operating Segments
Revenues:
Revenues	268	267
NGL
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	0	0
Segment Adjusted EBITDA	161	69
Maintenance capital expenditures	8	7
NGL | Operating Segments
Revenues:
Revenues	735	639
NGL | Product sales revenues | Operating Segments
Revenues:
Revenues	682	600
NGL | Services revenues | Operating Segments
Revenues:
Revenues	$ 53	$ 39

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Segment Information - Segment Adjusted EBITDA Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Segment Reporting, Reconciling Item from Segments to Consolidated [Line Items]
Segment Adjusted EBITDA	$ 614	$ 543
Adjustments:
Depreciation and amortization of unconsolidated entities	(20)	(20)
Gains/(losses) from derivative activities and inventory valuation adjustments	(88)	198
Long-term inventory costing adjustments	92	41
Deficiencies under minimum volume commitments, net	(6)	32
Equity-indexed compensation expense	(7)	(5)
Net gain on foreign currency revaluation	2	1
Adjusted EBITDA attributable to noncontrolling interests in consolidated joint ventures	76	3
Unallocated general and administrative expenses	(83)	(68)
Depreciation and amortization	(231)	(178)
Gains/(losses) on asset sales and asset impairments, net	42	(2)
Interest expense, net	(107)	(107)
Other expense, net	(37)	(60)
INCOME BEFORE TAX	244	445
Income tax expense	(35)	(53)
NET INCOME	209	392
Net income attributable to noncontrolling interests	(187)	(322)
NET INCOME ATTRIBUTABLE TO PAGP	22	70
Line 901 Incident
Adjustments:
Line 901 incident	(85)	0
Unallocated
Adjustments:
Unallocated general and administrative expenses	$ (1)	$ (1)