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, 2019~~March 31, 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,, Texas77002

(Address of principal executive offices) (Zip code)

(~~713~~) (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 31, 2019,~~May 1, 2020, there were ~~728,028,576~~728,053,007 Common Units outstanding.

Table of Contents

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, 2019~~Ma rch 31 , 20 20 and December 31, ~~2018~~20 1 9			3
Condensed Consolidated Statements of Operations: For the three ~~and nine~~ months ended ~~September 30, 2019~~ March 31 , 20 20 and ~~2018~~201 9			4
Condensed Consolidated Statements of Comprehensive ~~Income:~~Income/(Loss): For the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~			5
Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss): For the ~~nine~~three months ended ~~September 30, 2019~~March 31 , 20 20 and ~~2018~~201 9			5
Condensed Consolidated Statements of Cash Flows: For the ~~nine~~three months ended ~~September 30, 2019~~March 31 , 20 20 and ~~2018~~201 9			6
Condensed Consolidated Statements of Changes in Partners’ Capital: For the three ~~and nine~~ months ended ~~September 30, 2019~~March 31 , 20 20 and ~~2018~~201 9			7
Notes to the Condensed Consolidated Financial Statements:
1. Organization and Basis of Consolidation and Presentation			98
2. Summary of Significant Accounting Policies			1110
3. Revenues and Accounts Receivable			1211
4. Net ~~Income~~Income/(Loss) Per Common Unit			1614
5. Inventory, Linefill and Base Gas and Long-term Inventory			1816
6. Goodwill			1817
7. Investments in Unconsolidated Entities			1918
8. Debt			2019
9. Partners’ Capital and Distributions			2220
10. Derivatives and Risk Management Activities			2421
~~11. Leases~~1 1. Related Party Transactions			3127
12. ~~Related Party Transactions~~Commitments and Contingencies			3428
13. ~~Commitments and Contingencies~~Operating Segments			3533
14. ~~Operating Segments~~Acquisitions, Divestitures and Asset Impairments			4036
~~15. Income Taxes~~			43

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			4438
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			6861
Item 4. CONTROLS AND PROCEDURES			6962

PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS			7063
Item 1A. RISK FACTORS			7063
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			7065
Item 3. DEFAULTS UPON SENIOR SECURITIES			7065
Item 4. MINE SAFETY DISCLOSURES			7065
Item 5. OTHER INFORMATION			7065
Item 6. EXHIBITS			7166
SIGNATURES			7570

Table of Contents

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, 2019			December 31, 2018				March 31, 2020		December 31, 2019
	(unaudited)							(unaudited)
ASSETS							ASSETS

CURRENT ASSETS							CURRENT ASSETS
Cash and cash equivalents	$	609		$	66		Cash and cash equivalents	$	38	$	45
Restricted cash	59			—			Restricted cash	122		37
Trade accounts receivable and other receivables, net	2,912			2,454			Trade accounts receivable and other receivables, net	2,200		3,614
Inventory	816			640			Inventory	181		604
Other current assets	280			373			Other current assets	530		312
Total current assets	4,676			3,533			Total current assets	3,071		4,612

PROPERTY AND EQUIPMENT	18,694			17,866			PROPERTY AND EQUIPMENT	17,927		18,948
Accumulated depreciation	(3,437		)	(3,079		)	Accumulated depreciation	(3,525)		(3,593)
Property and equipment, net	15,257			14,787			Property and equipment, net	14,402		15,355

OTHER ASSETS							OTHER ASSETS
Investments in unconsolidated entities							Investments in unconsolidated entities	3,714		3,683
Goodwill	2,532			2,521			Goodwill	—		2,540
Investments in unconsolidated entities	3,485			2,702
Linefill and base gas	930			916			Linefill and base gas	955		981
Long-term operating lease right-of-use assets, net	443			—			Long-term operating lease right-of-use assets, net	430		466
Long-term inventory	159			136			Long-term inventory	73		182
Other long-term assets, net	895			916			Other long-term assets, net	1,055		858
Total assets	$	28,377		$	25,511		Total assets	$	23,700	$	28,677

LIABILITIES AND PARTNERS’ CAPITAL							LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES							CURRENT LIABILITIES
Trade accounts payable	$	3,034		$	2,704		Trade accounts payable	$	2,247	$	3,686
Short-term debt	1,084			66			Short-term debt	363		504
Other current liabilities	754			686			Other current liabilities	747		827
Total current liabilities	4,872			3,456			Total current liabilities	3,357		5,017

LONG-TERM LIABILITIES							LONG-TERM LIABILITIES
Senior notes, net	8,937			8,941			Senior notes, net	8,941		8,939
Other long-term debt, net	236			202			Other long-term debt, net	477		248
Long-term operating lease liabilities	348			—			Long-term operating lease liabilities	370		387
Other long-term liabilities and deferred credits	873			910			Other long-term liabilities and deferred credits	833		891
Total long-term liabilities	10,394			10,053			Total long-term liabilities	10,621		10,465

COMMITMENTS AND CONTINGENCIES (NOTE 13)
COMMITMENTS AND CONTINGENCIES (NOTE 12)							COMMITMENTS AND CONTINGENCIES (NOTE 12)

PARTNERS’ CAPITAL							PARTNERS’ CAPITAL
Series A preferred unitholders (71,090,468 and 71,090,468 units outstanding, respectively)	1,505			1,505			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			Series B preferred unitholders (800,000 and 800,000 units outstanding, respectively)	787		787
Common unitholders (728,028,576 and 726,361,924 units outstanding, respectively)	10,686			9,710
Common unitholders (728,053,007 and 728,028,576 units outstanding, respectively)							Common unitholders (728,053,007 and 728,028,576 units outstanding, respectively)	7,287		10,770
Total partners’ capital excluding noncontrolling interests	12,978			12,002			Total partners’ capital excluding noncontrolling interests	9,579		13,062
Noncontrolling interests	133			—			Noncontrolling interests	143		133
Total partners’ capital	13,111			12,002			Total partners’ capital	9,722		13,195
Total liabilities and partners’ capital	$	28,377		$	25,511		Total liabilities and partners’ capital	$	23,700	$	28,677

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

Table of Contents

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,							Three Months Ended March 31,
	2019			2018			2019			2018				2020		2019
	(unaudited)						(unaudited)							(unaudited)
REVENUES													REVENUES
Supply and Logistics segment revenues	$	7,541		$	8,482		$	23,477		$	24,374		Supply and Logistics segment revenues	$	7,907	$	8,022
Transportation segment revenues	196			161			581			458			Transportation segment revenues	187		197
Facilities segment revenues	149			149			457			437			Facilities segment revenues	175		156
Total revenues	7,886			8,792			24,515			25,269			Total revenues	8,269		8,375

COSTS AND EXPENSES													COSTS AND EXPENSES
Purchases and related costs	6,855			7,768			21,218			22,838			Purchases and related costs	7,367		7,119
Field operating costs	316			326			983			931			Field operating costs	304		326
General and administrative expenses	74			74			225			232			General and administrative expenses	69		76
Depreciation and amortization	156			129			439			385			Depreciation and amortization	168		136
(Gains)/losses on asset sales and asset impairments, net	(7		)	2			(7		)	(79		)
(Gains)/losses on asset sales and asset impairments, net (Note 14)													(Gains)/losses on asset sales and asset impairments, net (Note 14)	619		4
Goodwill impairment losses (Note 6)													Goodwill impairment losses (Note 6)	2,515		—
Total costs and expenses	7,394			8,299			22,858			24,307			Total costs and expenses	11,042		7,661

OPERATING INCOME	492			493			1,657			962
OPERATING INCOME/(LOSS)													OPERATING INCOME/(LOSS)	(2,773)		714

OTHER INCOME/(EXPENSE)													OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	102			110			274			281			Equity earnings in unconsolidated entities	110		89
Gain on investment in unconsolidated entities	4			210			271			210
Interest expense (net of capitalized interest of $7, $8, $29 and $21, respectively)	(108		)	(110		)	(311		)	(327		)
Gain on/(impairment of) investments in unconsolidated entities, net (Note 7)													Gain on/(impairment of) investments in unconsolidated entities, net (Note 7)	(22)		267
Interest expense (net of capitalized interest of $6 and $11, respectively)													Interest expense (net of capitalized interest of $6 and $11, respectively)	(108)		(101)
Other income/(expense), net	5			(3		)	23			8			Other income/(expense), net	(31)		25

INCOME BEFORE TAX	495			700			1,914			1,134
INCOME/(LOSS) BEFORE TAX													INCOME/(LOSS) BEFORE TAX	(2,824)		994
Current income tax expense	(19		)	(14		)	(72		)	(34		)	Current income tax expense	(6)		(30)
Deferred income tax (expense)/benefit	(22		)	24			30			(1		)	Deferred income tax (expense)/benefit	(15)		6

NET INCOME	454			710			1,872			1,099
NET INCOME/(LOSS)													NET INCOME/(LOSS)	(2,845)		970
Net income attributable to noncontrolling interests	(5		)	—			(7		)	—			Net income attributable to noncontrolling interests	(2)		—
NET INCOME ATTRIBUTABLE TO PAA	$	449		$	710		$	1,865		$	1,099
NET INCOME/(LOSS) ATTRIBUTABLE TO PAA													NET INCOME/(LOSS) ATTRIBUTABLE TO PAA	$	(2,847)	$	970

NET INCOME PER COMMON UNIT (NOTE 4):
Net income allocated to common unitholders — Basic	$	399		$	658		$	1,710		$	946
NET INCOME/(LOSS) PER COMMON UNIT (NOTE 4):													NET INCOME/(LOSS) PER COMMON UNIT (NOTE 4):
Net income/(loss) allocated to common unitholders — Basic													Net income/(loss) allocated to common unitholders — Basic	$	(2,897)	$	917
Basic weighted average common units outstanding	728			726			727			726			Basic weighted average common units outstanding	728		727
Basic net income per common unit	$	0.55		$	0.91		$	2.35		$	1.30
Basic net income/(loss) per common unit													Basic net income/(loss) per common unit	$	(3.98)	$	1.26

Net income allocated to common unitholders — Diluted	$	436		$	697		$	1,826		$	947
Net income/(loss) allocated to common unitholders — Diluted													Net income/(loss) allocated to common unitholders — Diluted	$	(2,897)	$	957
Diluted weighted average common units outstanding	800			799			800			728			Diluted weighted average common units outstanding	728		800
Diluted net income per common unit	$	0.55		$	0.87		$	2.28		$	1.30
Diluted net income/(loss) per common unit													Diluted net income/(loss) per common unit	$	(3.98)	$	1.20

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~~INCOME/(LOSS)

(in millions)

Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 2019 2018
(unaudited) (unaudited)
Net income $ 454
$ 710
$ 1,872
$ 1,099
Other comprehensive income/(loss) (99 ) 76
10
(46 )
Comprehensive income 355
786
1,882
1,053
Comprehensive income attributable to noncontrolling interests (5 ) —
(7 ) —
Comprehensive income attributable to PAA $ 350
$ 786
$ 1,875
$ 1,053


	Three Months Ended March 31,
	2020		2019
	(unaudited)
Net income/(loss)	$	(2,845)	$	970
Other comprehensive income/(loss)	(327)		58
Comprehensive income/(loss)	(3,172)		1,028
Comprehensive income attributable to noncontrolling interests	(2)		—
Comprehensive income/(loss) attributable to PAA	$	(3,174)	$	1,028

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	2		—		—		2
Unrealized loss on hedges	(79)		—		—		(79)
Currency translation adjustments	—		(251)		—		(251)
Other	—		—		1		1
Total period activity	(77)		(251)		1		(327)
Balance at March 31, 2020	$	(336)	$	(925)	$	1	$	(1,260)

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 )


													Derivative Instruments		Translation Adjustments		Other		Total
	Derivative Instruments			Translation Adjustments			Other		Total				(unaudited)
	(unaudited)
Balance at December 31, 2017	$	(223	)	$	(548	)	$	1	$	(770	)
Balance at December 31, 2018												Balance at December 31, 2018	$	(177)	$	(853)	$	—	$	(1,030)

Reclassification adjustments	6			—			—		6			Reclassification adjustments	2		—		—		2
Unrealized gain on hedges	60			—			—		60
Unrealized loss on hedges												Unrealized loss on hedges	(23)		—		—		(23)
Currency translation adjustments	—			(112		)	—		(112		)	Currency translation adjustments	—		78		—		78
Other												Other	—		—		1		1
Total period activity	66			(112		)	—		(46		)	Total period activity	(21)		78		1		58
Balance at September 30, 2018	$	(157	)	$	(660	)	$	1	$	(816	)
Balance at March 31, 2019												Balance at March 31, 2019	$	(198)	$	(775)	$	1	$	(972)

