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 June 30, 2021

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 July 30, 2021, there were 194,123,869 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 June 30, 2021 and December 31, 2020	3
Condensed Consolidated Statements of Operations: For the three and six months ended June 30, 2021 and 2020	4
Condensed Consolidated Statements of Comprehensive Income/(Loss): For the three and six months ended June 30, 2021 and 2020	5
Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss): For the six months ended June 30, 2021 and 2020	5
Condensed Consolidated Statements of Cash Flows: For the six months ended June 30, 2021 and 2020	6
Condensed Consolidated Statements of Changes in Partners’ Capital: For the three and six months ended June 30, 2021 and 2020	7
Notes to the Condensed Consolidated Financial Statements:
1. Organization and Basis of Consolidation and Presentation	9
2. Summary of Significant Accounting Policies	11
3. Revenues and Accounts Receivable	13
4. Net Income/(Loss) Per Class A Share	17
5. Inventory, Linefill and Base Gas and Long-term Inventory	18
6. Debt	19
7. Partners’ Capital and Distributions	20
8. Derivatives and Risk Management Activities	23
9. Related Party Transactions	28
10. Commitments and Contingencies	29
11. Operating Segments	33
12. Acquisitions, Divestitures and Other Transactions	37
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	38
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	60
Item 4. CONTROLS AND PROCEDURES	62
PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS	63
Item 1A. RISK FACTORS	63
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	63
Item 3. DEFAULTS UPON SENIOR SECURITIES	63
Item 4. MINE SAFETY DISCLOSURES	63
Item 5. OTHER INFORMATION	63
Item 6. EXHIBITS	64
SIGNATURES	67

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)

	June 30, 2021		December 31, 2020
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	26	$	25
Restricted cash	7		38
Trade accounts receivable and other receivables, net	3,897		2,553
Inventory	675		647
Other current assets	1,073		405
Total current assets	5,678		3,668
PROPERTY AND EQUIPMENT	17,577		18,620
Accumulated depreciation	(4,119)		(4,000)
Property and equipment, net	13,458		14,620
OTHER ASSETS
Investments in unconsolidated entities	3,745		3,764
Deferred tax asset	1,414		1,444
Linefill and base gas	909		982
Long-term operating lease right-of-use assets, net	344		378
Long-term inventory	210		130
Other long-term assets, net	1,054		965
Total assets	$	26,812	$	25,951
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES
Trade accounts payable	$	4,113	$	2,425
Short-term debt	1,456		831
Other current liabilities	594		999
Total current liabilities	6,163		4,255
LONG-TERM LIABILITIES
Senior notes, net	8,326		9,071
Other long-term debt, net	63		311
Long-term operating lease liabilities	289		317
Other long-term liabilities and deferred credits	910		807
Total long-term liabilities	9,588		10,506
COMMITMENTS AND CONTINGENCIES (NOTE 10)
PARTNERS’ CAPITAL
Class A shareholders (194,123,869 and 194,051,436 shares outstanding, respectively)	1,421		1,464
Noncontrolling interests	9,640		9,726
Total partners’ capital	11,061		11,190
Total liabilities and partners’ capital	$	26,812	$	25,951

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

3

PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(unaudited)				(unaudited)
REVENUES
Supply and Logistics segment revenues	$	9,623	$	2,925	$	17,706	$	10,833
Transportation segment revenues	162		151		299		338
Facilities segment revenues	145		149		308		323
Total revenues	9,930		3,225		18,313		11,494
COSTS AND EXPENSES
Purchases and related costs	9,277		2,525		16,669		9,893
Field operating costs	252		253		471		557
General and administrative expenses	74		74		142		144
Depreciation and amortization	197		166		375		335
(Gains)/losses on asset sales and asset impairments, net	369		(1)		370		618
Goodwill impairment losses	—		—		—		2,515
Total costs and expenses	10,169		3,017		18,027		14,062
OPERATING INCOME/(LOSS)	(239)		208		286		(2,568)
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	33		81		121		191
Gain on/(impairment of) investments in unconsolidated entities, net	—		(69)		—		(91)
Interest expense (net of capitalized interest of $5, $5, $10 and $11, respectively)	(107)		(108)		(213)		(215)
Other income/(expense), net	84		18		23		(13)
INCOME/(LOSS) BEFORE TAX	(229)		130		217		(2,696)
Current income tax expense	(1)		(15)		(3)		(22)
Deferred income tax (expense)/benefit	18		22		(33)		162
NET INCOME/(LOSS)	(212)		137		181		(2,556)
Net (income)/loss attributable to noncontrolling interests	143		(121)		(180)		1,991
NET INCOME/(LOSS) ATTRIBUTABLE TO PAGP	$	(69)	$	16	$	1	$	(565)
BASIC AND DILUTED NET INCOME/(LOSS) PER CLASS A SHARE	$	(0.35)	$	0.09	$	—	$	(3.08)
BASIC AND DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING	194		184		194		183

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/(LOSS)

(in millions)

 

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(unaudited)				(unaudited)
Net income/(loss)	$	(212)	$	137	$	181	$	(2,556)
Other comprehensive income/(loss)	—		116		108		(212)
Comprehensive income/(loss)	(212)		253		289		(2,768)
Comprehensive (income)/loss attributable to noncontrolling interests	143		(207)		(259)		2,150
Comprehensive income/(loss) attributable to PAGP	$	(69)	$	46	$	30	$	(618)

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, 2020	$	(258)	$	(657)	$	(3)	$	(918)
Reclassification adjustments	6		—		—		6
Unrealized gain on hedges	29		—		—		29
Currency translation adjustments	—		73		—		73
Total period activity	35		73		—		108
Balance at June 30, 2021	$	(223)	$	(584)	$	(3)	$	(810)

	Derivative Instruments		Translation Adjustments		Other		Total
	(unaudited)
Balance at December 31, 2019	$	(259)	$	(674)	$	—	$	(933)
Reclassification adjustments	5		—		—		5
Unrealized loss on hedges	(61)		—		—		(61)
Currency translation adjustments	—		(157)		—		(157)
Other	—		—		1		1
Total period activity	(56)		(157)		1		(212)
Balance at June 30, 2020	$	(315)	$	(831)	$	1	$	(1,145)

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)

	Six Months Ended June 30,
	2021		2020
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income/(loss)	$	181	$	(2,556)
Reconciliation of net income/(loss) to net cash provided by operating activities:
Depreciation and amortization	375		335
(Gains)/losses on asset sales and asset impairments, net	370		618
Goodwill impairment losses	—		2,515
Inventory valuation adjustments	—		232
Deferred income tax expense/(benefit)	33		(162)
(Gain)/loss on foreign currency revaluation	(15)		23
Settlement of terminated interest rate hedging instruments	—		(100)
Change in fair value of Preferred Distribution Rate Reset Option (Note 8)	(9)		(17)
Equity earnings in unconsolidated entities	(121)		(191)
Distributions on earnings from unconsolidated entities	211		236
(Gain on)/impairment of investments in unconsolidated entities, net	—		91
Other	27		15
Changes in assets and liabilities, net of acquisitions	(29)		(67)
Net cash provided by operating activities	1,023		972
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	(32)		(308)
Investments in unconsolidated entities	(71)		(314)
Additions to property, equipment and other	(182)		(472)
Proceeds from sales of assets	22		245
Other investing activities	(20)		(9)
Net cash used in investing activities	(283)		(858)
CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments under PAA commercial paper program (Note 6)	(159)		(93)
Net repayments under PAA senior secured hedged inventory facility (Note 6)	(167)		(325)
Proceeds from the issuance of PAA senior notes	—		748
Repayments of PAA senior notes	—		(17)
Repurchase of common units by a subsidiary (Note 7)	(53)		—
Distributions paid to Class A shareholders (Note 7)	(70)		(99)
Distributions paid to noncontrolling interests (Note 7)	(295)		(397)
Other financing activities	(28)		100
Net cash used in financing activities	(772)		(83)
Effect of translation adjustment	2		(9)
Net increase/(decrease) in cash and cash equivalents and restricted cash	(30)		22
Cash and cash equivalents and restricted cash, beginning of period	63		84
Cash and cash equivalents and restricted cash, end of period	$	33	$	106
Cash paid for:
Interest, net of amounts capitalized	$	202	$	213
Income taxes, net of amounts refunded	$	27	$	51

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, 2020	$	1,464	$	9,726	$	11,190
Net income	1		180		181
Distributions (Note 7)	(70)		(295)		(365)
Deferred tax asset	(7)		—		(7)
Other comprehensive income	29		79		108
Repurchase of common units by a subsidiary (Note 7)	1		(54)		(53)
Contributions from noncontrolling interests	—		1		1
Other	3		3		6
Balance at June 30, 2021	$	1,421	$	9,640	$	11,061
	Class A Shareholders		Noncontrolling Interests		Total Partners’ Capital
	(unaudited)
Balance at March 31, 2021	$	1,523	$	9,976	$	11,499
Net loss	(69)		(143)		(212)
Distributions (Note 7)	(35)		(144)		(179)
Repurchase of common units by a subsidiary (Note 7)	1		(51)		(50)
Other	1		2		3
Balance at June 30, 2021	$	1,421	$	9,640	$	11,061

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

7

PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(continued)

(in millions)

	Class A Shareholders		Noncontrolling Interests		Total Partners’ Capital
	(unaudited)
Balance at December 31, 2019	$	2,155	$	12,330	$	14,485
Net loss	(565)		(1,991)		(2,556)
Distributions	(99)		(397)		(496)
Deferred tax asset	13		—		13
Other comprehensive loss	(53)		(159)		(212)
Contributions from noncontrolling interests	—		10		10
Other	14		(5)		9
Balance at June 30, 2020	$	1,465	$	9,788	$	11,253
	Class A Shareholders		Noncontrolling Interests		Total Partners’ Capital
	(unaudited)
Balance at March 31, 2020	$	1,457	$	9,729	$	11,186
Net income	16		121		137
Distributions	(33)		(151)		(184)
Deferred tax asset	(7)		—		(7)
Other comprehensive income	30		86		116
Contributions from noncontrolling interests	—		2		2
Other	2		1		3
Balance at June 30, 2020	$	1,465	$	9,788	$	11,253

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

8

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 June 30, 2021, 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 June 30, 2021, PAGP owned (i) a 100% managing member interest in Plains All American GP LLC (“GP LLC”), an entity that has also elected to be taxed as a corporation for United States federal income tax purposes and (ii) an approximate 79% limited partner interest in Plains AAP, L.P. (“AAP”) through our direct ownership of approximately 193.1 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 June 30, 2021, directly owned a limited partner interest in PAA through its ownership of approximately 245.0 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 crude oil, NGL and natural gas. PAA’s business activities are conducted through three operating segments: Transportation, Facilities and Supply and Logistics. 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.

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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 2020 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. 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.

The condensed consolidated balance sheet data as of December 31, 2020 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three and six months ended June 30, 2021 should not be taken as indicative of results to be expected for the entire year.

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.

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 $1.414 billion and $1.444 billion as of June 30, 2021 and December 31, 2020, 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 six months ended June 30, 2021 or the year ended December 31, 2020. See Note 17 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for information regarding the Omnibus Agreement entered into by the Plains Entities on November 15, 2016.

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

Note 2—Summary of Significant Accounting Policies

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):

	June 30, 2021		December 31, 2020
Cash and cash equivalents	$	26	$	25
Restricted cash	7		38
Total cash and cash equivalents and restricted cash	$	33	$	63

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Property and Equipment

During the first quarter of 2021, we modified the useful lives of certain of our Pipelines and related facilities and Storage, terminal and rail facilities to useful lives of 10 to 50 years from useful lives of 10 to 70 years to reflect current expectations given our future operating and commercial outlook. These depreciable life adjustments will prospectively increase depreciation expense. For the three and six months ended June 30, 2021, these reductions in useful lives increased depreciation expense by approximately $18 million and $36 million, respectively, which resulted in a decrease in net income attributable to PAGP of $4 million and $7 million, respectively, from what these amounts would have been absent the change in useful lives. The impact to both basic and diluted net income per Class A share was approximately $0.01 for the three months ended June 30, 2021 and approximately $0.04 for the six months ended June 30, 2021.

Recent Accounting Pronouncements

Except as discussed below and in our 2020 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the six months ended June 30, 2021 that are of significance or potential significance to us.

Accounting Standards Updates Adopted During the Period

We adopted the ASU listed below effective January 1, 2021 and our adoption did not have a material impact on our financial position, results of operations or cash flows (see Note 2 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for additional information regarding this ASU):

•ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes.

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 2020 Annual Report on Form 10-K for additional information regarding our types of revenues and policies for revenue recognition.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Supply and Logistics segment revenues from contracts with customers
Crude oil transactions	$	9,619	$	2,928	$	17,331	$	10,251
NGL and other transactions	285		127		969		555
Total Supply and Logistics segment revenues from contracts with customers	$	9,904	$	3,055	$	18,300	$	10,806

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Transportation segment revenues from contracts with customers
Tariff activities:
Crude oil pipelines	$	462	$	405	$	859	$	917
NGL pipelines	27		26		53		52
Total tariff activities	489		431		912		969
Trucking	20		22		42		57
Total Transportation segment revenues from contracts with customers	$	509	$	453	$	954	$	1,026

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Facilities segment revenues from contracts with customers
Crude oil, NGL and other terminalling and storage	$	154	$	176	$	324	$	357
NGL and natural gas processing and fractionation	70		80		142		190
Rail load / unload	8		8		20		22
Total Facilities segment revenues from contracts with customers	$	232	$	264	$	486	$	569

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 (as described above for each segment) to segment revenues and total revenues as disclosed in our Condensed Consolidated Statements of Operations (in millions):

Three Months Ended June 30, 2021	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	509	$	232	$	9,904	$	10,645
Other items in revenues	44		12		(281)		(225)
Total revenues of reportable segments	$	553	$	244	$	9,623	$	10,420
Intersegment revenues							(490)
Total revenues							$	9,930
Three Months Ended June 30, 2020	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	453	$	264	$	3,055	$	3,772
Other items in revenues	4		12		(130)		(114)
Total revenues of reportable segments	$	457	$	276	$	2,925	$	3,658
Intersegment revenues							(433)
Total revenues							$	3,225
Six Months Ended June 30, 2021	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	954	$	486	$	18,300	$	19,740
Other items in revenues	85		29		(593)		(479)
Total revenues of reportable segments	$	1,039	$	515	$	17,707	$	19,261
Intersegment revenues							(948)
Total revenues							$	18,313
Six Months Ended June 30, 2020	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	1,026	$	569	$	10,806	$	12,401
Other items in revenues	10		20		28		58
Total revenues of reportable segments	$	1,036	$	589	$	10,834	$	12,459
Intersegment revenues							(965)
Total revenues							$	11,494

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	June 30, 2021		December 31, 2020
Billed and collected	Liability	$	54	$	73
Unbilled (1)	N/A	21		4
Total		$	75	$	77

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(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, 2020	$	501
Amounts recognized as revenue (1)	(384)
Additions	22
Balance at June 30, 2021	$	139

(1)Includes approximately $361 million associated with crude oil sales agreements that were entered into in the fourth quarter of 2020 in conjunction with storage arrangements and inventory exchanges, which were settled in the first quarter of 2021.

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 June 30, 2021 (in millions):

	Remainder of 2021		2022		2023		2024		2025		2026 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	92	$	174	$	174	$	151	$	129	$	461
Storage, terminalling and throughput agreement revenues	139		223		155		118		57		229
Total	$	231	$	397	$	329	$	269	$	186	$	690

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

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

•Supply and Logistics buy/sell arrangements with future committed volumes;

•All other Supply and Logistics contracts, due to the election of practical expedients related to variable consideration and short-term contracts;

•Transportation and Facilities contracts that are short-term;

•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 supply and logistics activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes.

During 2020, macroeconomic and geopolitical conditions including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply has caused liquidity issues impacting many energy companies, which in turn has increased the potential credit risks associated with certain counterparties with which we do business. 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 June 30, 2021 and December 31, 2020, 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.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	June 30, 2021		December 31, 2020
Trade accounts receivable arising from revenues from contracts with customers	$	3,177	$	2,317
Other trade accounts receivables and other receivables (1)	4,807		2,818
Impact due to contractual rights of offset with counterparties	(4,087)		(2,582)
Trade accounts receivable and other receivables, net	$	3,897	$	2,553

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

Note 4—Net Income/(Loss) Per Class A Share

Basic net income/(loss) per Class A share is determined by dividing net income/(loss) 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/(loss) per Class A share is determined by dividing net income/(loss) attributable to PAGP by the diluted weighted average number of Class A shares outstanding during the period. For purposes of calculating diluted net income per Class A share, both the net income/(loss) attributable to PAGP and the diluted weighted average number of Class A shares outstanding consider the impact of possible future exchanges of (i) AAP units and the associated Class B shares into our Class A shares and (ii) 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 2020 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 2020 Annual Report on Form 10-K for information regarding PAGP LTIP awards.

On a weighted-average basis, for the three months ended June 30, 2021 and 2020, the possible exchange of 51 million and 63 million AAP units, respectively, and for the six months ended June 30, 2021 and 2020, the possible exchange of 51 million and 64 million AAP units, respectively, would not have had a dilutive effect on basic net income/(loss) per Class A share. For each of the three and six months ended June 30, 2021 and 2020, the possible exchange of 1 million AAP Management Units would not have had a dilutive effect on basic net income/(loss) per Class A share on a weighted-average basis. For the three months ended June 30, 2021 and 2020, and for the six months ended June 30, 2020, our PAGP LTIP awards were antidilutive. For the six months ended June 30, 2021, our PAGP LTIP awards were dilutive; however, there were less than 0.1 million dilutive LTIP awards, which did not change the presentation of diluted weighted average Class A shares outstanding or diluted net income/(loss) 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/(loss) per Class A share (in millions, except per share data):

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Basic and Diluted Net Income/(Loss) per Class A Share
Net income/(loss) attributable to PAGP	$	(69)	$	16	$	1	$	(565)
Basic and diluted weighted average Class A shares outstanding	194		184		194		183
Basic and diluted net income/(loss) per Class A share	$	(0.35)	$	0.09	$	—	$	(3.08)

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

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

	June 30, 2021						December 31, 2020
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	9,674	barrels	$	508	$	52.51	13,450	barrels	$	441	$	32.79
NGL	7,097	barrels	162		$	22.83	12,302	barrels	199		$	16.18
Other	N/A		5		N/A		N/A		7		N/A
Inventory subtotal			675						647
Linefill and base gas
Crude oil	15,164	barrels	864		$	56.98	14,669	barrels	828		$	56.45
NGL	1,636	barrels	45		$	27.51	1,640	barrels	44		$	26.83
Natural gas (2)	—	Mcf	—		$	—	25,576	Mcf	110		$	4.30
Linefill and base gas subtotal			909						982
Long-term inventory
Crude oil	2,699	barrels	183		$	67.80	2,499	barrels	111		$	44.42
NGL	1,258	barrels	27		$	21.46	1,185	barrels	19		$	16.03
Long-term inventory subtotal			210						130
Total			$	1,794					$	1,759

(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.

(2)As of June 30, 2021, $110 million of base gas was classified as held for sale on our Condensed Consolidated Balance Sheet (in “Other current assets”) related to the sale of our Pine Prairie and Southern Pines natural gas storage facilities, which closed on August 2, 2021. See Note 12 for additional information.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 6—Debt

Debt consisted of the following (in millions):

	June 30, 2021		December 31, 2020
SHORT-TERM DEBT
PAA commercial paper notes, bearing a weighted-average interest rate of 0.4% and 0.7%, respectively (1)	$	388	$	547
PAA senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.2% (1)	—		167
PAA senior notes:
3.65% senior notes due June 2022	750		—
PAA GO Zone term loans, net of debt issuance costs of $1, bearing a weighted-average interest rate of 1.3% (2)	199		—
Other	119		117
Total short-term debt	1,456		831
LONG-TERM DEBT
PAA senior notes, net of unamortized discounts and debt issuance costs of $57 and $62, respectively	8,326		9,071
PAA GO Zone term loans, net of debt issuance costs of $1, bearing a weighted-average interest rate of 1.3%	—		199
Other	63		112
Total long-term debt	8,389		9,382
Total debt (3)	$	9,845	$	10,213

(1)We classified these commercial paper notes as short-term as of June 30, 2021 and December 31, 2020, respectively, and these credit facility borrowings as short-term as of December 31, 2020, as these notes and borrowings were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.

(2)The PAA GO Zone term loans were initially assumed by a subsidiary of PAA in connection with the acquisition of the Southern Pines natural gas storage facility. In connection with the sale of that facility, the loans were repaid on August 2, 2021. See Note 12 for additional information.

(3)PAA’s fixed-rate senior notes had a face value of approximately $9.1 billion at both June 30, 2021 and December 31, 2020. We estimated the aggregate fair value of these notes as of June 30, 2021 and December 31, 2020 to be approximately $10.0 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 credit facilities, commercial paper program and GO Zone term loans approximates fair value as interest rates reflect current market rates. The fair value estimates for PAA’s senior notes, credit facilities, commercial paper program and GO Zone term loans are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

Borrowings and Repayments

Total borrowings under the PAA credit facilities and commercial paper program for the six months ended June 30, 2021 and 2020 were approximately $26.1 billion and $12.6 billion, respectively. Total repayments under the PAA credit facilities and commercial paper program were approximately $26.4 billion and $13.0 billion for the six months ended June 30, 2021 and 2020, 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.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Letters of Credit

In connection with our supply and logistics 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 June 30, 2021 and December 31, 2020, we had outstanding letters of credit of $81 million and $129 million, respectively.

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, 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 Common Equity Repurchase Program (2)	—	—	(350,000)
Other	—	—	25,431
Outstanding at March 31, 2021	194,098,315	50,777,990	547,623,124
Exchange Right exercises (1)	25,554	(25,554)	—
Redemption Right exercises (1)	—	(535,009)	535,009
Repurchase of common units by a subsidiary under Common Equity Repurchase Program	—	—	(4,940,592)
Other	—	—	256,321
Outstanding at June 30, 2021	194,123,869	50,217,427	543,473,862

 

	Class A Shares	Class B Shares	Class C Shares
Outstanding at December 31, 2019	182,138,592	65,785,702	549,538,139
Conversion of AAP Management Units (1)	—	559,768	—
Exchange Right exercises (1)	2,101,487	(2,101,487)	—
Redemption Right exercises (1)	—	(1,206,599)	1,206,599
Other	—	—	24,431
Outstanding at March 31, 2020	184,240,079	63,037,384	550,769,169
Conversion of AAP Management Units (1)	—	35,349	—
Redemption Right exercises (1)	—	(40,679)	40,679
Other	20,099	—	27,292
Outstanding at June 30, 2020	184,260,178	63,032,054	550,837,140

(1)See Note 12 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for information regarding conversions of AAP Management Units, Exchange Rights and Redemption Rights.

