PLAINS ALL AMERICAN PIPELINE LP - Quarter Report: 2020 September (Form 10-Q)

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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 September 30, 2020

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

Commission File Number: 1-14569

________________________________________________________________

PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)


Delaware						76-0582150
(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
Common Units	PAA	New York Stock Exchange

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. (Check one):

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 October 30, 2020, there were 728,476,591 Common Units outstanding.

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PLAINS ALL AMERICAN PIPELINE, 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 September 30, 2020 and December 31, 2019			3
Condensed Consolidated Statements of Operations: For the three and nine months ended September 30, 2020 and 2019			4
Condensed Consolidated Statements of Comprehensive Income/(Loss): For the three and nine months ended Se ptember 30, 2020 and 2019			5
Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss): For the nine months ended September 30, 2020 and 2019			5
Condensed Consolidated Statements of Cash Flows: For the nine months ended September 30, 2020 and 2019			6
Condensed Consolidated Statements of Changes in Partners’ Capital: For the three and nine months ended September 30, 2020 and 2019			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			12
4. Net Income/(Loss) Per Common Unit			16
5. Inventory, Linefill and Base Gas and Long-term Inventory			18
6. Goodwill			19
7. Investments in Unconsolidated Entities			20
8. Debt			21
9. Partners’ Capital and Distributions			22
10. Derivatives and Risk Management Activities			24
11. Related Party Transactions			29
12. Commitments and Contingencies			30
13. Operating Segments			34
14. Acquisitions, Divestitures and Asset Impairments			37

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			39
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			67
Item 4. CONTROLS AND PROCEDURES			68

PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS			69
Item 1A. RISK FACTORS			69
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			69
Item 3. DEFAULTS UPON SENIOR SECURITIES			69
Item 4. MINE SAFETY DISCLOSURES			69
Item 5. OTHER INFORMATION			69
Item 6. EXHIBITS			69
SIGNATURES			74

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PART I. FINANCIAL INFORMATION

Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)


	September 30, 2020		December 31, 2019
	(unaudited)
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	25	$	45
Restricted cash	21		37
Trade accounts receivable and other receivables, net	2,153		3,614
Inventory	683		604
Other current assets	523		312
Total current assets	3,405		4,612

PROPERTY AND EQUIPMENT	18,420		18,948
Accumulated depreciation	(3,802)		(3,593)
Property and equipment, net	14,618		15,355

OTHER ASSETS
Investments in unconsolidated entities	3,743		3,683
Goodwill	—		2,540
Linefill and base gas	966		981
Long-term operating lease right-of-use assets, net	395		466
Long-term inventory	120		182
Other long-term assets, net	999		858
Total assets	$	24,246	$	28,677

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES
Trade accounts payable	$	2,091	$	3,686
Short-term debt	790		504
Other current liabilities	923		827
Total current liabilities	3,804		5,017

LONG-TERM LIABILITIES
Senior notes, net	9,069		8,939
Other long-term debt, net	312		248
Long-term operating lease liabilities	337		387
Other long-term liabilities and deferred credits	873		891
Total long-term liabilities	10,591		10,465

COMMITMENTS AND CONTINGENCIES (NOTE 12)

PARTNERS’ CAPITAL
Series A preferred unitholders (71,090,468 and 71,090,468 units outstanding, respectively)	1,505		1,505
Series B preferred unitholders (800,000 and 800,000 units outstanding, respectively)	787		787
Common unitholders (728,476,591 and 728,028,576 units outstanding, respectively)	7,414		10,770
Total partners’ capital excluding noncontrolling interests	9,706		13,062
Noncontrolling interests	145		133
Total partners’ capital	9,851		13,195
Total liabilities and partners’ capital	$	24,246	$	28,677

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(unaudited)				(unaudited)
REVENUES
Supply and Logistics segment revenues	$	5,537	$	7,541	$	16,370	$	23,477
Transportation segment revenues	146		196		484		581
Facilities segment revenues	150		149		473		457
Total revenues	5,833		7,886		17,327		24,515

COSTS AND EXPENSES
Purchases and related costs	5,107		6,855		15,000		21,218
Field operating costs	254		316		811		983
General and administrative expenses	61		74		201		225
Depreciation and amortization	160		156		493		439
(Gains)/losses on asset sales and asset impairments, net (Note 14)	(2)		(7)		617		(7)
Goodwill impairment losses (Note 6)	—		—		2,515		—
Total costs and expenses	5,580		7,394		19,637		22,858

OPERATING INCOME/(LOSS)	253		492		(2,310)		1,657

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	89		102		280		274
Gain on/(impairment of) investments in unconsolidated entities, net (Note 7)	(91)		4		(182)		271
Interest expense (net of capitalized interest of $6, $7, $17 and $29, respectively)	(113)		(108)		(329)		(311)
Other income/(expense), net	5		5		(7)		23

INCOME/(LOSS) BEFORE TAX	143		495		(2,548)		1,914
Current income tax expense	(17)		(19)		(39)		(72)
Deferred income tax (expense)/benefit	20		(22)		32		30

NET INCOME/(LOSS)	146		454		(2,555)		1,872
Net income attributable to noncontrolling interests	(3)		(5)		(7)		(7)
NET INCOME/(LOSS) ATTRIBUTABLE TO PAA	$	143	$	449	$	(2,562)	$	1,865

NET INCOME/(LOSS) PER COMMON UNIT (NOTE 4):
Net income/(loss) allocated to common unitholders — Basic	$	93	$	399	$	(2,712)	$	1,710
Basic weighted average common units outstanding	728		728		728		727
Basic net income/(loss) per common unit	$	0.13	$	0.55	$	(3.72)	$	2.35

Net income/(loss) allocated to common unitholders — Diluted	$	93	$	436	$	(2,712)	$	1,826
Diluted weighted average common units outstanding	728		800		728		800
Diluted net income/(loss) per common unit	$	0.13	$	0.55	$	(3.72)	$	2.28

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

(in millions)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(unaudited)				(unaudited)
Net income/(loss)	$	146	$	454	$	(2,555)	$	1,872
Other comprehensive income/(loss)	82		(99)		(129)		10
Comprehensive income/(loss)	228		355		(2,684)		1,882
Comprehensive income attributable to noncontrolling interests	(3)		(5)		(7)		(7)
Comprehensive income/(loss) attributable to PAA	$	225	$	350	$	(2,691)	$	1,875

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

PLAINS ALL AMERICAN PIPELINE, 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, 2019	$	(259)	$	(674)	$	—	$	(933)

Reclassification adjustments	8		—		—		8
Unrealized loss on hedges	(39)		—		—		(39)
Currency translation adjustments	—		(99)		—		(99)
Other	—		—		1		1
Total period activity	(31)		(99)		1		(129)
Balance at September 30, 2020	$	(290)	$	(773)	$	1	$	(1,062)


	Derivative Instruments		Translation Adjustments		Other		Total
	(unaudited)
Balance at December 31, 2018	$	(177)	$	(853)	$	—	$	(1,030)

Reclassification adjustments	7		—		—		7
Unrealized loss on hedges	(111)		—		—		(111)
Currency translation adjustments	—		113		—		113
Other	—		—		1		1
Total period activity	(104)		113		1		10
Balance at September 30, 2019	$	(281)	$	(740)	$	1	$	(1,020)

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	Nine Months Ended September 30,
	2020		2019
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income/(loss)	$	(2,555)	$	1,872
Reconciliation of net income/(loss) to net cash provided by operating activities:
Depreciation and amortization	493		439
(Gains)/losses on asset sales and asset impairments, net (Note 14)	617		(7)
Goodwill impairment losses (Note 6)	2,515		—
Equity-indexed compensation expense	8		31
Inventory valuation adjustments	233		11
Deferred income tax benefit	(32)		(30)

Settlement of terminated interest rate hedging instruments	(100)		(55)
Change in fair value of Preferred Distribution Rate Reset Option (Note 10)	(7)		(16)
Equity earnings in unconsolidated entities	(280)		(274)
Distributions on earnings from unconsolidated entities	344		307
(Gain on)/impairment of investments in unconsolidated entities, net (Note 7)	182		(271)
Other	29		22
Changes in assets and liabilities, net of acquisitions	(191)		(251)
Net cash provided by operating activities	1,256		1,778

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired (Note 14)	(310)		(47)
Investments in unconsolidated entities	(386)		(367)
Additions to property, equipment and other	(606)		(919)
Proceeds from sales of assets (Note 14)	246		8


Cash paid for purchases of linefill and base gas	(14)		(33)
Other investing activities	4		(9)
Net cash used in investing activities	(1,066)		(1,367)

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings under commercial paper program (Note 8)	19		—

Net repayments under senior secured hedged inventory facility (Note 8)	(325)		—

Proceeds from the issuance of senior notes (Note 8)	748		998
Repayments of senior notes (Note 8)	(17)		—

Distributions paid to Series A preferred unitholders (Note 9)	(112)		(112)
Distributions paid to Series B preferred unitholders (Note 9)	(25)		(25)
Distributions paid to common unitholders (Note 9)	(524)		(741)
Contributions from noncontrolling interests (Note 9)	11		—
Sale of noncontrolling interest in a subsidiary	—		128
Other financing activities	8		(52)
Net cash (used in)/provided by financing activities	(217)		196

Effect of translation adjustment	(9)		(5)

Net increase/(decrease) in cash and cash equivalents and restricted cash	(36)		602
Cash and cash equivalents and restricted cash, beginning of period	82		66
Cash and cash equivalents and restricted cash, end of period	$	46	$	668

Cash paid for:
Interest, net of amounts capitalized	$	285	$	263
Income taxes, net of amounts refunded	$	72	$	110

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(in millions)


	Limited Partners						Partners’ Capital Excluding Noncontrolling Interests		Noncontrolling Interests		Total Partners’ Capital
	Preferred Unitholders				Common Unitholders
	Series A		Series B
	(unaudited)
Balance at December 31, 2019	$	1,505	$	787	$	10,770	$	13,062	$	133	$	13,195
Net income/(loss)	112		37		(2,711)		(2,562)		7		(2,555)
Distributions (Note 9)	(112)		(37)		(524)		(673)		(6)		(679)
Other comprehensive loss	—		—		(129)		(129)		—		(129)
Contributions from noncontrolling interests (Note 9)	—		—		—		—		11		11
Other	—		—		8		8		—		8
Balance at September 30, 2020	$	1,505	$	787	$	7,414	$	9,706	$	145	$	9,851

	Limited Partners						Partners’ Capital Excluding Noncontrolling Interests		Noncontrolling Interests		Total Partners’ Capital
	Preferred Unitholders				Common Unitholders
	Series A		Series B
	(unaudited)
Balance at June 30, 2020	$	1,505	$	787	$	7,367	$	9,659	$	143	$	9,802
Net income	37		12		94		143		3		146
Distributions (Note 9)	(37)		(12)		(131)		(180)		(2)		(182)
Other comprehensive income	—		—		82		82		—		82
Contributions from noncontrolling interests (Note 9)	—		—		—		—		1		1
Other	—		—		2		2		—		2
Balance at September 30, 2020	$	1,505	$	787	$	7,414	$	9,706	$	145	$	9,851

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(continued)

(in millions)


	Limited Partners						Partners’ Capital Excluding Noncontrolling Interests		Noncontrolling Interests		Total Partners’ Capital
	Preferred Unitholders				Common Unitholders
	Series A		Series B
	(unaudited)
Balance at December 31, 2018	$	1,505	$	787	$	9,710	$	12,002	$	—	$	12,002
Net income	112		37		1,716		1,865		7		1,872
Distributions	(112)		(37)		(741)		(890)		(4)		(894)
Other comprehensive income	—		—		10		10		—		10
Sale of noncontrolling interest in a subsidiary	—		—		(2)		(2)		130		128
Other	—		—		(7)		(7)		—		(7)
Balance at September 30, 2019	$	1,505	$	787	$	10,686	$	12,978	$	133	$	13,111

	Limited Partners						Partners’ Capital Excluding Noncontrolling Interests		Noncontrolling Interests		Total Partners’ Capital
	Preferred Unitholders				Common Unitholders
	Series A		Series B
	(unaudited)
Balance at June 30, 2019	$	1,505	$	787	$	10,649	$	12,941	$	132	$	13,073
Net income	37		12		400		449		5		454
Distributions	(37)		(12)		(262)		(311)		(4)		(315)
Other comprehensive loss	—		—		(99)		(99)		—		(99)

Other	—		—		(2)		(2)		—		(2)
Balance at September 30, 2019	$	1,505	$	787	$	10,686	$	12,978	$	133	$	13,111

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Basis of Consolidation and Presentation

Organization

Plains All American Pipeline, L.P. (“PAA”) is a Delaware limited partnership formed in 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in this Form 10-Q and unless the context indicates otherwise, the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAA and its subsidiaries.

We own and operate midstream energy infrastructure and provide logistics services primarily for crude oil, natural gas liquids (“NGL”) and natural gas. We own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. Our business activities are conducted through three operating segments: Transportation, Facilities and Supply and Logistics. See Note 13 for further discussion of our operating segments.

Our non-economic general partner interest is held by PAA GP LLC (“PAA GP”), a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP, as of September 30, 2020, AAP also owned a limited partner interest in us through its ownership of approximately 245.8 million of our common units (approximately 31% of our total outstanding common units and Series A preferred units combined). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole and managing member of GP LLC, and, at September 30, 2020, owned an approximate 77% limited partner interest in AAP. PAA GP Holdings LLC (“PAGP GP”) is the general partner of PAGP.

As the sole member of GP LLC, PAGP has responsibility for conducting our business and managing our operations; however, the board of directors of PAGP GP has ultimate responsibility for managing the business and affairs of PAGP, AAP and us. GP LLC employs our domestic officers and personnel; our Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC.

References to our “general partner,” as the context requires, include any or all of PAGP GP, PAGP, GP LLC, AAP and PAA GP.

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PLAINS ALL AMERICAN PIPELINE, 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 2019 Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of PAA 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, 2019 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three and nine months ended September 30, 2020 should not be taken as indicative of results to be expected for the entire year.

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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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

COVID-19

During the first quarter of 2020, the novel coronavirus (“COVID-19”) pandemic resulted in a swift and material decline in global crude oil demand, which contributed to an oversupply of crude oil that was exacerbated by increases in production from certain suppliers in the global oil markets. These macroeconomic and industry specific challenges resulted in a number of impairment charges recognized during 2020. See Note 6 and Note 14 for further discussion of these impairments.

Many uncertainties remain with respect to COVID-19, including uncertainty regarding the length of time the pandemic will continue, as well as the timing, pace and extent of an economic recovery in the United States, Canada and elsewhere, and how such uncertainties will impact the energy industry and our business. As a result, these matters may affect our estimates and assumptions on amounts reported in the financial statements and accompanying notes in the near term.

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 Sheet that sum to the total of the amounts shown on our Condensed Consolidated Statement of Cash Flows (in millions):


	September 30, 2020		December 31, 2019
Cash and cash equivalents	$	25	$	45
Restricted cash	21		37
Total cash and cash equivalents and restricted cash	$	46	$	82

Recent Accounting Pronouncements

Except as discussed below and in our 2019 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the nine months ended September 30, 2020 that are of significance or potential significance to us.

Accounting Standards Updates Adopted During the Period

We adopted the ASUs listed below effective January 1, 2020 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 2019 Annual Report on Form 10-K for additional information regarding these ASUs):

•ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments—Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments;

•ASU 2018-17, Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities;

•ASU 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a consensus of the FASB Emerging Issues Task Force);

•ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement; and

•ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (along with a series of related ASUs).