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

Table of Contents

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	Nine Months Ended September 30,							Three Months Ended March 31,
	2019			2018				2020		2019
	(unaudited)							(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES							CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,872		$	1,099
Reconciliation of net income to net cash provided by operating activities:
Net income/(loss)							Net income/(loss)	$	(2,845)	$	970
Reconciliation of net income/(loss) to net cash provided by operating activities:							Reconciliation of net income/(loss) to net cash provided by operating activities:
Depreciation and amortization	439			385			Depreciation and amortization	168		136
(Gains)/losses on asset sales and asset impairments, net	(7		)	(79		)
Equity-indexed compensation expense	31			59
(Gains)/losses on asset sales and asset impairments, net (Note 14)							(Gains)/losses on asset sales and asset impairments, net (Note 14)	619		4
Goodwill impairment losses (Note 6)							Goodwill impairment losses (Note 6)	2,515		—
Equity-indexed compensation expense/(benefit)							Equity-indexed compensation expense/(benefit)	(4)		17
Inventory valuation adjustments	11			—			Inventory valuation adjustments	232		—
Deferred income tax expense/(benefit)	(30		)	1			Deferred income tax expense/(benefit)	15		(6)
Settlement of terminated interest rate hedging instruments	(55		)	14
Loss on foreign currency revaluation							Loss on foreign currency revaluation	46		4

Change in fair value of Preferred Distribution Rate Reset Option (Note 10)	(16		)	(3		)	Change in fair value of Preferred Distribution Rate Reset Option (Note 10)	(26)		(23)
Equity earnings in unconsolidated entities	(274		)	(281		)	Equity earnings in unconsolidated entities	(110)		(89)
Distributions on earnings from unconsolidated entities	307			324			Distributions on earnings from unconsolidated entities	125		98
Gain on investment in unconsolidated entities	(271		)	(210		)
(Gain on)/impairment of investments in unconsolidated entities, net (Note 7)							(Gain on)/impairment of investments in unconsolidated entities, net (Note 7)	22		(267)
Other	22			22			Other	5		7
Changes in assets and liabilities, net of acquisitions	(251		)	(37		)	Changes in assets and liabilities, net of acquisitions	128		182
Net cash provided by operating activities	1,778			1,294			Net cash provided by operating activities	890		1,033

CASH FLOWS FROM INVESTING ACTIVITIES							CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	(47		)	—
Cash paid in connection with acquisitions, net of cash acquired (Note 14)							Cash paid in connection with acquisitions, net of cash acquired (Note 14)	(308)		—
Investments in unconsolidated entities	(367		)	(300		)	Investments in unconsolidated entities	(147)		(125)
Additions to property, equipment and other	(919		)	(1,184		)	Additions to property, equipment and other	(245)		(280)
Proceeds from sales of assets	8			1,298
Return of investment from unconsolidated entities	—			10
Proceeds from sales of assets (Note 14)							Proceeds from sales of assets (Note 14)	104		—

Cash paid for purchases of linefill and base gas	(33		)	—			Cash paid for purchases of linefill and base gas	(5)		(16)
Other investing activities	(9		)	(8		)	Other investing activities	(9)		(8)
Net cash used in investing activities	(1,367		)	(184		)	Net cash used in investing activities	(610)		(429)

CASH FLOWS FROM FINANCING ACTIVITIES							CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments under commercial paper program (Note 8)	—			(63		)	Net repayments under commercial paper program (Note 8)	(93)		—
Net repayments under senior secured hedged inventory facility (Note 8)	—			(479		)
Proceeds from GO Zone term loans	—			200
Proceeds from the issuance of senior notes (Note 8)	998			—

Net borrowings under senior secured hedged inventory facility (Note 8)							Net borrowings under senior secured hedged inventory facility (Note 8)	89		—

Distributions paid to Series A preferred unitholders (Note 9)	(112		)	(75		)	Distributions paid to Series A preferred unitholders (Note 9)	(37)		(37)
Distributions paid to Series B preferred unitholders (Note 9)	(25		)	(25		)

Distributions paid to common unitholders (Note 9)	(741		)	(653		)	Distributions paid to common unitholders (Note 9)	(262)		(218)
Sale of noncontrolling interest in a subsidiary (Note 9)	128			—

Other financing activities	(52		)	(20		)	Other financing activities	111		57
Net cash provided by/(used in) financing activities	196			(1,115		)
Net cash used in financing activities							Net cash used in financing activities	(192)		(198)

Effect of translation adjustment	(5		)	(3		)	Effect of translation adjustment	(10)		(3)

Net increase/(decrease) in cash and cash equivalents and restricted cash	602			(8		)
Net increase in cash and cash equivalents and restricted cash							Net increase in cash and cash equivalents and restricted cash	78		403
Cash and cash equivalents and restricted cash, beginning of period	66			37			Cash and cash equivalents and restricted cash, beginning of period	82		66
Cash and cash equivalents and restricted cash, end of period	$	668		$	29		Cash and cash equivalents and restricted cash, end of period	$	160	$	469

Cash paid for:							Cash paid for:
Interest, net of amounts capitalized	$	263		$	281		Interest, net of amounts capitalized	$	65	$	70
Income taxes, net of amounts refunded	$	110		$	20		Income taxes, net of amounts refunded	$	51	$	65

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)	37		12		(2,896)		(2,847)		2		(2,845)
Distributions (Note 9)	(37)		(12)		(262)		(311)		—		(311)
Other comprehensive loss	—		—		(327)		(327)		—		(327)


Contributions from noncontrolling interests (Note 9)	—		—		—		—		8		8
Other	—		—		2		2		—		2
Balance at March 31, 2020	$	1,505	$	787	$	7,287	$	9,579	$	143	$	9,722

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 (Note 9) (112 ) (37 ) (741 ) (890 ) (4 ) (894 )
Other comprehensive income —
—
10
10
—
10
Equity-indexed compensation expense —
—
13
13
—
13
Sale of noncontrolling interest in a subsidiary (Note 9) —
—
(2 ) (2 ) 130
128
Other —
—
(20 ) (20 ) —
(20 )
Balance at September 30, 2019 $ 1,505
$ 787
$ 10,686
$ 12,978
$ 133
$ 13,111















	Limited Partners									Total Partners’ Capital
	Preferred Unitholders						Common Unitholders
	Series A		Series B
	(unaudited)
Balance at December 31, 2018	$	1,505	$	787	$	9,710		$	12,002
Net income	37		12		921			970
Distributions	(37)		(12)		(218)			(267)

Other comprehensive income	—		—		58			58

Other	—		—		(1)			(1)
Balance at March 31, 2019	$	1,505	$	787	$	10,470		$	12,762

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 (Note 9) (37 ) (12 ) (262 ) (311 ) (4 ) (315 )
Other comprehensive loss —
—
(99 ) (99 ) —
(99 )
Equity-indexed compensation expense —
—
6
6
—
6
Other —
—
(8 ) (8 ) —
(8 )
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~~

~~CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL~~

~~(continued)~~

~~(in millions)~~

Limited Partners Total
Partners’
Capital
Preferred Unitholders
Common
Unitholders

Series A Series B
(unaudited)
Balance at December 31, 2017 $ 1,505
$ 788
$ 8,665
$ 10,958
Impact of adoption of ASU 2017-05 —
—
113
113
Balance at January 1, 2018 1,505
788
8,778
11,071
Net income 112
37
950
1,099
Distributions (112 ) (37 ) (653 ) (802 )
Other comprehensive loss —
—
(46 ) (46 )
Equity-indexed compensation expense —
—
37
37
Other —
(1 ) (8 ) (9 )
Balance at September 30, 2018 $ 1,505
$ 787
$ 9,058
$ 11,350

Limited Partners
Total
Partners’
Capital
Preferred Unitholders
Common
Unitholders

Series A Series B
(unaudited)
Balance at June 30, 2018 $ 1,505
$ 787
$ 8,532
$ 10,824
Net income 37
12
661
710
Distributions (37 ) (12 ) (218 ) (267 )
Other comprehensive income —
—
76
76
Equity-indexed compensation expense —
—
14
14
Other —
—
(7 ) (7 )
Balance at September 30, 2018 $ 1,505
$ 787
$ 9,058
$ 11,350

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

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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 3 operating segments: Transportation, Facilities and Supply and Logistics. See Note 1413 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, 2019,~~March 31, 2020, AAP also owned a limited partner interest in us through its ownership of approximately ~~252.2~~248.4 million of our common units (approximately ~~32%~~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, 2019,~~March 31, 2020, owned an approximate ~~73%~~75% 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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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
DERs	=	Distribution equivalent rights
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 ~~2018~~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.

Effective for the fourth quarter of 2018, we present “(Gains)/losses on asset sales and asset impairments, net” as a separate line item on our Condensed Consolidated Statements of Operations. To conform to the current year presentation, amounts related to gains and losses on asset sales and asset impairments previously presented in “Depreciation and amortization” are now presented in “(Gains)/losses on asset sales and asset impairments, net” on our Condensed Consolidated Statements of Operations. This change was applied retrospectively and does not affect Operating income, Net income or Net income attributable to PAA.

The condensed consolidated balance sheet data as of December 31, ~~2018~~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, 2019~~March 31, 2020 should not be taken as indicative of results to be expected for the entire year.

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~~NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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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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 has been 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 the first quarter. See Note 26 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 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 ~~as of the end of the period~~ (in millions):

September 30,
2019
Cash and cash equivalents $ 609
Restricted cash 59
Total cash and cash equivalents and restricted cash $ 668


	March 31, 2020		December 31, 2019
Cash and cash equivalents	$	38	$	45
Restricted cash	122		37
Total cash and cash equivalents and restricted cash	$	160	$	82

~~We did not have any restricted cash as of December 31, 2018.~~

Recent Accounting Pronouncements

Except as discussed below and in our ~~2018~~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~~three months ended ~~September 30, 2019~~March 31, 2020 that are of significance or potential significance to us.

Accounting Standards Updates Adopted During the Period

~~In February 2016, the FASB issued ASU 2016-02,~~ ~~Leases~~,~~(followed by a series of related accounting standard updates(collectively referred to as~~“Topic 842”)), that revises the historical accounting model for leases. The most significant changes are the clarification of the definition of a lease and required lessee recognition on the balance sheet of right-of-use assets and lease liabilities with lease terms of more than 12 months (with the election of the practical expedient to exclude short-term leases on the balance sheet), including extensive quantitative and qualitative disclosures. This guidance became effective for interim and annual periods beginning after December 15, 2018. We adopted this guidance effective January 1, 2019. Our adoption resulted in the recording of additional net lease right-of-use assets and lease liabilities of approximately $560 million and $570 million, respectively, on January 1, 2019 and did not have a material impact on our results of operations or cash flows.

We elected the package of practical expedients permitted under the transition guidance within Topic 842, which, among other things, allowed us to carry forward the historical accounting related to lease identification, classification and indirect costs. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements (including rights of way) on existing agreements. Additionally, we elected the non-lease component separation practical expedient for certain classes of assets where we are the lessee and for all classes of assets where we are the lessor. Further, we elected the practical expedient which provides us with an optional transitional method, thereby applying the new guidance at the effective date, without adjusting the comparative periods and, if necessary, recognizing a cumulative-effect adjustment to the opening balance of Partners’ Capital upon adoption. There was no impact to retained earnings related to our adoption. We did not elect the practical expedient related to using hindsight in determining the lease term as this was not relevant following our election of the optional transitional method. We implemented a process to evaluate the impact of adopting this guidance on each type of lease contract we have entered into with counterparties. Our implementation team determined appropriate changes to our business processes, systems and controls to support recognition and disclosure under Topic 842. In addition to the above, which primarily relates to our accounting as a lessee, our accounting from a lessor perspective remains substantially unchanged under Topic 842. See ~~Note 11~~ ~~for information about our leases.~~

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~~NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~We also~~ adopted the ASUs listed below effective January 1, ~~2019~~2020 and our adoption did not have a material impact toon our financial position, results of operations or cash flows (see Note 2 to our Consolidated Financial Statements included in Part IV of our ~~2018~~2019 Annual Report on Form 10-K for additional information regarding these ASUs):

~~ASU 2018-16, Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes;~~

~~ASU 2018-09, Codification Improvements;~~

~~ASU 2018-07, Compensation—Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting; and~~

~~ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.~~

~~Accounting Standards Updates Issued During the Period~~

~~In July 2019, the FASB issued 2019-07,~~ •Codification Updates to SEC Sections: Amendments to SEC Paragraphs Pursuant to SEC Final Rule Releases No. 33-10532, Disclosure Update and Simplification, and Nos. 33-10231 and 33-10442, Investment Company Reporting Modernization, and Miscellaneous Updates~~, which~~amended SEC paragraphs in the ASC to reflect the SEC final rule releases Disclosure Update and Simplification, Investment Company Reporting Modernization and other miscellaneous updates. This guidance is effective upon issuance and did not have a material impact on our financial position, results of operations or cash flows.