(2)Trades for these units were executed in late December 2020, but settled in early January 2021.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Distributions

The following table details distributions to our Class A shareholders paid during or pertaining to the first six months of 2021 (in millions, except per share data):

Distribution Payment Date	Distributions to Class A Shareholders		Distributions per Class A Share
August 13, 2021 (1)	$	35	$	0.18
May 14, 2021	$	35	$	0.18
February 12, 2021	$	35	$	0.18

(1)Payable to shareholders of record at the close of business on July 30, 2021 for the period from April 1, 2021 through June 30, 2021.

Consolidated Subsidiaries

Noncontrolling Interests in Subsidiaries

As of June 30, 2021, noncontrolling interests in our subsidiaries consisted of (i) limited partner interests in PAA including a 69% interest in PAA’s common units and PAA’s Series A preferred units combined and 100% of PAA’s Series B preferred units, (ii) an approximate 21% limited partner interest in AAP and (iii) a 33% interest in Red River Pipeline Company LLC (“Red River LLC”).

Common Equity Repurchase Program

PAA repurchased 5,290,592 common units under the Common Equity Repurchase Program (the “Program”) through open market purchases that settled during the six months ended June 30, 2021. The total purchase price of these repurchases was $53 million, including commissions and fees. The repurchased common units were canceled immediately upon acquisition, as were the Class C shares held by PAA associated with the repurchased common units. At June 30, 2021, the remaining available capacity under the Program was $397 million. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for additional information regarding the Program.

PAA’s capital attributable to AAP was adjusted, in accordance with ASC 810, to reflect the accretion of its interest in PAA as a result of the repurchase of common units from public unitholders. Such adjustment is recognized by PAGP in proportion to its ownership interest in AAP, which results in a net increase in partners’ capital attributable to PAGP.

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 six months of 2021 (in millions, except per unit data):

	Series A Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit
August 13, 2021 (1)	$	37	$	0.525
May 14, 2021	$	37	$	0.525
February 12, 2021	$	37	$	0.525

(1)Payable to unitholders of record at the close of business on July 30, 2021 for the period from April 1, 2021 through June 30, 2021. At June 30, 2021, such amount was accrued as distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 17, 2021	$	24.5	$	30.625

At June 30, 2021, approximately $6 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 six months of 2021 (in millions, except per unit data):

	Distributions						Cash Distribution  per Common Unit
	Common Unitholders				Total Cash Distribution
Distribution Payment Date	Public		AAP
August 13, 2021 (1)	$	85	$	44	$	129	$	0.18
May 14, 2021	$	86	$	44	$	130	$	0.18
February 12, 2021	$	86	$	44	$	130	$	0.18

(1)Payable to unitholders of record at the close of business on July 30, 2021 for the period from April 1, 2021 through June 30, 2021.

AAP Distributions. The following table details the distributions to AAP’s partners paid during or pertaining to the first six months of 2021 from distributions received from PAA (in millions):

	Distributions to AAP’s Partners
Distribution Payment Date	Noncontrolling Interests		PAGP		Total Cash Distribution
August 13, 2021 (1)	$	9	$	35	$	44
May 14, 2021	$	9	$	35	$	44
February 12, 2021	$	9	$	35	$	44

(1)Payable to unitholders of record at the close of business on July 30, 2021 for the period from April 1, 2021 through June 30, 2021.

Other Distributions. During the six months ended June 30, 2021, we paid distributions of $6 million to noncontrolling interests in Red River Pipeline Company LLC.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 June 30, 2021 and December 31, 2020, 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 June 30, 2021, net derivative positions related to these activities included:

•A net long position of 1.6 million barrels associated with our crude oil purchases, which was unwound ratably during July 2021 to match monthly average pricing.

•A net short time spread position of 8.4 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through September 2022.

•A net crude oil basis spread position of 8.6 million barrels at multiple locations through December 2022. These derivatives allow us to lock in grade and location basis differentials.

•A net short position of 16.2 million barrels through December 2022 related to anticipated net sales of crude oil and NGL inventory.

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 June 30, 2021:

	Notional Volume
	(Short)/Long	Remaining Tenor
Natural gas purchases	51.9 Bcf	December 2022
Propane sales	(9.0) MMbls	December 2022
Butane sales	(2.6) MMbls	December 2022
Condensate sales (WTI position)	(0.8) MMbls	December 2022
Fuel gas requirements (1)	10.3 Bcf	December 2022
Power supply requirements (1)	0.7 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. A summary of the impact of our commodity derivatives recognized in earnings as follows (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Supply and Logistics segment revenues	$	(284)	$	(134)	$	(598)	$	15
Field operating costs	17		(1)		56		—
Net gain/(loss) from commodity derivative activity	$	(267)	$	(135)	$	(542)	$	15

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/(payable) (in millions):

	June 30, 2021		December 31, 2020
Initial margin	$	78	$	91
Variation margin posted/(returned)	369		290
Letters of credit	(40)		(63)
Net broker receivable/(payable)	$	407	$	318

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

	June 30, 2021								December 31, 2020
					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	$	205	$	(430)	$	407	$	182	$	71	$	(314)	$	318	$	75
Other long-term assets, net	6		—		—		6		5		—		—		5
Derivative Liabilities
Other current liabilities	3		(97)		—		(94)		9		(40)		—		(31)
Other long-term liabilities and deferred credits	7		(90)		—		(83)		—		(32)		—		(32)
Total	$	221	$	(617)	$	407	$	11	$	85	$	(386)	$	318	$	17

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 June 30, 2021 (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 June 30, 2021, there was a net loss of $223 million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the earnings recognition of the underlying hedged commodity transactions or (ii) 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 June 30, 2021; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Interest rate derivatives, net	$	(39)	$	19	$	29	$	(61)

At June 30, 2021, 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 $75 million. At December 31, 2020, the net fair value of these hedges totaled $46 million and was included in “Other long-term assets, net.”

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Currency Exchange Rate Risk Hedging

Because a significant portion of our Canadian business is conducted in CAD, we use foreign currency derivatives to minimize the risk of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts, forwards and options.

Our use of foreign currency derivatives include (i) derivatives we use to hedge currency exchange risk created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales and (ii) foreign currency exchange contracts we use to manage our Canadian business cash requirements.

The following table summarizes our open forward exchange contracts as of June 30, 2021 (in millions):

		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2021	$	144	$	177	$1.00 - $1.23
Forward exchange contracts that exchange USD for CAD:
	2021	$	142	$	172	$1.00 - $1.21

These derivatives are not designated in a hedging relationship for accounting purposes. As such, changes in fair value are recognized in earnings as a component of Supply and Logistics segment revenues. For the three months ended June 30, 2021 and 2020, the amounts recognized in earnings for our currency exchange rate hedges were gains of $2 million in each respective period. For the six months ended June 30, 2021 and 2020, the amounts recognized in earnings for our currency exchange rate hedges were a gain of $3 million and a loss of $4 million, respectively.

At June 30, 2021, the net fair value of these currency exchange rate hedges, which was included in “Other current assets” on our Condensed Consolidated Balance Sheet, totaled less than $1 million. At December 31, 2020, the net fair value of these currency exchange rate hedges, which was included in “Other current assets” on our Condensed Consolidated Balance Sheet, totaled $2 million.

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 June 30, 2021 and 2020, we recognized a gain of $77 million and a loss of $9 million, respectively. For the six months ended June 30, 2021 and 2020, we recognized net gains of $9 million and $17 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 $5 million and $14 million at June 30, 2021 and December 31, 2020, respectively. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for additional information regarding the 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 June 30, 2021								Fair Value as of December 31, 2020
Recurring Fair Value Measures (1)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivatives	$	(246)	$	(141)	$	(8)	$	(395)	$	(143)	$	(143)	$	(15)	$	(301)
Interest rate derivatives	—		75		—		75		—		46		—		46
Foreign currency derivatives	—		(1)		—		(1)		—		2		—		2
Preferred Distribution Rate Reset Option	—		—		(5)		(5)		—		—		(14)		(14)
Total net derivative asset/(liability)	$	(246)	$	(67)	$	(13)	$	(326)	$	(143)	$	(95)	$	(29)	$	(267)

(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 Supply and Logistics segment 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 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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Beginning Balance	$	(92)	$	(61)	$	(29)	$	(51)
Net gains/(losses) for the period included in earnings	77		18		9		8
Settlements	2		1		7		1
Ending Balance	$	(13)	$	(42)	$	(13)	$	(42)
Change in unrealized losses included in earnings relating to Level 3 derivatives still held at the end of the period	$	77	$	18	$	9	$	8

Note 9—Related Party Transactions

See Note 17 to our Consolidated Financial Statements included in Part IV of our 2020 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 and six months ended June 30, 2021 and 2020, 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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Revenues from related parties (1)	$	10	$	10	$	17	$	33
Purchases and related costs from related parties (1)	$	95	$	94	$	185	$	223

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

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

	June 30, 2021		December 31, 2020
Trade accounts receivable and other receivables, net from related parties (1)	$	29	$	34
Trade accounts payable to related parties (1) (2)	$	80	$	88

(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

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. 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.

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

At June 30, 2021, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled $159 million, of which $112 million was classified as short-term and $47 million was classified as long-term. At December 31, 2020, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident) totaled $141 million, of which $94 million was classified as short-term and $47 million was classified as long-term. Such short-term liabilities are reflected in “Trade accounts payable” and “Other current liabilities” and long-term liabilities are reflected in “Other long-term liabilities and deferred credits” on our Condensed Consolidated Balance Sheets. At June 30, 2021, we had recorded receivables totaling $114 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which $113 million was classified as short-term and $1 million was classified as long-term. At December 31, 2020, we had recorded $97 million of such receivables, of which $96 million was classified as short-term and $1 million was classified as long-term. Such short- and long-term receivables are reflected in “Trade accounts receivable and other receivables, net” and “Other long-term assets, net,” respectively, 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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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

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. The only pending matter relating to these proceedings is that the Superior Court indicated that it would conduct further hearings in 2021 on the issue of whether there were any “direct victims” of the spill that are entitled to restitution under applicable law. The Superior Court is currently in the process of conducting such hearings pursuant to a schedule that provides for various potential “direct victims” to present their claims to the Court on designated dates over the course of a several month period.

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. We are vigorously defending against those claims. A September 2020 trial date initially set by the Court has been postponed indefinitely due to COVID-19 related trial suspensions. In the second proceeding, the plaintiffs seek a declaratory judgment that Plains’ right-of-way agreements would not allow Plains to lay a new pipeline to replace Line 901 and/or the non-operating segment of Line 903 without paying additional compensation. No trial date has been set in that action.

In addition, four unitholder derivative lawsuits were filed by certain purported investors in PAA against PAGP and certain of PAA’s affiliates, officers and directors. After various claims were either dismissed or consolidated, one proceeding against PAGP remains pending in Delaware Chancery Court. Generally, the plaintiffs claim that PAGP failed to exercise proper oversight over the Partnership’s pipeline integrity efforts. We will continue to vigorously defend against the claim. No trial date has been set in this action.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

We have also received several other individual lawsuits and claims from companies, governmental agencies and individuals alleging damages arising out of the Line 901 incident. These lawsuits and claims generally seek restitution, compensatory and punitive damages, and/or injunctive relief. The majority of these lawsuits have been settled or dismissed by the court. Remaining claims include claims for lost revenue or profit asserted by a former oil producer that declared bankruptcy and shut in its offshore production platform following the Line 901 incident, a state agency that received royalties on oil produced from that platform until it was abandoned by its owner, and various companies and individuals who provided labor, goods, or services associated with oil production activities they claim were disrupted following the Line 901 incident. We are vigorously defending these suits. We may be subject to additional claims and lawsuits, which could materially impact the liabilities and costs we currently expect to incur as a result of the Line 901 incident.

Taking the foregoing into account, as of June 30, 2021, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $485 million, which includes actual and projected emergency response and clean-up costs, natural resource damage assessments, fines and penalties payable pursuant to the Consent Decree and certain third party claims settlements, as well as estimates for certain legal fees. 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 June 30, 2021, we had a remaining undiscounted gross liability of $104 million related to this event, which 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. Subject to such exclusions and deductibles, we believe that our coverage is adequate to cover the current estimated total emergency response and clean-up costs, claims settlement costs and remediation costs and we believe that this coverage is also adequate to cover any potential increase in the estimates for these costs that exceed the amounts currently identified. Through June 30, 2021, we had collected, subject to customary reservations, $250 million out of the approximate $360 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of June 30, 2021, we have recognized a receivable of approximately $110 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.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 11—Operating Segments

We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for a summary of the types of products and services from which each segment derives its revenues. Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below) and maintenance capital investment.

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 our proportionate share of the depreciation and amortization expense of unconsolidated entities, and further adjusted for certain selected items including (i) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance. Segment Adjusted EBITDA excludes depreciation and amortization.

Maintenance capital consists of 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.

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	Transportation		Facilities		Supply and Logistics		Intersegment Adjustment		Total
Three Months Ended June 30, 2021
Revenues:
External customers (1)	$	243	$	145	$	9,623	$	(81)	$	9,930
Intersegment (2)	310		99		—		81		490
Total revenues of reportable segments	$	553	$	244	$	9,623	$	—	$	10,420
Equity earnings in unconsolidated entities	$	31	$	2	$	—			$	33
Segment Adjusted EBITDA	$	433	$	140	$	5			$	578
Maintenance capital	$	20	$	14	$	3			$	37
Three Months Ended June 30, 2020
Revenues:
External customers (1)	$	234	$	149	$	2,925	$	(83)	$	3,225
Intersegment (2)	223		127		—		83		433
Total revenues of reportable segments	$	457	$	276	$	2,925	$	—	$	3,658
Equity earnings in unconsolidated entities	$	81	$	—	$	—			$	81
Segment Adjusted EBITDA	$	346	$	174	$	3			$	523
Maintenance capital	$	31	$	15	$	8			$	54
Six Months Ended June 30, 2021
Revenues:
External customers (1)	$	478	$	308	$	17,706	$	(179)	$	18,313
Intersegment (2)	561		207		1		179		948
Total revenues of reportable segments	$	1,039	$	515	$	17,707	$	—	$	19,261
Equity earnings in unconsolidated entities	$	117	$	4	$	—			$	121
Segment Adjusted EBITDA	$	821	$	311	$	(8)			$	1,124
Maintenance capital	$	47	$	20	$	6			$	73
Six Months Ended June 30, 2020
Revenues:
External customers (1)	$	532	$	323	$	10,833	$	(194)	$	11,494
Intersegment (2)	504		266		1		194		965
Total revenues of reportable segments	$	1,036	$	589	$	10,834	$	—	$	12,459
Equity earnings in unconsolidated entities	$	189	$	2	$	—			$	191
Segment Adjusted EBITDA	$	788	$	384	$	144			$	1,316
Maintenance capital	$	64	$	29	$	11			$	104

(1)Transportation revenues from External customers include tariff revenue from transporting volumes associated with certain inventory exchanges with our customers where our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for a discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenues from External customers presented above and adjusted those revenues out such that Total revenues from External customers reconciles to our Condensed Consolidated Statements of Operations. This presentation is consistent with the information provided to our CODM.

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(2)Segment revenues include intersegment amounts that are eliminated in Purchases and related costs and Field operating costs in our Condensed Consolidated Statements of Operations. 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/(loss) attributable to PAGP (in millions):

 

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Segment Adjusted EBITDA	$	578	$	523	$	1,124	$	1,316
Adjustments: (1)
Depreciation and amortization of unconsolidated entities (2)	(68)		(16)		(88)		(33)
Gains/(losses) from derivative activities and inventory valuation adjustments (3)	(163)		(90)		35		(121)
Long-term inventory costing adjustments (4)	27		51		68		(64)
Deficiencies under minimum volume commitments, net (5)	(6)		(7)		26		(6)
Equity-indexed compensation expense (6)	(4)		(5)		(9)		(8)
Net gain on foreign currency revaluation (7)	1		—		2		13
Significant transaction-related expenses (8)	(3)		—		(3)		(3)
Unallocated general and administrative expenses	(2)		(2)		(3)		(3)
Depreciation and amortization	(197)		(166)		(375)		(335)
Gains/(losses) on asset sales and asset impairments, net	(369)		1		(370)		(618)
Goodwill impairment losses	—		—		—		(2,515)
Gain on/(impairment of) investments in unconsolidated entities, net	—		(69)		—		(91)
Interest expense, net	(107)		(108)		(213)		(215)
Other income/(expense), net	84		18		23		(13)
Income/(loss) before tax	(229)		130		217		(2,696)
Income tax (expense)/benefit	17		7		(36)		140
Net income/(loss)	(212)		137		181		(2,556)
Net (income)/loss attributable to noncontrolling interests	143		(121)		(180)		1,991
Net income/(loss) attributable to PAGP	$	(69)	$	16	$	1	$	(565)

(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 investing activities, such as the purchase of linefill.

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(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 2020 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. See Note 8 for discussion regarding our currency exchange rate risk hedging activities.

(8)Includes expenses associated with the Permian Basin joint venture transaction announced in July 2021 and the acquisition of Felix Midstream LLC in 2020. See Note 12 for further discussion of the joint venture transaction and Note 7 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for additional discussion of the Felix Midstream LLC acquisition.

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 12—Acquisitions, Divestitures and Other Transactions

Asset Exchange

In June 2021, we closed on an asset exchange agreement (the “Asset Exchange”) with Inter Pipeline Ltd., through which we acquired additional interests in two straddle plants included in our Facilities segment that we currently operate, in exchange for a pipeline and related storage and truck offload facilities previously included in our Transportation segment and cash consideration of $32 million, including working capital and other adjustments. We recognized a gain of $106 million on the divestiture of the pipeline and related storage and truck offload facilities, which is included in “(Gains)/losses on asset sales and asset impairments, net” on our Condensed Consolidated Statement of Operations, based on the difference between the fair value of the divested assets and their carrying value.

Assets Held For Sale

In June 2021, we signed a definitive agreement to sell our Pine Prairie and Southern Pines natural gas storage facilities included in our Facilities segment for $850 million, subject to certain adjustments. As of June 30, 2021, we classified the assets related to this transaction (primarily “Property and equipment”), valued at the lower of the carrying amount or fair value less costs to sell, of approximately $832 million as assets held for sale on our Condensed Consolidated Balance Sheet (in “Other current assets”) with approximately $18 million of deferred losses on hedges remaining in other comprehensive income on our Condensed Consolidated Balance Sheet (in “Total partners’ capital”). This transaction closed on August 2, 2021.

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

Joint Venture Transaction

In July 2021, we entered into a definitive agreement with Oryx Midstream Holdings LLC (“Oryx Midstream”) pursuant to which we and Oryx Midstream intend to merge, in a cashless, debt-free transaction, our respective Permian Basin assets, operations and commercial activities into a newly formed joint venture, Plains Oryx Permian Basin LLC (“Plains Oryx Permian Basin”). The transaction will include all of Oryx’s Permian Basin assets and, with the exception of our long-haul pipeline systems and certain of our intra-basin terminal assets, the vast majority of our assets located within the Permian Basin. We will own 65% of Plains Oryx Permian Basin, operate the combined assets, and consolidate the financial results of the joint venture into our financial statements. Subject to satisfaction of customary and other closing conditions and receipt of regulatory approvals, the transactions contemplated by the merger agreement are expected to close in the fourth quarter of 2021.

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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 2020 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 

•Off-Balance Sheet Arrangements

•Recent Accounting Pronouncements

•Critical Accounting Policies and Estimates

•Forward-Looking Statements

Executive Summary

Company Overview

We are a Delaware limited partnership formed on July 17, 2013 that has elected to be taxed as a corporation for United States federal income tax purposes. As of June 30, 2021, our sole cash-generating assets consisted of (i) a 100% managing member interest in Plains All American GP LLC (“GP LLC”) that has also elected to be taxed as a corporation for United States federal income tax purposes and (ii) an approximate 79% limited partner interest in AAP through our direct ownership of approximately 193.1 million 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 June 30, 2021, directly owned a limited partner interest in PAA through its ownership of approximately 245.0 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, 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, NGL and natural gas. PAA’s business activities are conducted through three operating segments: Transportation, Facilities and Supply and Logistics. See “—Results of Operations—Analysis of Operating Segments” for further discussion.

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Overview of Operating Results, Capital Investments and Other Significant Activities

During the first six months of 2021, we recognized net income of $181 million as compared to a net loss of $2.556 billion recognized during the first six months of 2020.

The net loss for the 2020 period was primarily driven by goodwill impairment losses and non-cash impairment charges related to the write-down of certain pipeline and other long-lived assets, certain of our investments in unconsolidated entities, and assets upon classification as held for sale totaling approximately $3.24 billion. In addition, we recognized approximately $232 million of inventory valuation adjustments due to declines in commodity prices during the first quarter of 2020. The comparable six month 2021 period includes a net loss on asset sales and asset impairments of $370 million.

Results from our reporting segments during the first six months of 2021 decreased from the comparable 2020 period driven primarily by the impact of less favorable crude oil market conditions combined with lower realized NGL margins in our Supply and Logistics segment. In addition, our Facilities segment was unfavorably impacted by reduced NGL capacity utilization and market rates as well as the impact of asset sales. These unfavorable results were partially offset by favorable Transportation segment results that benefited from the collection of deficiency payments associated with minimum volume commitments and lower operating costs.

See further discussion of our operating results in the “—Results of Operations—Analysis of Operating Segments” and “—Other Income and Expenses” sections below. 

We invested $142 million in midstream infrastructure projects during the six months ended June 30, 2021, which primarily related to projects under development in the Permian Basin.

We paid cash distributions of approximately $365 million to our Class A shareholders and noncontrolling interests during the six months ended June 30, 2021.

PAA repurchased 5,290,592 common units for $53 million during the six months ended June 30, 2021, including $3 million associated with repurchases executed in December 2020 that settled in January 2021. See “—Liquidity and Capital Resources—Financing Activities—Common Equity Repurchase Program” for additional information.

Recent Events

In July 2021, we entered into a definitive agreement with Oryx Midstream pursuant to which we and Oryx Midstream intend to merge our respective Permian Basin assets, operations and commercial activities into a newly formed strategic joint venture, Plains Oryx Permian Basin. The transaction will include all of Oryx’s Permian Basin assets and, with the exception of our long-haul pipeline systems and certain of our intra-basin terminal assets, the vast majority of our assets located within the Permian Basin. We will own 65% of Plains Oryx Permian Basin, operate the combined assets, and consolidate the financial results of the joint venture into our financial statements. Structured as a debt-free joint venture entity through a cashless transaction, this aligns with our financial and portfolio optimization strategies, is near-term free cash flow accretive, and reinforces our ability to maximize free cash flow for our investors, while enhancing our overall credit profile. Subject to satisfaction of customary and other closing conditions and receipt of regulatory approvals, the transactions contemplated by the merger agreement are expected to close in the fourth quarter of 2021.

On August 2, 2021, we completed the sale of our Pine Prairie and Southern Pines natural gas storage facilities for $850 million, subject to certain adjustments. See Note 12 to our Condensed Consolidated Financial Statements for additional information.