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Accounting Standards Updates Issued During the Period

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. This guidance is effective prospectively upon issuance through December 31, 2022 and may be applied from the beginning of an interim period that includes the issuance date of this ASU. We are currently evaluating the effect that this guidance will have on our financial position, results of operations and cash flows.

In August 2020, the FASB issued ASU 2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity, by eliminating two of the three models that require separate accounting for embedded conversion features and the settlement assessment that entities are required to perform to determine whether a contract qualifies for equity classification. This guidance is effective for interim and annual periods beginning after December 15, 2021, with early adoption permitted. We are currently evaluating the effect that this guidance will have on our financial position, results of operations and cash flows.

Note 3—Revenues and Accounts Receivable

Revenue Recognition

We disaggregate our revenues by segment and type of activity under ASC Topic 606, Revenues from Contracts with Customers (“Topic 606”). 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 2019 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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Supply and Logistics segment revenues from contracts with customers
Crude oil transactions	$	5,394	$	7,185	$	15,644	$	21,716
NGL and other transactions	180		202		736		1,380
Total Supply and Logistics segment revenues from contracts with customers	$	5,574	$	7,387	$	16,380	$	23,096


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Transportation segment revenues from contracts with customers
Tariff activities:
Crude oil pipelines	$	442	$	532	$	1,360	$	1,504
NGL pipelines	26		25		77		75
Total tariff activities	468		557		1,437		1,579
Trucking	20		33		77		106
Total Transportation segment revenues from contracts with customers	$	488	$	590	$	1,514	$	1,685

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Facilities segment revenues from contracts with customers
Crude oil, NGL and other terminalling and storage	$	178	$	174	$	536	$	523
NGL and natural gas processing and fractionation	76		87		265		262
Rail load / unload	8		20		30		58
Total Facilities segment revenues from contracts with customers	$	262	$	281	$	831	$	843

Reconciliation to Total Revenues of Reportable Segments. The following tables present the reconciliation of our revenues from contracts with customers to segment revenues and total revenues as disclosed in our Condensed Consolidated Statements of Operations (in millions):


Three Months Ended September 30, 2020	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	488	$	262	$	5,574	$	6,324
Other items in revenues	6		9		(37)		(22)
Total revenues of reportable segments	$	494	$	271	$	5,537	$	6,302
Intersegment revenues							(469)
Total revenues							$	5,833

Three Months Ended September 30, 2019	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	590	$	281	$	7,387	$	8,258
Other items in revenues	7		10		155		172
Total revenues of reportable segments	$	597	$	291	$	7,542	$	8,430
Intersegment revenues							(544)
Total revenues							$	7,886

Nine Months Ended September 30, 2020	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	1,514	$	831	$	16,380	$	18,725
Other items in revenues	16		29		(9)		36
Total revenues of reportable segments	$	1,530	$	860	$	16,371	$	18,761
Intersegment revenues							(1,434)
Total revenues							$	17,327

Nine Months Ended September 30, 2019	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	1,685	$	843	$	23,096	$	25,624
Other items in revenues	27		37		384		448
Total revenues of reportable segments	$	1,712	$	880	$	23,480	$	26,072
Intersegment revenues							(1,557)
Total revenues							$	24,515

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Minimum Volume Commitments. We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. At September 30, 2020 and December 31, 2019, counterparty deficiencies associated with contracts with customers and buy/sell arrangements that include minimum volume commitments for which we have remaining performance obligations and the customers still have the ability to meet their obligations totaled $82 million and $42 million, respectively. Billed counterparty deficiencies of $68 million and $22 million at September 30, 2020 and December 31, 2019, respectively, were recorded as a liability. Unbilled counterparty deficiencies of $14 million and $20 million at September 30, 2020 and December 31, 2019, respectively, were not reflected in our Condensed Consolidated Financial Statements.

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 Topic 606 contract liability balance during the nine months ended September 30, 2020 (in millions):


	Contract Liabilities
Balance at December 31, 2019	$	354
Amounts recognized as revenue	(245)

Additions (1)	191

Balance at September 30, 2020	$	300

(1)Includes approximately $152 million associated with crude oil sales agreements that are entered into in conjunction with storage arrangements and future inventory exchanges. Such amount is expected to be recognized as revenue in the fourth quarter of 2020.

Remaining Performance Obligations. Topic 606 requires a presentation of information about partially and wholly unsatisfied performance obligations under contracts that exist as of the end of the period. The information includes the amount of consideration allocated to those remaining performance obligations and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These arrangements include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. These contracts are all within the scope of Topic 606. 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 September 30, 2020 (in millions):


	Remainder of 2020		2021		2022		2023		2024		2025 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	41	$	166	$	166	$	163	$	142	$	576
Storage, terminalling and throughput agreement revenues	101		332		270		205		173		433
Total	$	142	$	498	$	436	$	368	$	315	$	1,009

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

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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 Topic 606 or do not meet the requirements for presentation as remaining performance obligations under Topic 606. The following are examples of contracts that are not included in the table above because they are not within the scope of Topic 606 or do not meet the Topic 606 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 Topic 842, Leases; and

•Contracts within the scope of ASC Topic 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. During the first quarter of 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).

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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 September 30, 2020 and December 31, 2019, substantially all of our trade accounts receivable were less than 30 days past their scheduled invoice date. Our expected credit losses are immaterial. Although we consider our credit procedures to be adequate to mitigate any significant credit losses, given the sharp decline in demand for crude oil and the drop in prices, 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):


	September 30, 2020		December 31, 2019
Trade accounts receivable arising from revenues from contracts with customers	$	1,876	$	3,381
Other trade accounts receivables and other receivables (1)	2,577		3,576
Impact due to contractual rights of offset with counterparties	(2,300)		(3,343)
Trade accounts receivable and other receivables, net	$	2,153	$	3,614

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

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

We calculate basic and diluted net income/(loss) per common unit by dividing net income/(loss) attributable to PAA (after deducting amounts allocated to preferred unitholders and participating securities) by the basic and diluted weighted average number of common units outstanding during the period. Participating securities include LTIP awards that have vested distribution equivalent rights, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units.

The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units and (ii) our equity-indexed compensation plan awards. When applying the if-converted method prescribed by FASB guidance, the possible conversion of approximately 71 million Series A preferred units, on a weighted-average basis, were excluded from the calculation of diluted net income/(loss) per common unit for the three and nine months ended September 30, 2020 as the effect was antidilutive for each period. Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that were deemed to be dilutive during the three and nine months ended September 30, 2020 and 2019 were reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. As a result of the hypothetical common unit repurchase, there were no potentially dilutive equity-indexed compensation plan awards for the three months ended September 30, 2020 and approximately 0.4 million equity-indexed compensation plan awards, on a weighted-average basis, were excluded from the computation of diluted net loss per common unit as the effect was antidilutive for the nine months ended September 30, 2020. See Note 18 to our Consolidated Financial Statements included in Part IV of our 2019 Annual Report on Form 10-K for a complete discussion of our equity-indexed compensation plan awards.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Basic Net Income/(Loss) per Common Unit
Net income/(loss) attributable to PAA	$	143	$	449	$	(2,562)	$	1,865
Distributions to Series A preferred unitholders	(37)		(37)		(112)		(112)
Distributions to Series B preferred unitholders	(12)		(12)		(37)		(37)
Distributions to participating securities	(1)		(1)		(1)		(2)
Other	—		—		—		(4)
Net income/(loss) allocated to common unitholders (1)	$	93	$	399	$	(2,712)	$	1,710

Basic weighted average common units outstanding	728		728		728		727

Basic net income/(loss) per common unit	$	0.13	$	0.55	$	(3.72)	$	2.35

Diluted Net Income/(Loss) per Common Unit
Net income/(loss) attributable to PAA	$	143	$	449	$	(2,562)	$	1,865
Distributions to Series A preferred unitholders	(37)		—		(112)		—
Distributions to Series B preferred unitholders	(12)		(12)		(37)		(37)
Distributions to participating securities	(1)		(1)		(1)		(2)

Net income allocated/(loss) to common unitholders (1)	$	93	$	436	$	(2,712)	$	1,826

Basic weighted average common units outstanding	728		728		728		727
Effect of dilutive securities:
Series A preferred units	—		71		—		71
Equity-indexed compensation plan awards	—		1		—		2
Diluted weighted average common units outstanding	728		800		728		800

Diluted net income/(loss) per common unit	$	0.13	$	0.55	$	(3.72)	$	2.28

(1)We calculate net income/(loss) allocated to common unitholders based on the distributions pertaining to the current period’s net income (whether paid in cash or in-kind). After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (i.e., undistributed loss), if any, are allocated to the common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method.

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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):


	September 30, 2020						December 31, 2019
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	15,332	barrels	$	449	$	29.29	8,613	barrels	$	450	$	52.25
NGL	16,144	barrels	226		$	14.00	7,574	barrels	142		$	18.75

Other	N/A		8		N/A		N/A		12		N/A
Inventory subtotal			683						604

Linefill and base gas
Crude oil	14,496	barrels	813		$	56.08	14,316	barrels	826		$	57.70
NGL	1,642	barrels	43		$	26.19	1,701	barrels	47		$	27.63
Natural gas	25,576	Mcf	110		$	4.30	24,976	Mcf	108		$	4.32
Linefill and base gas subtotal			966						981

Long-term inventory
Crude oil	2,773	barrels	102		$	36.78	2,598	barrels	152		$	58.51
NGL	1,354	barrels	18		$	13.29	1,707	barrels	30		$	17.57
Long-term inventory subtotal			120						182

Total			$	1,769					$	1,767

(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.

At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Condensed Consolidated Statements of Operations. We recorded a charge of $233 million primarily during the first quarter of 2020 related to the write-down of our crude oil and NGL inventory, of which $40 million was associated with our long-term inventory, due to declines in prices. A portion of this inventory valuation adjustment was offset by the recognition of gains on derivative instruments being utilized to hedge future sales of our crude oil and NGL inventory. Such gains were recorded to “Supply and Logistics segment revenues” in our accompanying Consolidated Statement of Operations. See Note 10 for discussion of our derivative and risk management activities.

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Note 6—Goodwill

During the first quarter of 2020, we recorded impairment losses related to goodwill. Our market capitalization declined significantly during the first quarter driven by current 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, resulting in expected decreases in future cash flows for certain of our assets. In addition, the uncertainty related to oil demand continued to have a significant impact on the investment and operating plans of our primary customers. Based on these events, we concluded that a triggering event occurred which required us to perform a quantitative impairment test as of March 31, 2020, utilizing a discounted cash flow approach. We applied a discount rate of approximately 14% in the determination of the fair value of each of our reporting units, which represents our estimate of the cost of capital of a theoretical market participant as of March 31, 2020. The fair values of the reporting units are Level 3 measurements in the fair value hierarchy and were based on various inputs, as discussed below. The discounted cash flows for each reporting unit were based on six years of projected cash flows and terminal values that we believe would be applied by a theoretical market participant in similar market transactions. The discounted cash flows for the respective reporting units utilized various other assumptions, including, but not limited to (i) volumes (based on historical information and estimates of future drilling and completion activity, as well as expectations of future demand recovery), (ii) tariff and storage rates, (iii) future commodity prices (based on relevant indices and applicable quality and location differentials), and (iv) estimated fixed and variable costs. We used a range of cash flows for the discounted cash flow calculations, based on differing potential market scenarios but for each of the reporting units, the ultimate outcome of the impairment test was unchanged by the various points within the range of cash flows. Based upon the results of the impairment test, we concluded that the carrying value of each of our reporting units exceeded their respective fair values, resulting in a goodwill impairment charge for the entire goodwill balance for each reporting unit.

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


	Transportation		Facilities		Supply and Logistics		Total
Balance at December 31, 2019	$	1,052	$	982	$	506	$	2,540
Acquisitions	2		—		—		2
Foreign currency translation adjustments	(6)		(2)		(2)		(10)


Goodwill, gross	1,048		980		504		2,532
Impairments	(1,038)		(975)		(502)		(2,515)
Foreign currency translation adjustments	(10)		(5)		(2)		(17)
Accumulated impairment losses	(1,048)		(980)		(504)		(2,532)
Balance at September 30, 2020	$	—	$	—	$	—	$	—

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Note 7—Investments in Unconsolidated Entities

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


		Ownership Interest at September 30, 2020	Investment Balance
Entity (1)	Type of Operation		September 30, 2020		December 31, 2019
BridgeTex Pipeline Company, LLC	Crude Oil Pipeline	20%	$	422	$	431
Cactus II Pipeline LLC	Crude Oil Pipeline	65%	781		738
Capline Pipeline Company LLC	Crude Oil Pipeline (2)	54%	505		484
Diamond Pipeline LLC	Crude Oil Pipeline	50%	482		476
Eagle Ford Pipeline LLC	Crude Oil Pipeline	50%	375		382
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”)	Crude Oil Terminal and Dock	50%	122		126
Red Oak Pipeline LLC (“Red Oak”)	Crude Oil Pipeline	50%	35		20
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)	Crude Oil Pipeline	30%	199		234
STACK Pipeline LLC	Crude Oil Pipeline	50%	22		117
White Cliffs Pipeline, LLC	Crude Oil Pipeline	36%	194		196
Wink to Webster Pipeline LLC	Crude Oil Pipeline	16%	299		136
Other investments			307		343
Total investments in unconsolidated entities			$	3,743	$	3,683

(1)Except for Eagle Ford Terminals, which is reported in our Facilities segment, the financial results from the entities are reported in our Transportation segment.

(2)The Capline pipeline was taken out of service pending the reversal of the pipeline system.

Impairments

In March 2020, the partners of Red Oak announced they were deferring the Red Oak pipeline project and suspending actions that would require additional capital spending on the project, and that they would re-evaluate demand for the project in light of recent market developments. Subsequently, the partners determined that the project would not proceed as previously contemplated. We determined that there was an other-than-temporary impairment of our investment in Red Oak, and we wrote our investment in Red Oak down to the estimated residual value of our share of the net assets during the second quarter of 2020. In addition, during the first quarter of 2020, we recorded a write-down of certain of our investments included in “Other investments” in the table above due to an other-than-temporary impairment related to a decline in market conditions.

During the third quarter of 2020, we determined that there was an other-than-temporary impairment of our investment in STACK Pipeline LLC as a result of a continued decline of drilling activity and related volumes of crude oil in its area of operation. We wrote off the portion of the carrying amount of our investment that exceeded its fair value. The estimated fair value (which we consider a Level 3 measurement in the fair value hierarchy) was based on a discounted cash flow approach utilizing various assumptions and the application of a discount rate of approximately 14%, which represents our estimate of the cost of capital of a theoretical market participant. Such assumptions included (but were not limited to) (i) volumes (consistent with historical information and estimates of future drilling and completion activity), (ii) tariff rates, (iii) future commodity prices (based on relevant indices and applicable quality and location differentials), and (iv) estimated fixed and variable costs.

As a result of these write-downs, during the three and nine months ended September 30, 2020, we recognized losses of $91 million and $202 million, respectively. These losses are reflected in “Gain on/(impairment of) investments in unconsolidated entities, net” on our Condensed Consolidated Statement of Operations.