~~In May 2019, the FASB issued 2019-05,~~ ~~Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief, which provides transition relief and allows entities to elect the fair value option on certain financial instruments.We expect to adopt this guidance on January 1, 2020, and we are currently evaluating the effect that our adoption will have on our financial position, results of operations and cash flows.~~

~~In April 2019, the FASB issued~~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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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Accounting Standards Updates Issued During the Period

In March 2020, the FASB issued 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which ~~clarifies certain aspects~~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 ~~accounting for credit losses, hedging activities~~reference rate reform. This guidance is effective prospectively upon issuance through December 31, 2022 and ~~financial instruments.~~may be applied from the beginning of an interim period that includes the issuance date of this ASU. We ~~expect to adopt this guidance on January 1, 2020, and we~~ are currently evaluating the effect that ~~our adoption~~this guidance will have on our financial position, results of operations and cash flows.

Note 3—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 ~~2018~~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, ~~segment,~~ Transportation ~~segment~~ 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,
2019 2018 2019 2018
Supply and Logistics segment revenues from contracts with customers
Crude oil transactions $ 7,185
$ 7,978
$ 21,716
$ 22,651
NGL and other transactions 202
556
1,380
2,181
Total Supply and Logistics segment revenues from contracts with customers $ 7,387
$ 8,534
$ 23,096
$ 24,832


	Three Months Ended March 31,
	2020		2019
Supply and Logistics segment revenues from contracts with customers
Crude oil transactions	$	7,322	$	6,936
NGL and other transactions	428		910
Total Supply and Logistics segment revenues from contracts with customers	$	7,750	$	7,846


	Three Months Ended March 31,
	2020		2019
Transportation segment revenues from contracts with customers
Tariff activities:
Crude oil pipelines	$	512	$	478
NGL pipelines	26		27
Total tariff activities	538		505
Trucking	35		39
Total Transportation segment revenues from contracts with customers	$	573	$	544


	Three Months Ended March 31,
	2020		2019
Facilities segment revenues from contracts with customers
Crude oil, NGL and other terminalling and storage	$	182	$	176
NGL and natural gas processing and fractionation	109		87
Rail load / unload	14		20
Total Facilities segment revenues from contracts with customers	$	305	$	283

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 2019 2018
Transportation segment revenues from contracts with customers
Tariff activities:

Crude oil pipelines $ 532
$ 435
$ 1,504
$ 1,237
NGL pipelines 25
25
75
76
Total tariff activities 557
460
1,579
1,313
Trucking 33
36
106
103
Total Transportation segment revenues from contracts with customers $ 590
$ 496
$ 1,685
$ 1,416

Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 2019 2018
Facilities segment revenues from contracts with customers
Crude oil, NGL and other terminalling and storage $ 174
$ 174
$ 523
$ 511
NGL and natural gas processing and fractionation 87
87
262
278
Rail load / unload 20
24
58
56
Total Facilities segment revenues from contracts with customers $ 281
$ 285
$ 843
$ 845

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, 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

Three Months Ended September 30, 2018 Transportation Facilities Supply and
Logistics Total
Revenues from contracts with customers $ 496
$ 285
$ 8,534
$ 9,315
Other items in revenues 2
4
(51 ) (45 )
Total revenues of reportable segments $ 498
$ 289
$ 8,483
$ 9,270
Intersegment revenues (478 )
Total revenues $ 8,792

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~~NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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
















Three Months Ended March 31, 2020	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	573	$	305	$	7,750	$	8,628
Other items in revenues	6		8		158		172
Total revenues of reportable segments	$	579	$	313	$	7,908	$	8,800
Intersegment revenues							(531)
Total revenues							$	8,269

Three Months Ended March 31, 2019	Transportation		Facilities		Supply and Logistics		Total
Revenues from contracts with customers	$	544	$	283	$	7,846	$	8,673
Other items in revenues	12		16		176		204
Total revenues of reportable segments	$	556	$	299	$	8,022	$	8,877
Intersegment revenues							(502)
Total revenues							$	8,375

Nine Months Ended September 30, 2018 Transportation Facilities Supply and
Logistics Total
Revenues from contracts with customers $ 1,416
$ 845
$ 24,832
$ 27,093
Other items in revenues 11
21
(456 ) (424 )
Total revenues of reportable segments $ 1,427
$ 866
$ 24,376
$ 26,669
Intersegment revenues (1,400 )
Total revenues $ 25,269

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, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, counterparty deficiencies associated with contracts with customers and buy/sell arrangements that include minimum volume commitments totaled ~~$50~~$22 million and ~~$62~~$42 million, respectively, of which ~~$30~~$18 million and ~~$40~~$22 million, respectively, was recorded as a contract liability. The remaining balance of $4 million and $20 million ~~and $22 million~~ at ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, respectively, was related to deficiencies for which the counterparties had not met their contractual minimum commitments and were not reflected in our Condensed Consolidated Financial Statements as we had not yet billed or collected such amounts.

Contract Balances. Our contract balances consist of amounts received associated with services or sales for which we have not yet completed the related performance obligation. The following table presents the change in the contract liability balance during the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 (in millions):

Contract Liabilities
Balance at December 31, 2018 $ 338
Amounts recognized as revenue (226 )
Additions 82
Other (1 )
Balance at September 30, 2019 $ 193


	Contract Liabilities
Balance at December 31, 2019	$	354
Amounts recognized as revenue	(242)

Additions	36

Balance at March 31, 2020	$	148

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2019~~March 31, 2020 (in millions):


	Remainder of 2019		2020		2021		2022		2023		2024 and Thereafter			Remainder of 2020		2021		2022		2023		2024		2025 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements ⁽¹⁾	$	41	$	162	$	171	$	169	$	167	$	849	Pipeline revenues supported by minimum volume commitments and capacity agreements ⁽¹⁾	$	124	$	168	$	162	$	160	$	138	$	553
Storage, terminalling and throughput agreement revenues	114		369		270		211		176		483		Storage, terminalling and throughput agreement revenues	307		324		254		192		147		367
Total	$	155	$	531	$	441	$	380	$	343	$	1,332	Total	$	431	$	492	$	416	$	352	$	285	$	920


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

The presentation above does not include (i) expected revenues from legacy shippers not underpinned by minimum volume commitments, including pipelines where there are no or limited alternative pipeline transportation options, (ii) intersegment revenues and (iii) the amount of consideration associated with certain income generating contracts, which include a fixed minimum level of service, that are either not within the scope of 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 — Contracts include those related to the Permian Basin, Eagle Ford, Central, Rocky Mountain and Canada regions;~~dedications;

•Supply and Logistics buy/sell arrangements ~~— Contracts include agreements~~ with future committed ~~volumes on certain Permian Basin, Eagle Ford, Central and Canada region systems;~~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. ~~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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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Accounts receivable from the sale of crude oil are generally settled with counterparties on the industry settlement date, which is typically in the month following the month in which the title transfers. Otherwise, we generally invoice customers within 30 days of when the products or services were provided and generally require payment within 30 days of the invoice date. We review all outstanding accounts receivable balances on a monthly basis and record ~~a reserve for amounts that we expect will not be fully recovered.~~our receivables net of expected credit losses. We do not ~~apply actual~~write-off accounts receivable balances ~~against the reserve~~ until we have exhausted substantially all collection efforts. At ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, substantially all of our trade accounts receivable ~~(net of allowance for doubtful accounts)~~ were less than 30 days past their scheduled invoice date. Our ~~allowance for doubtful accounts receivable totaled $3 million at both September 30, 2019 and December 31, 2018.~~expected credit losses are immaterial. Although we consider our ~~allowance for doubtful accounts receivable~~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 ~~amounts~~amount of current and future credit losses could vary significantly from estimated amounts.

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


	March 31, 2020		December 31, 2019
Trade accounts receivable arising from revenues from contracts with customers	$	1,796	$	3,381
Other trade accounts receivables and other receivables ⁽¹⁾	2,668		3,576
Impact due to contractual rights of offset with counterparties	(2,264)		(3,343)
Trade accounts receivable and other receivables, net	$	2,200	$	3,614

September 30,
2019 December 31, 2018
Trade accounts receivable arising from revenues from contracts with customers $ 2,628
$ 2,277
Other trade accounts receivables and other receivables ⁽¹⁾
3,076
2,732
Impact due to contractual rights of offset with counterparties (2,792 ) (2,555 )
Trade accounts receivable and other receivables, net $ 2,912
$ 2,454


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

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

We calculate basic and diluted net ~~income~~income/(loss) per common unit by dividing net ~~income~~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 DERs, 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 ~~our~~approximately 71 million Series A preferred units was excluded from the calculation of diluted net ~~income~~income/(loss) per common unit for the ~~nine~~three months ended ~~September 30, 2018~~March 31, 2020 as the effect was antidilutive. Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered 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,~~March 31, 2020 and 2019 ~~and 2018~~ 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. Potentially dilutive LTIP awards of approximately 1 million units were excluded from the computation of diluted net loss per common unit for the three months ended March 31, 2020 as the effect was antidilutive. See Note 1718 to our Consolidated Financial Statements included in Part IV of our ~~2018~~2019 Annual Report on Form 10-K for a complete discussion of our equity-indexed compensation plan awards.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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


														Three Months Ended March 31,
	Three Months Ended September 30,						Nine Months Ended September 30,							2020		2019
	2019			2018			2019			2018
Basic Net Income per Common Unit
Net income attributable to PAA	$	449		$	710		$	1,865		$	1,099
Basic Net Income/(Loss) per Common Unit													Basic Net Income/(Loss) per Common Unit
Net income/(loss) attributable to PAA													Net income/(loss) attributable to PAA	$	(2,847)	$	970
Distributions to Series A preferred unitholders	(37		)	(37		)	(112		)	(112		)	Distributions to Series A preferred unitholders	(37)		(37)
Distributions to Series B preferred unitholders	(12		)	(12		)	(37		)	(37		)	Distributions to Series B preferred unitholders	(12)		(12)
Distributions to participating securities	(1		)	(1		)	(2		)	(2		)	Distributions to participating securities	(1)		(1)
Other	—			(2		)	(4		)	(2		)	Other	—		(3)
Net income allocated to common unitholders ⁽¹⁾	$	399		$	658		$	1,710		$	946
Net income/(loss) allocated to common unitholders ⁽¹⁾													Net income/(loss) allocated to common unitholders ⁽¹⁾	$	(2,897)	$	917

Basic weighted average common units outstanding	728			726			727			726			Basic weighted average common units outstanding	728		727

Basic net income per common unit	$	0.55		$	0.91		$	2.35		$	1.30
Basic net income/(loss) per common unit													Basic net income/(loss) per common unit	$	(3.98)	$	1.26

Diluted Net Income per Common Unit
Net income attributable to PAA	$	449		$	710		$	1,865		$	1,099
Diluted Net Income/(Loss) per Common Unit													Diluted Net Income/(Loss) per Common Unit
Net income/(loss) attributable to PAA													Net income/(loss) attributable to PAA	$	(2,847)	$	970
Distributions to Series A preferred unitholders	—			—			—			(112		)	Distributions to Series A preferred unitholders	(37)		—
Distributions to Series B preferred unitholders	(12		)	(12		)	(37		)	(37		)	Distributions to Series B preferred unitholders	(12)		(12)
Distributions to participating securities	(1		)	(1		)	(2		)	(2		)	Distributions to participating securities	(1)		(1)
Other	—			—			—			(1		)
Net income allocated to common unitholders ⁽¹⁾	$	436		$	697		$	1,826		$	947

Net income allocated/(loss) to common unitholders ⁽¹⁾													Net income allocated/(loss) to common unitholders ⁽¹⁾	$	(2,897)	$	957

Basic weighted average common units outstanding	728			726			727			726			Basic weighted average common units outstanding	728		727
Effect of dilutive securities:													Effect of dilutive securities:
Series A preferred units	71			71			71			—			Series A preferred units	—		71
Equity-indexed compensation plan awards	1			2			2			2			Equity-indexed compensation plan awards	—		2
Diluted weighted average common units outstanding	800			799			800			728			Diluted weighted average common units outstanding	728		800

Diluted net income per common unit	$	0.55		$	0.87		$	2.28		$	1.30
Diluted net income/(loss) per common unit													Diluted net income/(loss) per common unit	$	(3.98)	$	1.20

⁽¹⁾

⁽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.