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Results of Operations

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 June 30,				Variance				Six Months Ended June 30,				Variance
	2021		2020		$		%		2021		2020		$		%
Transportation Segment Adjusted EBITDA (1)	$	433	$	346	$	87	25	%	$	821	$	788	$	33	4	%
Facilities Segment Adjusted EBITDA (1)	140		174		(34)		(20)	%	311		384		(73)		(19)	%
Supply and Logistics Segment Adjusted EBITDA (1)	5		3		2		67	%	(8)		144		(152)		(106)	%
Adjustments:
Depreciation and amortization of unconsolidated entities	(68)		(16)		(52)		(325)	%	(88)		(33)		(55)		(167)	%
Selected items impacting comparability - Segment Adjusted EBITDA	(148)		(51)		(97)		**		119		(189)		308		**
Unallocated general and administrative expenses	(2)		(2)		—		—	%	(3)		(3)		—		—	%
Depreciation and amortization	(197)		(166)		(31)		(19)	%	(375)		(335)		(40)		(12)	%
Gains/(losses) on asset sales and asset impairments, net	(369)		1		(370)		**		(370)		(618)		248		40	%
Goodwill impairment losses	—		—		—		N/A		—		(2,515)		2,515		100	%
Gain on/(impairment of) investments in unconsolidated entities, net	—		(69)		69		100	%	—		(91)		91		100	%
Interest expense, net	(107)		(108)		1		1	%	(213)		(215)		2		1	%
Other income/(expense), net	84		18		66		367	%	23		(13)		36		277	%
Income tax (expense)/benefit	17		7		10		143	%	(36)		140		(176)		(126)	%
Net income/(loss)	(212)		137		(349)		(255)	%	181		(2,556)		2,737		107	%
Net (income)/loss attributable to noncontrolling interests	143		(121)		264		218	%	(180)		1,991		(2,171)		(109)	%
Net income/(loss) attributable to PAGP	$	(69)	$	16	$	(85)	**		$	1	$	(565)	$	566	100	%
Basic and diluted net income/(loss) per Class A share	$	(0.35)	$	0.09	$	(0.44)	(489)	%	$	—	$	(3.08)	$	3.08	100	%
Basic and diluted weighted average Class A shares outstanding	194		184		10		5	%	194		183		11		6	%

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

(1)Segment Adjusted EBITDA is the measure of segment performance that is utilized by our CODM to assess performance and allocate resources among our operating segments. This measure is adjusted for certain items, including those that our CODM believes impact comparability of results across periods. See Note 11 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.

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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 measure used by management is 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 (“Adjusted EBITDA”).

Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted EBITDA is reconciled to Net Income/(Loss), 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 Adjusted EBITDA provides useful information to investors regarding our performance and results of operations because this measure, 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. This non-GAAP measure 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 related to investing activities (such as the purchase of linefill) 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. This measure 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. 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.

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.”

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The following table sets forth the reconciliation of the non-GAAP financial performance measure Adjusted EBITDA from Net Income/(Loss) (in millions): 

	Three Months Ended June 30,				Variance				Six Months Ended June 30,				Variance
	2021		2020		$		%		2021		2020		$		%
Net income/(loss)	$	(212)	$	137	$	(349)	(255)	%	$	181	$	(2,556)	$	2,737	107	%
Add/(Subtract):
Interest expense, net	107		108		(1)		(1)	%	213		215		(2)		(1)	%
Income tax expense/(benefit)	(17)		(7)		(10)		(143)	%	36		(140)		176		126	%
Depreciation and amortization	197		166		31		19	%	375		335		40		12	%
(Gains)/losses on asset sales and asset impairments, net	369		(1)		370		**		370		618		(248)		(40)	%
Goodwill impairment losses	—		—		—		N/A		—		2,515		(2,515)		(100)	%
(Gain on)/impairment of investments in unconsolidated entities, net	—		69		(69)		(100)	%	—		91		(91)		(100)	%
Depreciation and amortization of unconsolidated entities (1)	68		16		52		325	%	88		33		55		167	%
Selected Items Impacting Comparability:
(Gains)/losses from derivative activities and inventory valuation adjustments	163		90		73		**		(35)		121		(156)		**
Long-term inventory costing adjustments	(27)		(51)		24		**		(68)		64		(132)		**
Deficiencies under minimum volume commitments, net	6		7		(1)		**		(26)		6		(32)		**
Equity-indexed compensation expense	4		5		(1)		**		9		8		1		**
Net gain on foreign currency revaluation	(1)		—		(1)		**		(2)		(13)		11		**
Significant transaction-related expenses	3		—		3		**		3		3		—		**
Selected Items Impacting Comparability - Segment Adjusted EBITDA (2)	148		51		97		**		(119)		189		(308)		**
(Gains)/losses from derivative activities (3)	(77)		9		(86)		**		(9)		(17)		8		**
Net (gain)/loss on foreign currency revaluation (4)	(6)		(23)		17		**		(13)		36		(49)		**
Net gain on early repayment of senior notes (5)	—		(3)		3		**		—		(3)		3		**
Selected Items Impacting Comparability - Adjusted EBITDA (6)	65		34		31		**		(141)		205		(346)		**
Adjusted EBITDA (6)	$	577	$	522	$	55	11	%	$	1,122	$	1,316	$	(194)	(15)	%

**    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)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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(3)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.

(4)During the periods presented, there were fluctuations in the value of the Canadian dollar (“CAD”) to the U.S. dollar (“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.

(5)Includes net gains recognized in connection with the repurchase of our outstanding senior notes on the open market.

(6)Other income/(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.

Analysis of Operating Segments

We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. Our CODM (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Adjusted EBITDA, segment volumes, Segment Adjusted EBITDA per barrel and maintenance capital investment.

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 our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects) of unconsolidated entities, and further adjusted for certain selected items including (i) the mark-to-market of derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance. See Note 11 to our Condensed Consolidated Financial Statements for a reconciliation of Segment Adjusted EBITDA to Net income/(loss) attributable to PAGP.

Revenues and expenses from our Canadian based subsidiaries, which use CAD as their functional currency, are translated at the prevailing average exchange rates for the month.

Transportation Segment

Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems and trucks. The Transportation segment generates revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The segment results generated by our tariff and other fee-related activities depend on the volumes transported on the pipeline and the level of the tariff and other fees charged, as well as the fixed and variable field costs of operating the pipeline.

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

Operating Results (1)	Three Months Ended June 30,				Variance				Six Months Ended June 30,				Variance
(in millions, except per barrel data)	2021		2020		$		%		2021		2020		$		%
Revenues	$	553	$	457	$	96	21	%	$	1,039	$	1,036	$	3	—	%
Purchases and related costs	(60)		(44)		(16)		(36)	%	(106)		(124)		18		15	%
Field operating costs	(140)		(140)		—		—	%	(245)		(302)		57		19	%
Segment general and administrative expenses (2)	(28)		(24)		(4)		(17)	%	(54)		(51)		(3)		(6)	%
Equity earnings in unconsolidated entities	31		81		(50)		(62)	%	117		189		(72)		(38)	%
Adjustments: (3)
Depreciation and amortization of unconsolidated entities	67		15		52		347	%	87		32		55		172	%
Losses from derivative activities and inventory valuation adjustments	(1)		(6)		5		**		(1)		—		(1)		**
Deficiencies under minimum volume commitments, net	7		4		3		**		(23)		—		(23)		**
Equity-indexed compensation expense	2		3		(1)		**		5		5		—		**
Significant transaction-related expenses	2		—		2		**		2		3		(1)		**
Segment Adjusted EBITDA	$	433	$	346	$	87	25	%	$	821	$	788	$	33	4	%
Maintenance capital	$	20	$	31	$	(11)	(35)	%	$	47	$	64	$	(17)	(27)	%
Segment Adjusted EBITDA per barrel	$	0.76	$	0.64	$	0.12	19	%	$	0.76	$	0.66	$	0.10	15	%

Average Daily Volumes	Three Months Ended June 30,		Variance			Six Months Ended June 30,		Variance
(in thousands of barrels per day) (4)	2021	2020	Volumes	%		2021	2020	Volumes	%
Tariff activities volumes
Crude oil pipelines (by region):
Permian Basin (5)	4,189	4,161	28	1	%	3,972	4,663	(691)	(15)	%
South Texas / Eagle Ford (5)	314	321	(7)	(2)	%	317	389	(72)	(19)	%
Central (5)	467	355	112	32	%	420	380	40	11	%
Gulf Coast	159	118	41	35	%	152	131	21	16	%
Rocky Mountain (5)	327	244	83	34	%	307	258	49	19	%
Western	256	215	41	19	%	246	209	37	18	%
Canada	294	242	52	21	%	305	285	20	7	%
Crude oil pipelines	6,006	5,656	350	6	%	5,719	6,315	(596)	(9)	%
NGL pipelines	181	194	(13)	(7)	%	182	190	(8)	(4)	%
Tariff activities total volumes	6,187	5,850	337	6	%	5,901	6,505	(604)	(9)	%
Trucking volumes	61	64	(3)	(5)	%	65	80	(15)	(19)	%
Transportation segment total volumes	6,248	5,914	334	6	%	5,966	6,585	(619)	(9)	%

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

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

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(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 the total volumes (attributable to our interest) for the period divided by the number of days in the period. 

(5)Region includes volumes (attributable to our interest) from pipelines owned by unconsolidated entities.

The following is a discussion of items impacting Transportation segment operating results for the periods indicated.

 Revenues, Purchases and Related Costs, Equity Earnings in Unconsolidated Entities and Volumes. The following table presents variances in revenues, purchases and related costs and equity earnings in unconsolidated entities by region:

	Favorable/(Unfavorable) Variance Three Months Ended June 30, 2021-2020						Favorable/(Unfavorable) Variance Six Months Ended June 30, 2021-2020
(in millions)	Revenues		Purchases and Related Costs		Equity Earnings		Revenues		Purchases and Related Costs		Equity Earnings
Permian Basin region	$	60	$	(16)	$	(11)	$	7	$	7	$	(17)
South Texas / Eagle Ford region	(1)		—		(2)		(8)		—		(12)
Central region	8		—		(21)		3		1		(24)
Gulf Coast region	2		—		(12)		2		—		(11)
Rocky Mountain region	8		—		(2)		12		—		(8)
Canada region	10		—		—		5		—		—
Other regions, NGL pipelines, trucking and pipeline loss allowance revenue	9		—		(2)		(18)		10		—
Total variance	$	96	$	(16)	$	(50)	$	3	$	18	$	(72)

•Permian Basin region. Revenues, net of purchases and related costs, (“net revenues”) increased by $44 million and $14 million for the three and six months ended June 30, 2021, respectively, compared to the same periods in 2020 primarily due to the recognition of revenue associated with minimum volume commitments. The recognition of previously deferred revenue associated with minimum volume commitments is reflected as an “Adjustment” in the table above as discussed further below under “—Adjustments: Deficiencies under minimum volume commitments, net.” The three-month comparative period was further favorably impacted by higher long-haul movements to Cushing, Oklahoma in the second quarter of 2021, as well as an increase in volumes on our gathering pipelines as a result of new connections and increased production, partially offset by lower volumes on our intra-basin pipelines. The six-month comparative period was further unfavorably impacted by lower volumes of crude oil produced in the Permian Basin in the first quarter of 2021, driven by the COVID-19 pandemic-related reset to production and compounded by shut-ins from the extreme winter weather event that occurred in February of 2021 (“Winter Storm Uri”).

Equity earnings decreased for the three and six months ended June 30, 2021 compared to the same periods in 2020 primarily due to our proportionate share of the write-off of costs associated with a capital project canceled during the second quarter of 2021, which is included in the table above as an “Adjustment” in “Depreciation and amortization of unconsolidated entities.” The six-month comparative period was further unfavorably impacted by depreciation expense and transition costs associated with phase one of the Wink to Webster pipeline being placed into service during the first quarter of 2021, partially offset by lower power costs related to Winter Storm Uri.

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•South Texas / Eagle Ford region. Revenues decreased for the six months ended June 30, 2021 compared to the same periods in 2020 due to lower production, including curtailments from Winter Storm Uri.

Equity earnings from our 50% interest in Eagle Ford Pipeline LLC decreased for the six months ended June 30, 2021 compared to the same period in 2020 due to a combination of lower joint tariff volumes from the Permian Basin via our Cactus I pipeline, and to a lesser extent, lower regional receipts, partially offset by the recognition of previously deferred revenue associated with minimum volume commitments. The recognition of such revenue is reflected as an “Adjustment” in the table above as discussed further below under “—Adjustments: Deficiencies under minimum volume commitments, net.”

•Central region. Revenues increased for the three and six months ended June 30, 2021 compared to the same periods in 2020 primarily due to higher volumes on certain of our pipelines in the region, including the Red River pipeline, as a result of an increase in committed volumes and an expansion placed into service in October 2020.

Equity earnings decreased for the three and six months ended June 30, 2021 compared to the same periods in 2020 primarily due our proportionate share of Diamond Pipeline’s write-off of costs associated with the cancellation of the Byhalia Connection construction project during the second quarter of 2021, which is included in the table above as an “Adjustment” in “Depreciation and amortization of unconsolidated entities.”

•Gulf Coast region. Equity earnings decreased for the three and six months ended June 30, 2021 compared to the same periods in 2020 primarily due to our proportionate share of Capline Pipeline’s write-off of costs associated with the cancellation of the Byhalia Connection construction project during the second quarter of 2021, which is included in the table above as an “Adjustment” in “Depreciation and amortization of unconsolidated entities.”

•Rocky Mountain region. Revenues increased for the three and six months ended June 30, 2021 compared to the same periods in 2020 primarily due to higher volumes.

Equity earnings decreased for the three and six months ended June 30, 2021 compared to the same periods in 2020 primarily due to the expiration of higher-tariff volume commitments in the current period on the White Cliffs pipeline, partially offset by higher volumes from committed shippers on the Saddlehorn pipeline.

•Canada region. Revenues increased for the three and six months ended June 30, 2021 compared to the same periods in 2020 primarily due to higher volumes from increased production and favorable foreign exchange impacts. Such favorable impacts were partially offset by a decrease in intersegment fees to reflect lower utilization and market rates, which had an offsetting favorable impact on our Supply and Logistics segment.

•Other regions, NGL pipelines, trucking and pipeline loss allowance revenue. The increase in net revenues for the three months ended June 30, 2021 compared to the same period in 2020 was primarily due to higher pipeline loss allowance revenue in 2021 primarily due to higher prices. The decrease in net revenues for the six months ended June 30, 2021 compared to the same period in 2020 was primarily due to lower pipeline loss allowance revenue due to lower volumes, partially offset by higher prices. Such unfavorable impacts were offset by lower trucking costs driven by lower volumes.

Adjustments: Deficiencies under minimum volume commitments, net. Many industry infrastructure projects developed and completed over the last several years were underpinned by long-term minimum volume commitment contracts whereby the shipper agreed to either: (i) ship and pay for certain stated volumes or (ii) pay the agreed upon price for a minimum contract quantity. Some of these agreements include make-up rights if the minimum volume is not met. If a counterparty has a make-up right associated with a deficiency, we bill the counterparty and defer the revenue attributable to the counterparty’s make-up right but record an adjustment to reflect such amount associated with the current period activity in Segment Adjusted EBITDA. We subsequently recognize the revenue, and record a corresponding reversal of the adjustment, 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.

For the three months ended June 30, 2021 and 2020, amounts billed to counterparties exceeded revenue recognized during the periods that was previously deferred. For the six months ended June 30, 2021, the recognition of previously deferred revenue exceeded amounts billed to counterparties associated with deficiencies under minimum volume commitments.

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Field Operating Costs. The decrease in field operating costs for the six months ended June 30, 2021 compared to the same period in 2020 was primarily due to (i) lower power costs, including the impact of gains related to hedged power costs resulting from Winter Storm Uri and (ii) streamlining efforts which have resulted in decreases in variable costs and maintenance and chemicals and additives costs.

Segment General and Administrative Expenses. The increase in segment general and administrative expenses for the three and six months ended June 30, 2021 compared to the same periods in 2020 was primarily due to increased information systems costs and reduced wage subsidies received by our Canadian subsidiary in the current periods.

Maintenance Capital. Maintenance capital consists of 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. The decrease in maintenance capital spending for the three and six months ended June 30, 2021 compared to the same periods in 2020 was primarily due to timing changes, the completion of multi-year reliability improvement programs and application of updated regulatory guidance, among other factors.

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Facilities Segment

Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services primarily for crude oil, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. The Facilities segment generates revenue through a combination of month-to-month and multi-year agreements.

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

Operating Results (1)	Three Months Ended June 30,				Variance				Six Months Ended June 30,				Variance
(in millions, except per barrel data)	2021		2020		$		%		2021		2020		$		%
Revenues	$	244	$	276	$	(32)	(12)	%	$	515	$	589	$	(74)	(13)	%
Purchases and related costs	(3)		(7)		4		57	%	(6)		(10)		4		40	%
Field operating costs	(74)		(72)		(2)		(3)	%	(151)		(159)		8		5	%
Segment general and administrative expenses (2)	(21)		(27)		6		22	%	(41)		(46)		5		11	%
Equity earnings in unconsolidated entities	2		—		2		N/A		4		2		2		100	%
Adjustments: (3)
Depreciation and amortization of unconsolidated entities	1		1		—		**		1		1		—		**
(Gains)/losses from derivative activities	(9)		(1)		(8)		**		(10)		—		(10)		**
Deficiencies under minimum volume commitments, net	(1)		3		(4)		**		(3)		6		(9)		**
Equity-indexed compensation expense	1		1		—		**		2		1		1		**
Segment Adjusted EBITDA	$	140	$	174	$	(34)	(20)	%	$	311	$	384	$	(73)	(19)	%
Maintenance capital	$	14	$	15	$	(1)	(7)	%	$	20	$	29	$	(9)	(31)	%
Segment Adjusted EBITDA per barrel	$	0.40	$	0.47	$	(0.07)	(15)	%	$	0.45	$	0.51	$	(0.06)	(12)	%

	Three Months Ended June 30,		Variance			Six Months Ended June 30,		Variance
Volumes (4)	2021	2020	Volumes	%		2021	2020	Volumes	%
Liquids storage (average monthly capacity in millions of barrels) (5)	100	109	(9)	(8)	%	100	110	(10)	(9)	%
Natural gas storage (average monthly working capacity in billions of cubic feet)	70	67	3	4	%	69	65	4	6	%
NGL fractionation (average volumes in thousands of barrels per day)	129	122	7	6	%	136	138	(2)	(1)	%
Facilities segment total volumes (average monthly volumes in millions of barrels) (6)	115	124	(9)	(7)	%	115	125	(10)	(8)	%

**    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.

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(4)Average monthly volumes are calculated as total volumes for the period divided by the number of months in the period. 

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

(6)Facilities segment total volumes are calculated as the sum of: (i) liquids storage capacity; (ii) natural gas storage working capacity divided by 6 to account for the 6:1 mcf of natural gas to crude Btu equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and (iii) NGL fractionation volumes multiplied by the number of days in the period and divided by the number of months in the period.

The following is a discussion of items impacting Facilities segment operating results.

Revenues, Purchases and Related Costs and Volumes. Variances in net revenues and average monthly volumes were primarily driven by the following:

•NGL Operations. Revenues from our NGL operations decreased by $16 million and $57 million for the three and six months ended June 30, 2021, respectively, compared to the same periods in 2020 primarily due to lower intersegment facility fee revenues due to rate decreases at certain of our storage, fractionation and processing facilities to reflect lower utilization and market rates (which had an offsetting favorable impact on our Supply and Logistics segment). The six-month comparative period was further unfavorably impacted by (i) a benefit in the 2020 comparative period from the receipt of a deficiency payment of approximately $20 million upon the expiration of a multi-year contract and (ii) the sale of certain NGL terminals in the second quarter of 2020. Such unfavorable impacts were partially offset for the three- and six-month comparative periods by more favorable foreign exchange impacts in 2021 of approximately $13 million and $19 million, respectively, and, for the six-month comparative period, gains at certain of our fractionation facilities in the first quarter of 2021.

•Crude Oil Storage. Revenues from our crude oil storage operations decreased by $16 million and $31 million for the three and six months ended June 30, 2021, respectively, compared to the same periods in 2020 primarily due to the sale of our Los Angeles Basin terminals in October of 2020.

•Natural Gas Storage. Net revenues increased by $17 million for the six months ended June 30, 2021 compared to the same period in 2020 primarily due to increased margins from hub activities in the first quarter of 2021 related to Winter Storm Uri.

Field Operating Costs. The decrease in field operating costs for the six months ended June 30, 2021 compared to the same period in 2020 was primarily due to (i) the sale of our Los Angeles Basin terminals and certain NGL terminals, (ii) decreased power costs related to derivative activity and (iii) reduced activity at our rail terminals.

Segment General and Administrative Expenses. The decrease in segment general and administrative expenses for the three and six months ended June 30, 2021 compared to the same periods in 2020 was primarily due to the impact of 2020 legal costs, partially offset by reduced wage subsidies received by our Canadian subsidiary in the current period.

Maintenance Capital. The decrease in maintenance capital spending for the three and six months ended June 30, 2021 compared to the same periods in 2020 was primarily due to timing changes, the impact of asset sales, the completion of multi-year reliability improvement programs and application of updated regulatory guidance, among other factors.

Supply and Logistics Segment

Revenues from our Supply and Logistics segment activities reflect the sale of gathered and bulk-purchased crude oil, as well as sales of NGL volumes. Generally, our segment results are impacted by (i) increases or decreases in our Supply and Logistics segment volumes (which consist of lease gathering crude oil purchases volumes and NGL sales volumes), (ii) the overall strength, weakness and volatility of market conditions, including regional differentials, (iii) the relationship between NGL prices and natural gas prices and (iv) the effects of competition on our lease gathering and NGL margins. In addition, the execution of our risk management strategies in conjunction with our assets can provide upside in certain markets.

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The following tables set forth our operating results from our Supply and Logistics segment:

Operating Results (1)	Three Months Ended June 30,				Variance				Six Months Ended June 30,				Variance
(in millions, except per barrel data)	2021		2020		$		%		2021		2020		$		%
Revenues	$	9,623	$	2,925	$	6,698	229	%	$	17,707	$	10,834	$	6,873	63	%
Purchases and related costs	(9,700)		(2,903)		(6,797)		(234)	%	(17,497)		(10,717)		(6,780)		(63)	%
Field operating costs	(42)		(45)		3		7	%	(83)		(103)		20		19	%
Segment general and administrative expenses (2)	(23)		(21)		(2)		(10)	%	(44)		(44)		—		—	%
Adjustments: (3)
(Gains)/losses from derivative activities and inventory valuation adjustments	173		97		76		**		(24)		121		(145)		**
Long-term inventory costing adjustments	(27)		(51)		24		**		(68)		64		(132)		**
Equity-indexed compensation expense	1		1		—		**		2		2		—		**
Net (gain)/loss on foreign currency revaluation	(1)		—		(1)		**		(2)		(13)		11		**
Significant transaction-related expenses	1		—		1		**		1		—		1		**
Segment Adjusted EBITDA	$	5	$	3	$	2	67	%	$	(8)	$	144	$	(152)	(106)	%
Maintenance capital	$	3	$	8	$	(5)	(63)	%	$	6	$	11	$	(5)	(45)	%
Segment Adjusted EBITDA per barrel	$	0.04	$	0.03	$	0.01	33	%	$	(0.03)	$	0.58	$	(0.61)	(105)	%

Average Daily Volumes (4)	Three Months Ended June 30,		Variance			Six Months Ended June 30,		Variance
(in thousands of barrels per day)	2021	2020	Volumes	%		2021	2020	Volumes	%
Crude oil lease gathering purchases	1,352	1,077	275	26	%	1,264	1,198	66	6	%
NGL sales	112	94	18	19	%	165	156	9	6	%
Supply and Logistics segment total volumes	1,464	1,171	293	25	%	1,429	1,354	75	6	%

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

(1)Revenues and costs 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 the total volumes for the period divided by the number of days in the period. 