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Divestitures

Saddlehorn. In February 2020, we sold a 10% ownership interest in Saddlehorn for proceeds of approximately $78 million and have retained a 30% ownership interest. We recorded a gain of approximately $21 million related to this sale, which is included in “Gain on/(impairment of) investments in unconsolidated entities, net” on our Condensed Consolidated Statement of Operations. We continue to account for our remaining interest under the equity method of accounting.

Note 8—Debt

Debt consisted of the following (in millions):


	September 30, 2020		December 31, 2019
SHORT-TERM DEBT
Commercial paper notes, bearing a weighted-average interest rate of 0.6% and 2.2%, respectively (1)	$	92	$	93
Senior secured hedged inventory facility, bearing a weighted-average interest rate of 2.7% (1)	—		325

Senior notes:
5.00% senior notes due February 2021	600		—

Other	98		86
Total short-term debt	790		504

LONG-TERM DEBT
Senior notes, net of unamortized discounts and debt issuance costs of $64 and $61, respectively (2)	9,069		8,939
Commercial paper notes (3)	20		—

GO Zone term loans, net of debt issuance costs of $1 and $1, respectively, bearing a weighted-average interest rate of 1.3% and 2.6%, respectively	199		199
Other	93		49
Total long-term debt	9,381		9,187
Total debt (4)	$	10,171	$	9,691

(1)We classified these commercial paper notes as short-term as of September 30, 2020 and December 31, 2019, respectively, and these credit facility borrowings as short-term as of December 31, 2019, 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)During the nine months ended September 30, 2020, we repurchased $17 million of our outstanding senior notes on the open market and recognized a gain of $3 million on these transactions, which is included in “Other income/(expense), net” on our Condensed Consolidated Statement of Operations.

(3)As of September 30, 2020, we classified a portion of our commercial paper notes as long-term based on our ability and intent to refinance such amounts on a long-term basis.

(4)Our fixed-rate senior notes had a face value of approximately $9.7 billion and $9.0 billion as of September 30, 2020 and December 31, 2019, respectively. We estimated the aggregate fair value of these notes as of September 30, 2020 and December 31, 2019 to be approximately $9.7 billion and $9.3 billion, respectively. Our 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 our 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 our 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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Senior Notes

On November 3, 2020, we redeemed our $600 million, 5.00% senior notes due February 2021.

Borrowings and Repayments

Total borrowings under our credit facilities and commercial paper program for the nine months ended September 30, 2020 and 2019 were approximately $20.2 billion and $10.5 billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately $20.5 billion and $10.5 billion for the nine months ended September 30, 2020 and 2019, 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 September 30, 2020 and December 31, 2019, we had outstanding letters of credit of $140 million and $157 million, respectively.

Note 9—Partners’ Capital and Distributions

Units Outstanding

The following tables present the activity for our preferred and common units:


	Limited Partners
	Series A Preferred Units	Series B Preferred Units	Common Units
Outstanding at December 31, 2019	71,090,468	800,000	728,028,576
Issuances of common units under equity-indexed compensation plans	—	—	24,431
Outstanding at March 31, 2020	71,090,468	800,000	728,053,007
Issuances of common units under equity-indexed compensation plans	—	—	47,391
Outstanding at June 30, 2020	71,090,468	800,000	728,100,398
Issuances of common units under equity-indexed compensation plans	—	—	376,193

Outstanding at September 30, 2020	71,090,468	800,000	728,476,591


	Limited Partners
	Series A Preferred Units	Series B Preferred Units	Common Units
Outstanding at December 31, 2018	71,090,468	800,000	726,361,924

Issuances of common units under equity-indexed compensation plans	—	—	423,889
Outstanding at March 31, 2019	71,090,468	800,000	726,785,813
Issuances of common units under equity-indexed compensation plans	—	—	638,806
Outstanding at June 30, 2019	71,090,468	800,000	727,424,619
Issuances of common units under equity-indexed compensation plans	—	—	603,957
Outstanding at September 30, 2019	71,090,468	800,000	728,028,576

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Common Equity Repurchase Program. On November 2, 2020, we announced that the board of directors of PAA GP Holdings LLC has approved a $500 million common equity repurchase program (the “Program”) to be utilized as an additional method of returning capital to investors. The Program authorizes the repurchase from time to time of up to $500 million of PAA common units and/or PAGP Class A shares via open market purchases or negotiated transactions conducted in accordance with applicable regulatory requirements. No time limit has been set for completion of the Program, and the Program may be suspended or discontinued at any time. The Program does not obligate us or PAGP to acquire a particular number of PAA common units or PAGP Class A shares. Any PAA common units or PAGP Class A shares that are repurchased will be canceled.

Distributions

Series A Preferred Unit Distributions. The following table details distributions to our Series A preferred unitholders paid during or pertaining to the first nine months of 2020 (in millions, except per unit data):


	Series A Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit
November 13, 2020 (1)	$	37	$	0.525
August 14, 2020	$	37	$	0.525
May 15, 2020	$	37	$	0.525
February 14, 2020	$	37	$	0.525

(1)Payable to unitholders of record at the close of business on October 30, 2020 for the period from July 1, 2020 through September 30, 2020. At September 30, 2020, such amount was accrued as distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

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


	Series B Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit
November 16, 2020 (1)	$	24.5	$	30.625
May 15, 2020	$	24.5	$	30.625

(1)Payable to unitholders of record at the close of business on November 2, 2020 for the period from May 15, 2020 through November 14, 2020.

At September 30, 2020, approximately $18 million of accrued distributions payable to our Series B preferred unitholders was included in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

Common Unit Distributions. The following table details distributions to our common unitholders paid during or pertaining to the first nine months of 2020 (in millions, except per unit data):


	Distributions						Cash Distribution per Common Unit
	Common Unitholders				Total Cash Distribution
Distribution Payment Date	Public		AAP
November 13, 2020 (1)	$	87	$	44	$	131	$	0.18
August 14, 2020	$	86	$	45	$	131	$	0.18
May 15, 2020	$	86	$	45	$	131	$	0.18
February 14, 2020	$	172	$	90	$	262	$	0.36

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(1)Payable to unitholders of record at the close of business on October 30, 2020 for the period from July 1, 2020 through September 30, 2020.

Noncontrolling Interests in Subsidiaries

During the nine months ended September 30, 2020, we received $11 million of contributions from noncontrolling interests in Red River Pipeline Company LLC related to the Red River pipeline capacity expansion and paid distributions of $6 million.

Note 10—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. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on hydrocarbon commodity (referred to herein as “commodity”) price changes. We use various derivative instruments to manage our exposure to (i) commodity price risk, as well as to optimize our profits, (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. 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 as a hedging instrument and derivatives that do not qualify for hedge accounting 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 September 30, 2020 and December 31, 2019, 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 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:

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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 September 30, 2020, net derivative positions related to these activities included:

•A net long position of 6.5 million barrels associated with our crude oil purchases, which was unwound ratably during October 2020 to match monthly average pricing.

•A net short time spread position of 4.7 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through October 2021.

•A net crude oil basis spread position of 3.1 million barrels at multiple locations through December 2021. These derivatives allow us to lock in grade basis differentials.

•A net short position of 36.5 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 September 30, 2020:

Notional Volume

(Short)/Long

Remaining Tenor

Natural gas purchases

23.8 Bcf

March 2021

Propane sales

(4.1) MMbls

March 2021

Butane sales

(1.3) MMbls

March 2021

Condensate sales (WTI position)

(0.5) MMbls

March 2021

Fuel gas requirements (1)

16.2 Bcf

December 2022

Power supply requirements (1)

0.8 TWh

December 2022

(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 as a hedging relationship, 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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Supply and Logistics segment revenues	$	(37)	$	149	$	(22)	$	380
Field operating costs	5		4		5		15
Net gain/(loss) from commodity derivative activity	$	(32)	$	153	$	(17)	$	395

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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):


	September 30, 2020		December 31, 2019
Initial margin	$	103	$	73
Variation margin posted/(returned)	105		(45)
Letters of credit	(75)		(73)
Net broker receivable/(payable)	$	133	$	(45)

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.


	September 30, 2020								December 31, 2019
					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	$	117	$	(80)	$	62	$	99	$	179	$	(37)	$	(45)	$	97
Other long-term assets, net	63		(3)		—		60		24		—		—		24
Derivative Liabilities
Other current liabilities	31		(151)		71		(49)		32		(56)		—		(24)
Other long-term liabilities and deferred credits	8		(62)		—		(54)		—		(12)		—		(12)
Total	$	219	$	(296)	$	133	$	56	$	235	$	(105)	$	(45)	$	85

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 September 30, 2020 (notional amounts in millions):

Hedged Transaction

Number and Types of
Derivatives Employed

Notional
Amount

Expected
Termination Date

Average Rate
Locked

Accounting
Treatment

Anticipated interest payments

8 forward starting swaps

(30-year)

200

6/15/2023

1.38

Cash flow hedge

Anticipated interest payments

8 forward starting swaps

(30-year)

200

6/14/2024

0.73

Cash flow hedge

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As of September 30, 2020, there was a net loss of $290 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 reclassified losses of $3 million and $2 million during the three months ended September 30, 2020 and 2019, respectively, and losses of $8 million and $7 million during the nine months ended September 30, 2020 and 2019, respectively. Of the total net loss deferred in AOCI at September 30, 2020, we expect to reclassify a loss of $13 million to earnings in the next twelve months. 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 September 30, 2020; 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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Interest rate derivatives, net	$	22	$	(53)	$	(39)	$	(111)

At September 30, 2020, the net fair value of our interest rate hedges, which were included in “Other long-term assets” and “Other long-term liabilities and deferred credits” on our Condensed Consolidated Balance Sheet, totaled $23 million and $6 million, respectively. At December 31, 2019, the fair value of these hedges was $44 million and included in “Other current liabilities.”

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 September 30, 2020 (in millions):


		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:		0
	2020	$	153	$	205	$1.00 - $1.34

Forward exchange contracts that exchange USD for CAD:
	2020	$	88	$	118	$1.00 - $1.34
	2021	$	21	$	28	$1.00 - $1.32

These derivatives are not designated as a hedging relationship. As such, changes in fair value are recognized in earnings as a component of Supply and Logistics segment revenues. For the three months ended September 30, 2020 and 2019, the amounts recognized in earnings for our currency exchange rate hedges were a gain of $2 million and a loss of $1 million, respectively. For the nine months ended September 30, 2020 and 2019, the amounts recognized in earnings for our currency exchange rate hedges were a loss of $2 million and a gain of $6 million, respectively.

At September 30, 2020, the net fair value of these currency exchange rate hedges was less than $1 million included in both “Other current assets” and “Other current liabilities” on our Condensed Consolidated Balance Sheet. At December 31, 2019, the net fair value of these currency exchange rate hedges, which was included in “Other current assets” and “Other current liabilities” on our Condensed Consolidated Balance Sheet, totaled $2 million and $1 million, respectively.

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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 our Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, our partnership agreement, and recorded at fair value on our Condensed Consolidated Balance Sheets. This embedded derivative is not designated as a hedging relationship and corresponding changes in fair value are recognized in “Other income/(expense), net” in our Condensed Consolidated Statement of Operations. For the three months ended September 30, 2020 and 2019, we recognized a loss of $10 million and a gain of $1 million, respectively. For the nine months ended September 30, 2020 and 2019, we recognized net gains of $7 million and $16 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 $27 million and $34 million at September 30, 2020 and December 31, 2019, respectively. See Note 13 to our Consolidated Financial Statements included in Part IV of our 2019 Annual Report on Form 10-K for additional information regarding our 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 September 30, 2020								Fair Value as of December 31, 2019
Recurring Fair Value Measures (1)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivatives	$	(81)	$	24	$	(20)	$	(77)	$	42	$	105	$	(17)	$	130
Interest rate derivatives	—		17		—		17		—		(44)		—		(44)
Foreign currency derivatives	—		—		—		—		—		1		—		1
Preferred Distribution Rate Reset Option	—		—		(27)		(27)		—		—		(34)		(34)
Total net derivative asset/(liability)	$	(81)	$	41	$	(47)	$	(87)	$	42	$	62	$	(51)	$	53

(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.

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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 our partnership agreement which is classified as an embedded derivative.

The fair values of our Level 3 physical commodity and other contracts and over-the-counter options are based on valuation models utilizing significant timing estimates, which involve management judgment, and pricing inputs from observable and unobservable markets with less volume and transaction frequency than active markets. Significant deviations from these estimates and inputs could result in a material change in fair value. We report unrealized gains and losses associated with these contracts in our Condensed Consolidated Statements of Operations as Supply and Logistics segment revenues.

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Beginning Balance	$	(42)	$	(26)	$	(51)	$	(24)
Net gains/(losses) for the period included in earnings	(9)		4		(1)		21
Settlements	4		1		5		(10)
Derivatives entered into during the period	—		(18)		—		(26)
Ending Balance	$	(47)	$	(39)	$	(47)	$	(39)

Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period	$	(9)	$	(14)	$	(1)	$	(5)

Note 11—Related Party Transactions

See Note 17 to our Consolidated Financial Statements included in Part IV of our 2019 Annual Report on Form 10-K for a complete discussion of our related party transactions.

Ownership of PAGP Class C Shares

As of September 30, 2020 and December 31, 2019, we owned 553,800,444 and 549,538,139, respectively, Class C shares of PAGP. The Class C shares represent a non-economic limited partner interest in PAGP that provides us a “pass-through” voting mechanism through which we, as the sole holder, vote on behalf of our common unitholders and Series A preferred unitholders, who have the right to vote, pro rata with the holders of Class A and Class B shares of PAGP, for the election of eligible PAGP GP directors.

Transactions with Other Related Parties

Our other related parties include (i) principal owners and their affiliated entities and (ii) entities in which we hold investments and account for under the equity method of accounting (see Note 7 for information regarding such entities). We recognize as our principal owners entities that have a designated representative on the board of directors of PAGP GP and/or own greater than 10% of the limited partner interests in AAP. Such limited partner interests in AAP translates into a significantly smaller indirect ownership interest in PAA. We also consider subsidiaries or funds identified as affiliated with principal owners to be related parties. As of September 30, 2020, Kayne Anderson Capital Advisors, L.P. was a principal owner.

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During the three and nine months ended September 30, 2020 and 2019, we recognized sales and transportation revenues, purchased petroleum products and utilized transportation services from our principal owners and their affiliated entities and our equity method investees. These transactions were conducted at posted tariff rates or prices that we believe approximate market. Included in these transactions was a crude oil buy/sell agreement that includes a multi-year minimum volume commitment. The impact to our Condensed Consolidated Statements of Operations from these transactions is included below (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Revenues from related parties (1) (2)	$	7	$	205	$	40	$	661

Purchases and related costs from related parties (1) (2)	$	116	$	(7)	$	339	$	93

(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.

(2)Revenues and purchases and related costs from related parties for 2019 include transactions with The Energy & Minerals Group (“EMG”) and its subsidiaries through May 2019 and Occidental Petroleum Corporation (“Oxy”) and its subsidiaries through September 2019. Following transactions reducing EMG and Oxy’s ownership interest in AAP in May and September 2019, respectively, EMG and Oxy are no longer recognized as principal owners. See Note 17 to our 2019 Annual Report on Form 10-K for additional information.

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


	September 30, 2020		December 31, 2019
Trade accounts receivable and other receivables, net from related parties (1)	$	83	$	134

Trade accounts payable to related parties (1) (2)	$	82	$	102

(1)Includes amounts related to crude oil purchases and sales, transportation 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 and transport crude oil at posted tariff rates on pipelines or at facilities that are owned by equity method investees, in which we own a 50% interest. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities.