We calculate net income 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, if any, are allocated to 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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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2019						December 31, 2018							March 31, 2020										December 31, 2019
	Volumes	Unit of Measure	Carrying Value		Price/ Unit ⁽¹⁾		Volumes	Unit of Measure	Carrying Value		Price/ Unit ⁽¹⁾			Volumes	Unit of Measure	Carrying Value		Price/ Unit ⁽¹⁾		Volumes	Unit of Measure	Carrying Value		Price/ Unit ⁽¹⁾
Inventory													Inventory
Crude oil	11,481	barrels	$	616	$	53.65	9,657	barrels	$	367	$	38.00	Crude oil	7,168	barrels	$	128	$	17.86	8,613	barrels	$	450	$	52.25
NGL	12,449	barrels	182		$	14.62	10,384	barrels	262		$	25.23	NGL	3,992	barrels	42		$	10.52	7,574	barrels	142		$	18.75

Other	N/A		18		N/A		N/A		11		N/A		Other	N/A		11		N/A		N/A		12		N/A
Inventory subtotal			816						640				Inventory subtotal			181						604

Linefill and base gas													Linefill and base gas
Crude oil	13,513	barrels	775		$	57.35	13,312	barrels	761		$	57.17	Crude oil	14,251	barrels	804		$	56.42	14,316	barrels	826		$	57.70
NGL	1,715	barrels	47		$	27.41	1,730	barrels	47		$	27.17	NGL	1,640	barrels	41		$	25.00	1,701	barrels	47		$	27.63
Natural gas	24,976	Mcf	108		$	4.32	24,976	Mcf	108		$	4.32	Natural gas	25,576	Mcf	110		$	4.30	24,976	Mcf	108		$	4.32
Linefill and base gas subtotal			930						916				Linefill and base gas subtotal			955						981

Long-term inventory													Long-term inventory
Crude oil	2,587	barrels	138		$	53.34	1,890	barrels	79		$	41.80	Crude oil	2,789	barrels	55		$	19.72	2,598	barrels	152		$	58.51
NGL	1,707	barrels	21		$	12.30	2,368	barrels	57		$	24.07	NGL	1,579	barrels	18		$	11.40	1,707	barrels	30		$	17.57
Long-term inventory subtotal			159						136				Long-term inventory subtotal			73						182

Total			$	1,905					$	1,692			Total			$	1,209					$	1,767


⁽¹⁾ ⁽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.	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 $232 million during the three months ended March 31, 2020 related to the write-down of our crude oil and NGL inventory, of which $40 million is associated with our long-term inventory, due to declines in prices during the first quarter of 2020. 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 ~~6—Goodwill~~10 for discussion of our derivative and risk management activities.

~~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, 2018 $ 1,040
$ 978
$ 503
$ 2,521
Foreign currency translation adjustments 7
2
2
11
Balance at September 30, 2019 $ 1,047
$ 980
$ 505
$ 2,532

~~We utilized a quantitative assessment in our goodwill impairment test as of June 30, 2019 and determined that there was 0 impairment of goodwill.~~

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 6—Goodwill

~~Note 7—Investments in Unconsolidated Entities~~

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

Ownership Interest at Investment Balance
Entity ⁽¹⁾
Type of Operation September 30,
2019 September 30, 2019 December 31, 2018
Advantage Pipeline Holdings LLC Crude Oil Pipeline 50% $ 74
$ 72
BridgeTex Pipeline Company, LLC Crude Oil Pipeline 20% 432
435
Cactus II Pipeline LLC Crude Oil Pipeline 65% 666
455
Caddo Pipeline LLC Crude Oil Pipeline 50% 66
65
Capline Pipeline Company LLC
Crude Oil Pipeline ⁽²⁾
54% 462
—
Cheyenne Pipeline LLC Crude Oil Pipeline 50% 44
44
Diamond Pipeline LLC Crude Oil Pipeline 50% 476
479
Eagle Ford Pipeline LLC Crude Oil Pipeline 50% 386
383
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”) Crude Oil Terminal and Dock 50% 124
108
Midway Pipeline LLC Crude Oil Pipeline 50% 76
78
Red Oak Pipeline LLC (“Red Oak”)
Crude Oil Pipeline ⁽³⁾
50% 3
—
Saddlehorn Pipeline Company, LLC Crude Oil Pipeline 40% 227
215
Settoon Towing, LLC Barge Transportation Services 50% 58
58
STACK Pipeline LLC Crude Oil Pipeline 50% 116
120
White Cliffs Pipeline, LLC Crude Oil Pipeline 36% 196
190
Wink to Webster Pipeline LLC (“W2W Pipeline”)
Crude Oil Pipeline ⁽³⁾
16% 79
—
Total investments in unconsolidated entities $ 3,485
$ 2,702


⁽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 in the fourth quarter of 2018. During the third quarter of 2019, the owners of Capline Pipeline Company LLC sanctioned the reversal of the Capline pipeline system.


⁽³⁾	~~Asset is currently under construction and has not yet been placed in service.~~

~~Formations~~

~~Capline LLC.~~ During the first quarter of ~~2019,~~2020, we recorded impairment losses related to goodwill. Our market capitalization declined significantly during the ~~owners~~first quarter driven by current macroeconomic and geopolitical conditions including the collapse of oil prices driven by both the ~~Capline pipeline system, which originates~~decrease in ~~St. James, Louisiana~~demand caused by the COVID-19 pandemic and ~~terminates~~excess supply as well as changing market conditions and expected lower crude oil production in ~~Patoka, Illinois, contributed their undivided joint interests~~certain regions, resulting in expected decreases in future cash flows for certain of our assets. In addition, the ~~system~~uncertainty related to a newly formed entity, Capline Pipeline Company LLC (“Capline LLC”), in exchange for equity interests in such entity. After the contribution, Capline LLC owns 100% of the pipeline system. Each owner’s undivided joint interest in the Capline pipeline system prioroil demand continues to ~~the transaction is equal to each owner’s equity interest in Capline LLC. Although we own a majority of Capline LLC’s equity, we do not~~ have a ~~controlling financial interest in Capline LLC because~~significant impact on the ~~other members have substantive participating rights. Therefore, we account for our ownership interest in Capline LLC as an equity method investment.~~

~~Under applicable accounting rules, the transaction resulted in a “loss of control”~~investment and operating plans of our ~~undivided joint interest,~~primary customers. Based on these events, we concluded that a triggering event occurred which ~~was derecognized and contributed to Capline LLC. The “loss of control”~~ required us to ~~measure our equity interest in Capline LLC at fair value. At the time~~perform a quantitative impairment test as of ~~the transaction, our 54% undivided joint interest~~March 31, 2020, utilizing a discounted cash flow approach. We applied a discount rate of approximately 14% in the ~~Capline pipeline system had a carrying value~~determination of ~~$175 million, which primarily related to property and equipment included in our Transportation segment. We determined~~ the fair value of each of our ~~investment~~reporting units, which represents our estimate of the cost of capital of a theoretical market participant. The fair values of the reporting units are Level 3 measurements in ~~Capline LLC~~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 ~~be approximately $444 million,~~(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 ~~recognition of a gain of $269 million during~~entire goodwill balance for each reporting unit.

Goodwill by segment and changes in goodwill are reflected in the ~~nine months ended September 30, 2019. Such gain is included in “Gain on investment in unconsolidated entities” on our Condensed Consolidated Statement of Operations.~~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	(19)		(7)		(5)		(31)


Goodwill, gross	1,035		975		501		2,511
Impairments	(1,038)		(975)		(502)		(2,515)
Foreign currency translation adjustments	3		—		1		4
Accumulated impairment losses	(1,035)		(975)		(501)		(2,511)
Balance at March 31, 2020	$	—	$	—	$	—	$	—

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 7—Investments in Unconsolidated Entities

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


		Ownership Interest at March 31, 2020	Investment Balance
Entity ⁽¹⁾	Type of Operation				March 31, 2020			December 31, 2019
BridgeTex Pipeline Company, LLC	Crude Oil Pipeline	20%	$	427		$	431
Cactus II Pipeline LLC	Crude Oil Pipeline	65%	767			738
Capline Pipeline Company LLC	Crude Oil Pipeline ⁽²⁾	54%	499			484
Diamond Pipeline LLC	Crude Oil Pipeline	50%	477			476
Eagle Ford Pipeline LLC	Crude Oil Pipeline	50%	391			382
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”)	Crude Oil Terminal and Dock	50%	128			126
Red Oak Pipeline LLC (“Red Oak”)	Crude Oil Pipeline ^{(3) (4)}	50%	54			20
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)	Crude Oil Pipeline	30%	181			234
STACK Pipeline LLC	Crude Oil Pipeline	50%	116			117
White Cliffs Pipeline, LLC	Crude Oil Pipeline	36%	193			196
Wink to Webster Pipeline LLC	Crude Oil Pipeline ⁽³⁾	16%	182			136
Other investments			299			343
Total investments in unconsolidated entities			$	3,714		$	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 ~~fair value~~Capline pipeline was taken out of ~~our investment~~service pending the reversal of the pipeline system.

⁽³⁾Asset is currently under construction and has not yet been placed in ~~Capline LLC was based~~service.

⁽⁴⁾In March 2020, the partners announced they were deferring the Red Oak pipeline project and suspending actions that would require additional capital spending on ~~an income approach utilizing~~the project, and that they would re-evaluate demand for the project in light of recent market developments.

Impairments

During the three months ended March 31, 2020, we recognized a ~~discounted cash flow analysis. This approach requires us to make long-term forecasts~~loss of ~~future revenues and expenditures. Those forecasts require the use of various assumptions and estimates which include those~~$43 million related to the ~~timing and amount~~write-down of ~~capital expenditures,~~certain of our investments included in “Other investments” in the ~~expected tariff rates and volumes of crude oil, and the terminal value. These assumptions are based on~~table above due to an other-than-temporary impairment related to a ~~potential reversal of the Capline pipeline and the initiation of southbound service on the Capline pipeline from Patoka to St. James, and potential service~~decline in market conditions. This loss is reflected in “Gain on/(impairment of) investments in unconsolidated entities, net” on our ~~Diamond joint venture pipeline and the Capline pipeline from Cushing, Oklahoma to St. James. We probability weighted various forecasted cash flow scenarios utilized in the analysis when~~Condensed Consolidated Statement of Operations.

Divestitures

Saddlehorn. In February 2020, we ~~considered the possible outcomes. We used~~sold a discount rate representing our estimate of the risk adjusted discount rate that would be used by market participants. These projects are dependent upon shipper interest. If shipper interest varies from the levels assumed in our model, the related cash flows, and thus the fair value of our investment, could be materially impacted. The fair value of our investment was determined using significant unobservable inputs, or Level 3 inputs in the fair value hierarchy.

~~W2W Pipeline.~~ In the first quarter of 2019, we announced the formation of W2W Pipeline, a joint venture with subsidiaries of ExxonMobil and Lotus Midstream, LLC. During the third quarter of 2019, three additional entities joined as partners in W2W Pipeline. As a result, our10% ownership interest in ~~W2W Pipeline decreased from 20%~~Saddlehorn for proceeds of approximately $78 million, including working capital adjustments, and have retained a 30% interest. We recorded a gain of approximately $21 million related to ~~16%.~~this sale, which is included in “Gain on/(impairment of) investments in unconsolidated entities” on our Condensed Consolidated Statement of Operations. We continue to account for our remaining interest in W2W Pipeline under the equity method of accounting. W2W Pipeline is currently developing a new pipeline system that will originate in the Permian Basin in West Texas and transport crude oil to the Texas Gulf Coast. The pipeline system will provide approximately 1.5 million barrels per day of crude oil and condensate capacity, and the project is targeted to commence operations in 2021. W2W Pipeline has entered into an undivided joint-ownership arrangement with a third party whereby the third party has acquired 29% of the capacity of the pipeline segment from Midland, Texas to Webster, Texas, and W2W Pipeline now owns 71% of this segment of the pipeline.