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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
Three Months Ended June 30, 2021	$	59	$	74
Three Months Ended June 30, 2020	$	(38)	$	40
Six Months Ended June 30, 2021	$	48	$	74
Six Months Ended June 30, 2020	$	(38)	$	63

Our crude oil and NGL supply, logistics and distribution operations 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 for both sales and purchases, revenues and costs related to purchases will fluctuate with market prices. However, the margins related to those sales and purchases will not necessarily have a corresponding increase or decrease. Additionally, net revenues are impacted by net gains and losses from certain derivative activities and inventory valuation and costing adjustments.

Our NGL operations are sensitive to weather-related demand, particularly during the approximate five-month peak heating season of November through March, and temperature differences from period-to-period may have a significant effect on NGL demand and thus our financial performance.

Segment Adjusted EBITDA and Volumes. The following summarizes the significant items impacting our Supply and Logistics Segment Adjusted EBITDA:

•Crude Oil Operations. Net revenues from our crude oil operations were slightly lower in the three-month period as contango margins were better in the 2020 period; however, this was largely offset by lease gathering margins and certain differentials that were more favorable in the 2021 period. For the six months ended June 30, 2021 compared to the same period in 2020, net revenues from our crude oil operations were lower due to less favorable market conditions.

•NGL Operations. Net revenues from our NGL operations were slightly higher for the three months ended June 30, 2021 compared to the same period in 2020 due to a decrease in intersegment fees. Net revenues from our NGL operations decreased for the six months ended June 30, 2021 compared to the same period in 2020, primarily due to lower realized margins on our NGL sales activities, partially offset by a decrease in intersegment fees. The intersegment fees were reduced in the 2021 periods to reflect lower utilization and market rates, and had an offsetting unfavorable impact on our Facilities and Transportation segments.

•Impact from Certain Derivative Activities and Inventory Valuation Adjustments. The impact from certain derivative activities on our net revenues includes mark-to-market and other gains and losses resulting from certain derivative instruments that are related to underlying activities in another period (or the reversal of mark-to-market gains and losses from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable. See Note 8 to our Condensed Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities. These gains and losses impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.

•Long-Term Inventory Costing Adjustments. Our net revenues are impacted by changes in the weighted average cost of our crude oil and NGL inventory pools that result from price movements during the periods. These costing adjustments related to long-term inventory necessary to meet our minimum inventory requirements in third-party assets and other working inventory that was 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. These costing adjustments impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.

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•Foreign Exchange Impacts. Our net revenues are impacted by 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 within our Canadian operations. These gains and losses impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.

•Field Operating Costs. The decrease in field operating costs for the six months ended June 30, 2021 compared to the same period in 2020 was primarily due to lower trucking costs due to more supply connected to pipelines resulting in lower trucking activity in the 2021 period.

Other Income and Expenses

Depreciation and Amortization

The increase in depreciation and amortization expense for the three and six months ended June 30, 2021 compared to the same periods in 2020 was largely driven by a reduction in the useful lives of certain assets. See Note 2 to our Condensed Consolidated Financial Statements for additional information.

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

The net loss on asset sales and asset impairments for the three and six months ended June 30, 2021, was primarily driven by an approximate $475 million non-cash impairment charge related to the write-down of our Pine Prairie and Southern Pines natural gas storage facilities upon classification as held for sale during the second quarter, which were subsequently sold on August 2, 2021, partially offset by a gain of $106 million related to the Asset Exchange transaction. See Note 12 to our Condensed Consolidated Financial Statements for additional information. The net loss on asset sales and asset impairments for the six months ended June 30, 2020 was largely driven by (i) non-cash impairment losses of approximately $446 million related to the write-down of certain pipeline and other long-lived assets due to macroeconomic and geopolitical conditions including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply, as well as changing market conditions and expected lower crude oil production in certain regions, and (ii) approximately $167 million of impairment losses recognized on assets upon classification as held for sale during the quarter, which were subsequently sold.

Goodwill Impairment Losses

During the first quarter of 2020, we recognized a goodwill impairment charge of $2.515 billion, representing the entire balance of goodwill.

Gain on/(Impairment of) Investments in Unconsolidated Entities, Net

During the three and six months ended June 30, 2020, we recognized losses of $69 million and $112 million, respectively, related to the write-down of certain of our investments in unconsolidated entities. Additionally, during the six months ended June 30, 2020, we recognized a gain of $21 million related to our sale of a 10% interest in Saddlehorn Pipeline Company, LLC.

Other Income/(Expense), Net

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Gain/(loss) related to mark-to-market adjustment of the Preferred Distribution Rate Reset Option (1)	$	77	$	(9)	$	9	$	17
Net gain/(loss) on foreign currency revaluation (2)	6		23		13		(36)
Other	1		4		1		6
	$	84	$	18	$	23	$	(13)

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(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)/Benefit

The income tax expense for the six months ended June 30, 2021 compared to the income tax benefit for the six months ended June 30, 2020 was primarily due to the impact of higher earnings at PAA on income attributable to PAGP in the first quarter of 2021 compared to the first quarter of 2020, which was partially offset by the impact of lower earnings at PAA on income attributable to PAGP for the second quarter of 2021 compared to the second quarter of 2020.

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 our divestiture program and in the past we 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 June 30, 2021, although we had a working capital deficit of $485 million, we had approximately $2.6 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 June 30, 2021
Availability under PAA senior unsecured revolving credit facility (1) (2)	$	1,532
Availability under PAA senior secured hedged inventory facility (1) (2)	1,387
Amounts outstanding under PAA commercial paper program	(388)
Subtotal	2,531
Cash and cash equivalents	26
Total	$	2,557

(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 $68 million and $13 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 its term loans 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 June 30, 2021.

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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 2020 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 2020 Annual Report on Form 10-K.

Net cash provided by operating activities for the first six months of 2021 and 2020 was $1.023 billion and $972 million, respectively, and primarily resulted from earnings from our operations. Additionally, during the six months ended June 30, 2020, we increased the volume of our crude oil inventory to be stored during the contango market; however, this increase was offset by lower prices for our inventory stored at the end of the current period compared to the end of 2019.

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 our divestiture program. 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):

	Six Months Ended June 30,
	2021		2020
Investment capital (1) (2)	$	142	$	654
Maintenance capital (1)	73		104
Acquisition capital (3)	32		308
	$	247	$	1,066

(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.

(3)Acquisition capital for 2021 represents the cash consideration paid as part of the Asset Exchange transaction. See Note 12 to our Condensed Consolidated Financial Statements for additional information. Acquisition capital for 2020 primarily includes Felix Midstream LLC, a crude oil gathering system located in the Delaware Basin.

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2021 Investment and Maintenance Capital. Total projected investment capital for the year ended December 31, 2021 is $325 million, a majority of which will be invested in our fee-based Transportation and Facilities segments. Additionally, maintenance capital for the full year of 2021 is projected to be $180 million. We expect to fund our 2021 investment and maintenance capital expenditures with retained cash flow and proceeds from assets sold as part of our divestiture program.

Divestitures

We continue to evaluate potential sales of non-core assets and/or sales of partial interests in assets to strategic joint venture partners. The following table summarizes the proceeds received during the first six months of 2021 and 2020 from sales of assets, which were previously reported in our Transportation and Facilities segments (in millions):

	Six Months Ended June 30,
	2021		2020
Proceeds from divestitures	$	22	$	245

Proceeds from divestitures were used to reduce debt levels and fund our investment capital projects.

On August 2, 2021, we closed the sale of our Pine Prairie and Southern Pines natural gas storage facilities for $850 million, subject to certain adjustments. See Note 12 to our Condensed Consolidated Financial Statements for additional information.

Ongoing Activities Related to Strategic Transactions

We are continuously engaged in the evaluation of potential transactions that support our current business strategy. While in the past such transactions have included acquisitions and large capital projects, consistent with our current strategic focus on capital discipline, leverage reduction, portfolio optimization and free cash flow generation, we are currently primarily focused on evaluating whether we should (i) sell assets that we regard as non-core or that we believe might be a better fit with the business and/or assets of a third-party buyer or (ii) sell partial interests in assets to strategic joint venture partners, in each case to optimize our asset portfolio and strengthen our balance sheet and leverage metrics. With respect to a potential divestiture, we may also conduct an auction process or may negotiate a transaction with one or a limited number of potential buyers. Such transactions could involve assets that, if sold or put into a joint venture or joint ownership arrangement, 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. However, 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, joint ventures, joint ownership arrangements and acquisitions involve risks that may adversely affect our business” included in our 2020 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.

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Borrowings and Repayments Under Credit Arrangements

During the six months ended June 30, 2021, we had net repayments on the PAA credit facilities and commercial paper program of $326 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.

During the six months ended June 30, 2020, we had net repayments on the PAA credit facilities and commercial paper program of $418 million. The net repayments resulted primarily from cash flow from operating activities, proceeds from asset sales and the issuance of $750 million, 3.80% senior notes in June 2020, which offset borrowings during the period related to funding needs for capital investments, inventory purchases and other general partnership purposes.

In connection with the sale of our Pine Prairie and Southern Pines natural gas storage facilities on August 2, 2021, we repaid PAA’s two GO Zone term loans totaling $200 million. See Note 12 for additional information regarding the sale of our natural gas storage facilities.

Common Equity Repurchase Program

PAA repurchased 5,290,592 common units under the Program through open market purchases that settled during the six months ended June 30, 2021. The total purchase price of these repurchases was $53 million, including commissions and fees. At June 30, 2021, the remaining available capacity under the Program was $397 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 June 30, 2021. 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 six months ended June 30, 2021.

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 June 30, 2021. 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 six months ended June 30, 2021.

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 2020 Annual Report on Form 10-K for additional discussion regarding distributions.

See Note 7 to our Condensed Consolidated Financial Statements for details of distributions paid during or pertaining to the first six months of 2021.

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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 June 30, 2021, noncontrolling interests in our subsidiaries consisted of (i) limited partner interests in PAA including a 69% interest in PAA’s common units and PAA’s Series A preferred units combined and 100% of PAA’s Series B preferred units, (ii) an approximate 21% limited partner interest in AAP and (iii) a 33% interest in Red River LLC. See Note 7 to our Condensed Consolidated Financial Statements for details of distributions to noncontrolling interests paid during or pertaining to the first six months of 2021.

Contingencies

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

Commitments

Contractual 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 13 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. The table below includes purchase obligations related to these activities. Where applicable, the amounts presented represent the net obligations associated with our counterparties (including giving effect to netting buy/sell contracts and those subject to a net settlement arrangement). 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 June 30, 2021 (in millions):

	Remainder of 2021		2022		2023		2024		2025		2026 and Thereafter		Total
Long-term debt and related interest payments (1)	$	402	$	1,137	$	1,461	$	1,083	$	1,300	$	8,337	$	13,720
Leases (2)	54		102		78		64		49		299		646
Other obligations (3)	197		408		329		282		269		935		2,420
Subtotal	653		1,647		1,868		1,429		1,618		9,571		16,786
Crude oil, NGL and other purchases (4)	11,039		19,545		18,494		17,483		14,182		54,615		135,358
Total	$	11,692	$	21,192	$	20,362	$	18,912	$	15,800	$	64,186	$	152,144

(1)Includes debt service payments, interest payments due on PAA’s senior notes and the commitment fee on assumed available capacity under the PAA credit facilities, as well as long-term borrowings under the PAA credit agreements and the PAA commercial paper program, if any. Although there may be short-term borrowings under the PAA credit agreements and the PAA commercial paper program, we historically repay and borrow at varying amounts. As such, we have included only the maximum commitment fee (as if no short-term borrowings were outstanding on the PAA credit agreements or the PAA commercial paper program) in the amounts above. For additional information regarding PAA’s debt obligations, see Note 6 to our Condensed Consolidated Financial Statements.

(2)Includes both operating and finance leases as defined by FASB guidance. Leases are primarily for (i) railcars, (ii) land, (iii) office space, (iv) storage tanks, (v) tractor trailers and (vi) vehicles. See Note 14 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for additional information.

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(3)Includes (i) other long-term liabilities, (ii) storage, processing and transportation agreements (including certain agreements for which the amount and timing of expected payments is subject to the completion of underlying construction projects), (iii) certain rights-of-way easements and (iv) noncancelable commitments related to our investment capital projects, including projected contributions for our share of the capital spending of our equity method investments. The storage, processing and transportation agreements include approximately $1.9 billion associated with agreements to store crude oil at facilities and transport crude oil or utilize capacity on pipelines owned by equity method investees at posted tariff rates or prices that we believe approximate market. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities. 

(4)Amounts are primarily based on estimated volumes and market prices based on average activity during June 2021. 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 supply and logistics 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 June 30, 2021 and December 31, 2020, we had outstanding letters of credit of approximately $81 million and $129 million, respectively.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements as defined by Item 303 of Regulation S-K.

Recent Accounting Pronouncements

See Note 2 to our Condensed Consolidated Financial Statements.

Critical Accounting Policies and Estimates

For a discussion regarding our critical accounting policies and estimates, see “Critical Accounting Policies and Estimates” under Item 7 of our 2020 Annual Report on Form 10-K.

Change in Accounting Estimate

In early 2021, we conducted a review to assess the useful lives of our property and equipment. Based on this review, we modified the useful lives of certain of our Pipelines and related facilities and Storage, terminal and rail facilities to useful lives of 10 to 50 years from useful lives of 10 to 70 years to reflect current expectations given our future operating and commercial outlook. This change in accounting estimate was effective January 1, 2021. Based on the net carrying amount of this property and equipment as of January 1, 2021, we currently estimate that these useful life reductions will prospectively increase annual depreciation expense by approximately $72 million.

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,

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natural gas liquids (“NGL”) and natural gas 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 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);

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

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

•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;

•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;

•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, legal constraints (including governmental orders or guidance), or other factors;

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

•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;

•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;

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

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

•the impact of current and future laws, rulings, governmental regulations, trade policies, accounting standards and statements, and related interpretations, including legislation or regulatory initiatives 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;

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•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;

•inability of producers, who have made commitments to our pipelines, to access capital to fund their drilling and completion activities;

•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 and the timing, pace and extent of economic recovery) that impact demand for crude oil, drilling and production activities and therefore the demand for the midstream services we provide and commercial opportunities available to us;

•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;

•significant under-utilization of our assets and facilities;

•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 storage of natural gas and the processing, transportation, fractionation, storage and marketing of natural gas liquids.

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 2020 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.

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 Supply and Logistics and Transportation segments. 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.

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•Natural gas

We utilize natural gas derivatives to hedge commodity price risk inherent in our Supply and Logistics and Facilities segments. Our objectives for these derivatives include hedging anticipated purchases of natural gas. 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 Supply and Logistics segment. 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 June 30, 2021 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	$	(254)	$	(71)	$	72
Natural gas	50		$	16	$	(16)
NGL and other	(191)		$	(67)	$	67
Total fair value	$	(395)

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 June 30, 2021, approximately $588 million, was subject to interest rate re-sets that generally range from one day to approximately one month. The average interest rate on variable rate debt that was outstanding during the six months ended June 30, 2021 was 0.8%, based upon rates in effect during such period. The fair value of our interest rate derivatives was a net asset of $75 million as of June 30, 2021. A 10% increase in the forward LIBOR curve as of June 30, 2021 would have resulted in an increase of $17 million to the fair value of our interest rate derivatives. A 10% decrease in the forward LIBOR curve as of June 30, 2021 would have resulted in a decrease of $17 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.

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Currency Exchange Rate Risk

We use foreign currency derivatives to hedge foreign currency exchange rate risk associated with our exposure to fluctuations in the USD-to-CAD exchange rate. Because a significant portion of our Canadian business is conducted in CAD, we use certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts, forwards and options. The fair value of our foreign currency derivatives was a liability of $1 million as of June 30, 2021. A 10% increase in the exchange rate (USD-to-CAD) would have resulted in an increase of less than $1 million to the fair value of our foreign currency derivatives. A 10% decrease in the exchange rate (USD-to-CAD) would have resulted in a decrease of less than $1 million to the fair value of our foreign currency derivatives. See Note 8 to our Condensed Consolidated Financial Statements for a discussion of our currency exchange rate risk hedging.

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 $5 million as of June 30, 2021. A 10% increase or decrease in the fair value would have an impact of less than $1 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 June 30, 2021, 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 second quarter of 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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.

62

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 2020 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 June 30, 2021, certain Legacy Owners or their permitted transferees exercised the Exchange Right, which resulted in the issuance of 25,554 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.

63

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	—	Third Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC dated as of February 16, 2017 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed February 21, 2017).
3.6	—	Amendment No. 1 dated October 1, 2018 to the Third Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed August 20, 2018).
3.7	—	Amendment No. 2 dated December 10, 2018 to the Third Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed December 11, 2018).
3.8	—	Amendment No. 3 dated November 21, 2019 to the Third Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed November 27, 2019).
3.9	—	Amendment No. 4 dated February 25, 2021 to the Third Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed March 3, 2021).
3.10	—	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).
3.11	—	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).
3.12	—	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).
3.13	—	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).
3.14	—	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).
3.15	—	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).

64

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	—	Twentieth Supplemental Indenture (3.65% Senior Notes due 2022) 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 4.1 to PAA’s Current Report on Form 8-K filed March 26, 2012).
4.5	—	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).
4.6	—	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).
4.7	—	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).
4.8	—	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).
4.9	—	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).
4.10	—	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).
4.11	—	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).
4.12	—	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).
4.13	—	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).
4.14	—	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).

65

4.15	—	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).
4.16	—	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).
4.17	—	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, 2020).
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.
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.

66

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)
August 6, 2021
	By:	/s/ Al Swanson
		Al Swanson,
		Executive Vice President and Chief Financial Officer of PAA GP Holdings LLC
		(Principal Financial Officer)
August 6, 2021
	By:	/s/ Chris Herbold
		Chris Herbold,
		Senior Vice President and Chief Accounting Officer of PAA GP Holdings LLC
		(Principal Accounting Officer)
August 6, 2021

67

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: August 6, 2021

/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: August 6, 2021

/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 June 30, 2021 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: August 6, 2021

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 June 30, 2021 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: August 6, 2021

XML

Cover Page - shares	6 Months Ended
	Jun. 30, 2021	Jul. 30, 2021
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2021
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)		194,123,869
Entity Central Index Key	0001581990
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q2

XML

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
CURRENT ASSETS
Cash and cash equivalents	$ 26	$ 25
Restricted cash	7	38
Trade accounts receivable and other receivables, net	3,897	2,553
Inventory	675	647
Other current assets	1,073	405
Total current assets	5,678	3,668
PROPERTY AND EQUIPMENT	17,577	18,620
Accumulated depreciation	(4,119)	(4,000)
Property and equipment, net	13,458	14,620
OTHER ASSETS
Investments in unconsolidated entities	3,745	3,764
Deferred tax asset	1,414	1,444
Linefill and base gas	909	982
Long-term operating lease right-of-use assets, net	344	378
Long-term inventory	210	130
Other long-term assets, net	1,054	965
Total assets	26,812	25,951
CURRENT LIABILITIES
Trade accounts payable	4,113	2,425
Short-term debt	1,456	831
Other current liabilities	594	999
Total current liabilities	6,163	4,255
LONG-TERM LIABILITIES
Senior notes, net	8,326	9,071
Other long-term debt, net	63	311
Long-term operating lease liabilities	289	317
Other long-term liabilities and deferred credits	910	807
Total long-term liabilities	9,588	10,506
COMMITMENTS AND CONTINGENCIES (NOTE 10)
PARTNERS’ CAPITAL
Noncontrolling interests	9,640	9,726
Total partners’ capital	11,061	11,190
Total liabilities and partners’ capital	26,812	25,951
Class A Shares
PARTNERS’ CAPITAL
Class A shareholders (194,123,869 and 194,051,436 shares outstanding, respectively)	$ 1,421	$ 1,464

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019
Class A Shares
Shares outstanding
Shares outstanding (shares)	194,123,869	194,098,315	194,051,436	184,260,178	184,240,079	182,138,592

XML

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
REVENUES
Total revenues	$ 9,930	$ 3,225	$ 18,313	$ 11,494
COSTS AND EXPENSES
Purchases and related costs	9,277	2,525	16,669	9,893
Field operating costs	252	253	471	557
General and administrative expenses	74	74	142	144
Depreciation and amortization	197	166	375	335
(Gains)/losses on asset sales and asset impairments, net	369	(1)	370	618
Goodwill impairment losses				2,515
Total costs and expenses	10,169	3,017	18,027	14,062
OPERATING INCOME/(LOSS)	(239)	208	286	(2,568)
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	33	81	121	191
Gain on/(impairment of) investments in unconsolidated entities, net		(69)		(91)
Interest expense (net of capitalized interest of $5, $5, $10 and $11, respectively)	(107)	(108)	(213)	(215)
Other income/(expense), net	84	18	23	(13)
INCOME/(LOSS) BEFORE TAX	(229)	130	217	(2,696)
Current income tax expense	(1)	(15)	(3)	(22)
Deferred income tax (expense)/benefit	18	22	(33)	162
NET INCOME/(LOSS)	(212)	137	181	(2,556)
Net (income)/loss attributable to noncontrolling interests	143	(121)	(180)	1,991
NET INCOME/(LOSS) ATTRIBUTABLE TO PAGP	$ (69)	$ 16	$ 1	$ (565)
Class A Shares
OTHER INCOME/(EXPENSE)
BASIC NET INCOME/(LOSS) PER CLASS A SHARE (in dollars per share)	$ (0.35)	$ 0.09	$ 0	$ (3.08)
DILUTED NET INCOME/(LOSS) PER CLASS A SHARE (in dollars per share)	$ (0.35)	$ 0.09	$ 0	$ (3.08)
BASIC WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING (in shares)	194	184	194	183
DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING (in shares)	194	184	194	183
Supply and Logistics
REVENUES
Total revenues	$ 9,623	$ 2,925	$ 17,706	$ 10,833
Transportation
REVENUES
Total revenues	162	151	299	338
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	31	81	117	189
Facilities
REVENUES
Total revenues	145	149	308	323
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	$ 2	$ 0	$ 4	$ 2

XML

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Income Statement [Abstract]
Interest expense, capitalized interest	$ 5	$ 5	$ 10	$ 11

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Statement of Comprehensive Income [Abstract]
Net income/(loss)	$ (212)	$ 137	$ 181	$ (2,556)
Other comprehensive income/(loss)		116	108	(212)
Comprehensive income/(loss)	(212)	253	289	(2,768)
Comprehensive (income)/loss attributable to noncontrolling interests	143	(207)	(259)	2,150
Comprehensive income/(loss) attributable to PAGP	$ (69)	$ 46	$ 30	$ (618)