Note 12—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.

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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 September 30, 2020, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled $188 million, of which $143 million was classified as short-term and $45 million was classified as long-term. At December 31, 2019, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident) totaled $140 million, of which $60 million was classified as short-term and $80 million was classified as long-term. Such short- and long-term environmental liabilities are reflected in “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Condensed Consolidated Balance Sheets. At September 30, 2020, we had recorded receivables totaling $120 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which $119 million was classified as short-term and $1 million was classified as long-term. At December 31, 2019, we had recorded $72 million of such receivables, of which $35 million was classified as short-term and $37 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.

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

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 following 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”): the United States Department of Interior, the National Oceanic and Atmospheric Administration, CDFW, the California Department of Parks and Recreation, the California State Lands Commission, and the Regents of the University of California. As part of the NRDA process, the Partnership and the Trustees jointly and independently planned and conducted a number of natural resource assessment activities related to the Line 901 incident. 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”). The Consent Decree, which 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 United States Environmental Protection Agency, 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, settles all of the claims asserted in the lawsuit. The Consent Decree requires Plains to pay $24 million in civil penalties and implement certain agreed-upon injunctive relief, and pay $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 the requirements for restarting Line 901 and the Sisquoc to Pentland portion of Line 903. The Consent Decree was approved and entered by the Federal District Court for the Central District of California on October 14, 2020. We have included the costs associated with the Consent Decree settlement in the loss accrual described below.

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In late May of 2015, the California Attorney General’s Office and the District Attorney’s office for the County of Santa Barbara (collectively, the “Prosecutors”) began investigating the Line 901 incident to determine whether any applicable state or local laws had been violated. On May 16, 2016, PAA and one of its employees were 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. The May 2016 Indictment included a total of 46 counts against PAA. On July 28, 2016, at an arraignment hearing held in California Superior Court in Santa Barbara County, PAA pled not guilty to all counts. Between May of 2016 and May of 2018, 31 of the criminal charges against PAA (including one felony charge) and all of the criminal charges against our employee, were dismissed. The remaining 15 charges were the subject of a jury trial in California Superior Court in Santa Barbara County that began in May of 2018. 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 jury deadlocked on three counts (including two felony discharge counts and one strict liability animal takings count), and two misdemeanor discharge counts were dropped. 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 Superior Court also indicated that it would conduct further hearings on the issue of whether there were any “direct victims” of the spill that are entitled to restitution under applicable law. In April of 2019, the Prosecutors announced their intent to re-try the two felony discharge counts for which no jury verdict was returned. The strict liability animal taking count for which no jury verdict was returned has been dismissed. On October 7, 2019, upon motion from Plains, the court dismissed the two remaining felony counts and vacated a second trial on these counts.

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 have received a number of claims through the claims line and we have processed those claims and made payments as appropriate. In addition, we have also had nine class action lawsuits filed against us, six of which were administratively consolidated into a single proceeding in the United States District Court for the Central District of California. In general, the plaintiffs are seeking to establish different classes of claimants that have allegedly been damaged by the release. The court originally certified three sub-classes of claimants and denied certification of the other proposed sub-class. On appeal, the Ninth Circuit Court of Appeals overturned the certification of one of the three sub-classes, the oil-industry sub-class, and the District Court subsequently dismissed the oil-industry sub-class representatives’ claims. The two remaining sub-classes include (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 landed in such areas; and (ii) residential beachfront properties on a beach and residential properties with a private easement to a beach where oil from the spill washed up. The September 2020 trial date initially set by the Court has been postponed due to COVID-19 related trial suspensions. We are also defending a separate class action lawsuit proceeding in the United States District Court for the Central District of California brought on behalf of the Line 901 and Line 903 easement holders seeking injunctive relief as well as compensatory damages.

In addition, four unitholder derivative lawsuits were filed by certain purported investors in the Partnership against PAGP and certain of the Partnership’s affiliates, officers and directors. One lawsuit was filed in State District Court in Harris County, Texas and subsequently dismissed by the Court. Two of these lawsuits were filed in the United States District Court for the Southern District of Texas and were administratively consolidated into one action and later dismissed on the basis that Plains Partnership agreements require that derivative suits be filed in Delaware Chancery Court.

Following the order dismissing the Texas Federal Court suits, a new derivative suit brought by different plaintiffs was filed in Delaware Chancery Court and subsequently dismissed without prejudice. Plaintiffs amended and refiled their complaint on June 3, 2019. All claims against the officers and directors of the Partnership and all affiliates of the Partnership, except PAGP, were dismissed with prejudice in January 2020. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we have indemnified and funded the defense costs of our officers and directors in connection with these lawsuits. We will vigorously defend the remaining derivative claim against PAGP.

We have also received several other individual lawsuits and complaints from companies, governmental agencies and individuals alleging damages arising out of the Line 901 incident. These lawsuits and claims generally seek compensatory and punitive damages, and in some cases permanent injunctive relief. The majority of these lawsuits have been settled or dismissed by the court. 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.

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Taking the foregoing into account, as of September 30, 2020, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $455 million, which estimate 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, 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 September 30, 2020, we had a remaining undiscounted gross liability of $134 million related to this event, which is presented in “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 September 30, 2020, we had collected, subject to customary reservations, $218 million out of the approximate $330 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of September 30, 2020, we have recognized a receivable of approximately $112 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 natural resource damage assessment and compensation, legal, professional and regulatory costs, in addition to fines and penalties, during future periods.

Note 13—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 2019 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.

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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 September 30, 2020
Revenues:
External customers (1)	$	242	$	150	$	5,537	$	(96)	$	5,833
Intersegment (2)	252		121		—		96		469
Total revenues of reportable segments	$	494	$	271	$	5,537	$	—	$	6,302
Equity earnings in unconsolidated entities	$	87	$	2	$	—			$	89
Segment Adjusted EBITDA	$	444	$	176	$	61			$	681
Maintenance capital	$	34	$	10	$	9			$	53

Three Months Ended September 30, 2019
Revenues:
External customers (1)	$	319	$	149	$	7,541	$	(123)	$	7,886
Intersegment (2)	278		142		1		123		544
Total revenues of reportable segments	$	597	$	291	$	7,542	$	—	$	8,430
Equity earnings in unconsolidated entities	$	102	$	—	$	—			$	102
Segment Adjusted EBITDA	$	462	$	173	$	92			$	727
Maintenance capital	$	42	$	28	$	15			$	85

Nine Months Ended September 30, 2020
Revenues:
External customers (1)	$	774	$	473	$	16,370	$	(290)	$	17,327
Intersegment (2)	756		387		1		290		1,434
Total revenues of reportable segments	$	1,530	$	860	$	16,371	$	—	$	18,761
Equity earnings in unconsolidated entities	$	276	$	4	$	—			$	280
Segment Adjusted EBITDA	$	1,233	$	560	$	205			$	1,998
Maintenance capital	$	98	$	40	$	19			$	157

Nine Months Ended September 30, 2019
Revenues:
External customers (1)	$	938	$	457	$	23,477	$	(357)	$	24,515
Intersegment (2)	774		423		3		357		1,557
Total revenues of reportable segments	$	1,712	$	880	$	23,480	$	—	$	26,072
Equity earnings in unconsolidated entities	$	274	$	—	$	—			$	274
Segment Adjusted EBITDA	$	1,271	$	529	$	571			$	2,371
Maintenance capital	$	110	$	74	$	20			$	204

As of September 30, 2020
Total assets	$	13,704	$	6,013	$	4,529			$	24,246
As of December 31, 2019
Total assets	$	14,902	$	7,336	$	6,439			$	28,677

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(1)Transportation revenues from External customers include 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 2019 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 PAA (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Segment Adjusted EBITDA	$	681	$	727	$	1,998	$	2,371
Adjustments (1):
Depreciation and amortization of unconsolidated entities (2)	(18)		(18)		(51)		(45)
Gains/(losses) from derivative activities, net of inventory valuation adjustments (3)	(88)		29		(210)		60
Long-term inventory costing adjustments (4)	(2)		1		(66)		(3)
Deficiencies under minimum volume commitments, net (5)	(64)		4		(69)		10
Equity-indexed compensation expense (6)	(5)		(5)		(13)		(13)
Net gain/(loss) on foreign currency revaluation (7)	(4)		5		9		(7)
Line 901 incident (8)	—		—		—		(10)
Significant acquisition-related expenses (9)	—		—		(3)		—
Depreciation and amortization	(160)		(156)		(493)		(439)
Gains/(losses) on asset sales and asset impairments, net	2		7		(617)		7
Goodwill impairment losses	—		—		(2,515)		—
Gain on/(impairment of) investments in unconsolidated entities, net	(91)		4		(182)		271
Interest expense, net	(113)		(108)		(329)		(311)
Other income/(expense), net	5		5		(7)		23
Income/(loss) before tax	143		495		(2,548)		1,914
Income tax (expense)/benefit	3		(41)		(7)		(42)
Net income/(loss)	146		454		(2,555)		1,872
Net income attributable to noncontrolling interests	(3)		(5)		(7)		(7)
Net income/(loss) attributable to PAA	$	143	$	449	$	(2,562)	$	1,865

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

(2)Includes our proportionate share of the depreciation and amortization 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

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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 the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining Segment Adjusted EBITDA. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable.

(4)We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We exclude the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and write-downs of such inventory that result from price declines from Segment Adjusted EBITDA.

(5)We 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)Includes equity-indexed compensation expense associated with awards that will or may be settled in units.

(7)Includes gains and losses realized on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency.

(8)Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. See Note 12 for additional information regarding the Line 901 incident.

(9)Includes acquisition-related expenses associated with the Felix Midstream LLC acquisition. See Note 14 for additional discussion. An adjustment for these non-recurring expenses is included in the calculation of Segment Adjusted EBITDA for the nine months ended September 30, 2020 as our CODM does not view such expenses as integral to understanding our core segment operating performance.

Note 14—Acquisitions, Divestitures and Asset Impairments

Acquisitions

Felix Midstream LLC. In February 2020, we acquired Felix Midstream LLC, now known as FM Gathering LLC (“FM Gathering”) from Felix Energy Holdings II, LLC for approximately $300 million, net of working capital and other adjustments. FM Gathering owns and operates a newly constructed crude oil gathering system in the Delaware Basin, with associated crude oil storage and truck offloading capacity, and is supported by a long-term acreage dedication. The assets acquired are primarily included in our Transportation and Supply and Logistics segments. This acquisition was accounted for using the acquisition method of accounting and the determination of the fair value of the assets acquired and liabilities assumed has been estimated in accordance with the applicable accounting guidance. The assets acquired primarily consisted of property and equipment of $115 million and intangible assets of $187 million. The fair value of the tangible assets is a Level 3 measurement in the fair value hierarchy and was determined using a cost approach. The cost approach was based on costs incurred on similar recent construction projects. The fair value of the intangible assets is also a Level 3 measurement in the fair value hierarchy and was determined by applying a discounted cash flow approach. Such approach utilized discount rates varying from 18% to 19%, based on our estimate of the risk that a theoretical market participant would assign to the respective intangible assets.

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Divestitures

Saddlehorn Pipeline Company, LLC. In February 2020, we sold a 10% ownership interest in Saddlehorn Pipeline Company, LLC for proceeds of approximately $78 million. We recorded a gain of approximately $21 million related to this sale, which is included in “Gain on/(impairment of) investments in unconsolidated entities, net” on our Condensed Consolidated Statement of Operations.

Assets Held For Sale. As of September 30, 2020, we classified approximately $224 million as assets held for sale on our Condensed Consolidated Balance Sheet (in “Other current assets”). The assets held for sale, which were valued at the lower of the carrying amount or fair value less costs to sell, are primarily property and equipment related to transactions to divest our interests in certain Los Angeles Basin (“LA Basin”) terminals included in our Facilities segment. In January 2020, we signed a definitive agreement to sell certain of our LA Basin crude oil terminals. This transaction closed in the fourth quarter of 2020 for proceeds of approximately $200 million, subject to certain adjustments.

During the first quarter of 2020, certain NGL terminals included in our Facilities segment were also classified as held for sale. In April 2020, the transaction closed for proceeds of approximately $163 million, subject to certain adjustments.

Upon these classifications to assets held for sale, we recognized non-cash impairment losses of approximately $167 million during the first quarter of 2020. Such impairment losses are reflected in “(Gains)/losses on asset sales and asset impairments, net” on our Condensed Consolidated Statement of Operations.

Asset Impairments (Held and Used)

During the nine months ended September 30, 2020, we recognized approximately $648 million of non-cash impairment losses related to certain pipeline and other long-lived assets included in our Transportation and Facilities segments, along with certain of our investments in unconsolidated entities. Of these losses, approximately $446 million is reflected in “(Gains)/losses on asset sales and asset impairments, net” with the remainder reflected in “Gain on/(impairment of) investments in unconsolidated entities, net” on our Condensed Consolidated Statement of Operations. See Note 7 for additional information regarding our investments in unconsolidated entities.

The current 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, resulted in expected decreases in future cash flows for certain of our assets, which was a triggering event that required us to assess the recoverability of our carrying value of such long-lived assets. As a result of our impairment review, we wrote off the portion of the carrying amount of these long-lived assets that exceeded their fair value. Our estimated fair values (which we consider a Level 3 measurement in the fair value hierarchy) were based upon a discounted cash flow approach utilizing various assumptions and the application of a discount rate of approximately 14%, which represents our estimate of the cost of capital of a theoretical market participant. Such assumptions included (but were not limited to) (i) volumes (consistent with historical information and estimates of future drilling and completion activity), (ii) tariff rates, (iii) future commodity prices (based on relevant indices and applicable quality and location differentials), and (iv) estimated fixed and variable costs.

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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 2019 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

•Acquisitions and Capital Projects

•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 own and operate midstream energy infrastructure and provide logistics services primarily for crude oil, NGL and natural gas. We own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. We were formed in 1998, and our operations are conducted directly and indirectly through our operating subsidiaries and are managed through three operating segments: Transportation, Facilities and Supply and Logistics. See “—Results of Operations—Analysis of Operating Segments” for further discussion.

Recent Events & Outlook

During the first quarter of 2020, COVID-19 escalated into a global pandemic, which led to widespread shelter-in-place or similar requirements throughout North America and across the world, resulting in significantly reduced energy demand. As a result, North American producers responded aggressively by shutting in significant levels of production early in the second quarter, which mitigated the pace of crude oil inventory builds and the risk of testing storage maximums. Subsequently, United States refinery utilization increased, the previously steep contango market structure tempered, and crude oil prices improved to more constructive levels. This supported the ability for producers to bring a substantial portion of previously shut-in production back on line and resume completion activity during the third quarter at a level likely to be sufficient to offset natural declines.

Additionally, in the third quarter, United States Lower 48 horizontal crude oil rig counts increased modestly but as of quarter end represented approximately 25% of peak levels reached in 2019. Additionally, although United States inventories of crude oil and distillate had constructive draws during the third quarter, they remained elevated relative to their prior five-year range. The combination of steep shale declines relative to drilling and completion activity, substantial inventory overhang, and the potential for a prolonged demand recovery has challenged the ability of North American liquids production to return to a sustainable growth trajectory in 2020, and which is likely to persist into 2021. Furthermore, we expect a continuation of elevated near-term market uncertainty to be driven by various risks, including potential COVID-19 resurgence, regulatory changes and evolving geo-political dynamics. In aggregate, we expect these market dynamics to have a negative impact on our business relative to pre-pandemic levels, with the impacts in 2021 potentially being more pronounced than in 2020.