~~Red Oak.~~ In June 2019, we announced the formation of Red Oak, a joint venture with a subsidiary of Phillips 66. We own a 50% interest in Red Oak, which is currently developing a new pipeline that will provide crude oil transportation service from Cushing, Oklahoma, and the Permian Basin in West Texas to Corpus Christi, Ingleside, Houston and Beaumont, Texas. Initial service from Cushing to the Gulf Coast is targeted to commence in 2021, subject to receipt of applicable permits and regulatory approvals. We account for our interest in Red Oak under the equity method of accounting.

In addition to contributing cash for construction of the Red Oak pipeline system, we have also entered into a pipeline capacity lease agreement with Red Oak whereby Red Oak has agreed to lease 260,000 barrels of capacity on our Sunrise II pipeline once the Red Oak pipeline system is operational. Once the Red Oak pipeline system is operational, we will record (i) a $155 million increase to our investment in Red Oak associated with our deemed contribution of the value attributable to the capacity lease and (ii) corresponding deferred revenue that will be recognized on a straight-line basis over the initial lease term of 33 years.

~~Note 8—Debt~~

~~Debt consisted of the following (in millions):~~

September 30,
2019 December 31,
2018
SHORT-TERM DEBT

Senior notes:
2.60% senior notes due December 2019 $ 500
$ —
5.75% senior notes due January 2020 500
—
Other 84
66
Total short-term debt 1,084
66

LONG-TERM DEBT
Senior notes, net of unamortized discounts and debt issuance costs of $63 and $59, respectively ⁽¹⁾
8,937
8,941
GO Zone term loans, net of debt issuance costs of $1 and $2, respectively, bearing a weighted-average interest rate of 2.9% and 3.1%, respectively 199
198
Other 37
4
Total long-term debt 9,173
9,143
Total debt ⁽²⁾
$ 10,257
$ 9,209

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 8—Debt

Debt consisted of the following (in millions):


	March 31, 2020		December 31, 2019
SHORT-TERM DEBT
Commercial paper notes, bearing a weighted-average interest rate of 2.2% ⁽¹⁾	$	—	$	93
Senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.8%and 2.7%, respectively ⁽¹⁾	237		325




Other	126		86
Total short-term debt	363		504

LONG-TERM DEBT
Senior notes, net of unamortized discounts and debt issuance costs of $59 and $61, respectively ⁽²⁾	8,941		8,939

Senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.8% ⁽²⁾	177		—
GO Zone term loans, net of debt issuance costs of $1 and $1, respectively, bearing a weighted-average interest rate of 2.5% and 2.6%, respectively	199		199
Other	101		49
Total long-term debt	9,418		9,187
Total debt ⁽³⁾	$	9,781	$	9,691


⁽¹⁾ ⁽¹⁾We classified these commercial paper notes and credit facility borrowings as short-term as of March 31, 2020 and 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.	~~As of December 31, 2018, we classified our $500 million, 2.60% senior notes due December 2019 as long-term based on our ability and intent to refinance such amounts on a long-term basis.~~

⁽²⁾

Our fixed-rate senior notes had a face value of approximately $10.0 billion and $9.0 billion at September 30, 2019 and December 31, 2018, respectively. We estimated the aggregate fair value of these notes as of September 30, 2019 and December 31, 2018 to be approximately $10.3 billion and $8.6 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.

~~Credit Facilities~~

~~In August 2019,~~⁽²⁾As of March 31, 2020, we ~~extended the maturity dates~~classified our $600 million, 5.00% senior notes due February 2021 and a portion of our ~~senior unsecured revolving credit facility and~~ senior secured hedged inventory facility borrowings as long-term based on our ability and intent to refinance such amounts on a long-term basis.

⁽³⁾Our fixed-rate senior notes had a face value of approximately $9.0 billion at both March 31, 2020 and December 31, 2019. We estimated the aggregate fair value of these notes as of March 31, 2020 and December 31, 2019 to be approximately $7.2 billion and $9.3 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by ~~one year to August 2024~~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 ~~August 2022, respectively,~~GO Zone term loans approximates fair value as interest rates reflect current market rates. The fair value estimates for ~~each extending lender.~~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.

Borrowings and Repayments

Total borrowings under our credit facilities and commercial paper program for the ~~nine~~three months ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~ were approximately ~~$10.5~~$9.6 billion and ~~$38.6~~$0.5 billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately ~~$10.5~~$9.6 billion and ~~$39.2~~$0.5 billion for the ~~nine~~three months ended ~~September 30,~~March 31, 2020 and 2019, ~~and 2018,~~ respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Letters of Credit

In connection with our supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, we had outstanding letters of credit of ~~$149~~$106 million and ~~$184~~$157 million, respectively.

~~Senior Notes~~

~~In October 2019, we sent notice to the holders of our $500 million, 2.60% senior notes due December 2019 that we will redeem the notes on November 15, 2019.~~

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~~NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Note 9—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, 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


	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


	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

Limited Partners

Series A
Preferred Units

Series B
Preferred Units
Common Units
Outstanding at December 31, 2017 69,696,542
800,000
725,189,138
Issuance of Series A preferred units in connection with in-kind distribution 1,393,926
—
—
Issuances of common units under equity-indexed compensation plans —
—
17,766
Outstanding at March 31, 2018 71,090,468
800,000
725,206,904
Issuances of common units under equity-indexed compensation plans —
—
375,835
Outstanding at June 30, 2018 71,090,468
800,000
725,582,739
Issuances of common units under equity-indexed compensation plans —
—
505,650
Outstanding at September 30, 2018 71,090,468
800,000
726,088,389

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~~three months of ~~2019~~2020 (in millions, except per unit data):

Series A Preferred Unitholders
Distribution Payment Date Cash Distribution Distribution per Unit
November 14, 2019 ⁽¹⁾
$ 37
$ 0.525
August 14, 2019 $ 37
$ 0.525
May 15, 2019 $ 37
$ 0.525
February 14, 2019 $ 37
$ 0.525


	Series A Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit


May 15, 2020 ⁽¹⁾	$	37	$	0.525
February 14, 2020	$	37	$	0.525


⁽¹⁾ ⁽¹⁾Payable to unitholders of record at the close of business on May 1, 2020 for the period from January 1, 2020 through March 31, 2020. At March 31, 2020, such amount was accrued as distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet.	Payable to unitholders of record at the close of business on October 31, 2019 for the period from July 1, 2019 through September 30, 2019. At September 30, 2019, such amount was accrued to distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

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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 ~~during the first nine months of 2019~~ (in millions, except per unit data):

Series B Preferred Unitholders
Distribution Payment Date Cash Distribution Distribution per Unit
November 15, 2019 ⁽¹⁾
$ 24.5
$ 30.625
May 15, 2019 $ 24.5
$ 30.625


	Series B Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit

May 15, 2020 ⁽¹⁾	$	24.5	$	30.625


⁽¹⁾ ⁽¹⁾Payable to unitholders of record at the close of business on May 1, 2020 for the period from November 15, 2019 through May 14, 2020.	~~Payable to unitholders of record at the close of business on November 1, 2019 for the period from May 15, 2019 through November 14, 2019.~~

~~As of September 30, 2019, we had accrued~~

At March 31, 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~~three months of ~~2019~~2020 (in millions, except per unit data):

Distributions Cash Distribution per Common Unit
Common Unitholders Total Cash Distribution
Distribution Payment Date Public AAP
November 14, 2019 ⁽¹⁾
$ 171
$ 91
$ 262
$ 0.36
August 14, 2019 $ 166
$ 96
$ 262
$ 0.36
May 15, 2019 $ 161
$ 101
$ 262
$ 0.36
February 14, 2019 $ 134
$ 84
$ 218
$ 0.30


	Distributions									Cash Distribution per Common Unit
	Common Unitholders						Total Cash Distribution
Distribution Payment Date	Public		AAP


May 15, 2020 ⁽¹⁾	$	86	$	45	$	131		$	0.18
February 14, 2020	$	172	$	90	$	262		$	0.36


⁽¹⁾ ⁽¹⁾Payable to unitholders of record at the close of business on May 1, 2020 for the period from January 1, 2020 through March 31, 2020.	~~Payable to unitholders of record at the close of business on October 31, 2019 for the period from July 1, 2019 through September 30, 2019.~~

Noncontrolling Interests in Subsidiaries

~~In May 2019,~~ During the three months ended March 31, 2020, we ~~formed a joint venture,~~received $8 million of contributions from noncontrolling interests in Red River Pipeline Company LLC ~~(“Red River LLC”), with Delek Logistics Partners, LP (“Delek”) on our~~related to the Red River pipeline ~~system. We received approximately $128 million for Delek’s 33% interest in Red River LLC. We consolidate Red River LLC, with Delek’s 33% interest accounted for as a noncontrolling interest.~~capacity expansion.

~~During the nine months ended September 30, 2019, we paid $4 million of distributions to noncontrolling interests in Red River LLC.~~

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~~NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Note 10—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.

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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 March 31, 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:

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, 2019,~~March 31, 2020, net derivative positions related to these activities included:

•A net long position of ~~3.1~~9.9 million barrels associated with our crude oil purchases, which was unwound ratably during ~~October 2019~~April 2020 to match monthly average pricing.

•A net short time spread position of ~~6.9~~6.0 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through ~~December 2020.~~May 2021.

•A net crude oil basis spread position of ~~23.1~~6.3 million barrels at multiple locations through December 2021. These derivatives allow us to lock in grade basis differentials.

•A net short position of ~~12.1~~15.7 million barrels through December ~~2021~~2022 related to anticipated net sales of crude oil and NGL inventory.

Storage Capacity Utilization — For capacity allocated to our supply and logistics operations, we have utilization risk in a backwardated market structure. As of ~~September 30, 2019,~~March 31, 2020, we used derivatives to manage the risk that a portion of our storage capacity will not be utilized (an average of approximately ~~0.9~~2.0 million barrels per month of storage capacity through ~~January~~December 2021). These positions involve no outright price ~~exposure, but instead enable us to profitably use the capacity to store hedged crude oil.~~exposure.

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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, 2019:~~March 31, 2020:

Notional Volume

(Short)/Long

Remaining Tenor

Natural gas purchases

41.8 Bcf

December 2022

Propane sales

(3.0) MMbls

December 2020

Butane sales

(1.8) MMbls

December 2020

Condensate sales (WTI position)

(0.9) MMbls

December 2020

~~Notional Volume~~

~~(Short)/Long~~

~~Remaining Tenor~~

~~Natural gas purchases~~

~~59.5 Bcf~~

~~December 2022~~

~~Propane sales~~

~~(5.7) MMbls~~

~~March 2021~~

~~Butane sales~~

~~(2.7) MMbls~~

~~March 2021~~

~~Condensate sales (WTI position)~~

~~(0.7) MMbls~~

~~March 2021~~

~~Specification products sales (put option)~~

~~0.1 MMbls~~

~~March 2020~~

Power supply requirements ⁽¹⁾

~~1.0~~0.9 TWh

December 2022


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

~~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, 2019 (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
6/15/2020 3.06 % Cash flow hedge

~~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.~~

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~~NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~The following table summarizes our open forward exchange contracts as of September 30, 2019 (in millions):~~

USD CAD Average Exchange Rate
USD to CAD
Forward exchange contracts that exchange CAD for USD:

2019 $ 42
$ 56
$1.00 - $1.32

Forward exchange contracts that exchange USD for CAD:

2019 $ 98
$ 130
$1.00 - $1.32

~~Preferred Distribution Rate Reset Option~~

~~Summary of Financial Impact~~

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 physical transactions are recognized in earnings. Derivatives that are not designated as a hedging ~~instrument and derivatives that do not qualify for hedge accounting~~relationship, as such, changes in the fair value are ~~recognized~~reported 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.