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CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance	$ 11,499	$ 11,186	$ 11,190	$ 14,485
Total period activity		116	108	(212)
Ending balance	11,061	11,253	11,061	11,253
Derivative Instruments
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance			(258)	(259)
Reclassification adjustments			6	5
Unrealized gain (loss) on hedges			29	(61)
Total period activity			35	(56)
Ending balance	(223)	(315)	(223)	(315)
Translation Adjustments
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance			(657)	(674)
Currency translation adjustments			73	(157)
Total period activity			73	(157)
Ending balance	(584)	(831)	(584)	(831)
Other
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance			(3)	0
Other				1
Total period activity			0	1
Ending balance	(3)	1	(3)	1
Total
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance			(918)	(933)
Reclassification adjustments			6	5
Unrealized gain (loss) on hedges			29	(61)
Currency translation adjustments			73	(157)
Other				1
Total period activity			108	(212)
Ending balance	$ (810)	$ (1,145)	$ (810)	$ (1,145)

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
CASH FLOWS FROM OPERATING ACTIVITIES
Net income/(loss)	$ 181	$ (2,556)
Reconciliation of net income/(loss) to net cash provided by operating activities:
Depreciation and amortization	375	335
(Gains)/losses on asset sales and asset impairments, net	370	618
Goodwill impairment losses		2,515
Inventory valuation adjustments		232
Deferred income tax expense/(benefit)	33	(162)
(Gain)/loss on foreign currency revaluation	(15)	23
Settlement of terminated interest rate hedging instruments		(100)
Change in fair value of Preferred Distribution Rate Reset Option (Note 8)	(9)	(17)
Equity earnings in unconsolidated entities	(121)	(191)
Distributions on earnings from unconsolidated entities	211	236
(Gain on)/impairment of investments in unconsolidated entities, net		91
Other	27	15
Changes in assets and liabilities, net of acquisitions	(29)	(67)
Net cash provided by operating activities	1,023	972
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	(32)	(308)
Investments in unconsolidated entities	(71)	(314)
Additions to property, equipment and other	(182)	(472)
Proceeds from sales of assets	22	245
Other investing activities	(20)	(9)
Net cash used in investing activities	(283)	(858)
CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments under PAA commercial paper program (Note 6)	(159)	(93)
Net repayments under PAA senior secured hedged inventory facility (Note 6)	(167)	(325)
Proceeds from the issuance of PAA senior notes		748
Repayments of PAA senior notes		(17)
Repurchase of common units by a subsidiary (Note 7)	(53)
Distributions paid to Class A shareholders (Note 7)	(70)	(99)
Distributions paid to noncontrolling interests (Note 7)	(295)	(397)
Other financing activities	(28)	100
Net cash used in financing activities	(772)	(83)
Effect of translation adjustment	2	(9)
Net increase/(decrease) in cash and cash equivalents and restricted cash	(30)	22
Cash and cash equivalents and restricted cash, beginning of period	63	84
Cash and cash equivalents and restricted cash, end of period	33	106
Cash paid for:
Interest, net of amounts capitalized	202	213
Income taxes, net of amounts refunded	$ 27	$ 51

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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, 2019	$ 14,485	$ 12,330	$ 2,155
Increase (Decrease) in Partners' Capital
Net income/(loss)	(2,556)	(1,991)	(565)
Distributions (Note 7)	(496)	(397)	(99)
Deferred tax asset	13		13
Other comprehensive income/(loss)	(212)	(159)	(53)
Contributions from noncontrolling interests	10	10
Other	9	(5)	14
Ending balance at Jun. 30, 2020	11,253	9,788	1,465
Beginning balance at Mar. 31, 2020	11,186	9,729	1,457
Increase (Decrease) in Partners' Capital
Net income/(loss)	137	121	16
Distributions (Note 7)	(184)	(151)	(33)
Deferred tax asset	(7)		(7)
Other comprehensive income/(loss)	116	86	30
Contributions from noncontrolling interests	2	2
Other	3	1	2
Ending balance at Jun. 30, 2020	11,253	9,788	1,465
Beginning balance at Dec. 31, 2020	11,190	9,726	1,464
Increase (Decrease) in Partners' Capital
Net income/(loss)	181	180	1
Distributions (Note 7)	(365)	(295)	(70)
Deferred tax asset	(7)	0	(7)
Other comprehensive income/(loss)	108	79	29
Repurchase of common units by a subsidiary (Note 7)	(53)	(54)	1
Contributions from noncontrolling interests	1	1
Other	6	3	3
Ending balance at Jun. 30, 2021	11,061	9,640	1,421
Beginning balance at Mar. 31, 2021	11,499	9,976	1,523
Increase (Decrease) in Partners' Capital
Net income/(loss)	(212)	(143)	(69)
Distributions (Note 7)	(179)	(144)	(35)
Repurchase of common units by a subsidiary (Note 7)	(50)	(51)	1
Other	3	2	1
Ending balance at Jun. 30, 2021	$ 11,061	$ 9,640	$ 1,421

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Organization and Basis of Consolidation and Presentation

6 Months Ended

Jun. 30, 2021

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 June 30, 2021, 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 June 30, 2021, PAGP owned (i) a 100% managing member interest in Plains All American GP LLC (“GP LLC”), an entity that has also elected to be taxed as a corporation for United States federal income tax purposes and (ii) an approximate 79% limited partner interest in Plains AAP, L.P. (“AAP”) through our direct ownership of approximately 193.1 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 June 30, 2021, directly owned a limited partner interest in PAA through its ownership of approximately 245.0 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 crude oil, NGL and natural gas. PAA’s business activities are conducted through three operating segments: Transportation, Facilities and Supply and Logistics. 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 2020 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. 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.

The condensed consolidated balance sheet data as of December 31, 2020 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three and six months ended June 30, 2021 should not be taken as indicative of results to be expected for the entire year.

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 $1.414 billion and $1.444 billion as of June 30, 2021 and December 31, 2020, 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 six months ended June 30, 2021 or the year ended December 31, 2020. See Note 17 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for information regarding the Omnibus Agreement entered into by the Plains Entities on November 15, 2016.

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

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2021

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):

	June 30, 2021		December 31, 2020
Cash and cash equivalents	$	26	$	25
Restricted cash	7		38
Total cash and cash equivalents and restricted cash	$	33	$	63

Property and Equipment

During the first quarter of 2021, we modified the useful lives of certain of our Pipelines and related facilities and Storage, terminal and rail facilities to useful lives of 10 to 50 years from useful lives of 10 to 70 years to reflect current expectations given our future operating and commercial outlook. These depreciable life adjustments will prospectively increase depreciation expense. For the three and six months ended June 30, 2021, these reductions in useful lives increased depreciation expense by approximately $18 million and $36 million, respectively, which resulted in a decrease in net income attributable to PAGP of $4 million and $7 million, respectively, from what these amounts would have been absent the change in useful lives. The impact to both basic and diluted net income per Class A share was approximately $0.01 for the three months ended June 30, 2021 and approximately $0.04 for the six months ended June 30, 2021.

Recent Accounting Pronouncements

Except as discussed below and in our 2020 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the six months ended June 30, 2021 that are of significance or potential significance to us.

Accounting Standards Updates Adopted During the Period

We adopted the ASU listed below effective January 1, 2021 and our adoption did not have a material impact on our financial position, results of operations or cash flows (see Note 2 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for additional information regarding this ASU):

•ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes.

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Revenues and Accounts Receivable

6 Months Ended

Jun. 30, 2021

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 2020 Annual Report on Form 10-K for additional information regarding our types of revenues and policies for revenue recognition.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Supply and Logistics segment revenues from contracts with customers
Crude oil transactions	$	9,619	$	2,928	$	17,331	$	10,251
NGL and other transactions	285		127		969		555
Total Supply and Logistics segment revenues from contracts with customers	$	9,904	$	3,055	$	18,300	$	10,806

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Transportation segment revenues from contracts with customers
Tariff activities:
Crude oil pipelines	$	462	$	405	$	859	$	917
NGL pipelines	27		26		53		52
Total tariff activities	489		431		912		969
Trucking	20		22		42		57
Total Transportation segment revenues from contracts with customers	$	509	$	453	$	954	$	1,026

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Facilities segment revenues from contracts with customers
Crude oil, NGL and other terminalling and storage	$	154	$	176	$	324	$	357
NGL and natural gas processing and fractionation	70		80		142		190
Rail load / unload	8		8		20		22
Total Facilities segment revenues from contracts with customers	$	232	$	264	$	486	$	569

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 (as described above for each segment) to segment revenues and total revenues as disclosed in our Condensed Consolidated Statements of Operations (in millions):

Three Months Ended June 30, 2021	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	509	$	232	$	9,904	$	10,645
Other items in revenues	44		12		(281)		(225)
Total revenues of reportable segments	$	553	$	244	$	9,623	$	10,420
Intersegment revenues							(490)
Total revenues							$	9,930
Three Months Ended June 30, 2020	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	453	$	264	$	3,055	$	3,772
Other items in revenues	4		12		(130)		(114)
Total revenues of reportable segments	$	457	$	276	$	2,925	$	3,658
Intersegment revenues							(433)
Total revenues							$	3,225
Six Months Ended June 30, 2021	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	954	$	486	$	18,300	$	19,740
Other items in revenues	85		29		(593)		(479)
Total revenues of reportable segments	$	1,039	$	515	$	17,707	$	19,261
Intersegment revenues							(948)
Total revenues							$	18,313
Six Months Ended June 30, 2020	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	1,026	$	569	$	10,806	$	12,401
Other items in revenues	10		20		28		58
Total revenues of reportable segments	$	1,036	$	589	$	10,834	$	12,459
Intersegment revenues							(965)
Total revenues							$	11,494

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	June 30, 2021		December 31, 2020
Billed and collected	Liability	$	54	$	73
Unbilled (1)	N/A	21		4
Total		$	75	$	77

(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, 2020	$	501
Amounts recognized as revenue (1)	(384)
Additions	22
Balance at June 30, 2021	$	139

(1)Includes approximately $361 million associated with crude oil sales agreements that were entered into in the fourth quarter of 2020 in conjunction with storage arrangements and inventory exchanges, which were settled in the first quarter of 2021.

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 June 30, 2021 (in millions):

	Remainder of 2021		2022		2023		2024		2025		2026 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	92	$	174	$	174	$	151	$	129	$	461
Storage, terminalling and throughput agreement revenues	139		223		155		118		57		229
Total	$	231	$	397	$	329	$	269	$	186	$	690

(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;

•Supply and Logistics buy/sell arrangements with future committed volumes;

•All other Supply and Logistics contracts, due to the election of practical expedients related to variable consideration and short-term contracts;

•Transportation and Facilities contracts that are short-term;

•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 supply and logistics activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes.

During 2020, macroeconomic and geopolitical conditions including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply has caused liquidity issues impacting many energy companies, which in turn has increased the potential credit risks associated with certain counterparties with which we do business. 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 June 30, 2021 and December 31, 2020, 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):

	June 30, 2021		December 31, 2020
Trade accounts receivable arising from revenues from contracts with customers	$	3,177	$	2,317
Other trade accounts receivables and other receivables (1)	4,807		2,818
Impact due to contractual rights of offset with counterparties	(4,087)		(2,582)
Trade accounts receivable and other receivables, net	$	3,897	$	2,553

(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/(Loss) Per Class A Share

6 Months Ended

Jun. 30, 2021

Earnings Per Share [Abstract]

Net Income/(Loss) Per Class A Share

Net Income/(Loss) Per Class A Share

Basic net income/(loss) per Class A share is determined by dividing net income/(loss) 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/(loss) per Class A share is determined by dividing net income/(loss) attributable to PAGP by the diluted weighted average number of Class A shares outstanding during the period. For purposes of calculating diluted net income per Class A share, both the net income/(loss) attributable to PAGP and the diluted weighted average number of Class A shares outstanding consider the impact of possible future exchanges of (i) AAP units and the associated Class B shares into our Class A shares and (ii) 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 2020 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 2020 Annual Report on Form 10-K for information regarding PAGP LTIP awards.

On a weighted-average basis, for the three months ended June 30, 2021 and 2020, the possible exchange of 51 million and 63 million AAP units, respectively, and for the six months ended June 30, 2021 and 2020, the possible exchange of 51 million and 64 million AAP units, respectively, would not have had a dilutive effect on basic net income/(loss) per Class A share. For each of the three and six months ended June 30, 2021 and 2020, the possible exchange of 1 million AAP Management Units would not have had a dilutive effect on basic net income/(loss) per Class A share on a weighted-average basis. For the three months ended June 30, 2021 and 2020, and for the six months ended June 30, 2020, our PAGP LTIP awards were antidilutive. For the six months ended June 30, 2021, our PAGP LTIP awards were dilutive; however, there were less than 0.1 million dilutive LTIP awards, which did not change the presentation of diluted weighted average Class A shares outstanding or diluted net income/(loss) per Class A share.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Basic and Diluted Net Income/(Loss) per Class A Share
Net income/(loss) attributable to PAGP	$	(69)	$	16	$	1	$	(565)
Basic and diluted weighted average Class A shares outstanding	194		184		194		183
Basic and diluted net income/(loss) per Class A share	$	(0.35)	$	0.09	$	—	$	(3.08)

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Inventory, Linefill and Base Gas and Long-term Inventory

6 Months Ended

Jun. 30, 2021

Inventory, Linefill and Base Gas and Long-term Inventory

Inventory, Linefill and Base Gas and Long-term Inventory

Inventory, Linefill and Base Gas and Long-term Inventory

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

	June 30, 2021						December 31, 2020
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	9,674	barrels	$	508	$	52.51	13,450	barrels	$	441	$	32.79
NGL	7,097	barrels	162		$	22.83	12,302	barrels	199		$	16.18
Other	N/A		5		N/A		N/A		7		N/A
Inventory subtotal			675						647
Linefill and base gas
Crude oil	15,164	barrels	864		$	56.98	14,669	barrels	828		$	56.45
NGL	1,636	barrels	45		$	27.51	1,640	barrels	44		$	26.83
Natural gas (2)	—	Mcf	—		$	—	25,576	Mcf	110		$	4.30
Linefill and base gas subtotal			909						982
Long-term inventory
Crude oil	2,699	barrels	183		$	67.80	2,499	barrels	111		$	44.42
NGL	1,258	barrels	27		$	21.46	1,185	barrels	19		$	16.03
Long-term inventory subtotal			210						130
Total			$	1,794					$	1,759

(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.

(2)As of June 30, 2021, $110 million of base gas was classified as held for sale on our Condensed Consolidated Balance Sheet (in “Other current assets”) related to the sale of our Pine Prairie and Southern Pines natural gas storage facilities, which closed on August 2, 2021. See Note 12 for additional information.

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Debt

6 Months Ended

Jun. 30, 2021

Debt Disclosure [Abstract]

Debt

Debt

Debt consisted of the following (in millions):

	June 30, 2021		December 31, 2020
SHORT-TERM DEBT
PAA commercial paper notes, bearing a weighted-average interest rate of 0.4% and 0.7%, respectively (1)	$	388	$	547
PAA senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.2% (1)	—		167
PAA senior notes:
3.65% senior notes due June 2022	750		—
PAA GO Zone term loans, net of debt issuance costs of $1, bearing a weighted-average interest rate of 1.3% (2)	199		—
Other	119		117
Total short-term debt	1,456		831
LONG-TERM DEBT
PAA senior notes, net of unamortized discounts and debt issuance costs of $57 and $62, respectively	8,326		9,071
PAA GO Zone term loans, net of debt issuance costs of $1, bearing a weighted-average interest rate of 1.3%	—		199
Other	63		112
Total long-term debt	8,389		9,382
Total debt (3)	$	9,845	$	10,213

(1)We classified these commercial paper notes as short-term as of June 30, 2021 and December 31, 2020, respectively, and these credit facility borrowings as short-term as of December 31, 2020, as these notes and borrowings were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.

(2)The PAA GO Zone term loans were initially assumed by a subsidiary of PAA in connection with the acquisition of the Southern Pines natural gas storage facility. In connection with the sale of that facility, the loans were repaid on August 2, 2021. See Note 12 for additional information.

(3)PAA’s fixed-rate senior notes had a face value of approximately $9.1 billion at both June 30, 2021 and December 31, 2020. We estimated the aggregate fair value of these notes as of June 30, 2021 and December 31, 2020 to be approximately $10.0 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 credit facilities, commercial paper program and GO Zone term loans approximates fair value as interest rates reflect current market rates. The fair value estimates for PAA’s senior notes, credit facilities, commercial paper program and GO Zone term loans are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

Borrowings and Repayments

Total borrowings under the PAA credit facilities and commercial paper program for the six months ended June 30, 2021 and 2020 were approximately $26.1 billion and $12.6 billion, respectively. Total repayments under the PAA credit facilities and commercial paper program were approximately $26.4 billion and $13.0 billion for the six months ended June 30, 2021 and 2020, 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.

Letters of Credit

In connection with our supply and logistics 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 June 30, 2021 and December 31, 2020, we had outstanding letters of credit of $81 million and $129 million, respectively.

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Partners' Capital and Distributions

6 Months Ended

Jun. 30, 2021

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, 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 Common Equity Repurchase Program (2)	—	—	(350,000)
Other	—	—	25,431
Outstanding at March 31, 2021	194,098,315	50,777,990	547,623,124
Exchange Right exercises (1)	25,554	(25,554)	—
Redemption Right exercises (1)	—	(535,009)	535,009
Repurchase of common units by a subsidiary under Common Equity Repurchase Program	—	—	(4,940,592)
Other	—	—	256,321
Outstanding at June 30, 2021	194,123,869	50,217,427	543,473,862

 

	Class A Shares	Class B Shares	Class C Shares
Outstanding at December 31, 2019	182,138,592	65,785,702	549,538,139
Conversion of AAP Management Units (1)	—	559,768	—
Exchange Right exercises (1)	2,101,487	(2,101,487)	—
Redemption Right exercises (1)	—	(1,206,599)	1,206,599
Other	—	—	24,431
Outstanding at March 31, 2020	184,240,079	63,037,384	550,769,169
Conversion of AAP Management Units (1)	—	35,349	—
Redemption Right exercises (1)	—	(40,679)	40,679
Other	20,099	—	27,292
Outstanding at June 30, 2020	184,260,178	63,032,054	550,837,140

(1)See Note 12 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for information regarding conversions of AAP Management Units, Exchange Rights and Redemption Rights.

(2)Trades for these units were executed in late December 2020, but settled in early January 2021.

Distributions

The following table details distributions to our Class A shareholders paid during or pertaining to the first six months of 2021 (in millions, except per share data):

Distribution Payment Date	Distributions to Class A Shareholders		Distributions per Class A Share
August 13, 2021 (1)	$	35	$	0.18
May 14, 2021	$	35	$	0.18
February 12, 2021	$	35	$	0.18

(1)Payable to shareholders of record at the close of business on July 30, 2021 for the period from April 1, 2021 through June 30, 2021.

Consolidated Subsidiaries

Noncontrolling Interests in Subsidiaries

As of June 30, 2021, noncontrolling interests in our subsidiaries consisted of (i) limited partner interests in PAA including a 69% interest in PAA’s common units and PAA’s Series A preferred units combined and 100% of PAA’s Series B preferred units, (ii) an approximate 21% limited partner interest in AAP and (iii) a 33% interest in Red River Pipeline Company LLC (“Red River LLC”).

Common Equity Repurchase Program

PAA repurchased 5,290,592 common units under the Common Equity Repurchase Program (the “Program”) through open market purchases that settled during the six months ended June 30, 2021. The total purchase price of these repurchases was $53 million, including commissions and fees. The repurchased common units were canceled immediately upon acquisition, as were the Class C shares held by PAA associated with the repurchased common units. At June 30, 2021, the remaining available capacity under the Program was $397 million. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for additional information regarding the Program.

PAA’s capital attributable to AAP was adjusted, in accordance with ASC 810, to reflect the accretion of its interest in PAA as a result of the repurchase of common units from public unitholders. Such adjustment is recognized by PAGP in proportion to its ownership interest in AAP, which results in a net increase in partners’ capital attributable to PAGP.

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 six months of 2021 (in millions, except per unit data):

	Series A Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit
August 13, 2021 (1)	$	37	$	0.525
May 14, 2021	$	37	$	0.525
February 12, 2021	$	37	$	0.525

(1)Payable to unitholders of record at the close of business on July 30, 2021 for the period from April 1, 2021 through June 30, 2021. At June 30, 2021, 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 17, 2021	$	24.5	$	30.625

At June 30, 2021, approximately $6 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 six months of 2021 (in millions, except per unit data):

	Distributions						Cash Distribution  per Common Unit
	Common Unitholders				Total Cash Distribution
Distribution Payment Date	Public		AAP
August 13, 2021 (1)	$	85	$	44	$	129	$	0.18
May 14, 2021	$	86	$	44	$	130	$	0.18
February 12, 2021	$	86	$	44	$	130	$	0.18

(1)Payable to unitholders of record at the close of business on July 30, 2021 for the period from April 1, 2021 through June 30, 2021.

AAP Distributions. The following table details the distributions to AAP’s partners paid during or pertaining to the first six months of 2021 from distributions received from PAA (in millions):

	Distributions to AAP’s Partners
Distribution Payment Date	Noncontrolling Interests		PAGP		Total Cash Distribution
August 13, 2021 (1)	$	9	$	35	$	44
May 14, 2021	$	9	$	35	$	44
February 12, 2021	$	9	$	35	$	44

(1)Payable to unitholders of record at the close of business on July 30, 2021 for the period from April 1, 2021 through June 30, 2021.

Other Distributions. During the six months ended June 30, 2021, we paid distributions of $6 million to noncontrolling interests in Red River Pipeline Company LLC.

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Derivatives and Risk Management Activities

6 Months Ended

Jun. 30, 2021

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 June 30, 2021 and December 31, 2020, 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 June 30, 2021, net derivative positions related to these activities included:

•A net long position of 1.6 million barrels associated with our crude oil purchases, which was unwound ratably during July 2021 to match monthly average pricing.

•A net short time spread position of 8.4 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through September 2022.

•A net crude oil basis spread position of 8.6 million barrels at multiple locations through December 2022. These derivatives allow us to lock in grade and location basis differentials.

•A net short position of 16.2 million barrels through December 2022 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 June 30, 2021:

	Notional Volume
	(Short)/Long	Remaining Tenor
Natural gas purchases	51.9 Bcf	December 2022
Propane sales	(9.0) MMbls	December 2022
Butane sales	(2.6) MMbls	December 2022
Condensate sales (WTI position)	(0.8) MMbls	December 2022
Fuel gas requirements (1)	10.3 Bcf	December 2022
Power supply requirements (1)	0.7 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. A summary of the impact of our commodity derivatives recognized in earnings as follows (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Supply and Logistics segment revenues	$	(284)	$	(134)	$	(598)	$	15
Field operating costs	17		(1)		56		—
Net gain/(loss) from commodity derivative activity	$	(267)	$	(135)	$	(542)	$	15

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/(payable) (in millions):

	June 30, 2021		December 31, 2020
Initial margin	$	78	$	91
Variation margin posted/(returned)	369		290
Letters of credit	(40)		(63)
Net broker receivable/(payable)	$	407	$	318

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.