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We believe our business is well positioned to manage through the current challenging market environment. We expect global demand for hydrocarbons will recover, which should drive a return of constructive crude oil price levels and higher production levels in key onshore shale basins, which should support growing demand for our assets.

In addition, in response to the challenging near-term market conditions, we have taken steps to further strengthen our balance sheet, liquidity and long-term financial flexibility. These actions include significantly reducing and continuing to challenge our capital program, reducing the amount of our common unit distribution payable, progressing asset sales, and reducing costs, while remaining focused on operating safely and responsibly.

Specifically, since April, we have reduced our 2020/2021 capital program by $850 million, or 37%, and have decreased our common unit distributions and PAGP’s Class A share distributions by 50% versus the distributions paid in February 2020, which reflects a reduction of $525 million on an annualized basis. We have completed approximately $450 million of asset sales (which amount includes an approximately $200 million asset sale that closed in October 2020). While each of these actions should contribute to a stronger balance sheet and enhanced liquidity and long-term financial flexibility, we can provide no assurance that we will be able to effect certain future actions (such as additional capital reductions, asset sales and expense reductions) and additional actions may be necessary to achieve our balance sheet, liquidity and financial security objectives. See “Risk Factors—Risks Related to Our Business” discussed in Item 1A. of our 2019 Annual Report on Form 10‑K and Part II, Item 1A. “Risk Factors” in our Quarterly Report on Form 10-Q for the period ended March 31, 2020.

While some modifications in our operations have been necessary to deal with risks associated with the COVID-19 pandemic, we have not experienced any material constraints in our ability to continue our essential business functions and have not incurred any significant additional operating costs as a result of the pandemic, including costs associated with navigating the applicable shelter-in-place or similar restrictions and implementing our business continuity plans. We remain focused on the health and safety of our workforce, and have modified our operations in ways that we believe are prudent and appropriate in order to protect our employees while continuing to operate our assets in an effective, safe and responsible manner.

In addition, many governments have enacted or are contemplating measures to provide aid and economic stimulus in response to the COVID-19 pandemic. These measures include actions by both the United States federal government and the government of Canada. There has been no material impact to our financial position, results of operations or cash flows resulting from these measures. However, our Canadian subsidiary participated in a wage subsidy program during the second and third quarters of 2020 for subsidies totaling approximately $20 million. The impact of such subsidies is included in the line items “Field operating costs” and “Segment general and administrative expenses” of the applicable segments. See “—Results of Operations—Analysis of Operating Segments” for further discussion.

Overview of Operating Results, Capital Investments and Other Significant Activities

The macroeconomic and industry specific challenges discussed above have resulted in a number of impairment charges recognized during 2020 as discussed further below. See “—Liquidity and Capital Resources” for additional discussion of the expected and potential impact of COVID-19 and related market conditions on our business.

During the first nine months of 2020, we recognized a net loss of $2.555 billion as compared to net income of $1.872 billion recognized during the first nine months of 2019. The net loss for the period was driven by goodwill impairment losses of $2.5 billion and was also impacted by non-cash impairment charges of approximately $815 million 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. In addition, we recognized approximately $233 million of inventory valuation adjustments due to declines in commodity prices primarily during the first quarter of 2020.

Our results for the comparative period were also impacted by:

•Less favorable results from our Supply and Logistics segment due to less favorable crude oil differentials, lower NGL margins and the unfavorable impact of the mark-to-market of certain derivative instruments, resulting from losses recognized in the 2020 period compared to gains in the 2019 period, partially offset by the favorable impact of contango market conditions during the second and third quarters of 2020;

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•Less favorable results from our Transportation segment driven by lower volumes from shut-ins of crude oil production, reduced drilling and completion activity and compressed regional basis differentials, a portion of which are covered by minimum volume commitments that will be made up or paid for in future periods, and lower pipeline loss allowance revenue in 2020 due to lower prices and volumes, partially offset by lower field operating costs;

•Higher depreciation and amortization expense in the 2020 period primarily due to additional depreciation expense associated with the completion of various investment capital projects and by a reduction in the useful lives of certain assets;

•Unfavorable foreign currency impacts of $20 million recognized in “Other income/(expense), net” in the 2020 period;

•A gain of $21 million recognized in the current period related to the sale of a portion of our interest in Saddlehorn Pipeline Company, LLC in February 2020, compared to a non-cash gain of $269 million recognized in the 2019 period related to a fair value adjustment resulting from the accounting for the contribution of our undivided joint interest in the Capline pipeline system for an equity interest in Capline Pipeline Company LLC; partially offset by

•Favorable results from our Facilities segment primarily due to lower field operating costs; and

•A decrease in income tax expense primarily due to lower earnings in our Canadian operations, partially offset by the recognition of a deferred tax benefit of approximately $60 million during the second quarter of 2019 as a result of the reduction of the provincial tax rate in Alberta, Canada.

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 $785 million in midstream infrastructure projects during the nine months ended September 30, 2020, which primarily related to projects under development in the Permian Basin. Additionally, during the first quarter of 2020, we acquired approximately $310 million of assets, which primarily included a crude oil gathering system located in the Delaware Basin. See the “—Acquisitions and Capital Projects” section below for additional information.

In June 2020, we completed the issuance of $750 million, 3.80% senior notes due September 2030. We used the net proceeds from this offering of $742 million, after deducting the underwriting discount and offering expenses, to repay the principal amounts of our 5.00% senior notes due February 2021 (which were redeemed on November 3, 2020). Prior to such repayment, we used a portion of the proceeds to repay outstanding borrowings under our commercial paper program and credit facilities and for general partnership purposes.

We paid approximately $524 million of cash distributions to our common unitholders during the nine months ended September 30, 2020. We also paid cash distributions of approximately $112 million to our Series A preferred unitholders, and we paid a semi-annual cash distribution of $25 million to our Series B preferred unitholders.

On November 2, 2020, we announced that the board of directors of PAA GP Holdings LLC has approved a $500 million common equity repurchase program (the “Program”) to be utilized as an additional method of returning capital to investors. The Program authorizes the repurchase from time to time of up to $500 million of PAA common units and/or PAGP Class A shares via open market purchases or negotiated transactions conducted in accordance with applicable regulatory requirements. Ultimately, the amount, timing and pace of potential repurchase activity will be determined by a number of factors, including market conditions, our financial performance and flexibility, actual and expected Free Cash Flow after distributions, the absolute and relative equity prices of PAA common units and PAGP Class A shares, and the extent to which we are positioned to achieve and maintain our targeted leverage ratio. No time limit has been set for completion of the Program, and the Program may be suspended or discontinued at any time. The Program does not obligate us or PAGP to acquire a particular number of PAA common units or PAGP Class A shares. Any PAA common units or PAGP Class A shares that are repurchased will be canceled.

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Acquisitions and Capital Projects

The following table summarizes our expenditures for acquisition capital, investment capital and maintenance capital (in millions):


	Nine Months Ended September 30,
	2020		2019
Acquisition capital	$	310	$	47
Investment capital (1) (2) (3)	785		988
Maintenance capital (3)	157		204
	$	1,252	$	1,239

(1)“Investment capital” was previously termed “Expansion capital”. Although what is included in this category has not changed, we consider the term “Investment capital” to be more descriptive.

(2)Contributions to unconsolidated entities related to investment capital projects of such entities are recognized in “Investment capital.” We account for our investments in such entities under the equity method of accounting.

(3)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.”

Investment Capital Projects

In April 2020, in response to the current dynamic and uncertain market conditions, we announced our plan to significantly reduce and continue to challenge our capital program. Total investment capital for 2020/2021 is now targeted to be approximately $1.45 billion, or $850 million (37%) lower than the previously targeted $2.3 billion investment capital program, and $1.45 billion (50%) lower when eliminating $600 million of assumed joint venture project financing (net to our share) for the Red Oak project, which was deferred in March 2020. Subsequently, the partners of Red Oak determined that the project would not proceed as previously contemplated. The balance of the investment capital reductions relate to cancellations, cost savings and scope adjustments to other investment capital projects. The following table summarizes our notable projects in progress during 2020 and the estimated cost for the year ending December 31, 2020 (in millions):


Projects	2020
Long-haul Pipeline Projects (Non-Permian)	$	185
Permian Basin Takeaway Pipeline Projects	305
Complementary Permian Basin Projects	210
Selected Facilities/Downstream Projects	125
Other Projects	125
Total Projected 2020 Investment Capital Expenditures	$	950

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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 unit data):


	Three Months Ended September 30,				Variance				Nine Months Ended September 30,				Variance
	2020		2019		$		%		2020		2019		$		%
Transportation Segment Adjusted EBITDA (1)	$	444	$	462	$	(18)	(4)	%	$	1,233	$	1,271	$	(38)	(3)	%
Facilities Segment Adjusted EBITDA (1)	176		173		3		2	%	560		529		31		6	%
Supply and Logistics Segment Adjusted EBITDA (1)	61		92		(31)		(34)	%	205		571		(366)		(64)	%
Adjustments:
Depreciation and amortization of unconsolidated entities	(18)		(18)		—		—	%	(51)		(45)		(6)		(13)	%
Selected items impacting comparability - Segment Adjusted EBITDA	(163)		34		(197)		**		(352)		37		(389)		**
Depreciation and amortization	(160)		(156)		(4)		(3)	%	(493)		(439)		(54)		(12)	%
Gains/(losses) on asset sales and asset impairments, net	2		7		(5)		(71)	%	(617)		7		(624)		**
Goodwill impairment losses	—		—		—		N/A		(2,515)		—		(2,515)		N/A
Gain on/(impairment of) investments in unconsolidated entities, net	(91)		4		(95)		**		(182)		271		(453)		(167)	%
Interest expense, net	(113)		(108)		(5)		(5)	%	(329)		(311)		(18)		(6)	%
Other income/(expense), net	5		5		—		—	%	(7)		23		(30)		(130)	%
Income tax (expense)/benefit	3		(41)		44		107	%	(7)		(42)		35		83	%
Net income/(loss)	146		454		(308)		(68)	%	(2,555)		1,872		(4,427)		(236)	%
Net income attributable to noncontrolling interests	(3)		(5)		2		40	%	(7)		(7)		—		—	%
Net income/(loss) attributable to PAA	$	143	$	449	$	(306)	(68)	%	$	(2,562)	$	1,865	$	(4,427)	(237)	%

Basic net income/(loss) per common unit	$	0.13	$	0.55	$	(0.42)	**		$	(3.72)	$	2.35	$	(6.07)	**
Diluted net income/(loss) per common unit	$	0.13	$	0.55	$	(0.42)	**		$	(3.72)	$	2.28	$	(6.00)	**
Basic weighted average common units outstanding	728		728		—		**		728		727		1		**
Diluted weighted average common units outstanding	728		800		(72)		**		728		800		(72)		**

** 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 13 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 and to assess the amount of cash that is available for distributions, debt repayments and other general partnership purposes.

The primary additional measures used by management are earnings before interest, taxes, depreciation and amortization (including our proportionate share of depreciation and amortization 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”), Implied distributable cash flow (“DCF”), Free Cash Flow and Free Cash Flow After Distributions.

Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted EBITDA and Implied DCF are reconciled to Net Income/(Loss), and Free Cash Flow and Free Cash Flow After Distributions are reconciled to Net Cash Provided by Operating Activities, the most directly comparable measures 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.

Performance Measures

Management believes that the presentation of Adjusted EBITDA and Implied DCF provides useful information to investors regarding our performance and results of operations because these measures, when used to supplement related GAAP financial measures, (i) provide additional information about our core operating performance and ability to fund distributions to our unitholders through cash generated by our operations, (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions and (iii) present measures that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These non-GAAP measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) gains or 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 business outlook and/or (v) other items that we believe should be excluded in understanding our core operating performance. These measures may further be adjusted to include amounts related to deficiencies associated with minimum volume commitments whereby we have billed the counterparties for their deficiency obligation and such amounts are recognized as deferred revenue in “Other current liabilities” in our Condensed Consolidated Financial Statements. 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, investment capital projects and numerous other factors as discussed, as applicable, in “Analysis of Operating Segments.”

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The following tables set forth the reconciliation of the non-GAAP financial performance measures Adjusted EBITDA and Implied DCF from Net Income/(Loss) (in millions):


	Three Months Ended September 30,				Variance				Nine Months Ended September 30,				Variance
	2020		2019		$		%		2020		2019		$		%
Net income/(loss)	$	146	$	454	$	(308)	(68)	%	$	(2,555)	$	1,872	$	(4,427)	(236)	%
Add/(Subtract):
Interest expense, net	113		108		5		5	%	329		311		18		6	%
Income tax expense/(benefit)	(3)		41		(44)		(107)	%	7		42		(35)		(83)	%
Depreciation and amortization	160		156		4		3	%	493		439		54		12	%
(Gains)/losses on asset sales and asset impairments, net	(2)		(7)		5		71	%	617		(7)		624		**
Goodwill impairment losses	—		—		—		N/A		2,515		—		2,515		N/A
(Gain on)/impairment of investments in unconsolidated entities, net	91		(4)		95		**		182		(271)		453		167	%
Depreciation and amortization of unconsolidated entities (1)	18		18		—		—	%	51		45		6		13	%
Selected Items Impacting Comparability:
(Gains)/losses from derivative activities, net of inventory valuation adjustments (2)	88		(29)		117		**		210		(60)		270		**
Long-term inventory costing adjustments (3)	2		(1)		3		**		66		3		63		**
Deficiencies under minimum volume commitments, net (4)	64		(4)		68		**		69		(10)		79		**
Equity-indexed compensation expense (5)	5		5		—		**		13		13		—		**
Net (gain)/loss on foreign currency revaluation (6)	4		(5)		9		**		(9)		7		(16)		**
Line 901 incident (7)	—		—		—		**		—		10		(10)		**
Significant acquisition-related expenses (8)	—		—		—		**		3		—		3		**
Selected Items Impacting Comparability - Segment Adjusted EBITDA	163		(34)		197		**		352		(37)		389		**
(Gains)/losses from derivative activities (2)	10		(1)		11		**		(7)		(16)		9		**
Net (gain)/loss on foreign currency revaluation (6)	(14)		—		(14)		**		20		(1)		21		**
Net gain on early repayment of senior notes (9)	—		—		—		**		(3)		—		(3)		**
Selected Items Impacting Comparability - Adjusted EBITDA (10)	159		(35)		194		**		362		(54)		416		**
Adjusted EBITDA (10)	$	682	$	731	$	(49)	(7)	%	$	2,001	$	2,377	$	(376)	(16)	%

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	Three Months Ended September 30,				Variance				Nine Months Ended September 30,				Variance
	2020		2019		$		%		2020		2019		$		%
Adjusted EBITDA (10)	$	682	$	731	$	(49)	(7)	%	$	2,001	$	2,377	$	(376)	(16)	%
Interest expense, net of certain non-cash items (11)	(107)		(104)		(3)		(3)	%	(313)		(298)		(15)		(5)	%
Maintenance capital (12)	(53)		(85)		32		38	%	(157)		(204)		47		23	%
Current income tax expense	(17)		(19)		2		11	%	(39)		(72)		33		46	%
Distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings (13)	(1)		(13)		12		**		7		(12)		19		**
Distributions to noncontrolling interests (14)	(2)		(4)		2		50		(6)		(4)		(2)		(50)
Implied DCF	$	502	$	506	$	(4)	(1)	%	$	1,493	$	1,787	$	(294)	(16)	%
Preferred unit distributions (15)	(37)		(37)		—		—	%	(137)		(137)		—		—	%
Implied DCF Available to Common Unitholders	$	465	$	469	$	(4)	(1)	%	$	1,356	$	1,650	$	(294)	(18)	%
Common unit cash distributions (14)	(131)		(262)						(524)		(741)
Implied DCF Excess (16)	$	334	$	207					$	832	$	909

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

(1)Over the past several years, we have increased our participation in strategic pipeline joint ventures accounted for under the equity method of accounting. We exclude our proportionate share of the depreciation and amortization expense of such unconsolidated entities when reviewing Adjusted EBITDA, similar to our consolidated assets.