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

Three Months Ended September 30, 2019
Location of Gain/(Loss) Commodity
Derivatives Foreign Currency Derivatives Preferred Distribution Rate Reset Option Interest Rate Derivatives Total
Supply and Logistics segment revenues ⁽¹⁾
$ 149
$ (1 ) $ —
$ —
$ 148
Field operating costs ⁽¹⁾
4
—
—
—
4
Interest expense, net ⁽²⁾
—
—
—
(2 ) (2 )
Other income/(expense), net ⁽¹⁾
—
—
1
—
1
Total gain/(loss) on derivatives recognized in net income $ 153
$ (1 ) $ 1
$ (2 ) $ 151

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Three Months Ended September 30, 2018
Location of Gain/(Loss) Commodity
Derivatives Foreign Currency Derivatives Preferred Distribution Rate Reset Option Interest Rate Derivatives Total
Supply and Logistics segment revenues ⁽¹⁾
$ (59 ) $ 5
$ —
$ —
$ (54 )
Field operating costs ⁽¹⁾
(1 ) —
—
—
(1 )
Interest expense, net ⁽²⁾
—
—
—
(2 ) (2 )
Other income/(expense), net ⁽¹⁾
—
—
(2 ) —
(2 )
Total gain/(loss) on derivatives recognized in net income $ (60 ) $ 5
$ (2 ) $ (2 ) $ (59 )

Nine Months Ended September 30, 2019
Location of Gain/(Loss) Commodity
Derivatives Foreign Currency Derivatives Preferred Distribution Rate Reset Option Interest Rate Derivatives Total
Supply and Logistics segment revenues ⁽¹⁾
$ 380
$ 6
$ —
$ —
$ 386
Field operating costs ⁽¹⁾
15
—
—
—
15
Interest expense, net ⁽²⁾
—
—
—
(7 ) (7 )
Other income/(expense), net ⁽¹⁾
—
—
16
—
16
Total gain/(loss) on derivatives recognized in net income $ 395
$ 6
$ 16
$ (7 ) $ 410

Nine Months Ended September 30, 2018
Location of Gain/(Loss) Commodity
Derivatives Foreign Currency Derivatives Preferred Distribution Rate Reset Option Interest Rate Derivatives Total
Supply and Logistics segment revenues ⁽¹⁾
$ (443 ) $ (7 ) $ —
$ —
$ (450 )
Field operating costs ⁽¹⁾
—
—
—
—
—
Interest expense, net ⁽²⁾
—
—
—
(3 ) (3 )
Other income/(expense), net ⁽¹⁾
—
—
3
—
3
Total gain/(loss) on derivatives recognized in net income $ (443 ) $ (7 ) $ 3
$ (3 ) $ (450 )


⁽¹⁾	~~Derivatives not designated as a hedge.~~


⁽²⁾	~~Derivatives in hedging relationships.~~

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~~NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of September 30, 2019 (in millions):~~

Derivatives Not Designated As Hedging Instruments
Balance Sheet Location Commodity
Derivatives Foreign Currency Derivatives Preferred Distribution Rate Reset Option Total
Interest Rate Derivatives ⁽¹⁾
Total Derivatives
Derivative Assets
Other current assets $ 376
$ —
$ —
$ 376
$ —
$ 376
Other long-term assets, net 59
—
—
59
—
59
Other current liabilities 2
—
—
2
—
2
Total Derivative Assets $ 437
$ —
$ —
$ 437
$ —
$ 437

Derivative Liabilities
Other current assets $ (67 ) $ —
$ —
$ (67 ) $ —
$ (67 )
Other long-term assets, net (5 ) —
—
(5 ) —
(5 )
Other current liabilities (14 ) (1 ) —
(15 ) (64 ) (79 )
Other long-term liabilities and deferred credits (14 ) —
(19 ) (33 ) —
(33 )
Total Derivative Liabilities $ (100 ) $ (1 ) $ (19 ) $ (120 ) $ (64 ) $ (184 )


⁽¹⁾	~~Derivatives in hedging relationships.~~

~~The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of December 31, 2018 (in millions):~~

Derivatives Not Designated As Hedging Instruments
Balance Sheet Location Commodity
Derivatives Foreign Currency Derivatives Preferred Distribution Rate Reset Option Total
Interest Rate Derivatives ⁽¹⁾
Total Derivatives
Derivative Assets
Other current assets $ 441
$ —
$ —
$ 441
$ 2
$ 443
Other long-term assets, net 34
—
—
34
—
34
Other long-term liabilities and deferred credits 3
—
—
3
—
3
Total Derivative Assets $ 478
$ —
$ —
$ 478
$ 2
$ 480

Derivative Liabilities
Other current assets $ (182 ) $ —
$ —
$ (182 ) $ —
$ (182 )
Other long-term assets, net (7 ) —
—
(7 ) —
(7 )
Other current liabilities (10 ) (9 ) —
(19 ) (1 ) (20 )
Other long-term liabilities and deferred credits (9 ) —
(36 ) (45 ) (8 ) (53 )
Total Derivative Liabilities $ (208 ) $ (9 ) $ (36 ) $ (253 ) $ (9 ) $ (262 )


⁽¹⁾	~~Derivatives in hedging relationships.~~

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	Three Months Ended March 31,
	2020		2019
Supply and Logistics segment revenues	$	149	$	213
Field operating costs	1		7
Net gain/(loss) from commodity derivative activity	$	150	$	220

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,
2019 December 31,
2018
Initial margin $ 96
$ 95
Variation margin returned (131 ) (91 )
Letters of credit (75 ) (84 )
Net broker payable $ (110 ) $ (80 )


	March 31, 2020		December 31, 2019
Initial margin	$	163	$	73
Variation margin posted/(returned)	(214)		(45)
Letters of credit	(74)		(73)
Net broker payable	$	(125)	$	(45)

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


	March 31, 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	$	446	$	(256)	$	(125)	$	65	$	179	$	(37)	$	(45)		$	97
Other long-term assets, net	99		(15)		—		84		24		—		—			24
Derivative Liabilities
Other current liabilities	161		(171)		—		(10)		32		(56)		—			(24)
Other long-term liabilities and deferred credits	—		(12)		—		(12)		—		(12)		—			(12)
Total	$	706	$	(454)	$	(125)	$	127	$	235	$	(105)	$	(45)		$	85

Interest Rate Risk Hedging

The following table summarizes the terms of our outstanding interest rate derivatives as of March 31, 2020 (notional amounts in millions):

September 30, 2019 December 31, 2018
Derivative
Asset Positions Derivative
Liability Positions Derivative
Asset Positions Derivative
Liability Positions
Netting Adjustments:

Gross position - asset/(liability) $ 437
$ (184 ) $ 480
$ (262 )
Netting adjustment (74 ) 74
(192 ) 192
Cash collateral received (110 ) —
(80 ) —
Net position - asset/(liability) $ 253
$ (110 ) $ 208
$ (70 )

Balance Sheet Location After Netting Adjustments:

Other current assets $ 199
$ —
$ 181
$ —
Other long-term assets, net 54
—
27
—
Other current liabilities —
(77 ) —
(20 )
Other long-term liabilities and deferred credits —
(33 ) —
(50 )
$ 253
$ (110 ) $ 208
$ (70 )


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	6/15/2020	3.06	%	Cash flow hedge
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	6/15/2023	1.38	%	Cash flow hedge
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	6/14/2024	0.73	%	Cash flow hedge

As of ~~September 30, 2019,~~March 31, 2020, there was a net loss of ~~$281~~$336 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 a net loss of $2 million and $2 million during the three months ended March 31, 2020 and 2019, respectively. Of the total net loss deferred in AOCI at ~~September 30, 2019,~~March 31, 2020, we expect to reclassify a net loss of ~~$10~~$12 million to earnings in the next twelve months. We estimate that substantially all of the remaining deferred loss will be reclassified to earnings through ~~2050~~2054 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of ~~September 30, 2019;~~March 31, 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,
2019 2018 2019 2018
Interest rate derivatives, net $ (53 ) $ 15
$ (111 ) $ 60


	Three Months Ended March 31,
	2020		2019
Interest rate derivatives, net	$	(79)	$	(23)

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At ~~September 30,~~March 31, 2020, the net fair value of our interest rate hedges, which were included in “Other current liabilities” and “Other long-term liabilities and deferred credits” on our Condensed Consolidated Balance Sheet, totaled $115 million and $9 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

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 March 31, 2020 (in millions):


		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2020	$	132	$	175	$1.00 - $1.32

Forward exchange contracts that exchange USD for CAD:
	2020	$	300	$	404	$1.00 - $1.35

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 March 31, 2020 and 2019, the amounts recognized in earnings for our currency exchange rate hedges were a loss of $6 million and a gain of $5 million, respectively.

At March 31, 2020, 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 $1 million and $6 million, respectively. 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.

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 March 31, 2020 and 2019, we recognized gains of $26 million and $23 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 $8 million and $34 million at March 31, 2020 and December 31, ~~2018, none~~2019, respectively. See Note 13 to our Consolidated Financial Statements included in Part IV of our ~~outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in~~2019 Annual Report on Form 10-K for additional information regarding our ~~credit ratings. Although we may be required to post margin on our cleared derivatives as described above, we do not require our non-cleared derivative counterparties to post collateral with us.~~Series A preferred units and the Preferred Distribution Rate Reset Option.

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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, 2019											Fair Value as of December 31, 2018												Fair Value as of March 31, 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			Recurring Fair Value Measures ⁽¹⁾	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivatives	$	167	$	190		$	(20	)	$	337		$	171	$	87		$	12		$	270		Commodity derivatives	$	177	$	128	$	(53)	$	252	$	42	$	105	$	(17)	$	130
Interest rate derivatives	—		(64		)	—			(64		)	—		(7		)	—			(7		)	Interest rate derivatives	—		(124)		—		(124)		—		(44)		—		(44)
Foreign currency derivatives	—		(1		)	—			(1		)	—		(9		)	—			(9		)	Foreign currency derivatives	—		(5)		—		(5)		—		1		—		1
Preferred Distribution Rate Reset Option	—		—			(19		)	(19		)	—		—			(36		)	(36		)	Preferred Distribution Rate Reset Option	—		—		(8)		(8)		—		—		(34)		(34)
Total net derivative asset/(liability)	$	167	$	125		$	(39	)	$	253		$	171	$	71		$	(24	)	$	218		Total net derivative asset/(liability)	$	177	$	(1)	$	(61)	$	115	$	42	$	62	$	(51)	$	53


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

Level 1

Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives and over-the-counter commodity contracts such as futures and swaps. The fair value of exchange-traded commodity derivatives and over-the-counter commodity contracts is based on unadjusted quoted prices in active markets.

Level 2

Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives and over-the-counter commodity, interest rate and foreign currency derivatives that are traded in observable markets with less volume and transaction frequency than active markets. In addition, it includes certain physical commodity contracts. The fair values of these derivatives are corroborated with market observable inputs.

Level 3

Level 3 of the fair value hierarchy includes certain physical commodity and other contracts, over-the-counter options and the Preferred Distribution Rate Reset Option contained in 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.

The fair value of the embedded derivative feature contained in our partnership agreement is based on a valuation model that estimates the fair value of the Series A preferred units with and without the Preferred Distribution Rate Reset Option. This model contains inputs, including our common unit price, ten-year U.S. Treasury rates, default probabilities and timing estimates, some of which involve management judgment. A significant change in these inputs could result in a material change in fair value to this embedded derivative feature. We report unrealized gains and losses associated with this embedded derivative in our Condensed Consolidated Statements of Operations in “Other income/(expense), net.”

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~~To the extent any transfers between levels of the fair value hierarchy occur, our policy is to reflect these transfers as of the beginning of the reporting period in which they occur.~~

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,
2019 2018 2019 2018
Beginning Balance $ (26 ) $ (18 ) $ (24 ) $ (30 )
Net gains/(losses) for the period included in earnings 4
(5 ) 21
2
Settlements 1
—
(10 ) 7
Derivatives entered into during the period (18 ) —
(26 ) (2 )
Ending Balance $ (39 ) $ (23 ) $ (39 ) $ (23 )

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


	Three Months Ended March 31,
	2020		2019
Beginning Balance	$	(51)	$	(24)
Net gains/(losses) for the period included in earnings	(10)		23
Settlements	—		(10)
Derivatives entered into during the period	—		1
Ending Balance	$	(61)	$	(10)

Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period	$	(10)	$	24

~~Note 11—Leases~~

~~Lessee~~

We evaluate all agreements entered into or modified after the date of adoption of Topic 842 that convey to us the use of property or equipment for a term to determine whether the agreement is or contains a lease. We lease certain property and equipment under noncancelable and cancelable operating and finance leases. Our operating leases primarily relate to railcars, office space, land, vehicles, and storage tanks, and our finance leases primarily relate to tractor trailers, vehicles and land. For leases with an initial term of greater than 12 months, we recognize a right-of-use asset and lease liability on the balance sheet. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Our lease agreements have remaining lease terms ranging from one year to approximately 60 years. When applicable, this range includes additional terms associated with leases for which we are reasonably certain to exercise the option to renew and such renewal options are recognized as part of our right-of-use assets and lease liabilities. We have renewal options for leases with terms ranging from one year to 40 years that are not recognized as part of our right-of-use assets or lease liabilities as we have determined we are not reasonably certain to exercise the option to renew.