	June 30, 2021								December 31, 2020
					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	$	205	$	(430)	$	407	$	182	$	71	$	(314)	$	318	$	75
Other long-term assets, net	6		—		—		6		5		—		—		5
Derivative Liabilities
Other current liabilities	3		(97)		—		(94)		9		(40)		—		(31)
Other long-term liabilities and deferred credits	7		(90)		—		(83)		—		(32)		—		(32)
Total	$	221	$	(617)	$	407	$	11	$	85	$	(386)	$	318	$	17

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 June 30, 2021 (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 June 30, 2021, there was a net loss of $223 million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the earnings recognition of the underlying hedged commodity transactions or (ii) 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 June 30, 2021; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Interest rate derivatives, net	$	(39)	$	19	$	29	$	(61)

At June 30, 2021, 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 $75 million. At December 31, 2020, the net fair value of these hedges totaled $46 million and was included in “Other long-term assets, net.”

Currency Exchange Rate Risk Hedging

Because a significant portion of our Canadian business is conducted in CAD, we use foreign currency derivatives to minimize the risk of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts, forwards and options.

Our use of foreign currency derivatives include (i) derivatives we use to hedge currency exchange risk created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales and (ii) foreign currency exchange contracts we use to manage our Canadian business cash requirements.

The following table summarizes our open forward exchange contracts as of June 30, 2021 (in millions):

		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2021	$	144	$	177	$1.00 - $1.23
Forward exchange contracts that exchange USD for CAD:
	2021	$	142	$	172	$1.00 - $1.21

These derivatives are not designated in a hedging relationship for accounting purposes. As such, changes in fair value are recognized in earnings as a component of Supply and Logistics segment revenues. For the three months ended June 30, 2021 and 2020, the amounts recognized in earnings for our currency exchange rate hedges were gains of $2 million in each respective period. For the six months ended June 30, 2021 and 2020, the amounts recognized in earnings for our currency exchange rate hedges were a gain of $3 million and a loss of $4 million, respectively.

At June 30, 2021, the net fair value of these currency exchange rate hedges, which was included in “Other current assets” on our Condensed Consolidated Balance Sheet, totaled less than $1 million. At December 31, 2020, the net fair value of these currency exchange rate hedges, which was included in “Other current assets” on our Condensed Consolidated Balance Sheet, totaled $2 million.

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 June 30, 2021 and 2020, we recognized a gain of $77 million and a loss of $9 million, respectively. For the six months ended June 30, 2021 and 2020, we recognized net gains of $9 million and $17 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 $5 million and $14 million at June 30, 2021 and December 31, 2020, respectively. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for additional information regarding the 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 June 30, 2021								Fair Value as of December 31, 2020
Recurring Fair Value Measures (1)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivatives	$	(246)	$	(141)	$	(8)	$	(395)	$	(143)	$	(143)	$	(15)	$	(301)
Interest rate derivatives	—		75		—		75		—		46		—		46
Foreign currency derivatives	—		(1)		—		(1)		—		2		—		2
Preferred Distribution Rate Reset Option	—		—		(5)		(5)		—		—		(14)		(14)
Total net derivative asset/(liability)	$	(246)	$	(67)	$	(13)	$	(326)	$	(143)	$	(95)	$	(29)	$	(267)

(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 Supply and Logistics segment 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 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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Beginning Balance	$	(92)	$	(61)	$	(29)	$	(51)
Net gains/(losses) for the period included in earnings	77		18		9		8
Settlements	2		1		7		1
Ending Balance	$	(13)	$	(42)	$	(13)	$	(42)
Change in unrealized losses included in earnings relating to Level 3 derivatives still held at the end of the period	$	77	$	18	$	9	$	8

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Related Party Transactions

6 Months Ended

Jun. 30, 2021

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

See Note 17 to our Consolidated Financial Statements included in Part IV of our 2020 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 and six months ended June 30, 2021 and 2020, 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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Revenues from related parties (1)	$	10	$	10	$	17	$	33
Purchases and related costs from related parties (1)	$	95	$	94	$	185	$	223

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

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

	June 30, 2021		December 31, 2020
Trade accounts receivable and other receivables, net from related parties (1)	$	29	$	34
Trade accounts payable to related parties (1) (2)	$	80	$	88

(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

6 Months Ended

Jun. 30, 2021

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

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. 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 June 30, 2021, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled $159 million, of which $112 million was classified as short-term and $47 million was classified as long-term. At December 31, 2020, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident) totaled $141 million, of which $94 million was classified as short-term and $47 million was classified as long-term. Such short-term liabilities are reflected in “Trade accounts payable” and “Other current liabilities” and long-term liabilities are reflected in “Other long-term liabilities and deferred credits” on our Condensed Consolidated Balance Sheets. At June 30, 2021, we had recorded receivables totaling $114 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which $113 million was classified as short-term and $1 million was classified as long-term. At December 31, 2020, we had recorded $97 million of such receivables, of which $96 million was classified as short-term and $1 million was classified as long-term. Such short- and long-term receivables are reflected in “Trade accounts receivable and other receivables, net” and “Other long-term assets, net,” respectively, 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. The only pending matter relating to these proceedings is that the Superior Court indicated that it would conduct further hearings in 2021 on the issue of whether there were any “direct victims” of the spill that are entitled to restitution under applicable law. The Superior Court is currently in the process of conducting such hearings pursuant to a schedule that provides for various potential “direct victims” to present their claims to the Court on designated dates over the course of a several month period.

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. We are vigorously defending against those claims. A September 2020 trial date initially set by the Court has been postponed indefinitely due to COVID-19 related trial suspensions. In the second proceeding, the plaintiffs seek a declaratory judgment that Plains’ right-of-way agreements would not allow Plains to lay a new pipeline to replace Line 901 and/or the non-operating segment of Line 903 without paying additional compensation. No trial date has been set in that action.

In addition, four unitholder derivative lawsuits were filed by certain purported investors in PAA against PAGP and certain of PAA’s affiliates, officers and directors. After various claims were either dismissed or consolidated, one proceeding against PAGP remains pending in Delaware Chancery Court. Generally, the plaintiffs claim that PAGP failed to exercise proper oversight over the Partnership’s pipeline integrity efforts. We will continue to vigorously defend against the claim. No trial date has been set in this action.

We have also received several other individual lawsuits and claims from companies, governmental agencies and individuals alleging damages arising out of the Line 901 incident. These lawsuits and claims generally seek restitution, compensatory and punitive damages, and/or injunctive relief. The majority of these lawsuits have been settled or dismissed by the court. Remaining claims include claims for lost revenue or profit asserted by a former oil producer that declared bankruptcy and shut in its offshore production platform following the Line 901 incident, a state agency that received royalties on oil produced from that platform until it was abandoned by its owner, and various companies and individuals who provided labor, goods, or services associated with oil production activities they claim were disrupted following the Line 901 incident. We are vigorously defending these suits. We may be subject to additional claims and lawsuits, which could materially impact the liabilities and costs we currently expect to incur as a result of the Line 901 incident.

Taking the foregoing into account, as of June 30, 2021, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $485 million, which includes actual and projected emergency response and clean-up costs, natural resource damage assessments, fines and penalties payable pursuant to the Consent Decree and certain third party claims settlements, as well as estimates for certain legal fees. 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 June 30, 2021, we had a remaining undiscounted gross liability of $104 million related to this event, which 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. Subject to such exclusions and deductibles, we believe that our coverage is adequate to cover the current estimated total emergency response and clean-up costs, claims settlement costs and remediation costs and we believe that this coverage is also adequate to cover any potential increase in the estimates for these costs that exceed the amounts currently identified. Through June 30, 2021, we had collected, subject to customary reservations, $250 million out of the approximate $360 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of June 30, 2021, we have recognized a receivable of approximately $110 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.

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Operating Segments

6 Months Ended

Jun. 30, 2021

Segment Reporting [Abstract]

Operating Segments

Operating Segments

We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for a summary of the types of products and services from which each segment derives its revenues. Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below) and maintenance capital investment.

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 our proportionate share of the depreciation and amortization expense of unconsolidated entities, and further adjusted for certain selected items including (i) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance. Segment Adjusted EBITDA excludes depreciation and amortization.

Maintenance capital consists of 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.

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

	Transportation		Facilities		Supply and Logistics		Intersegment Adjustment		Total
Three Months Ended June 30, 2021
Revenues:
External customers (1)	$	243	$	145	$	9,623	$	(81)	$	9,930
Intersegment (2)	310		99		—		81		490
Total revenues of reportable segments	$	553	$	244	$	9,623	$	—	$	10,420
Equity earnings in unconsolidated entities	$	31	$	2	$	—			$	33
Segment Adjusted EBITDA	$	433	$	140	$	5			$	578
Maintenance capital	$	20	$	14	$	3			$	37
Three Months Ended June 30, 2020
Revenues:
External customers (1)	$	234	$	149	$	2,925	$	(83)	$	3,225
Intersegment (2)	223		127		—		83		433
Total revenues of reportable segments	$	457	$	276	$	2,925	$	—	$	3,658
Equity earnings in unconsolidated entities	$	81	$	—	$	—			$	81
Segment Adjusted EBITDA	$	346	$	174	$	3			$	523
Maintenance capital	$	31	$	15	$	8			$	54
Six Months Ended June 30, 2021
Revenues:
External customers (1)	$	478	$	308	$	17,706	$	(179)	$	18,313
Intersegment (2)	561		207		1		179		948
Total revenues of reportable segments	$	1,039	$	515	$	17,707	$	—	$	19,261
Equity earnings in unconsolidated entities	$	117	$	4	$	—			$	121
Segment Adjusted EBITDA	$	821	$	311	$	(8)			$	1,124
Maintenance capital	$	47	$	20	$	6			$	73
Six Months Ended June 30, 2020
Revenues:
External customers (1)	$	532	$	323	$	10,833	$	(194)	$	11,494
Intersegment (2)	504		266		1		194		965
Total revenues of reportable segments	$	1,036	$	589	$	10,834	$	—	$	12,459
Equity earnings in unconsolidated entities	$	189	$	2	$	—			$	191
Segment Adjusted EBITDA	$	788	$	384	$	144			$	1,316
Maintenance capital	$	64	$	29	$	11			$	104

(1)Transportation revenues from External customers include tariff revenue from transporting volumes associated with certain inventory exchanges with our customers where our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for a discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenues from External customers presented above and adjusted those revenues out such that Total revenues from External customers reconciles to our Condensed Consolidated Statements of Operations. This presentation is consistent with the information provided to our CODM.

(2)Segment revenues include intersegment amounts that are eliminated in Purchases and related costs and Field operating costs in our Condensed Consolidated Statements of Operations. 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/(loss) attributable to PAGP (in millions):

 

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Segment Adjusted EBITDA	$	578	$	523	$	1,124	$	1,316
Adjustments: (1)
Depreciation and amortization of unconsolidated entities (2)	(68)		(16)		(88)		(33)
Gains/(losses) from derivative activities and inventory valuation adjustments (3)	(163)		(90)		35		(121)
Long-term inventory costing adjustments (4)	27		51		68		(64)
Deficiencies under minimum volume commitments, net (5)	(6)		(7)		26		(6)
Equity-indexed compensation expense (6)	(4)		(5)		(9)		(8)
Net gain on foreign currency revaluation (7)	1		—		2		13
Significant transaction-related expenses (8)	(3)		—		(3)		(3)
Unallocated general and administrative expenses	(2)		(2)		(3)		(3)
Depreciation and amortization	(197)		(166)		(375)		(335)
Gains/(losses) on asset sales and asset impairments, net	(369)		1		(370)		(618)
Goodwill impairment losses	—		—		—		(2,515)
Gain on/(impairment of) investments in unconsolidated entities, net	—		(69)		—		(91)
Interest expense, net	(107)		(108)		(213)		(215)
Other income/(expense), net	84		18		23		(13)
Income/(loss) before tax	(229)		130		217		(2,696)
Income tax (expense)/benefit	17		7		(36)		140
Net income/(loss)	(212)		137		181		(2,556)
Net (income)/loss attributable to noncontrolling interests	143		(121)		(180)		1,991
Net income/(loss) attributable to PAGP	$	(69)	$	16	$	1	$	(565)

(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 investing activities, such as the purchase of linefill.

(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 2020 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. See Note 8 for discussion regarding our currency exchange rate risk hedging activities.

(8)Includes expenses associated with the Permian Basin joint venture transaction announced in July 2021 and the acquisition of Felix Midstream LLC in 2020. See Note 12 for further discussion of the joint venture transaction and Note 7 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for additional discussion of the Felix Midstream LLC acquisition.

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Acquisitions, Divestitures and Other Transactions

6 Months Ended

Jun. 30, 2021

Business Combination and Asset Acquisition [Abstract]

Acquisitions, Divestitures and Other Transactions

Acquisitions, Divestitures and Other Transactions

Asset Exchange

In June 2021, we closed on an asset exchange agreement (the “Asset Exchange”) with Inter Pipeline Ltd., through which we acquired additional interests in two straddle plants included in our Facilities segment that we currently operate, in exchange for a pipeline and related storage and truck offload facilities previously included in our Transportation segment and cash consideration of $32 million, including working capital and other adjustments. We recognized a gain of $106 million on the divestiture of the pipeline and related storage and truck offload facilities, which is included in “(Gains)/losses on asset sales and asset impairments, net” on our Condensed Consolidated Statement of Operations, based on the difference between the fair value of the divested assets and their carrying value.

Assets Held For Sale

In June 2021, we signed a definitive agreement to sell our Pine Prairie and Southern Pines natural gas storage facilities included in our Facilities segment for $850 million, subject to certain adjustments. As of June 30, 2021, we classified the assets related to this transaction (primarily “Property and equipment”), valued at the lower of the carrying amount or fair value less costs to sell, of approximately $832 million as assets held for sale on our Condensed Consolidated Balance Sheet (in “Other current assets”) with approximately $18 million of deferred losses on hedges remaining in other comprehensive income on our Condensed Consolidated Balance Sheet (in “Total partners’ capital”). This transaction closed on August 2, 2021.

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

Joint Venture Transaction

In July 2021, we entered into a definitive agreement with Oryx Midstream Holdings LLC (“Oryx Midstream”) pursuant to which we and Oryx Midstream intend to merge, in a cashless, debt-free transaction, our respective Permian Basin assets, operations and commercial activities into a newly formed joint venture, Plains Oryx Permian Basin LLC (“Plains Oryx Permian Basin”). The transaction will include all of Oryx’s Permian Basin assets and, with the exception of our long-haul pipeline systems and certain of our intra-basin terminal assets, the vast majority of our assets located within the Permian Basin. We will own 65% of Plains Oryx Permian Basin, operate the combined assets, and consolidate the financial results of the joint venture into our financial statements. Subject to satisfaction of customary and other closing conditions and receipt of regulatory approvals, the transactions contemplated by the merger agreement are expected to close in the fourth quarter of 2021.

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2021

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 and Accounting Standards Updates Adopted During the Period

Recent Accounting Pronouncements

Except as discussed below and in our 2020 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the six months ended June 30, 2021 that are of significance or potential significance to us.

Accounting Standards Updates Adopted During the Period

We adopted the ASU listed below effective January 1, 2021 and our adoption did not have a material impact on our financial position, results of operations or cash flows (see Note 2 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for additional information regarding this ASU):

•ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes.

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Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2021

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):

	June 30, 2021		December 31, 2020
Cash and cash equivalents	$	26	$	25
Restricted cash	7		38
Total cash and cash equivalents and restricted cash	$	33	$	63

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Revenues and Accounts Receivable (Tables)

6 Months Ended

Jun. 30, 2021

Disaggregation of Revenue [Line Items]

Disaggregation of revenue

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

Three Months Ended June 30, 2021	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	509	$	232	$	9,904	$	10,645
Other items in revenues	44		12		(281)		(225)
Total revenues of reportable segments	$	553	$	244	$	9,623	$	10,420
Intersegment revenues							(490)
Total revenues							$	9,930
Three Months Ended June 30, 2020	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	453	$	264	$	3,055	$	3,772
Other items in revenues	4		12		(130)		(114)
Total revenues of reportable segments	$	457	$	276	$	2,925	$	3,658
Intersegment revenues							(433)
Total revenues							$	3,225
Six Months Ended June 30, 2021	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	954	$	486	$	18,300	$	19,740
Other items in revenues	85		29		(593)		(479)
Total revenues of reportable segments	$	1,039	$	515	$	17,707	$	19,261
Intersegment revenues							(948)
Total revenues							$	18,313
Six Months Ended June 30, 2020	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	1,026	$	569	$	10,806	$	12,401
Other items in revenues	10		20		28		58
Total revenues of reportable segments	$	1,036	$	589	$	10,834	$	12,459
Intersegment revenues							(965)
Total revenues							$	11,494

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	June 30, 2021		December 31, 2020
Billed and collected	Liability	$	54	$	73
Unbilled (1)	N/A	21		4
Total		$	75	$	77

(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 contract 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, 2020	$	501
Amounts recognized as revenue (1)	(384)
Additions	22
Balance at June 30, 2021	$	139

(1)Includes approximately $361 million associated with crude oil sales agreements that were entered into in the fourth quarter of 2020 in conjunction with storage arrangements and inventory exchanges, which were settled in the first quarter of 2021.

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):

	June 30, 2021		December 31, 2020
Trade accounts receivable arising from revenues from contracts with customers	$	3,177	$	2,317
Other trade accounts receivables and other receivables (1)	4,807		2,818
Impact due to contractual rights of offset with counterparties	(4,087)		(2,582)
Trade accounts receivable and other receivables, net	$	3,897	$	2,553

(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 June 30, 2021 (in millions):

	Remainder of 2021		2022		2023		2024		2025		2026 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	92	$	174	$	174	$	151	$	129	$	461
Storage, terminalling and throughput agreement revenues	139		223		155		118		57		229
Total	$	231	$	397	$	329	$	269	$	186	$	690

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

Supply and Logistics

Disaggregation of Revenue [Line Items]

Disaggregation of revenue

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Supply and Logistics segment revenues from contracts with customers
Crude oil transactions	$	9,619	$	2,928	$	17,331	$	10,251
NGL and other transactions	285		127		969		555
Total Supply and Logistics segment revenues from contracts with customers	$	9,904	$	3,055	$	18,300	$	10,806

Transportation

Disaggregation of Revenue [Line Items]

Disaggregation of revenue

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Transportation segment revenues from contracts with customers
Tariff activities:
Crude oil pipelines	$	462	$	405	$	859	$	917
NGL pipelines	27		26		53		52
Total tariff activities	489		431		912		969
Trucking	20		22		42		57
Total Transportation segment revenues from contracts with customers	$	509	$	453	$	954	$	1,026

Facilities

Disaggregation of Revenue [Line Items]

Disaggregation of revenue

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Facilities segment revenues from contracts with customers
Crude oil, NGL and other terminalling and storage	$	154	$	176	$	324	$	357
NGL and natural gas processing and fractionation	70		80		142		190
Rail load / unload	8		8		20		22
Total Facilities segment revenues from contracts with customers	$	232	$	264	$	486	$	569

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Net Income/(Loss) Per Class A Share (Tables)

6 Months Ended

Jun. 30, 2021

Earnings Per Share [Abstract]

Calculation of basic and diluted net income/(loss) per Class A share

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Basic and Diluted Net Income/(Loss) per Class A Share
Net income/(loss) attributable to PAGP	$	(69)	$	16	$	1	$	(565)
Basic and diluted weighted average Class A shares outstanding	194		184		194		183
Basic and diluted net income/(loss) per Class A share	$	(0.35)	$	0.09	$	—	$	(3.08)

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Inventory, Linefill and Base Gas and Long-term Inventory (Tables)

6 Months Ended

Jun. 30, 2021

Inventory, Linefill and Base Gas and Long-term Inventory

Schedule of inventory, linefill and base gas and long-term inventory

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

	June 30, 2021						December 31, 2020
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	9,674	barrels	$	508	$	52.51	13,450	barrels	$	441	$	32.79
NGL	7,097	barrels	162		$	22.83	12,302	barrels	199		$	16.18
Other	N/A		5		N/A		N/A		7		N/A
Inventory subtotal			675						647
Linefill and base gas
Crude oil	15,164	barrels	864		$	56.98	14,669	barrels	828		$	56.45
NGL	1,636	barrels	45		$	27.51	1,640	barrels	44		$	26.83
Natural gas (2)	—	Mcf	—		$	—	25,576	Mcf	110		$	4.30
Linefill and base gas subtotal			909						982
Long-term inventory
Crude oil	2,699	barrels	183		$	67.80	2,499	barrels	111		$	44.42
NGL	1,258	barrels	27		$	21.46	1,185	barrels	19		$	16.03
Long-term inventory subtotal			210						130
Total			$	1,794					$	1,759

(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.

(2)As of June 30, 2021, $110 million of base gas was classified as held for sale on our Condensed Consolidated Balance Sheet (in “Other current assets”) related to the sale of our Pine Prairie and Southern Pines natural gas storage facilities, which closed on August 2, 2021. See Note 12 for additional information.

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Debt (Tables)

6 Months Ended

Jun. 30, 2021

Debt Disclosure [Abstract]

Schedule of debt

Debt consisted of the following (in millions):

	June 30, 2021		December 31, 2020
SHORT-TERM DEBT
PAA commercial paper notes, bearing a weighted-average interest rate of 0.4% and 0.7%, respectively (1)	$	388	$	547
PAA senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.2% (1)	—		167
PAA senior notes:
3.65% senior notes due June 2022	750		—
PAA GO Zone term loans, net of debt issuance costs of $1, bearing a weighted-average interest rate of 1.3% (2)	199		—
Other	119		117
Total short-term debt	1,456		831
LONG-TERM DEBT
PAA senior notes, net of unamortized discounts and debt issuance costs of $57 and $62, respectively	8,326		9,071
PAA GO Zone term loans, net of debt issuance costs of $1, bearing a weighted-average interest rate of 1.3%	—		199
Other	63		112
Total long-term debt	8,389		9,382
Total debt (3)	$	9,845	$	10,213

(1)We classified these commercial paper notes as short-term as of June 30, 2021 and December 31, 2020, respectively, and these credit facility borrowings as short-term as of December 31, 2020, as these notes and borrowings were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.

(2)The PAA GO Zone term loans were initially assumed by a subsidiary of PAA in connection with the acquisition of the Southern Pines natural gas storage facility. In connection with the sale of that facility, the loans were repaid on August 2, 2021. See Note 12 for additional information.