(2)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 of operations, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining Adjusted EBITDA. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. See Note 10 to our Condensed Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities.

(3)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 treat 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 as a selected item impacting comparability. See Note 5 to our Consolidated Financial Statements included in Part IV of our 2019 Annual Report on Form 10-K for additional inventory disclosures.

(4)We 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

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selected item impacting comparability. We believe the inclusion of the contractually committed revenues associated with that period is meaningful to investors 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.

(5)Our total equity-indexed compensation expense includes expense associated with awards that will or may be settled in units and awards that will or may be settled in cash. The awards that will or may be settled in units are included in our diluted net income per unit calculation when the applicable performance criteria have been met. We consider the compensation expense associated with these awards as a selected item impacting comparability as the dilutive impact of the outstanding awards is included in our diluted net income per unit calculation, as applicable, and the majority of the awards are expected to be settled in units. The portion of compensation expense associated with awards that are certain to be settled in cash is not considered a selected item impacting comparability. See Note 18 to our Consolidated Financial Statements included in Part IV of our 2019 Annual Report on Form 10-K for a comprehensive discussion regarding our equity-indexed compensation plans.

(6)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 thus classified as a selected item impacting comparability. See Note 10 to our Condensed Consolidated Financial Statements for discussion regarding our currency exchange rate risk hedging activities.

(7)Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. See Note 12 to our Condensed Consolidated Financial Statements for additional information regarding the Line 901 incident.

(8)Includes acquisition-related expenses associated with the Felix Midstream acquisition in February 2020. See Note 14 for additional information.

(9)Includes net gains recognized in connection with the repurchase of our outstanding senior notes on the open market. See Note 8 to our Condensed Consolidated Financial Statements for additional information.

(10)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.

(11)Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.

(12)Maintenance capital expenditures are defined as 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.

(13)Comprised of cash distributions received from unconsolidated entities less equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization).

(14)Cash distributions paid during the period presented.

(15)Cash distributions paid to our preferred unitholders during the period presented. The current $0.5250 quarterly ($2.10 annualized) per unit distribution requirement of our Series A preferred units was paid-in-kind for each quarterly distribution from their issuance through February 2018. Distributions on our Series A preferred units have been paid in cash since the May 2018 quarterly distribution. The current $61.25 per unit annual distribution requirement of our Series B preferred units is payable in cash semi-annually in arrears on May 15 and November 15. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2019 Annual Report on Form 10-K for additional information regarding our preferred units.

(16)Excess DCF is retained to establish reserves for future distributions, capital expenditures and other partnership purposes.

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Liquidity Measures

Management also uses the non-GAAP financial measures Free Cash Flow and Free Cash Flow After Distributions to assess the amount of cash that is available for distributions, debt repayments and other general partnership purposes. Free Cash Flow is defined as Net Cash Provided by Operating Activities, less Net Cash Used in Investing Activities, which primarily includes acquisition, investment and maintenance capital expenditures, investments in unconsolidated entities and the impact from the purchase and sale of linefill and base gas, net of proceeds from the sales of assets and further impacted by distributions to, contributions from and proceeds from the sale of noncontrolling interests. Free Cash Flow is further reduced by cash distributions paid to preferred and common unitholders to arrive at Free Cash Flow After Distributions.

The following table sets forth the reconciliation of the non-GAAP financial liquidity measures Free Cash Flow and Free Cash Flow After Distributions from Net Cash Provided by Operating Activities (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Net cash provided by operating activities	$	282	$	314	$	1,256	$	1,778
Adjustments to reconcile net cash provided by operating activities to free cash flow:
Net cash used in investing activities	(208)		(389)		(1,066)		(1,367)
Cash contributions from noncontrolling interests	1		—		11		—
Cash distributions paid to noncontrolling interests (1)	(2)		(4)		(6)		(4)
Sale of noncontrolling interest in a subsidiary	—		—		—		128
Free cash flow	$	73	$	(79)	$	195	$	535
Cash distributions (2)	(168)		(299)		(661)		(878)
Free cash flow after distributions	$	(95)	$	(378)	$	(466)	$	(343)

(1)Cash distributions paid during the period presented.

(2)Cash distributions paid to our preferred and common unitholders during the period presented.

For a discussion of the primary drivers of cash flow from operating activities, see “Liquidity and Capital Resources—Cash Flow from Operating Activities.”

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 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 13 to our Condensed Consolidated Financial Statements for a reconciliation of Segment Adjusted EBITDA to Net income/(loss) attributable to PAA.

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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.

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


Operating Results (1)	Three Months Ended September 30,				Variance				Nine Months Ended September 30,				Variance
(in millions, except per barrel data)	2020		2019		$		%		2020		2019		$		%
Revenues	$	494	$	597	$	(103)	(17)	%	$	1,530	$	1,712	$	(182)	(11)	%
Purchases and related costs	(60)		(55)		(5)		(9)	%	(184)		(155)		(29)		(19)	%
Field operating costs	(139)		(172)		33		19	%	(440)		(532)		92		17	%
Segment general and administrative expenses (2)	(22)		(26)		4		15	%	(73)		(80)		7		9	%
Equity earnings in unconsolidated entities	87		102		(15)		(15)	%	276		274		2		1	%

Adjustments (3):
Depreciation and amortization of unconsolidated entities	17		18		(1)		(6)	%	49		45		4		9	%
(Gains)/losses from derivative activities, net of inventory valuation adjustments	—		(1)		1		**		—		1		(1)		**
Deficiencies under minimum volume commitments, net	64		(4)		68		**		64		(10)		74		**
Equity-indexed compensation expense	3		3		—		**		8		6		2		**
Line 901 incident	—		—		—		**		—		10		(10)		**
Significant acquisition-related expenses	—		—		—		**		3		—		3		**
Segment Adjusted EBITDA	$	444	$	462	$	(18)	(4)	%	$	1,233	$	1,271	$	(38)	(3)	%
Maintenance capital	$	34	$	42	$	(8)	(19)	%	$	98	$	110	$	(12)	(11)	%
Segment Adjusted EBITDA per barrel	$	0.79	$	0.71	$	0.08	11	%	$	0.70	$	0.69	$	0.01	1	%

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Average Daily Volumes	Three Months Ended September 30,		Variance			Nine Months Ended September 30,		Variance
(in thousands of barrels per day) (4)	2020	2019	Volumes	%		2020	2019	Volumes	%
Tariff activities volumes
Crude oil pipelines (by region):
Permian Basin (5)	4,200	4,852	(652)	(13)	%	4,507	4,568	(61)	(1)	%
South Texas / Eagle Ford (5)	370	429	(59)	(14)	%	383	445	(62)	(14)	%
Central (5)	388	538	(150)	(28)	%	383	524	(141)	(27)	%
Gulf Coast	137	176	(39)	(22)	%	133	160	(27)	(17)	%
Rocky Mountain (5)	238	284	(46)	(16)	%	251	300	(49)	(16)	%
Western	232	212	20	9	%	217	196	21	11	%
Canada	303	316	(13)	(4)	%	291	319	(28)	(9)	%
Crude oil pipelines	5,868	6,807	(939)	(14)	%	6,165	6,512	(347)	(5)	%
NGL pipelines	180	193	(13)	(7)	%	187	195	(8)	(4)	%
Tariff activities total volumes	6,048	7,000	(952)	(14)	%	6,352	6,707	(355)	(5)	%
Trucking volumes	67	81	(14)	(17)	%	75	86	(11)	(13)	%
Transportation segment total volumes	6,115	7,081	(966)	(14)	%	6,427	6,793	(366)	(5)	%

** 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 13 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.

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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 September 30, 2020-2019						Favorable/(Unfavorable) Variance Nine Months Ended September 30, 2020-2019
(in millions)	Revenues		Purchases and Related Costs		Equity Earnings		Revenues		Purchases and Related Costs		Equity Earnings
Permian Basin region	$	(48)	$	(16)	$	9	$	(40)	$	(50)	$	53
South Texas / Eagle Ford region	(2)		—		(10)		(6)		—		(24)
Central region	(12)		1		(7)		(31)		—		(14)

Rocky Mountain region	(2)		—		(7)		(5)		—		(15)

Canada region	(7)		—		—		(21)		—		—
Other regions, trucking and pipeline loss allowance revenue	(32)		10		—		(79)		21		2
Total variance	$	(103)	$	(5)	$	(15)	$	(182)	$	(29)	$	2

•Permian Basin region. The decrease in revenues, net of purchases and related costs, of $64 million and $90 million for the three and nine months ended September 30, 2020, respectively, compared to the same periods in 2019, was primarily due to lower long-haul pipeline movements to Cushing and Corpus Christi due to compressed regional basis differentials. Some shippers on the pipelines to Cushing and Corpus Christi have under-delivered relative to their minimum volume commitments; however, the earnings related to these volume shortfalls will not be recognized until future periods when either the shortfall is made up or when the shipper’s make-up rights expire. Such deficiencies are reflected as an “Adjustment” in the table above as discussed further below under “—Adjustments: Deficiencies under minimum volume commitments, net.” For the nine-month comparative period, increased volumes from our gathering pipelines, including the gathering system we acquired from Felix Midstream in February 2020, were more than offset by declines on our long-haul pipelines.

The increase in equity earnings over the comparative periods was primarily from our 65% interest in the Cactus II pipeline, which was placed in service in August 2019, partially offset by lower equity earnings from our 30% interest in BridgeTex Pipeline Company, LLC primarily due to lower volumes.

•South Texas / Eagle Ford region. Equity earnings from our 50% interest in Eagle Ford Pipeline LLC decreased for the three and nine months ended September 30, 2020 compared to the three and nine months ended September 30, 2019 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.

•Central region. The decrease in revenues, net of purchases and related costs, for the three and nine months ended September 30, 2020 compared to the same periods in 2019 was primarily due to lower volumes as a result of (i) voluntary curtailments and shut-ins by oil producers and (ii) a significant decrease in drilling and completion activity in the Mid-Continent, both factors are due to the low crude oil prices during the current year. In addition, the production declines in this area, like other areas in which we operate, has resulted in an increase in competition for the remaining production in this region.

The decrease in equity earnings for the three and nine months ended September 30, 2020 compared to the same periods in 2019 was primarily due to the impact of refinery downtime on certain of the demand pull pipelines out of Cushing, Oklahoma, in which we own a 50% interest, as well as voluntary curtailments and shut-ins by oil producers due to the low crude oil prices during the current year.

•Rocky Mountain region. Equity earnings decreased for the three and nine months ended September 30, 2020 compared to the same periods in 2019 primarily due to (i) the sale of a 10% interest in Saddlehorn in February 2020 and (ii) lower volumes of higher tariff crude oil movements, partially offset by new movements of lower tariff NGL volumes on the pipelines owned by White Cliffs, in which we own a 36% interest.

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•Canada region. Revenues decreased for the three and nine months ended September 30, 2020 compared to the three and nine months ended September 30, 2019 primarily due to voluntary curtailments and shut-ins by oil producers due to the low crude oil prices during the current year.

•Other regions, trucking and pipeline loss allowance revenue. The decrease in other revenues, net of purchases and related costs, for the three and nine months ended September 30, 2020 compared to the three and nine months ended September 30, 2019 was primarily due to lower pipeline loss allowance revenue in 2020 due to lower prices and volumes. Additionally, volumes in our Gulf Coast region were impacted by a decrease in throughput due to reduced refinery demand on a lower tariff pipeline, which did not result in a significant impact on revenue.

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 and nine months ended September 30, 2020, amounts billed to counterparties exceeded revenue recognized during the period that was previously deferred. For the three and nine months ended September 30, 2019, the recognition of previously deferred revenue exceeded amounts billed to counterparties associated with deficiencies under minimum volume commitments.

Field Operating Costs. The decrease in field operating costs for the three and nine months ended September 30, 2020 compared to the same periods in 2019 was primarily due to (i) a decrease in variable costs including reductions in generator and power costs, the use of drag reducing agents and corrosion inhibiting chemicals due to lower volumes, (ii) reductions in compensation costs, including the benefit of wage subsidies received by our Canadian subsidiary, and (iii) a decrease of maintenance and integrity management activities, primarily due to interval changes facilitated through risk-based data application, partially offset by (iv) higher property taxes due to assets placed in service in 2020. In addition, the nine-month comparative period was favorably impacted by (i) lower equity-based compensation costs on liability-classified awards (which are not included as an “Adjustment” in the table above) due to a decrease in our common unit price and (ii) additional estimated costs recognized in the second quarter of 2019 associated with the Line 901 incident (which impact field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above).

Segment General and Administrative Expenses. The decrease in segment general and administrative expenses for the three and nine months ended September 30, 2020 compared to the same periods in 2019 was primarily due to lower equity-based compensation costs on liability-classified awards (which are not included as an “Adjustment” in the table above), due to a decrease in our common unit price, and lower compensation costs including the benefit of wage subsidies received by our Canadian subsidiary.

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 nine months ended September 30, 2020 compared to the same periods in 2019 was primarily due to interval changes facilitated through risk-based data application to integrity management activities.

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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 September 30,				Variance				Nine Months Ended September 30,				Variance
(in millions, except per barrel data)	2020		2019		$		%		2020		2019		$		%
Revenues	$	271	$	291	$	(20)	(7)	%	$	860	$	880	$	(20)	(2)	%
Purchases and related costs	(2)		(3)		1		33	%	(12)		(10)		(2)		(20)	%
Field operating costs	(73)		(92)		19		21	%	(233)		(267)		34		13	%
Segment general and administrative expenses (2)	(18)		(21)		3		14	%	(63)		(62)		(1)		(2)	%
Equity earnings in unconsolidated entities	2		—		2		N/A		4		—		4		N/A

Adjustments (3):
Depreciation and amortization of unconsolidated entities	1		—		1		**		2		—		2		**
Gains from derivative activities	(6)		(3)		(3)		**		(5)		(15)		10		**
Deficiencies under minimum volume commitments, net	—		—		—		**		5		—		5		**

Equity-indexed compensation expense	1		1		—		**		2		3		(1)		**
Segment Adjusted EBITDA	$	176	$	173	$	3	2	%	$	560	$	529	$	31	6	%
Maintenance capital	$	10	$	28	$	(18)	(64)	%	$	40	$	74	$	(34)	(46)	%
Segment Adjusted EBITDA per barrel	$	0.47	$	0.46	$	0.01	2	%	$	0.50	$	0.47	$	0.03	6	%


	Three Months Ended September 30,		Variance			Nine Months Ended September 30,		Variance
Volumes (4)	2020	2019	Volumes	%		2020	2019	Volumes	%
Liquids storage (average monthly capacity in millions of barrels) (5)	111	110	1	1	%	110	109	1	1	%
Natural gas storage (average monthly working capacity in billions of cubic feet)	67	63	4	6	%	66	63	3	5	%
NGL fractionation (average volumes in thousands of barrels per day)	110	140	(30)	(21)	%	129	145	(16)	(11)	%
Facilities segment total volumes (average monthly volumes in millions of barrels) (6)	125	125	—	—	%	125	124	1	1	%

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

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

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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 is 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 revenues and average monthly volumes were primarily driven by the following:

•Crude Oil Storage. Revenues from our crude oil storage operations increased by $13 million and $28 million for the three and nine months ended September 30, 2020 compared to three and nine months ended September 30, 2019, respectively, primarily due to (i) the addition of an aggregate of 3.1 million barrels of storage capacity at our Cushing, St. James and Midland terminals, (ii) increased activity at our Cushing and Midland terminals and (iii) increased spot activity at certain of our West Coast terminals.