Certain of our leases have variable lease payments, many of which are based on changes in market indices such as the Consumer Price Index. Our lease agreements for our tractor trailers contain residual value guarantees equal to the fair market value of the tractor trailers at the end of the lease term in the event that we elect not to purchase the asset for an amount equal to the fair value. Our lease agreements do not contain any material restrictive covenants.

For determining the present value of lease payments, we use the discount rate implicit in the lease when readily determinable; however, such rate is not readily determinable for most of our leases. For those leases for which the discount rate is not readily determinable, we utilize incremental borrowing rates that reflect collateralized borrowing with payments and terms that mirror our lease portfolio to discount the lease payments based on information available at the lease commencement date.

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

Lease Cost Three Months Ended
September 30, 2019 Nine Months Ended
September 30, 2019
Operating lease cost $ 32
$ 95
Short-term lease cost 11
32
Other ⁽¹⁾
(1 ) —
Total lease cost $ 42
$ 127


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

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

Nine Months Ended
September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases $ 101
Financing cash flows for finance leases $ 13

Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications:
Operating leases $ 16
Finance leases $ 10

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



	~~September 30, 2019~~
~~Weighted-average remaining lease term (in years):~~
~~Operating leases~~	~~10.2~~
~~Finance leases~~	~~3.6~~

~~Weighted-average discount rate:~~
~~Operating leases~~	~~4.5%~~
~~Finance leases~~	~~2.4%~~

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~~The following table presents the amount and location of our operating and finance lease right-of-use assets and liabilities on our Condensed Consolidated Balance Sheet (in millions):~~

Leases Balance Sheet Location September 30, 2019
Assets
Operating lease right-of-use assets Long-term operating lease right-of-use assets, net $ 443

Finance lease right-of-use assets Property and equipment $ 110
Accumulated depreciation (15 )
Property and equipment, net $ 95

Total lease right-of-use assets $ 538

Liabilities
Operating lease liabilities
Current Other current liabilities $ 103
Noncurrent Long-term operating lease liabilities 348
Total operating lease liabilities $ 451

Finance lease liabilities
Current Short-term debt $ 19
Noncurrent Other long-term debt, net 37
Total finance lease liabilities $ 56

Total lease liabilities $ 507

The following table presents the maturity of undiscounted cash flows for future minimum lease payments under noncancelable leases as of September 30, 2019 reconciled to our lease liabilities on our Condensed Consolidated Balance Sheet (amounts in millions):

Operating Finance
Future minimum lease payments⁽¹⁾:

Remainder of 2019 $ 31
$ 5
2020 113
18
2021 93
9
2022 78
10
2023 54
7
Thereafter 247
10
Total 616
59
Less: Present value discount (165 ) (3 )
Lease liabilities $ 451
$ 56


⁽¹⁾	~~Excludes future minimum payments for short-term and other immaterial leases not included on our Condensed Consolidated Balance Sheet.~~

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~~Lessor~~

We evaluate all agreements entered into or modified after the date of adoption of Topic 842 that convey to others the use of property or equipment for a term to determine whether the agreement is or contains a lease. Significant judgment is required when determining whether a customer obtains the right to direct the use of identified property or equipment. The underlying assets associated with these agreements are evaluated for future use beyond the lease term.

Our Facilities and Transportation segments enter into agreements to conduct fee-based activities associated with (i) providing storage services primarily for crude oil, NGL and natural gas and (ii) transporting crude oil and NGL. Certain of these agreements convey counterparties the right to direct the operation of physically distinct assets. Such agreements include (i) fixed consideration, which is measured based on an available capacity during the period multiplied by the rate in the agreement, or (ii) a fixed monthly fee and variable consideration based on usage. These agreements often include options to extend or terminate the lease, with advance notice. These agreements are operating leases under Topic 842. For the three and nine months ended September 30, 2019, our lease revenue was not material.

The table below presents the maturity of lease payments for operating lease agreements in effect as of September 30, 2019. This presentation includes minimum fixed lease payments and does not include an estimate of variable lease consideration. These agreements have remaining lease terms ranging from two years to 23 years. The following table presents the undiscounted cash flows expected to be received related to these agreements (in millions):

Remainder
of 2019 2020 2021 2022 2023 Thereafter
Lease revenue $ 5
$ 19
$ 22
$ 25
$ 21
$ 226

Note 12—11—Related Party Transactions

See Note 1617 to our Consolidated Financial Statements included in Part IV of our ~~2018~~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, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, we owned ~~546,897,362~~550,769,169 and ~~516,938,280,~~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, as the sole holder, a “pass-through” voting right through which our common unitholders and Series A preferred unitholders have the effective 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 ~~additional~~ 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, 2019,~~March 31, 2020, Kayne Anderson Capital Advisors, L.P. was a principal owner. Through various transactions by an affiliate of The Energy & Minerals Group (“EMG”) in May 2019, EMG’s limited partner interest in AAP was significantly reduced, which caused EMG to lose its right to designate a representative on the board of directors of PAGP GP. As a result, EMG’s board designee, John T. Raymond, was automatically removed from the PAGP GP board. Subsequent to such removal, Mr. Raymond was elected to continue to serve as a director of the PAGP GP board. Additionally, as a result of various transactions by a subsidiary of Occidental Petroleum Corporation (“Oxy”) in September 2019, Oxy no longer holds a limited partner interest in AAP and lost its right to designate a representative on the board of directors of PAGP GP. As a result, Oxy’s board designee, Oscar Brown, was automatically removed from the PAGP GP board. Following these transactions, we no longer recognize EMG or Oxy as a principal owner.

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During the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and 2019, ~~and 2018,~~ 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,
2019 2018 2019 2018
Revenues from related parties ^{(1) (2)}
$ 205
$ 266
$ 661
$ 832

Purchases and related costs from related parties ⁽²⁾
$ (7 ) $ 157
$ 93
$ 317


	Three Months Ended March 31,
	2020		2019
Revenues from related parties ^{(1) (2) (3)}	$	23	$	225

Purchases and related costs from related parties ^{(2) (3)}	$	129	$	114

⁽¹⁾

⁽¹⁾A majority of these revenues are included in “Supply and Logistics segment revenues” on our Condensed Consolidated Statements of Operations.

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⁽²⁾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.

⁽³⁾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.

~~A majority of these revenues are included in “Supply and Logistics segment revenues” on our Condensed Consolidated Statements of Operations.~~


⁽²⁾	Crude oil purchases that are part of inventory exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Condensed Consolidated Statements of Operations.

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

September 30,
2019 December 31,
2018
Trade accounts receivable and other receivables, net from related parties ^{(1) (2)}
$ 165
$ 144

Trade accounts payable to related parties ^{(1) (2) (3)}
$ 105
$ 121


	March 31, 2020		December 31, 2019
Trade accounts receivable and other receivables, net from related parties ⁽¹⁾	$	180	$	134

Trade accounts payable to related parties ^{(1) (2)}	$	97	$	102


⁽¹⁾ ⁽¹⁾Includes amounts related to crude oil purchases and sales, transportation services and amounts owed to us or advanced to us related to expansion projects of equity method investees where we serve as construction manager.	~~We have a netting arrangement with certain related parties. Receivables and payables are presented net of such amounts.~~


⁽²⁾	Includes amounts related to crude oil purchases and sales, transportation services and amounts owed to us or advanced to us related to expansion projects of equity method investees where we serve as construction manager.


⁽³⁾	We have an agreement to transport crude oil at posted tariff rates on a pipeline that is owned by an equity method investee, in which we own a 50% interest. A portion of our commitment to transport is supported by crude oil buy/sell agreements with third parties with commensurate quantities.

⁽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 13—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.

~~Taking into account what~~ Accordingly, we believe to be all relevant known facts and circumstances, and based on what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing laws and regulations, we do not believecan provide no assurance that the outcome of the various legal proceedings ~~in which~~that we are currently involved ~~(including those described below)~~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.

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Environmental — General

Although ~~over the course of the last several years~~ we have made significant investments in our maintenance and integrity programs, ~~and have hired additional personnel in those areas,~~ 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, 2019,~~March 31, 2020, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled ~~$135~~$142 million, of which ~~$62~~$89 million was classified as short-term and ~~$73~~$53 million was classified as long-term. At December 31, ~~2018,~~2019, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident) totaled ~~$135~~$140 million, of which ~~$43~~$60 million was classified as short-term and ~~$92~~$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, 2019,~~March 31, 2020, we had recorded receivables totaling ~~$62~~$81 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which ~~$31~~$69 million was classified as short-term and ~~$31~~$12 million was classified as long-term. At December 31, ~~2018,~~2019, we had recorded ~~$61~~$72 million of such receivables, of which ~~$28~~$35 million was classified as short-term and ~~$33~~$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.

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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. We may be subject to additional claims, investigations and lawsuits, which could materially impact the liabilities and costs we currently expect to incur as a result of the Line 901 incident. Set forth below is a brief summary of actions and matters that are currently pending:

On May 21, 2015, we received a corrective action order from the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”), the governmental agency with jurisdiction over the operation of Line 901 as well as over a second stretch of pipeline extending from Gaviota Pump Station in Santa Barbara County to Emidio Pump Station in Kern County, California (Line 903), requiring us to shut down, purge, review, remediate and test Line 901. The corrective action order was subsequently amended on June 3, 2015; November 12, 2015; and June 16, 2016 to require us to take additional corrective actions with respect to both Lines 901 and 903 (as amended, the “CAO”). Among other requirements, the CAO obligated us to conduct a root cause failure analysis with respect to Line 901 and present remedial work plans and restart plans to PHMSA prior to returning Line 901 and 903 to service; the CAO also imposed a pressure restriction on the section of Line 903 between Pentland Pump Station and Emidio Pump Station, which was subsequently lifted, and required us to take other specified actions with respect to both Lines 901 and 903. We intend to continue to comply with the CAO and to cooperate with any other governmental investigations relating to or arising out of the release. Excavation and removal of the affected section of the pipeline was completed on May 28, 2015. Line 901 and Line 903 have been purged and are not currently operational, with the exception of the Pentland to Emidio segment of Line 903, which remains in service. No timeline has been established for the restart of Line 901 or Line 903. The remaining uncompleted portions of the CAO, which primarily relate to returning Lines 901 and 903 to service, have been incorporated into the Consent Decree (defined and discussed below). Upon entry of the Consent Decree by the Court, we expect that the CAO will be closed out by PHMSA.

On February 17, 2016, PHMSA issued a Preliminary Factual Report of the Line 901 failure, which contains PHMSA’s preliminary findings regarding factual information about the events leading up to the accident and the technical analysis that has been conducted to date. On May 19, 2016, PHMSA issued its final Failure Investigation Report regarding the Line 901 incident. PHMSA’s findings indicate that the direct cause of the Line 901 incident was external corrosion that thinned the pipe wall to a level where it ruptured suddenly and released crude oil. PHMSA also concluded that there were numerous contributory causes of the Line 901 incident, including ineffective protection against external corrosion, failure to detect and mitigate the corrosion and a lack of timely detection and response to the rupture. The report also included copies of various engineering and technical reports regarding the incident. ~~By virtue~~All potential claims by PHMSA against PAA arising out of its statutory authority, PHMSA has the power and authority to impose fines and penalties on us and cause civil or criminal charges to be brought against us. While to date PHMSA has not imposed any such fines or penalties or brought any such civil or criminal charges with respect to the Line 901 ~~release, their investigation is still open and we are likely~~failure would be settled pursuant to ~~have fines or penalties imposed upon us, and civil charges brought against us, in~~ the ~~future.~~Consent Decree discussed 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 1one 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 1 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 1 felony discharge count and 8 misdemeanor counts (which included 1 reporting count, 1 strict liability discharge count and 6 strict liability animal takings counts) and (ii) found not guilty on 1 strict liability animal takings count. The jury deadlocked on 3 counts (including 2 felony discharge counts and 1 strict liability animal takings count), and 2 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. ~~We do not anticipate that the victim restitution, if any, imposed as a result of these proceedings will have a material adverse impact on the financial position or operations of the Partnership.~~ 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 2 remaining felony counts and vacated a second trial on these counts.