(3)PAA’s fixed-rate senior notes had a face value of approximately $9.1 billion at both June 30, 2021 and December 31, 2020. We estimated the aggregate fair value of these notes as of June 30, 2021 and December 31, 2020 to be approximately $10.0 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 credit facilities, commercial paper program and GO Zone term loans approximates fair value as interest rates reflect current market rates. The fair value estimates for PAA’s senior notes, credit facilities, commercial paper program and GO Zone term loans are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

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Partners' Capital and Distributions (Tables)

6 Months Ended

Jun. 30, 2021

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, 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 Common Equity Repurchase Program (2)	—	—	(350,000)
Other	—	—	25,431
Outstanding at March 31, 2021	194,098,315	50,777,990	547,623,124
Exchange Right exercises (1)	25,554	(25,554)	—
Redemption Right exercises (1)	—	(535,009)	535,009
Repurchase of common units by a subsidiary under Common Equity Repurchase Program	—	—	(4,940,592)
Other	—	—	256,321
Outstanding at June 30, 2021	194,123,869	50,217,427	543,473,862

 

	Class A Shares	Class B Shares	Class C Shares
Outstanding at December 31, 2019	182,138,592	65,785,702	549,538,139
Conversion of AAP Management Units (1)	—	559,768	—
Exchange Right exercises (1)	2,101,487	(2,101,487)	—
Redemption Right exercises (1)	—	(1,206,599)	1,206,599
Other	—	—	24,431
Outstanding at March 31, 2020	184,240,079	63,037,384	550,769,169
Conversion of AAP Management Units (1)	—	35,349	—
Redemption Right exercises (1)	—	(40,679)	40,679
Other	20,099	—	27,292
Outstanding at June 30, 2020	184,260,178	63,032,054	550,837,140

(1)See Note 12 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for information regarding conversions of AAP Management Units, Exchange Rights and Redemption Rights.

(2)Trades for these units were executed in late December 2020, but settled in early January 2021.

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 six months of 2021 from distributions received from PAA (in millions):

	Distributions to AAP’s Partners
Distribution Payment Date	Noncontrolling Interests		PAGP		Total Cash Distribution
August 13, 2021 (1)	$	9	$	35	$	44
May 14, 2021	$	9	$	35	$	44
February 12, 2021	$	9	$	35	$	44

(1)Payable to unitholders of record at the close of business on July 30, 2021 for the period from April 1, 2021 through June 30, 2021.

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 six months of 2021 (in millions, except per share data):

Distribution Payment Date	Distributions to Class A Shareholders		Distributions per Class A Share
August 13, 2021 (1)	$	35	$	0.18
May 14, 2021	$	35	$	0.18
February 12, 2021	$	35	$	0.18

(1)Payable to shareholders of record at the close of business on July 30, 2021 for the period from April 1, 2021 through June 30, 2021.

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 six months of 2021 (in millions, except per unit data):

	Series A Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit
August 13, 2021 (1)	$	37	$	0.525
May 14, 2021	$	37	$	0.525
February 12, 2021	$	37	$	0.525

(1)Payable to unitholders of record at the close of business on July 30, 2021 for the period from April 1, 2021 through June 30, 2021. At June 30, 2021, 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 17, 2021	$	24.5	$	30.625

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 six months of 2021 (in millions, except per unit data):

	Distributions						Cash Distribution  per Common Unit
	Common Unitholders				Total Cash Distribution
Distribution Payment Date	Public		AAP
August 13, 2021 (1)	$	85	$	44	$	129	$	0.18
May 14, 2021	$	86	$	44	$	130	$	0.18
February 12, 2021	$	86	$	44	$	130	$	0.18

(1)Payable to unitholders of record at the close of business on July 30, 2021 for the period from April 1, 2021 through June 30, 2021.

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Derivatives and Risk Management Activities (Tables)

6 Months Ended

Jun. 30, 2021

Derivatives and Risk Management Activities

Impact of derivatives recognized in earnings

A summary of the impact of our commodity derivatives recognized in earnings as follows (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Supply and Logistics segment revenues	$	(284)	$	(134)	$	(598)	$	15
Field operating costs	17		(1)		56		—
Net gain/(loss) from commodity derivative activity	$	(267)	$	(135)	$	(542)	$	15

Schedule of net broker receivable/(payable)

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

	June 30, 2021		December 31, 2020
Initial margin	$	78	$	91
Variation margin posted/(returned)	369		290
Letters of credit	(40)		(63)
Net broker receivable/(payable)	$	407	$	318

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.

	June 30, 2021								December 31, 2020
					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	$	205	$	(430)	$	407	$	182	$	71	$	(314)	$	318	$	75
Other long-term assets, net	6		—		—		6		5		—		—		5
Derivative Liabilities
Other current liabilities	3		(97)		—		(94)		9		(40)		—		(31)
Other long-term liabilities and deferred credits	7		(90)		—		(83)		—		(32)		—		(32)
Total	$	221	$	(617)	$	407	$	11	$	85	$	(386)	$	318	$	17

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

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Interest rate derivatives, net	$	(39)	$	19	$	29	$	(61)

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 June 30, 2021								Fair Value as of December 31, 2020
Recurring Fair Value Measures (1)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivatives	$	(246)	$	(141)	$	(8)	$	(395)	$	(143)	$	(143)	$	(15)	$	(301)
Interest rate derivatives	—		75		—		75		—		46		—		46
Foreign currency derivatives	—		(1)		—		(1)		—		2		—		2
Preferred Distribution Rate Reset Option	—		—		(5)		(5)		—		—		(14)		(14)
Total net derivative asset/(liability)	$	(246)	$	(67)	$	(13)	$	(326)	$	(143)	$	(95)	$	(29)	$	(267)

(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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Beginning Balance	$	(92)	$	(61)	$	(29)	$	(51)
Net gains/(losses) for the period included in earnings	77		18		9		8
Settlements	2		1		7		1
Ending Balance	$	(13)	$	(42)	$	(13)	$	(42)
Change in unrealized losses included in earnings relating to Level 3 derivatives still held at the end of the period	$	77	$	18	$	9	$	8

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 June 30, 2021:

	Notional Volume
	(Short)/Long	Remaining Tenor
Natural gas purchases	51.9 Bcf	December 2022
Propane sales	(9.0) MMbls	December 2022
Butane sales	(2.6) MMbls	December 2022
Condensate sales (WTI position)	(0.8) MMbls	December 2022
Fuel gas requirements (1)	10.3 Bcf	December 2022
Power supply requirements (1)	0.7 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 June 30, 2021 (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

Foreign Currency Derivatives

Derivatives and Risk Management Activities

Summary of open derivative positions

The following table summarizes our open forward exchange contracts as of June 30, 2021 (in millions):

		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2021	$	144	$	177	$1.00 - $1.23
Forward exchange contracts that exchange USD for CAD:
	2021	$	142	$	172	$1.00 - $1.21

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Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2021

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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Revenues from related parties (1)	$	10	$	10	$	17	$	33
Purchases and related costs from related parties (1)	$	95	$	94	$	185	$	223

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

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

	June 30, 2021		December 31, 2020
Trade accounts receivable and other receivables, net from related parties (1)	$	29	$	34
Trade accounts payable to related parties (1) (2)	$	80	$	88

(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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Operating Segments (Tables)

6 Months Ended

Jun. 30, 2021

Segment Reporting [Abstract]

Segment financial data

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

	Transportation		Facilities		Supply and Logistics		Intersegment Adjustment		Total
Three Months Ended June 30, 2021
Revenues:
External customers (1)	$	243	$	145	$	9,623	$	(81)	$	9,930
Intersegment (2)	310		99		—		81		490
Total revenues of reportable segments	$	553	$	244	$	9,623	$	—	$	10,420
Equity earnings in unconsolidated entities	$	31	$	2	$	—			$	33
Segment Adjusted EBITDA	$	433	$	140	$	5			$	578
Maintenance capital	$	20	$	14	$	3			$	37
Three Months Ended June 30, 2020
Revenues:
External customers (1)	$	234	$	149	$	2,925	$	(83)	$	3,225
Intersegment (2)	223		127		—		83		433
Total revenues of reportable segments	$	457	$	276	$	2,925	$	—	$	3,658
Equity earnings in unconsolidated entities	$	81	$	—	$	—			$	81
Segment Adjusted EBITDA	$	346	$	174	$	3			$	523
Maintenance capital	$	31	$	15	$	8			$	54
Six Months Ended June 30, 2021
Revenues:
External customers (1)	$	478	$	308	$	17,706	$	(179)	$	18,313
Intersegment (2)	561		207		1		179		948
Total revenues of reportable segments	$	1,039	$	515	$	17,707	$	—	$	19,261
Equity earnings in unconsolidated entities	$	117	$	4	$	—			$	121
Segment Adjusted EBITDA	$	821	$	311	$	(8)			$	1,124
Maintenance capital	$	47	$	20	$	6			$	73
Six Months Ended June 30, 2020
Revenues:
External customers (1)	$	532	$	323	$	10,833	$	(194)	$	11,494
Intersegment (2)	504		266		1		194		965
Total revenues of reportable segments	$	1,036	$	589	$	10,834	$	—	$	12,459
Equity earnings in unconsolidated entities	$	189	$	2	$	—			$	191
Segment Adjusted EBITDA	$	788	$	384	$	144			$	1,316
Maintenance capital	$	64	$	29	$	11			$	104

(1)Transportation revenues from External customers include tariff revenue from transporting volumes associated with certain inventory exchanges with our customers where our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for a discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenues from External customers presented above and adjusted those revenues out such that Total revenues from External customers reconciles to our Condensed Consolidated Statements of Operations. This presentation is consistent with the information provided to our CODM.

(2)Segment revenues include intersegment amounts that are eliminated in Purchases and related costs and Field operating costs in our Condensed Consolidated Statements of Operations. 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/(loss) attributable to PAGP

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

 

	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Segment Adjusted EBITDA	$	578	$	523	$	1,124	$	1,316
Adjustments: (1)
Depreciation and amortization of unconsolidated entities (2)	(68)		(16)		(88)		(33)
Gains/(losses) from derivative activities and inventory valuation adjustments (3)	(163)		(90)		35		(121)
Long-term inventory costing adjustments (4)	27		51		68		(64)
Deficiencies under minimum volume commitments, net (5)	(6)		(7)		26		(6)
Equity-indexed compensation expense (6)	(4)		(5)		(9)		(8)
Net gain on foreign currency revaluation (7)	1		—		2		13
Significant transaction-related expenses (8)	(3)		—		(3)		(3)
Unallocated general and administrative expenses	(2)		(2)		(3)		(3)
Depreciation and amortization	(197)		(166)		(375)		(335)
Gains/(losses) on asset sales and asset impairments, net	(369)		1		(370)		(618)
Goodwill impairment losses	—		—		—		(2,515)
Gain on/(impairment of) investments in unconsolidated entities, net	—		(69)		—		(91)
Interest expense, net	(107)		(108)		(213)		(215)
Other income/(expense), net	84		18		23		(13)
Income/(loss) before tax	(229)		130		217		(2,696)
Income tax (expense)/benefit	17		7		(36)		140
Net income/(loss)	(212)		137		181		(2,556)
Net (income)/loss attributable to noncontrolling interests	143		(121)		(180)		1,991
Net income/(loss) attributable to PAGP	$	(69)	$	16	$	1	$	(565)

(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 investing activities, such as the purchase of linefill.

(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 2020 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. See Note 8 for discussion regarding our currency exchange rate risk hedging activities.

(8)Includes expenses associated with the Permian Basin joint venture transaction announced in July 2021 and the acquisition of Felix Midstream LLC in 2020. See Note 12 for further discussion of the joint venture transaction and Note 7 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for additional discussion of the Felix Midstream LLC acquisition.

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Organization and Basis of Consolidation and Presentation - Additional Information (Details) shares in Millions, $ in Millions	6 Months Ended
	Jun. 30, 2021 USD ($) segment shares	Dec. 31, 2020 USD ($)
Organization and basis of presentation
Operating segments number | segment	3
Deferred tax asset | $	$ 1,414	$ 1,444
PAA | AAP
Organization and basis of presentation
Ownership interest	31.00%
Ownership interest (in units)	245.0
GP LLC
Organization and basis of presentation
Ownership interest	100.00%
AAP
Organization and basis of presentation
Ownership interest	79.00%
Ownership interest (in units)	193.1
AAP | GP LLC
Organization and basis of presentation
Ownership interest (in units)	1.0
Consolidated Entity Excluding VIE
Organization and basis of presentation
Deferred tax asset | $	$ 1,414	$ 1,444

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Summary of Significant Accounting Policies - Cash and Restricted Cash (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020	Jun. 30, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Cash and cash equivalents	$ 26	$ 25
Restricted cash	7	38
Total cash and cash equivalents and restricted cash	$ 33	$ 63	$ 106	$ 84

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Summary of Significant Accounting Policies - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended			6 Months Ended		12 Months Ended
	Jun. 30, 2021	Mar. 31, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Impact to net income attributable to PAGP	$ (69)		$ 16	$ 1	$ (565)
Change in Useful Life
Property, Plant and Equipment [Line Items]
Increase in depreciation expense	18			36
Impact to net income attributable to PAGP	$ (4)			$ (7)
Class A Shares
Property, Plant and Equipment [Line Items]
Impact to basic net income per Class A share (in dollars per share)	$ (0.35)		$ 0.09	$ 0	$ (3.08)
Impact to diluted net income per Class A share (in dollars per share)	(0.35)		$ 0.09	0	$ (3.08)
Class A Shares | Change in Useful Life
Property, Plant and Equipment [Line Items]
Impact to basic net income per Class A share (in dollars per share)	(0.01)			(0.04)
Impact to diluted net income per Class A share (in dollars per share)	$ (0.01)			$ (0.04)
Pipeline and related facilities and Storage, terminal and rail facilities | Minimum
Property, Plant and Equipment [Line Items]
Property and equipment, useful life						10 years
Pipeline and related facilities and Storage, terminal and rail facilities | Minimum | Change in Useful Life
Property, Plant and Equipment [Line Items]
Property and equipment, useful life		10 years
Pipeline and related facilities and Storage, terminal and rail facilities | Maximum
Property, Plant and Equipment [Line Items]
Property and equipment, useful life						70 years
Pipeline and related facilities and Storage, terminal and rail facilities | Maximum | Change in Useful Life
Property, Plant and Equipment [Line Items]
Property and equipment, useful life		50 years

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Revenues and Accounts Receivable - Disaggregation of Revenue (Details) - Operating Segments - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 10,645	$ 3,772	$ 19,740	$ 12,401
Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	9,904	3,055	18,300	10,806
Supply and Logistics | Crude oil transactions
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	9,619	2,928	17,331	10,251
Supply and Logistics | NGL and other transactions
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	285	127	969	555
Transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	509	453	954	1,026
Transportation | Total tariff activities
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	489	431	912	969
Transportation | Crude oil pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	462	405	859	917
Transportation | NGL pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	27	26	53	52
Transportation | Trucking
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	20	22	42	57
Facilities
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	232	264	486	569
Facilities | Crude oil, NGL and other terminalling and storage
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	154	176	324	357
Facilities | NGL and natural gas processing and fractionation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	70	80	142	190
Facilities | Rail load / unload
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 8	$ 8	$ 20	$ 22

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Revenues and Accounts Receivable - Segment Revenue (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Disaggregation of Revenue [Line Items]
Total revenues	$ 9,930	$ 3,225	$ 18,313	$ 11,494
Transportation
Disaggregation of Revenue [Line Items]
Total revenues	162	151	299	338
Facilities
Disaggregation of Revenue [Line Items]
Total revenues	145	149	308	323
Supply and Logistics
Disaggregation of Revenue [Line Items]
Total revenues	9,623	2,925	17,706	10,833
Operating Segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	10,645	3,772	19,740	12,401
Other items in revenues	(225)	(114)	(479)	58
Total revenues	10,420	3,658	19,261	12,459
Operating Segments | Transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	509	453	954	1,026
Other items in revenues	44	4	85	10
Total revenues	553	457	1,039	1,036
Operating Segments | Facilities
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	232	264	486	569
Other items in revenues	12	12	29	20
Total revenues	244	276	515	589
Operating Segments | Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	9,904	3,055	18,300	10,806
Other items in revenues	(281)	(130)	(593)	28
Total revenues	9,623	2,925	17,707	10,834
Intersegment
Disaggregation of Revenue [Line Items]
Total revenues	(490)	(433)	(948)	(965)
Intersegment | Transportation
Disaggregation of Revenue [Line Items]
Total revenues	(310)	(223)	(561)	(504)
Intersegment | Facilities
Disaggregation of Revenue [Line Items]
Total revenues	(99)	(127)	(207)	(266)
Intersegment | Supply and Logistics
Disaggregation of Revenue [Line Items]
Total revenues	$ 0	$ 0	$ (1)	$ (1)

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Revenues and Accounts Receivable - Counterparty Deficiencies (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Minimum Volume Commitments [Line Items]
Counterparty deficiencies billed and collected	$ 139	$ 501
Minimum Volume Commitments
Minimum Volume Commitments [Line Items]
Counterparty deficiencies billed and collected	54	73
Counterparty deficiencies unbilled	21	4
Counterparty deficiencies	$ 75	$ 77

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Revenues and Accounts Receivable - Contract Balances (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Dec. 31, 2020	Jun. 30, 2021
Change in Contract with Customer, Liability [Roll Forward]
Beginning balance		$ 501
Amounts recognized as revenue (1)		(384)
Additions		22
Ending balance	$ 501	$ 139
Crude Oil Sales Agreements Entered Into In Conjunction With Storage Arrangements And Future Inventory Exchanges Member
Change in Contract with Customer, Liability [Roll Forward]
Amounts recognized as revenue (1)	$ (361)

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Revenues and Accounts Receivable - Performance Obligations (Details) $ in Millions	Jun. 30, 2021 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2021-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 231
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	397
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	329
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	269
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	186
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	690
Pipeline revenues supported by minimum volume commitments and capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2021-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 92
Remaining performance obligations, expected timing of satisfaction, period	6 months
Pipeline revenues supported by minimum volume commitments and capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01
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: 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	$ 151
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	$ 129
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	$ 461
Remaining performance obligations, expected timing of satisfaction, period
Storage, terminalling and throughput agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2021-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 139
Remaining performance obligations, expected timing of satisfaction, period	6 months
Storage, terminalling and throughput agreement revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 223
Remaining performance obligations, expected timing of satisfaction, period	1 year
Storage, terminalling and throughput 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	$ 155
Remaining performance obligations, expected timing of satisfaction, period	1 year
Storage, terminalling and throughput 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	$ 118
Remaining performance obligations, expected timing of satisfaction, period	1 year
Storage, terminalling and throughput 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	$ 57
Remaining performance obligations, expected timing of satisfaction, period	1 year
Storage, terminalling and throughput 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	$ 229
Remaining performance obligations, expected timing of satisfaction, period

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Revenues and Accounts Receivable - Narrative (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2021	Dec. 31, 2020
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

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Revenues and Accounts Receivable - Trade Accounts Receivable and Other Receivables (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Trade accounts receivable arising from revenues from contracts with customers	$ 3,177	$ 2,317
Other trade accounts receivables and other receivables	4,807	2,818
Impact due to contractual rights of offset with counterparties	(4,087)	(2,582)
Trade accounts receivable and other receivables, net	$ 3,897	$ 2,553

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Net Income/(Loss) Per Class A Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Basic and Diluted Net Income/(Loss) per Class A Share
Net income (loss) attributable to PAGP	$ (69)	$ 16	$ 1	$ (565)
AAP Units
Net Income Per Class A Share
Antidilutive securities excluded from computation of earnings per share (per share)	51.0	63.0	51.0	64.0
AAP Management Units
Net Income Per Class A Share
Antidilutive securities excluded from computation of earnings per share (per share)	1.0	1.0	1.0	1.0
Class A Shares
Basic and Diluted Net Income/(Loss) per Class A Share
Basic weighted average Class A shares outstanding (in shares)	194.0	184.0	194.0	183.0
Diluted weighted average Class A shares outstanding (in shares)	194.0	184.0	194.0	183.0
BASIC NET INCOME/(LOSS) PER CLASS A SHARE (in dollars per share)	$ (0.35)	$ 0.09	$ 0	$ (3.08)
DILUTED NET INCOME/(LOSS) PER CLASS A SHARE (in dollars per share)	$ (0.35)	$ 0.09	$ 0	$ (3.08)
Maximum
Net Income Per Class A Share
Dilutive LTIP awards (shares)	0.1		0.1

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Inventory, Linefill and Base Gas and Long-term Inventory (Details) bbl in Thousands, Mcf in Thousands, $ in Millions	Jun. 30, 2021 USD ($) $ / bbl $ / Mcf bbl Mcf	Dec. 31, 2020 USD ($) $ / Mcf $ / bbl bbl Mcf
Inventory by category
Inventory	$ 675	$ 647
Linefill and base gas	909	982
Long-term inventory	210	130
Total	$ 1,794	$ 1,759
Crude oil
Inventory by category
Inventory, Volumes (in barrels) | bbl	9,674	13,450
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl	15,164	14,669
Long-term inventory, Volumes (in barrels) | bbl	2,699	2,499
Inventory	$ 508	$ 441
Linefill and base gas	864	828
Long-term inventory	$ 183	$ 111
Inventory (Price/Unit of measure) | $ / bbl	52.51	32.79
Linefill and base gas (Price/Unit of measure) | $ / bbl	56.98	56.45
Long-term inventory (Price/Unit of measure) | $ / bbl	67.80	44.42
NGL
Inventory by category
Inventory, Volumes (in barrels) | bbl	7,097	12,302
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl	1,636	1,640
Long-term inventory, Volumes (in barrels) | bbl	1,258	1,185
Inventory	$ 162	$ 199
Linefill and base gas	45	44
Long-term inventory	$ 27	$ 19
Inventory (Price/Unit of measure) | $ / bbl	22.83	16.18
Linefill and base gas (Price/Unit of measure) | $ / bbl	27.51	26.83
Long-term inventory (Price/Unit of measure) | $ / bbl	21.46	16.03
Natural gas
Inventory by category
Linefill and base gas, Volumes (in barrels or in Mcf) | Mcf	0	25,576
Linefill and base gas	$ 0	$ 110
Linefill and base gas (Price/Unit of measure) | $ / Mcf	0	4.30
Natural gas | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Pine Prairie and Southern Pines Natural Gas Storage Facilities
Inventory by category
Linefill and base gas	$ 110
Other
Inventory by category
Inventory	$ 5	$ 7

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Debt - Components (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Short-term debt:
Total short-term debt	$ 1,456	$ 831
Long-term debt:
Senior notes, net	8,326	9,071
Other long-term debt, net	63	311
Total long-term debt	8,389	9,382
Total debt	9,845	10,213
Senior notes
Long-term debt:
Senior notes, net	8,326	9,071
Unamortized discounts and debt issuance costs	57	62
Debt instrument face value	9,100	9,100
Other
Long-term debt:
Other long-term debt, net	63	112
Level 2 | Senior notes
Long-term debt:
Debt instrument fair value	10,000	9,900
Other
Short-term debt:
Total short-term debt	119	117
Commercial Paper | Line of Credit
Short-term debt:
Short-term debt	$ 388	$ 547
Weighted average interest rate, short-term	0.40%	0.70%
Senior Secured Hedged Inventory Facility | Line of Credit
Short-term debt:
Short-term debt		$ 167
Weighted average interest rate, short-term	1.20%	1.20%
3.65% senior notes due June 2022 | Senior notes
Short-term debt:
Total short-term debt	$ 750
Stated percentage	3.65%
GO Zone term loans | Term loan
Short-term debt:
Debt issuance costs		$ 1
Long-term debt:
Other long-term debt, net		$ 199
Weighted average interest rate, long-term		1.30%
GO Zone term loans | Term loan
Short-term debt:
Total short-term debt	$ 199
Weighted average interest rate, short-term	1.30%
Debt issuance costs	$ 1