The increase in equity earnings over the comparative periods was from our 50% interest in Eagle Ford Terminals, which owns a crude oil storage facility in Corpus Christi that was placed in service in September of 2019.

•Rail Terminals. Revenues from our rail terminals decreased by $13 million and $29 million for the three and nine months ended September 30, 2020 compared to three and nine months ended September 30, 2019, respectively, primarily due to decreased activity at certain of our rail terminals as a result of lower volumes due to voluntary shut-ins and curtailments, as well as less favorable market conditions.

•NGL Operations. Revenues from our NGL operations decreased by $18 million and $12 million for the three and nine months ended September 30, 2020 compared to the same periods in 2019, respectively, primarily due to the sale of certain NGL terminals in the fourth quarter of 2019 and the second quarter of 2020 and net unfavorable foreign exchange impacts of approximately $1 million and $7 million, respectively. The three and nine month comparative periods were further unfavorably impacted by lower revenues from our NGL processing facilities. The decrease in revenues for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019 was partially offset by the favorable impact of the receipt of a deficiency payment of approximately $20 million upon the expiration of a multi-year contract.

•Natural Gas and Condensate Processing. Revenues, net of purchases and related costs, from our natural gas and condensate processing operations decreased by $9 million for nine months ended September 30, 2020 compared to the same period in 2019 primarily due to the unfavorable impact of a $5 million payment to resolve a contractual dispute as well as a decrease in condensate processing volumes and rates.

Field Operating Costs. The decrease in field operating costs for the three and nine months ended September 30, 2020 compared to the same periods in 2019 was primarily due to (i) lower integrity management and maintenance activities due to interval changes facilitated through risk-based data application, (ii) reduced activity at our rail terminals and (iii) reductions in compensation costs including the benefit of wage subsidies received by our Canadian subsidiary. In addition, the three-month comparative period was favorably impacted by mark-to-market gains in the current period on fuel hedges (which impacts field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above), and the nine-month comparative period was favorably impacted by lower insurance claims costs.

Segment General and Administrative Expenses. The decrease in segment general and administrative expenses for the three months ended September 30, 2020 compared to the same period in 2019 was primarily driven by lower compensation costs including the benefit of wage subsidies received by our Canadian subsidiary.

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Maintenance Capital. The decrease in maintenance capital spending for the three and nine months ended September 30, 2020 compared to the same periods in 2019 was primarily due to interval changes facilitated through risk-based data application to integrity management activities.

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, and (iii) 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.

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


Operating Results (1)	Three Months Ended September 30,				Variance				Nine Months Ended September 30,				Variance
(in millions, except per barrel data)	2020		2019		$		%		2020		2019		$		%
Revenues	$	5,537	$	7,542	$	(2,005)	(27)	%	$	16,371	$	23,480	$	(7,109)	(30)	%
Purchases and related costs	(5,510)		(7,337)		1,827		25	%	(16,227)		(22,599)		6,372		28	%
Field operating costs	(46)		(56)		10		18	%	(149)		(195)		46		24	%
Segment general and administrative expenses (2)	(21)		(27)		6		22	%	(65)		(83)		18		22	%

Adjustments (3):
(Gains)/losses from derivative activities, net of inventory valuation adjustments	94		(25)		119		**		215		(46)		261		**
Long-term inventory costing adjustments	2		(1)		3		**		66		3		63		**
Equity-indexed compensation expense	1		1		—		**		3		4		(1)		**
Net (gain)/loss on foreign currency revaluation	4		(5)		9		**		(9)		7		(16)		**
Segment Adjusted EBITDA	$	61	$	92	$	(31)	(34)	%	$	205	$	571	$	(366)	(64)	%
Maintenance capital	$	9	$	15	$	(6)	(40)	%	$	19	$	20	$	(1)	(5)	%
Segment Adjusted EBITDA per barrel	$	0.54	$	0.79	$	(0.25)	(32)	%	$	0.57	$	1.57	$	(1.00)	(64)	%


Average Daily Volumes (4)	Three Months Ended September 30,		Variance			Nine Months Ended September 30,		Variance
(in thousands of barrels per day)	2020	2019	Volumes	%		2020	2019	Volumes	%
Crude oil lease gathering purchases	1,147	1,146	1	—	%	1,181	1,126	55	5	%
NGL sales	83	124	(41)	(33)	%	132	202	(70)	(35)	%
Supply and Logistics segment total volumes	1,230	1,270	(40)	(3)	%	1,313	1,328	(15)	(1)	%

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

(1)Revenues and costs include intersegment amounts.

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

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 September 30, 2020	$	37	$	43
Three Months Ended September 30, 2019	$	52	$	62

Nine Months Ended September 30, 2020	$	(38)	$	63
Nine Months Ended September 30, 2019	$	46	$	66

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 during the periods.

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. Revenues, net of purchases and related costs, (“net revenues”) from our crude oil operations decreased for the three and nine months ended September 30, 2020 compared to the three and nine months ended September 30, 2019, primarily due to a combination of (i) less favorable market conditions, (ii) the impact of lower volumes in higher margin areas, partially offset by volume increases in lower margin areas, and (iii) the impact of weighted average inventory costing resulting in lower margins during the period (which will result in higher margins in subsequent periods), partially offset by the favorable impact of contango market conditions during the second and third quarters of 2020.

•NGL Operations. Net revenues from our NGL operations decreased for the three and nine months ended September 30, 2020 compared to the three and nine months ended September 30, 2019, primarily due to weaker fractionation spreads, lower border flows through our straddle plants and the decision to decrease shoulder month sales volumes and increase winter month sales volumes, as well as the absence of the favorable impact from certain non-recurring items recorded in the second quarter of 2019.

•Impact from Certain Derivative Activities Net of 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), losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable. See Note 10 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.

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•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.

•Foreign Exchange Impacts. Our net revenues are impacted by fluctuations in the value of CAD to USD, which result 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 non-cash 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 three and nine months ended September 30, 2020 compared to the same periods in 2019 was primarily driven by a decrease in long-haul third-party trucking costs and a decrease in company personnel and truck costs as additional pipeline capacity came into service after the first half of 2019.

•Segment General and Administrative Expenses. The decrease in segment general and administrative expenses for the three and nine months ended September 30, 2020 compared to the same periods in 2019 was primarily driven by lower compensation costs including the benefit of wage subsidies received by our Canadian subsidiary and decreased travel and entertainment costs. The nine-month comparative period was further favorably impacted by a decrease in equity-based compensation costs on liability-classified awards (which are not included as an “Adjustment” in the table above) due to a decrease in our common unit price.

Maintenance Capital. The decrease in maintenance capital spending for the three months ended September 30, 2020 compared to the same period in 2019 was due to lower tractor trailer lease buyouts.

Other Income and Expenses

Depreciation and Amortization

Depreciation and amortization expense increased for the three and nine months ended September 30, 2020 compared to the three and nine months ended September 30, 2019 largely driven by additional depreciation expense associated with acquired assets and the completion of various investment capital projects. In addition, the increase for the nine-month comparative period was also impacted by a reduction in the useful lives of certain assets.

Gains/Losses on Asset Sales and Asset Impairments, Net

The net loss on asset sales and asset impairments for the nine months ended September 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 the current 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. See Note 14 for additional information regarding these asset impairments.

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Goodwill Impairment Losses

During the first quarter of 2020, we recognized a goodwill impairment charge of $2.5 billion, representing the entire balance of goodwill. See Note 6 to our Condensed Consolidated Financial Statements for additional information.

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

During the three and nine months ended September 30, 2020, we recognized losses of $91 million and $202 million, respectively, related to the write-down of certain of our investments in unconsolidated entities. Additionally, during the nine months ended September 30, 2020, we recognized a gain of $21 million related to our sale of a 10% interest in Saddlehorn Pipeline Company, LLC. See Note 7 to our Condensed Consolidated Financial Statements for additional information. During the nine months ended September 30, 2019, we recognized a non-cash gain of $269 million related to a fair value adjustment resulting from the accounting for the contribution of our undivided joint interest in the Capline pipeline system for an equity interest in Capline Pipeline Company LLC.

Interest Expense

The increase in interest expense for the three and nine months ended September 30, 2020 compared to the three and nine months ended September 30, 2019 was primarily due to a higher weighted average debt balance during the 2020 period, partially offset by lower weighted average rates. In addition, the nine-month comparative period was further unfavorably impacted by lower capitalized interest for the nine months ended September 30, 2020 driven by fewer capital projects under construction.

Other Income/(Expense), Net

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Gain/(loss) related to mark-to-market adjustment of our Preferred Distribution Rate Reset Option (1)	$	(10)	$	1	$	7	$	16
Net gain/(loss) on foreign currency revaluation (2)	14		—		(20)		1
Other	1		4		6		6
	$	5	$	5	$	(7)	$	23

(1)See Note 10 to our Condensed Consolidated Financial Statements for additional information.

(2)The activity during 2020 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 decrease in income tax expense for the three and nine months ended September 30, 2020 compared to the three and nine months ended September 30, 2019 was primarily due to lower earnings in our Canadian operations. The decrease in income tax expense for the nine-month comparative period was partially offset by the recognition of a deferred tax benefit of approximately $60 million during the second quarter of 2019 as a result of the reduction of the provincial tax rate in Alberta, Canada.

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Liquidity and Capital Resources

General

Our primary sources of liquidity are (i) cash flow from operating activities, (ii) borrowings under our credit facilities or commercial paper program and (iii) funds received from sales of equity and debt securities. In addition, we may supplement these sources of liquidity with proceeds from our divestiture program, as further discussed below in the section entitled “—Acquisitions and Capital Expenditures.” 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 our long-term debt and (v) distributions to our unitholders. We generally expect to fund our short-term cash requirements through cash flow generated from operating activities and/or borrowings under our commercial paper program or 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 our 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 September 30, 2020, although we had a working capital deficit of $399 million, we had approximately $2.8 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 September 30, 2020
Availability under senior unsecured revolving credit facility (1) (2)	$	1,504
Availability under senior secured hedged inventory facility (1) (2)	1,356
Amounts outstanding under commercial paper program	(112)
Subtotal	2,748
Cash and cash equivalents	25
Total	$	2,773

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

(2)Available capacity under our senior unsecured revolving credit facility and senior secured hedged inventory facility was reduced by outstanding letters of credit of $96 million and $44 million, respectively.

On November 3, 2020, we repaid our $600 million, 5.00% senior notes due February 2021 at par and used borrowings under our commercial paper program and cash on hand for the repayment. See further discussion in “Equity and Debt Financing Activities” below.

Current 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; however, we believe that we have, and will continue to have, the ability to access our 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 liquidity; however, extended disruptions in the financial markets and/or energy price volatility that adversely affect our business may have a materially adverse effect on our financial condition, results of operations or cash flows. In addition, usage of our credit facilities, which provide the financial backstop for our commercial paper program, is subject to ongoing compliance with covenants. As of September 30, 2020, we were in compliance with all such covenants. Also, see Item 1A. “Risk Factors” included in our 2019 Annual Report on Form 10-K and Item 1A. “Risk Factors” in Part II of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 for further discussion regarding such 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 2019 Annual Report on Form 10-K.

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Net cash provided by operating activities for the first nine months of 2020 and 2019 was $1.256 billion and $1.778 billion, respectively, and primarily resulted from earnings from our operations. Additionally, as discussed further below, changes during these periods in our inventory levels and associated margin balances required as part of our hedging activities impacted our cash flow from operating activities.

During the nine months ended September 30, 2020, we increased the volume of both our crude oil inventory to be stored during the contango market and our NGL inventory in anticipation of the 2020-2021 heating season as well as the margin balances required as part of our hedging activities, all of which was funded by short-term debt. The cash outflows associated with these activities were partially offset by lower prices for inventory purchased and stored at the end of the current period compared to the end of 2019.

During the nine months ended September 30, 2019, our cash provided by operating activities was positively impacted by the proceeds from the sale of inventory that we held, primarily due to the sale of NGL inventory. The favorable effects from the liquidation of such inventory were partially offset by the timing of revenue recognized during the period for which cash was received in prior periods.

Acquisitions and Capital Expenditures

In addition to our operating needs discussed above, we also use cash for our acquisition activities and investment capital projects and maintenance capital activities. Historically, we have financed these expenditures primarily with cash generated by operating activities and the financing activities discussed in “—Equity and Debt Financing Activities” below. In recent years, we have also used proceeds from our divestiture program. We have made and will continue to make capital expenditures for acquisitions, investment capital projects and maintenance activities. However, in the near term we do not plan to issue common equity to fund such activities.

Acquisitions. In February 2020, we acquired a crude oil gathering system and related assets in the Delaware Basin for approximately $300 million. See Note 14 to our Condensed Consolidated Financial Statements for additional information.

Capital Projects. We invested $785 million in midstream infrastructure during the nine months ended September 30, 2020, and we expect to invest approximately $950 million during the full year ending December 31, 2020. Our expected capital investment for 2020 reflects a reduction from our expected capital investment at year-end 2019 due to the current dynamic and uncertain market conditions. See “—Acquisitions and Capital Projects” for additional information. We expect to fund our 2020 capital program with retained cash flow, proceeds from assets sold as part of our divestiture program or debt.

Divestitures. In January 2020, we signed a definitive agreement to sell certain of our LA Basin crude oil terminals. This transaction closed in the fourth quarter of 2020 for proceeds of approximately $200 million, subject to certain adjustments. In April 2020, we sold certain NGL terminals for $163 million, subject to certain adjustments. See Note 14 to our Condensed Consolidated Financial Statements for additional information. Additionally, we sold a 10% ownership interest in Saddlehorn Pipeline Company, LLC for proceeds of approximately $78 million. See Note 7 to our Condensed Consolidated Financial Statements for additional information.

Ongoing Acquisition, Divestiture and Investment Activities. We intend to continue to focus on activities to enhance investment returns and reinforce capital discipline through asset optimization, joint ventures, potential divestitures and similar arrangements. 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 acquisition or investment efforts will be successful, or that our strategic asset divestitures will be completed. Although we expect the acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized. Also, see Item 1A. “Risk Factors—Risks Related to Our Business” of our 2019 Annual Report on Form 10-K for further discussion regarding risks related to our acquisitions and divestitures.

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Equity and Debt 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. Our financing activities have primarily consisted of equity offerings, senior notes offerings and borrowings and repayments under our credit facilities or commercial paper program and other debt agreements, as well as payment of distributions to our unitholders.