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Debt - Letters of Credit, Borrowings and Repayments (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Debt
Outstanding letters of credit	$ 81		$ 129
Credit facilities and PAA commercial paper program
Debt
Total borrowings	26,100	$ 12,600
Total repayments	$ 26,400	$ 13,000

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Partners' Capital and Distributions - Exchange Rights and Shares Activity (Details) - shares	3 Months Ended
	Jun. 30, 2021	Mar. 31, 2021	Jun. 30, 2020	Mar. 31, 2020
Class A Shares
Activity for Class A shares, Class B shares and Class C shares
Balance, beginning of period (shares)	194,098,315	194,051,436	184,240,079	182,138,592
Exchange Right exercises (shares)	25,554	46,879		2,101,487
Other (shares)			20,099
Balance, end of period (shares)	194,123,869	194,098,315	184,260,178	184,240,079
Class B Shares
Activity for Class A shares, Class B shares and Class C shares
Balance, beginning of period (shares)	50,777,990	50,640,192	63,037,384	65,785,702
Conversion of AAP Management Units (shares)		414,608	35,349	559,768
Exchange Right exercises (shares)	(25,554)	(46,879)		(2,101,487)
Redemption Right exercises (shares)	(535,009)	(229,931)	(40,679)	(1,206,599)
Balance, end of period (shares)	50,217,427	50,777,990	63,032,054	63,037,384
Class C Shares
Activity for Class A shares, Class B shares and Class C shares
Balance, beginning of period (shares)	547,623,124	547,717,762	550,769,169	549,538,139
Redemption Right exercises (shares)	535,009	229,931	40,679	1,206,599
Repurchase of common units by a subsidiary under Common Equity Repurchase Program (shares)	(4,940,592)	(350,000)
Other (shares)	256,321	25,431	27,292	24,431
Balance, end of period (shares)	543,473,862	547,623,124	550,837,140	550,769,169

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Partners' Capital and Distributions - Distributions, Class A (Details) - Cash Distribution - Class A Shares - USD ($) $ / shares in Units, $ in Millions	Aug. 13, 2021	May 14, 2021	Feb. 12, 2021
Partners' Capital and Distributions
Distributions to Class A shareholders		$ 35	$ 35
Distribution per Class A share, paid (usd per share)		$ 0.18	$ 0.18
Forecast
Partners' Capital and Distributions
Distributions to Class A shareholders	$ 35
Distribution per Class A share, paid (usd per share)	$ 0.18

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Partners' Capital and Distributions - Noncontrolling Interests in Subsidiaries (Details)	Jun. 30, 2021
AAP
Partners' Capital and Distributions
Noncontrolling interests in subsidiaries (percent)	21.00%
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%

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Partners' Capital and Distributions - Common Equity Repurchase Program (Details) - Common Equity Repurchase Program $ in Millions	6 Months Ended
	Jun. 30, 2021 USD ($) shares
Partners Capital and Distribution [Line Items]
Common equity repurchase program, remaining amount	$ 397
PAA
Partners Capital and Distribution [Line Items]
Common equity repurchase program, repurchased amount (dollars)	$ 53
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) | shares	5,290,592

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Partners' Capital and Distributions - Subsidiary Distributions (Details) - USD ($) $ / shares in Units, $ in Millions					3 Months Ended		6 Months Ended
	Aug. 13, 2021	May 17, 2021	May 14, 2021	Feb. 12, 2021	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Partners' Capital and Distributions
Total distributions paid					$ 179.0	$ 184.0	$ 365.0	$ 496.0
PAA | Series A Preferred Units | Cash Distribution
Partners' Capital and Distributions
Preferred unit distribution amount			$ 37.0	$ 37.0
Preferred unit distribution amount (in dollars per unit)			$ 0.525	$ 0.525
PAA | Series A Preferred Units | Cash Distribution | Forecast
Partners' Capital and Distributions
Preferred unit distribution amount	$ 37.0
Preferred unit distribution amount (in dollars per unit)	$ 0.525
PAA | Series B Preferred Units | Cash Distribution
Partners' Capital and Distributions
Preferred unit distribution amount		$ 24.5
Preferred unit distribution amount (in dollars per unit)		$ 30.625
PAA | Common Units | Cash Distribution
Partners' Capital and Distributions
Total distributions paid			$ 130.0	$ 130.0
Distributions per common unit, paid (usd per unit)			$ 0.18	$ 0.18
PAA | Common Units | Cash Distribution | Forecast
Partners' Capital and Distributions
Total distributions paid	$ 129.0
Distributions per common unit, paid (usd per unit)	$ 0.18
AAP | Cash Distribution
Partners' Capital and Distributions
Distributions to noncontrolling interests			$ 9.0	$ 9.0
Distributions to PAGP			35.0	35.0
Total distributions paid			44.0	44.0
AAP | Cash Distribution | Forecast
Partners' Capital and Distributions
Distributions to noncontrolling interests	$ 9.0
Distributions to PAGP	35.0
Total distributions paid	44.0
Public | PAA | Common Units | Cash Distribution
Partners' Capital and Distributions
Distributions to common unitholders			86.0	86.0
Public | PAA | Common Units | Cash Distribution | Forecast
Partners' Capital and Distributions
Distributions to common unitholders	85.0
AAP | PAA | Common Units | Cash Distribution
Partners' Capital and Distributions
Distributions to common unitholders			$ 44.0	$ 44.0
AAP | PAA | Common Units | Cash Distribution | Forecast
Partners' Capital and Distributions
Distributions to common unitholders	$ 44.0
Other current liabilities | PAA | Series B Preferred Units
Partners' Capital and Distributions
Amount accrued to distributions payable					6.0		6.0
Noncontrolling Interests
Partners' Capital and Distributions
Total distributions paid					$ 144.0	$ 151.0	295.0	$ 397.0
Noncontrolling Interests | Red River LLC
Partners' Capital and Distributions
Total distributions paid							$ 6.0

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Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions	6 Months Ended
	Jun. 30, 2021 TWh bbl Bcf MMBbls
Net long position associated with crude oil purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf)	1.6
Net short time spread position hedging anticipated crude oil lease gathering purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf)	8.4
Net crude oil basis spread position
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf)	8.6
Net short position related to anticipated net sales of crude oil and NGL inventory
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf)	16.2
Long natural gas position for natural gas purchases for processing and operational needs
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf) | Bcf	51.9
Short propane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf) | MMBbls	9.0
Short butane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf) | MMBbls	2.6
Short condensate WTI position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf) | MMBbls	0.8
Long fuel gas position for fuel gas requirements
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels, MMbls or Bcf) | Bcf	10.3
Long power position for power supply requirements
Commodity Price Risk Hedging:
Derivative position notional amount (in Terawatt hours) | TWh	0.7

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Derivatives and Risk Management Activities - Financial Impact (Details) - Derivatives Not Designated as a Hedge - Commodity Derivatives - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	$ (267)	$ (135)	$ (542)	$ 15
Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	(284)	(134)	(598)	15
Field operating costs
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	$ 17	$ (1)	$ 56	$ 0

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Derivatives and Risk Management Activities - Broker Receivable/Payable (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Offsetting Assets, Liabilities [Line Items]
Initial margin	$ 78	$ 91
Variation margin posted/(returned)	369	290
Letters of credit	(81)	(129)
Net broker receivable/(payable)	407	318
Exchange traded
Offsetting Assets, Liabilities [Line Items]
Letters of credit	$ (40)	$ (63)

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Derivatives and Risk Management Activities - Offsetting Asset and Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Derivative Asset Positions
Effect of Collateral Netting	$ 407	$ 318
Commodity Derivatives
Derivative Asset Positions
Effect of Collateral Netting	407	318
Derivative Liability Positions
Gross Position - Asset	221	85
Gross Position - Liability	(617)	(386)
Net Carrying Value Presented on the Balance Sheet, Total	11	17
Other current assets | Commodity Derivatives
Derivative Asset Positions
Gross Position - Asset	205	71
Gross Position - Liability	(430)	(314)
Effect of Collateral Netting	407	318
Net Carrying Value Presented on the Balance Sheet	182	75
Other long-term assets, net | Commodity Derivatives
Derivative Asset Positions
Gross Position - Asset	6	5
Gross Position - Liability	0	0
Net Carrying Value Presented on the Balance Sheet	6	5
Other current liabilities | Commodity Derivatives
Derivative Liability Positions
Gross Position - Asset	3	9
Gross Position - Liability	(97)	(40)
Net Carrying Value Presented on the Balance Sheet	(94)	(31)
Other long-term liabilities and deferred credits | Commodity Derivatives
Derivative Liability Positions
Gross Position - Asset	7	0
Gross Position - Liability	(90)	(32)
Net Carrying Value Presented on the Balance Sheet	$ (83)	$ (32)

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Derivatives and Risk Management Activities - Interest Rate Risk Hedging (Details) - Cash flow hedge $ in Millions	6 Months Ended
	Jun. 30, 2021 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%

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Derivatives and Risk Management Activities - Net Unrealized Gain/(Loss) Recognized in AOCI (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Other long-term assets, net
Derivative assets and liabilities
Interest rate fair value hedge liability at fair value	$ 75		$ 75		$ 46
AOCI cash flow hedge
Derivative assets and liabilities
Net loss deferred in AOCI	223		223
Interest Rate Derivatives
Derivative assets and liabilities
Net unrealized gain/(loss) recognized in AOCI	$ (39)	$ 19	$ 29	$ (61)

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Derivatives and Risk Management Activities - Currency Exchange Rate Risk Hedging (Details) $ in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021 USD ($) $ / $	Jun. 30, 2020 USD ($)	Jun. 30, 2021 USD ($) $ / $	Jun. 30, 2020 USD ($)	Jun. 30, 2021 CAD ($) $ / $	Dec. 31, 2020 USD ($)
Foreign Currency Derivatives | Derivatives Not Designated as a Hedge | Supply and Logistics segment revenues
Currency Exchange Rate Risk Hedging:
Gain/(loss) recognized in earnings | $	$ 2	$ 2	$ 3	$ (4)
Forward exchange contracts that exchange CAD For USD maturing in 2021
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 144		$ 144		$ 177
Forward exchange contracts that exchange CAD For USD maturing in 2021 | Minimum
Currency Exchange Rate Risk Hedging:
Average exchange rate (cad per usd)	1.00		1.00		1.00
Forward exchange contracts that exchange CAD For USD maturing in 2021 | Maximum
Currency Exchange Rate Risk Hedging:
Average exchange rate (cad per usd)	1.23		1.23		1.23
Forward exchange contracts that exchange USD for CAD maturing in 2021
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 142		$ 142		$ 172
Forward exchange contracts that exchange USD for CAD maturing in 2021 | Minimum
Currency Exchange Rate Risk Hedging:
Average exchange rate (cad per usd)	1.00		1.00		1.00
Forward exchange contracts that exchange USD for CAD maturing in 2021 | Maximum
Currency Exchange Rate Risk Hedging:
Average exchange rate (cad per usd)	1.21		1.21		1.21
Interest Rate Derivatives | Derivatives in Hedging Relationships | Other current assets
Currency Exchange Rate Risk Hedging:
Derivative asset | $						$ 2
Interest Rate Derivatives | Derivatives in Hedging Relationships | Other current assets | Maximum
Currency Exchange Rate Risk Hedging:
Derivative asset | $	$ 1		$ 1

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Derivatives and Risk Management Activities - Preferred Distribution Rate (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Derivatives and Risk Management Activities
Gain/(loss) recognized			$ 9	$ 17
Preferred Distribution Rate Reset Option | Derivatives Not Designated as a Hedge | Other long-term liabilities and deferred credits
Derivatives and Risk Management Activities
Derivative liability	$ 5		5		$ 14
Preferred Distribution Rate Reset Option | Derivatives Not Designated as a Hedge | Other expense, net
Derivatives and Risk Management Activities
Gain/(loss) recognized	$ 77	$ (9)	$ 9	$ 17

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Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Level 3
Rollforward of Level 3 Net Asset/(Liability)
Beginning Balance	$ (92)	$ (61)	$ (29)	$ (51)
Net gains/(losses) for the period included in earnings	77	18	9	8
Settlements	2	1	7	1
Ending Balance	(13)	(42)	(13)	(42)
Change in unrealized losses included in earnings relating to Level 3 derivatives still held at the end of the period	77	$ 18	9	$ 8
Recurring Fair Value Measures
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(326)		(326)		$ (267)
Recurring Fair Value Measures | Commodity Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(395)		(395)		(301)
Recurring Fair Value Measures | Interest Rate Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	75		75		46
Recurring Fair Value Measures | Foreign Currency Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(1)		(1)		2
Recurring Fair Value Measures | Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(5)		(5)		(14)
Recurring Fair Value Measures | Level 1
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(246)		(246)		(143)
Recurring Fair Value Measures | Level 1 | Commodity Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(246)		(246)		(143)
Recurring Fair Value Measures | Level 1 | Interest Rate Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	0		0		0
Recurring Fair Value Measures | Level 1 | Foreign Currency Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	0		0		0
Recurring Fair Value Measures | Level 1 | Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Total net derivative asset/(liability)	0		0		0
Recurring Fair Value Measures | Level 2
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(67)		(67)		(95)
Recurring Fair Value Measures | Level 2 | Commodity Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(141)		(141)		(143)
Recurring Fair Value Measures | Level 2 | Interest Rate Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	75		75		46
Recurring Fair Value Measures | Level 2 | Foreign Currency Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(1)		(1)		2
Recurring Fair Value Measures | Level 2 | Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Total net derivative asset/(liability)	0		0		0
Recurring Fair Value Measures | Level 3
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(13)		(13)		(29)
Recurring Fair Value Measures | Level 3 | Commodity Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(8)		(8)		(15)
Recurring Fair Value Measures | Level 3 | Interest Rate Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	0		0		0
Recurring Fair Value Measures | Level 3 | Foreign Currency Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	0		0		0
Recurring Fair Value Measures | Level 3 | Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Total net derivative asset/(liability)	$ (5)		$ (5)		$ (14)

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Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Related Party Transactions [Abstract]
Revenues from related parties	$ 10	$ 10	$ 17	$ 33
Purchases and related costs from related parties	95	$ 94	185	$ 223
Trade accounts receivable and other receivables, net from related parties	29		29		$ 34
Trade accounts payable to related parties	$ 80		$ 80		$ 88

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Commitments and Contingencies - Legal, Environmental or Regulatory (Details) $ in Thousands	1 Months Ended	9 Months Ended	74 Months Ended
	May 31, 2015 bbl	Jun. 30, 2021 USD ($)	Jun. 30, 2021 USD ($) lawsuit	Dec. 31, 2020 USD ($)	Apr. 25, 2019 USD ($)	Sep. 07, 2018 count
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities		$ 159,000	$ 159,000	$ 141,000
Amounts probable of recovery under insurance and from third parties under indemnification agreements		114,000	114,000	97,000
Other long-term liabilities and deferred credits
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities, long-term		47,000	47,000	47,000
Trade accounts payable and Other current liabilities
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities, short-term		112,000	112,000	94,000
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	1,000	1,000
Trade accounts receivable and other receivables, net
Legal, Environmental or Regulatory Matters
Amounts probable of recovery under insurance and from third parties under indemnification agreements		113,000	113,000	$ 96,000
Line 901 Incident
Legal, Environmental or Regulatory Matters
Amounts probable of recovery under insurance and from third parties under indemnification agreements		110,000	110,000
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		485,000	485,000
Recoveries from insurance carriers			250,000
Total release costs probable of recovery		360,000	360,000
Line 901 Incident | Trade accounts payable and Other current liabilities
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities		104,000	$ 104,000
Line 901 Incident | Civil Penalties
Legal, Environmental or Regulatory Matters
Penalties or compensation paid		24,000
Line 901 Incident | Consent Decree, Compensation for Injuries to, Destruction of, Loss of Use of, Natural Resources
Legal, Environmental or Regulatory Matters
Penalties or compensation paid		$ 22,325
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
Fines or penalties assessed					$ 3,350
Line 901 Incident | Class Action Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed during the period | lawsuit			9
Line 901 Incident | Unitholder Derivative Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed during the period | lawsuit			4

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Operating Segments - Segment Financial Data (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021 USD ($)	Jun. 30, 2020 USD ($)	Jun. 30, 2021 USD ($) segment	Jun. 30, 2020 USD ($)
Segment Reporting Information [Line Items]
Operating segments number | segment			3
Revenues:
Revenues	$ 9,930	$ 3,225	$ 18,313	$ 11,494
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	33	81	121	191
Segment Adjusted EBITDA	578	523	1,124	1,316
Maintenance capital	37	54	73	104
Transportation
Revenues:
Revenues	162	151	299	338
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	31	81	117	189
Segment Adjusted EBITDA	433	346	821	788
Maintenance capital	20	31	47	64
Facilities
Revenues:
Revenues	145	149	308	323
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	2	0	4	2
Segment Adjusted EBITDA	140	174	311	384
Maintenance capital	14	15	20	29
Supply and Logistics
Revenues:
Revenues	9,623	2,925	17,706	10,833
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment Adjusted EBITDA	5	3	(8)	144
Maintenance capital	3	8	6	11
Operating Segments Excluding Intersegment Elimination | Transportation
Revenues:
Revenues	243	234	478	532
Operating Segments Excluding Intersegment Elimination | Facilities
Revenues:
Revenues	145	149	308	323
Operating Segments Excluding Intersegment Elimination | Supply and Logistics
Revenues:
Revenues	9,623	2,925	17,706	10,833
Intersegment
Revenues:
Revenues	(490)	(433)	(948)	(965)
Intersegment | Transportation
Revenues:
Revenues	(310)	(223)	(561)	(504)
Intersegment | Facilities
Revenues:
Revenues	(99)	(127)	(207)	(266)
Intersegment | Supply and Logistics
Revenues:
Revenues	0	0	(1)	(1)
Intersegment Adjustment
Revenues:
Revenues	(81)	(83)	(179)	(194)
Operating Segments
Revenues:
Revenues	10,420	3,658	19,261	12,459
Operating Segments | Transportation
Revenues:
Revenues	553	457	1,039	1,036
Operating Segments | Facilities
Revenues:
Revenues	244	276	515	589
Operating Segments | Supply and Logistics
Revenues:
Revenues	$ 9,623	$ 2,925	$ 17,707	$ 10,834

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Operating Segments - Segment Adjusted EBITDA Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Segment Reporting, Reconciling Item from Segments to Consolidated [Line Items]
Segment Adjusted EBITDA	$ 578	$ 523	$ 1,124	$ 1,316
Adjustments:
Depreciation and amortization of unconsolidated entities	(68)	(16)	(88)	(33)
Gains/(losses) from derivative activities and inventory valuation adjustments	(163)	(90)	35	(121)
Long-term inventory costing adjustments	27	51	68	(64)
Deficiencies under minimum volume commitments, net	(6)	(7)	26	(6)
Equity-indexed compensation expense	(4)	(5)	(9)	(8)
Net gain on foreign currency revaluation	1		2	13
Significant transaction-related expenses	(3)		(3)	(3)
Unallocated general and administrative expenses	(74)	(74)	(142)	(144)
Depreciation and amortization	(197)	(166)	(375)	(335)
Gains/(losses) on asset sales and asset impairments, net	(369)	1	(370)	(618)
Goodwill impairment losses				(2,515)
Gain on/(impairment of) investments in unconsolidated entities, net		(69)		(91)
Interest expense, net	(107)	(108)	(213)	(215)
Other income/(expense), net	84	18	23	(13)
INCOME/(LOSS) BEFORE TAX	(229)	130	217	(2,696)
Income tax (expense)/benefit	17	7	(36)	140
NET INCOME/(LOSS)	(212)	137	181	(2,556)
Net (income)/loss attributable to noncontrolling interests	143	(121)	(180)	1,991
NET INCOME/(LOSS) ATTRIBUTABLE TO PAGP	(69)	16	1	(565)
Unallocated
Adjustments:
Unallocated general and administrative expenses	$ (2)	$ (2)	$ (3)	$ (3)

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Acquisitions, Divestitures and Other Transactions (Details) $ in Millions	1 Months Ended	3 Months Ended			6 Months Ended
	Jun. 30, 2021 USD ($) plant	Dec. 31, 2021	Jun. 30, 2021 USD ($)	Jun. 30, 2020 USD ($)	Jun. 30, 2021 USD ($)	Jun. 30, 2020 USD ($)	Mar. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Mar. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Business Acquisition [Line Items]
Gain on divestiture of assets			$ (369)	$ 1	$ (370)	$ (618)
Deferred losses on hedges remaining in other comprehensive income	$ 11,061		11,061	11,253	11,061	11,253	$ 11,499	$ 11,190	$ 11,186	$ 14,485
Derivative Instruments
Business Acquisition [Line Items]
Deferred losses on hedges remaining in other comprehensive income	(223)		(223)	$ (315)	(223)	$ (315)		$ (258)		$ (259)
Disposal Group, Held-for-sale, Not Discontinued Operations | Pine Prairie and Southern Pines Natural Gas Storage Facilities | Derivative Instruments
Business Acquisition [Line Items]
Deferred losses on hedges remaining in other comprehensive income	18		18		18
Disposal Group, Held-for-sale, Not Discontinued Operations | Pine Prairie and Southern Pines Natural Gas Storage Facilities | Other current assets
Business Acquisition [Line Items]
Assets held for sale, current	832		832		832
Disposal Group, Held-for-sale, Not Discontinued Operations | Pine Prairie and Southern Pines Natural Gas Storage Facilities | (Gains)/losses on asset sales and asset impairments, net
Business Acquisition [Line Items]
Non-cash impairment losses upon classification to assets held for sale			475
Facilities | Disposal Group, Held-for-sale, Not Discontinued Operations | Pine Prairie and Southern Pines Natural Gas Storage Facilities
Business Acquisition [Line Items]
Consideration to be received for sale of assets	850		$ 850		$ 850
Asset Exchange Transaction | Inter Pipeline Ltd | Transportation | (Gains)/losses on asset sales and asset impairments, net
Business Acquisition [Line Items]
Gain on divestiture of assets	106
Joint Venture Transaction | Oryx Midstream Holdings LLC | Forecast | Plains Oryx Permian Basin LLC | PAA
Business Acquisition [Line Items]
Ownership interest		65.00%
Additional Interests in Straddle Plants | Asset Exchange Transaction | Inter Pipeline Ltd
Business Acquisition [Line Items]
Cash consideration, including working capital and other adjustments	$ 32
Additional Interests in Straddle Plants | Asset Exchange Transaction | Inter Pipeline Ltd | Facilities
Business Acquisition [Line Items]
Number of straddle plants, additional interests acquired | plant	2