Registration Statements. We periodically access the capital markets for both equity and debt financing. We have filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to an aggregate of $1.1 billion of debt or equity securities (“Traditional Shelf”). At September 30, 2020, we had approximately $1.1 billion of unsold securities available under the Traditional Shelf. We did not conduct any offerings under our Traditional Shelf during the nine months ended September 30, 2020. We also have access to a universal shelf registration statement (“WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. The offering of $750 million, 3.80% senior notes in June 2020 was conducted under our WKSI Shelf.

Credit Agreements, Commercial Paper Program and Indentures. The credit agreements for our revolving credit facilities (which impact our ability to access our commercial paper program because they provide the financial backstop that supports our short-term credit ratings) and our GO Zone term loans and the indentures governing our senior notes contain cross-default provisions. A default under our credit agreements or indentures would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with the provisions in our credit agreements, our ability to make distributions of available cash is not restricted. As of September 30, 2020, we were in compliance with the covenants contained in our credit agreements and indentures.

During the nine months ended September 30, 2020, we had net repayments on our credit facilities and commercial paper program of $306 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.

As of September 30, 2019 and December 31, 2018, we had no outstanding borrowings under our credit agreements or commercial paper program. However, during the nine months ended September 30, 2019, we borrowed and repaid $10.5 billion under our credit facilities and commercial paper program. These repayments resulted primarily from cash flow from operating activities and proceeds from senior notes issuances.

In June 2020, we completed the offering of $750 million, 3.80% senior notes due September 2030 at a public offering price of 99.794%. Interest payments are due on March 15 and September 15 of each year, commencing on September 15, 2020. We used the net proceeds from this offering of $742 million, after deducting the underwriting discount and offering expenses, primarily to repay the principal amounts of our 5.00% senior notes due February 2021 (which were redeemed on November 3, 2020). Prior to such repayment, we used a portion of the proceeds to repay outstanding borrowings under our commercial paper program and credit facilities and for general partnership purposes.

On November 3, 2020, we redeemed our $600 million, 5.00% senior notes due February 2021.

Distributions to Our Unitholders

Distributions to our Series A preferred unitholders. On November 13, 2020, we will pay a cash distribution of $37 million ($0.525 per unit) on our Series A preferred units outstanding as of October 30, 2020, the record date for such distribution for the period from July 1, 2020 through September 30, 2020. See Note 9 to our Condensed Consolidated Financial Statements for details of distributions made during or pertaining to the first nine months of 2020.

Distributions to Series B preferred unitholders. Distributions on our Series B preferred units are payable in cash semi-annually in arrears on the 15th day of May and November. On November 16, 2020, we will pay the semi-annual cash distribution of $24.5 million on our Series B preferred units to holders of record at the close of business on November 2, 2020 for the period from May 15, 2020 to November 14, 2020. See Note 9 to our Condensed Consolidated Financial Statements for additional information.

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Distributions to our common unitholders. In accordance with our partnership agreement, after making distributions to holders of our outstanding preferred units, we distribute the remainder of our available cash to common unitholders of record within 45 days following the end of each quarter. 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 law or contractual obligations and funding of future distributions to our Series A and Series B preferred unitholders. Our available cash also includes cash on hand resulting from borrowings made after the end of the quarter. On November 13, 2020, we will pay a quarterly distribution of $0.18 per common unit ($0.72 per common unit on an annualized basis), which is unchanged from our prior quarterly distribution, but equates to a reduction of 50% compared to the quarterly distribution of $0.36 per common unit ($1.44 per common unit on an annualized basis) paid in February 2020. This reduction was made in response to the current dynamic and uncertain market conditions to further reinforce our commitment to maintaining a solid capital structure and strong liquidity. See “—Executive Summary—Recent Events & Outlook” for further discussion. See Note 9 to our Condensed Consolidated Financial Statements for details of distributions paid during or pertaining to the first nine months of 2020. Also, see Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy” included in our 2019 Annual Report on Form 10-K for additional discussion regarding distributions.

We believe that we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under our 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. A prolonged material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity and cost of borrowing.

Contingencies

For a discussion of contingencies that may impact us, see Note 12 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.

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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 September 30, 2020 (in millions):


	Remainder of 2020		2021		2022		2023		2024		2025 and Thereafter		Total
Long-term debt and related interest payments (1)	$	704	$	412	$	1,160	$	1,662	$	1,103	$	9,633	$	14,674
Leases (2)	30		105		99		76		63		355		728
Other obligations (3)	156		577		345		322		277		1,191		2,868
Subtotal	890		1,094		1,604		2,060		1,443		11,179		18,270
Crude oil, NGL and other purchases (4)	2,512		8,108		7,605		6,966		6,628		24,562		56,381
Total	$	3,402	$	9,202	$	9,209	$	9,026	$	8,071	$	35,741	$	74,651

(1)Includes debt service payments, interest payments due on senior notes and the commitment fee on assumed available capacity under our credit facilities, as well as long-term borrowings under our credit agreements and commercial paper program, if any. Although there may be short-term borrowings under our credit agreements and 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 credit agreements or commercial paper program) in the amounts above. For additional information regarding our debt obligations, see Note 8 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) office space, (iii), land, (iv) vehicles, (v) storage tanks and (vi) tractor trailers. See Note 14 to our Consolidated Financial Statements included in Part IV of our 2019 Annual Report on Form 10-K for additional information.

(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 $2.0 billion associated with agreements to store and transport crude oil at posted tariff rates on pipelines or at facilities 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.

(4)Amounts are primarily based on estimated volumes and market prices based on average activity during September 2020. 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 September 30, 2020 and December 31, 2019, we had outstanding letters of credit of approximately $140 million and $157 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 2019 Annual Report on Form 10-K.

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FORWARD-LOOKING STATEMENTS

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

Factors Related Primarily to the COVID-19 Pandemic and Excess Supply Situation:

•further declines in global crude oil demand and crude oil prices that correspondingly lead to a significant reduction of domestic crude oil, 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;

•uncertainty regarding the length of time it will take for the United States, Canada, and the rest of the world to contain the spread of the COVID-19 virus to the point where restrictions on various commercial and economic activities are (or remain) lifted and the extent to which consumer demand and demand for crude oil rebound in the future;

•uncertainty regarding the future actions of foreign oil producers such as Saudi Arabia and Russia and the risk that they take actions that will prolong or exacerbate the current over-supply of crude oil;

•uncertainty regarding the timing, pace and extent of an economic recovery in the United States and elsewhere, which in turn will likely affect demand for crude oil and therefore the demand for the midstream services we provide and the commercial opportunities available to us;

•the effect of an overhang of significant amounts of crude oil inventory stored in the United States and elsewhere and the impact that such inventory overhang ultimately has on the timing of a return to market conditions that are more conducive to an increase in drilling and production activities in the United States and a resulting increase in demand for the midstream services we provide;

•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 (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;

•operational difficulties due to physical distancing restrictions and the additional demands such restrictions may place on our employees;

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

•our inability to reduce capital expenditures to the extent forecasted, whether due to the incurrence of unexpected or unplanned expenditures, third-party claims or other factors;

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•the inability to complete forecasted asset sale transactions due to governmental action, litigation, counterparty non-performance or other factors;

General Factors:

•the effects of competition, including the effects of capacity overbuild in areas where we operate;

•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 in ways 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;

•maintenance of our 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, including cyber or other attacks on our electronic and computer systems;

•the successful integration and future performance of acquired assets or businesses and 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;

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

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

•the impact of current and future laws, rulings, governmental regulations, accounting standards and statements, and related interpretations, including legislation or regulatory initiatives that prohibit, restrict or regulate hydraulic fracturing;

•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;

•general economic, market or business conditions (both within the United States and globally and including the potential for a recession or significant slowdown in economic activity levels) and the amplification of other risks caused by volatile financial markets, capital constraints and liquidity concerns;

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

•the currency exchange rate of the Canadian dollar;

•continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business;

•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;

•non-utilization of our assets and facilities;

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

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

•the effectiveness of our risk management activities;

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

•risks related to the development and operation of our assets, including our ability to satisfy our contractual obligations to our customers; 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 2019 Annual Report on Form 10-K and in Part II of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

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

•Crude oil

We utilize crude oil derivatives to hedge commodity price risk inherent in our 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.

•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 10 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 September 30, 2020 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	$	(95)	$	(64)	$	65
Natural gas	15		$	7	$	(7)
NGL and other	3		$	(38)	$	38
Total fair value	$	(77)

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.

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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 our senior notes are fixed rate notes and thus are not subject to interest rate risk. Our variable rate debt outstanding at September 30, 2020, approximately $312 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 nine months ended September 30, 2020 was 1.6%, based upon rates in effect during such period. The fair value of our interest rate derivatives was a net asset of $17 million as of September 30, 2020. A 10% increase in the forward LIBOR curve as of September 30, 2020 would have resulted in an increase of $12 million to the fair value of our interest rate derivatives. A 10% decrease in the forward LIBOR curve as of September 30, 2020 would have resulted in a decrease of $12 million to the fair value of our interest rate derivatives. See Note 10 to our Condensed Consolidated Financial Statements for a discussion of our interest rate risk hedging activities.

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 less than $1 million as of September 30, 2020. A 10% increase in the exchange rate (USD-to-CAD) would have resulted in an increase of $4 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 $4 million to the fair value of our foreign currency derivatives. See Note 10 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 our Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, our partnership agreement, and recorded at fair value in our Condensed Consolidated Balance Sheets. The valuation model utilized for this embedded derivative contains inputs including our common unit price, ten-year United States treasury rates, default probabilities and timing estimates to ultimately calculate the fair value of our Series A preferred units with and without the Preferred Distribution Rate Reset Option. The fair value of this embedded derivative was a liability of $27 million as of September 30, 2020. A 10% increase or decrease in the fair value would have an impact of $3 million. See Note 10 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 September 30, 2020, 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 third quarter of 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Certifications

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

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

The information required by this item is included in Note 12 to our Condensed Consolidated Financial Statements, and is incorporated herein by reference thereto.

Item 1A. RISK FACTORS

Other than the risk factors contained in Part II, Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, there are no material changes from the risk factors as previously disclosed in Part I, Item 1A of our 2019 Annual Report on Form 10-K.

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

The Omnibus Agreement, entered into as part of the Simplification Transactions, which closed on November 15, 2016, provides for the mechanics by which (i) the total number of PAGP’s outstanding Class A shares will equal the number of AAP units held by PAGP, and (ii) the total number of our common units held by AAP will equal the sum of the number of outstanding Class A units of AAP (“AAP units”) and the number of AAP units that are issuable to the holders of vested and earned Class B units of AAP (“AAP Management Units”). As such, we are obligated to issue common units to AAP in connection with PAGP’s issuance of Class A shares upon PAGP LTIP award vestings. During the three months ended September 30, 2020, we issued 26,215 common units to AAP in connection with PAGP LTIP award vestings. This issuance 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.

Item 6. EXHIBITS


Exhibit No.		Description

3.1	—	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 our Current Report on Form 8-K filed October 12, 2017).

3.2	—	Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.3	—	Amendment No. 1 dated December 31, 2010 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.9 to our Annual Report on Form 10-K for the year ended December 31, 2010).

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3.4	—	Amendment No. 2 dated January 1, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2010).

3.5	—	Amendment No. 3 dated June 30, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.7 to our Annual Report on Form 10-K for the year ended December 31, 2013).

3.6	—	Amendment No. 4 dated January 1, 2013 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P (incorporated by reference to Exhibit 3.8 to our Annual Report on Form 10-K for the year ended December 31, 2013).

3.7	—	Amendment No. 5 dated December 1, 2019 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.7 to our Annual Report on Form 10-K for the year ended December, 31, 2019).

3.8	—	Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.3 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.9	—	Amendment No. 1 dated January 1, 2013 to the Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. (incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2013).

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

3.11	—	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).

3.12	—	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).

3.13	—	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).

3.14	—	Certificate of Incorporation of PAA Finance Corp. (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2006).

3.15	—	Bylaws of PAA Finance Corp. (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.11 to our Annual Report on Form 10-K for the year ended December 31, 2006).

3.16	—	Limited Liability Company Agreement of PAA GP LLC dated December 28, 2007 (incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K filed January 4, 2008).

3.17	—	Certificate of Limited Partnership of Plains GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to PAGP’s Registration Statement on Form S-1 (333-190227) filed July 29, 2013).

3.18	—	Second Amended and Restated Agreement of Limited Partnership of Plains GP Holdings, L.P. dated November 15, 2016 (incorporated by reference to Exhibit 3.2 to PAGP’s Current Report on Form 8-K filed November 21, 2016).

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

3.20	—	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).

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3.21	—	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).

3.22	—	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).

3.23	—	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).

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 our Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).

4.2	—	Sixth Supplemental Indenture (Series A and Series B 6.70% Senior Notes due 2036) dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our 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 our Current Report on Form 8-K filed October 30, 2006).

4.4	—	Nineteenth Supplemental Indenture (5.00% Senior Notes due 2021) dated January 14, 2011 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 4.1 to our Current Report on Form 8-K filed January 11, 2011).

4.5	—	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 our Current Report on Form 8-K filed March 26, 2012).

4.6	—	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 our Current Report on Form 8-K filed March 26, 2012).

4.7	—	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 our Current Report on Form 8-K filed December 12, 2012).

4.8	—	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 our Current Report on Form 8-K filed December 12, 2012).

4.9	—	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 our Current Report on Form 8-K filed August 15, 2013).

4.10	—	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).

4.11	—	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).

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4.12	—	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).

4.13	—	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 our Current Report on Form 8-K filed August 26, 2015).

4.14	—	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 our Current Report on Form 8-K filed November 29, 2016).

4.15	—	Thirty-First Supplemental Indenture (3.55% Senior Notes due 2029) dated September 16, 2019, 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 17, 2019).

4.16	—	Thirty-Second Supplemental Indenture (3.80% Senior Notes due 2030) dated June 11, 2020, 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 June 11, 2020).

4.17	—	Registration Rights Agreement dated September 3, 2009 by and between Plains All American Pipeline, L.P. and Vulcan Gas Storage LLC (incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-3, File No. 333-162477).

4.18	—	Registration Rights Agreement dated as of January 28, 2016 among Plains All American Pipeline, L.P. and the Purchasers named therein (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed February 2, 2016).

4.19	—	Registration Rights Agreement by and among Plains All American Pipeline, L.P. and the Holders defined therein, dated November 15, 2016 (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed November 21, 2016).

4.20	—	Description of Our Securities (incorporated by reference to Exhibit 4.19 to our Annual Report on Form 10-K for the year ended December 31, 2019).

10.1 *†	—	Form of LTIP Grant Letter dated August 13, 2020 (Officers)

10.2 *†	—	Form of LTIP Grant Letter dated August 13, 2020 (Directors)

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

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104†			—			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

† Filed herewith.

†† Furnished herewith.

* Management compensatory plan or arrangement.

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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 ALL AMERICAN PIPELINE, L.P.

	By:	PAA GP LLC,
		its general partner

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

	By:	Plains All American GP LLC,
		its general partner

	By:	/s/ Willie Chiang
		Willie Chiang,
		Chief Executive Officer of Plains All American GP LLC
		(Principal Executive Officer)

November 6, 2020

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

November 6, 2020

	By:	/s/ Chris Herbold
		Chris Herbold,
		Senior Vice President and Chief Accounting Officer of Plains All American GP LLC
		(Principal Accounting Officer)

November 6, 2020