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Also in late May of 2015, the United States Attorney for the Department of Justice, Central District of California, Environmental Crimes Section (“DOJ”) began an investigation into whether there were any violations of federal criminal statutes in connection with the Line 901 incident, including potential violations of the federal Clean Water Act. We have cooperated with the DOJ’s investigation by responding to their requests for documents and access to our employees. Consistent with the terms of our governing organizational documents, we are funding our employees’ defense costs, including the costs of separate counsel engaged to represent such individuals. On August 26, 2015, we received a Request for Information from the EPA relating to Line 901. We have provided various responsive materials to date and we will continue to do so in the future in cooperation with the EPA. Except in connection with the May 2016 Indictment and the 2019 Sentence, to date no ~~civil enforcement actions or~~ criminal charges with respect to the Line 901 release have been brought against PAA or any of its affiliates, officers or employees by PHMSA, the DOJ, the EPA, the California Attorney General or the California Department of Fish and Wildlife, and no fines or penalties have been imposed by such governmental agencies; however, the investigations being conducted by such agencies are still open and we may have fines or penalties imposed upon us, our officers or our employees in the future, or civil actions or criminal charges brought against us, our officers or our employees in the future, whether by those or other governmental agencies.employees.

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 been processing those claims and making payments as appropriate. In addition, we have also had 9 class action lawsuits filed against us, 6 of which have been 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. ~~To date, the~~The court ~~has~~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, soand the District Court subsequently dismissed the oil-industry sub-class representatives’ claims. The two remaining sub-classes ~~that have been certified~~ include (i) commercial fishermen who landed fish in certain specified fishing blocks in the waters adjacent to Santa Barbara County or persons or businesses who resold commercial seafood landed in such areas; and (ii) residential beachfront ~~property~~properties on a beach and residential properties with a private easement ~~owners whose properties were oiled.~~to a beach where oil from the spill washed up. The court has tentatively set a trial date of September 1, 2020 for those two sub-classes. 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.

There were also 2 securities law class action lawsuits filed on behalf of certain purported investors in the Partnership and/or PAGP against the Partnership, PAGP and/or certain of their respective officers, directors and underwriters. Both of these lawsuits were consolidated into a single proceeding in the United States District Court for the Southern District of Texas. In general, these lawsuits alleged that the various defendants violated securities laws by misleading investors regarding the integrity of the Partnership’s pipelines and related facilities through false and misleading statements, omission of material

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facts and concealing of the true extent of the spill. The plaintiffs claimed unspecified damages as a result of the reduction in value of their investments in the Partnership and PAGP, which they attributed to the alleged wrongful acts of the defendants. The Partnership and PAGP, and the other defendants, denied the allegations in, and moved to dismiss these lawsuits. On March 29, 2017, the Court ruled in our favor dismissing all claims against all defendants. Plaintiffs refiled their complaint. On April 2, 2018, the Court dismissed all of the refiled claims against all defendants with prejudice. Plaintiffs appealed the dismissal, and on July 16, 2019 the Fifth Circuit Court of Appeals affirmed the dismissal. The time period for a further appeal to the U.S. Supreme Court has lapsed so this ruling is now final. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we indemnified and funded the defense costs of our officers and directors in connection with this lawsuit; we also indemnified and funded the defense costs of our underwriters pursuant to the terms of the underwriting agreements we previously entered into with such underwriters.

In addition, 4 unitholder derivative lawsuits have been filed by certain purported investors in the Partnership against ~~the Partnership,~~PAGP and certain of ~~its~~the Partnership’s affiliates, ~~and certain~~ officers and directors. ~~One~~NaN lawsuit was filed in State District Court in Harris County, Texas and subsequently dismissed by the Court. ~~Two~~NaN 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 ~~are indemnifying~~have indemnified and ~~funding~~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.

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In addition to the foregoing, 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. ~~We are currently involved~~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 ~~discussions with~~ the ~~Trustees to determine~~form of a Consent Decree (the “Consent Decree”). The Consent Decree, which was pre-negotiated and signed by DOJ, PHMSA, EPA, CDFW, California Department of Parks and Recreation, California State Lands Commission, Office of the ~~amount we~~State Fire Marshal, Central Coast Regional Water Quality Control Board, and Regents of the University of California, will, ~~be required~~if entered by the court, settle all of the claims asserted in the lawsuit. The Consent Decree would require 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 is subject to a public notice and comment period that is set to expire on May 20, 2020, and review and approval by the Federal District Court for the Central District of California. We ~~also~~ have ~~exposure to~~included the ~~payment of additional fines, penalties and~~ costs ~~under other applicable federal, state and local laws, statutes and regulations. We are actively involved in discussions~~associated with the relevant federal and state agencies to determine the amount of such fines, penalties and costs, and we have included an estimate of such costs in the loss accrual described below. To the extent any unpaid natural resource damages or other fines, penalties or costs are reasonably estimable, we have included an estimate of such costsConsent Decree settlement in the loss accrual described below.

Taking the foregoing into account, as of ~~September 30, 2019,~~March 31, 2020, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately ~~$380~~$400 million, which estimate includes actual and projected emergency response and clean-up costs, natural resource damage assessments and certain third party claims settlements, as well as estimates for fines, penalties and 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 duration of the natural resource damage assessment process and the ultimate amount of damages determined, (ii) 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, (iii) the determination and calculation of fines and penalties, but excluding fines and penalties that are not probable or reasonably estimable and (iv) 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

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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, claims and investigations 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. In addition, with respect to fines and penalties, the ultimate amount of any fines and penalties assessed against us depends on a wide variety of factors, many of which are not estimable at this time. Where fines and penalties are probable and estimable, we have included them in our estimate, although such estimates could turn out to be wrong. Accordingly, our assumptions and estimates may turn out to be inaccurate and our total costs could turn out to be materially higher; therefore, we can provide no assurance that we will not have to accrue significant additional costs in the future with respect to the Line 901 incident.

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As of ~~September 30, 2019,~~March 31, 2020, we had a remaining undiscounted gross liability of ~~$79~~$90 million related to this event, of which approximately ~~$52~~$80 million is presented in “Other current liabilities” on our Condensed Consolidated Balance Sheet, with the remainder presented in “Other long-term liabilities and deferred credits.” 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, 2019,~~March 31, 2020, we had collected, subject to customary reservations, ~~$200~~$203 million out of the approximate ~~$255~~$275 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of ~~September 30, 2019,~~March 31, 2020, we have recognized a receivable of approximately ~~$55~~$72 million for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected. Of this amount, approximately ~~$26~~$63 million is recognized as a current asset in “Trade accounts receivable and other receivables, net” on our Condensed Consolidated Balance Sheet, with the remainder in “Other long-term assets, net.” 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.

~~San Joaquin Valley Air Pollution Control District.~~ After conducting inspections of the Plains LPG Services, L.P. (“Plains LPG”) facility in Shafter, California during March and June of 2018, the San Joaquin Valley Air Pollution Control District (the “District”) issued four Notices of Violation which totaled $597,000 in the aggregate. Plains LPG entered into a settlement with the District whereby Plains LPG agreed to enter the District’s INSPECT program (a self-reporting and inspection program) and pay a reduced fine of $275,000, which was paid in July 2019.

Note 14—13—Operating Segments

We manage our operations through 3 operating segments: Transportation, Facilities and Supply and Logistics. See Note 3 to our Consolidated Financial Statements included in Part IV of our ~~2018~~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 ~~and gains and losses on significant asset sales by,~~ unconsolidated entities, and further adjusted for certain selected items including (i) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance. Segment Adjusted EBITDA excludes depreciation and amortization.

Maintenance capital consists of capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets.

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


Three Months Ended September 30, 2019	Transportation		Facilities		Supply and Logistics		Intersegment Adjustment			Total

													Transportation		Facilities		Supply and Logistics		Intersegment Adjustment		Total
Three Months Ended March 31, 2020												Three Months Ended March 31, 2020
Revenues:												Revenues:
External customers ⁽¹⁾	$	319	$	149	$	7,541	$	(123	)	$	7,886	External customers ⁽¹⁾	$	297	$	175	$	7,907	$	(110)	$	8,269
Intersegment ⁽²⁾	278		142		1		123			544		Intersegment ⁽²⁾	282		138		1		110		531
Total revenues of reportable segments	$	597	$	291	$	7,542	$	—		$	8,430	Total revenues of reportable segments	$	579	$	313	$	7,908	$	—	$	8,800
Equity earnings in unconsolidated entities	$	102	$	—	$	—				$	102	Equity earnings in unconsolidated entities	$	108	$	2	$	—			$	110
Segment Adjusted EBITDA	$	462	$	173	$	92				$	727	Segment Adjusted EBITDA	$	442	$	210	$	141			$	793
Maintenance capital	$	42	$	28	$	15				$	85	Maintenance capital	$	34	$	14	$	3			$	51

Three Months Ended March 31, 2019												Three Months Ended March 31, 2019
Revenues:												Revenues:
External customers ⁽¹⁾												External customers ⁽¹⁾	$	303	$	156	$	8,022	$	(106)	$	8,375
Intersegment ⁽²⁾												Intersegment ⁽²⁾	253		143		—		106		502
Total revenues of reportable segments												Total revenues of reportable segments	$	556	$	299	$	8,022	$	—	$	8,877
Equity earnings in unconsolidated entities												Equity earnings in unconsolidated entities	$	89	$	—	$	—			$	89
Segment Adjusted EBITDA												Segment Adjusted EBITDA	$	399	$	184	$	278			$	861
Maintenance capital												Maintenance capital	$	27	$	17	$	2			$	46

As of March 31, 2020												As of March 31, 2020
Total assets												Total assets	$	13,669	$	6,094	$	3,937			$	23,700
As of December 31, 2019												As of December 31, 2019
Total assets												Total assets	$	14,902	$	7,336	$	6,439			$	28,677

Three Months Ended September 30, 2018 Transportation Facilities Supply and
Logistics Intersegment Adjustment Total
Revenues:

External customers ⁽¹⁾
$ 292
$ 149
$ 8,482
$ (131 ) $ 8,792
Intersegment ⁽²⁾
206
140
1
131
478
Total revenues of reportable segments $ 498
$ 289
$ 8,483
$ —
$ 9,270
Equity earnings in unconsolidated entities $ 110
$ —
$ —
$ 110
Segment Adjusted EBITDA $ 388
$ 173
$ 75
$ 636
Maintenance capital $ 41
$ 33
$ 4
$ 78

Nine Months Ended September 30, 2019 Transportation Facilities Supply and
Logistics Intersegment Adjustment Total
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

Nine Months Ended September 30, 2018 Transportation Facilities Supply and
Logistics Intersegment Adjustment Total
Revenues:

External customers ⁽¹⁾
$ 808
$ 437
$ 24,374
$ (350 ) $ 25,269
Intersegment ⁽²⁾
619
429
2
350
1,400
Total revenues of reportable segments $ 1,427
$ 866
$ 24,376
$ —
$ 26,669
Equity earnings in unconsolidated entities $ 281
$ —
$ —
$ 281
Segment Adjusted EBITDA $ 1,083
$ 530
$ 120
$ 1,733
Maintenance capital $ 102
$ 74
$ 10
$ 186

⁽¹⁾

⁽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.

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 2018 Annual Report on Form 10-K for a discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenues from External customers presented above and adjusted those revenues out such that Total revenues from External customers reconciles to our Condensed Consolidated Statements of Operations. This presentation is consistent with the information provided to our CODM.

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⁽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~~income/(loss) attributable to PAA (in millions):


	Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended March 31,
	2019			2018			2019			2018				2020		2019
Segment Adjusted EBITDA	$	727		$	636		$	2,371		$	1,733		Segment Adjusted EBITDA	$	793	$	861
Adjustments ⁽¹⁾:													Adjustments ⁽¹⁾:
Depreciation and amortization of unconsolidated entities ⁽²⁾	(18		)	(15		)	(45		)	(44		)	Depreciation and amortization of unconsolidated entities ⁽²⁾	(17)		(12)
Gains/(losses) from derivative activities, net of inventory valuation adjustments ⁽³⁾	29			110			60			(107		)	Gains/(losses) from derivative activities, net of inventory valuation adjustments ⁽³⁾	(30)		74
Long-term inventory costing adjustments ⁽⁴⁾	1			10			(3		)	18			Long-term inventory costing adjustments ⁽⁴⁾	(115)		21
Deficiencies under minimum volume commitments, net ⁽⁵⁾	4			4			10			(9		)	Deficiencies under minimum volume commitments, net ⁽⁵⁾	2		7
Equity-indexed compensation expense ⁽⁶⁾	(5		)	(14		)	(13		)	(37		)	Equity-indexed compensation expense ⁽⁶⁾	(4)		(3)
Net gain/(loss) on foreign currency revaluation ⁽⁷⁾	5			3			(7		)	(5		)	Net gain/(loss) on foreign currency revaluation ⁽⁷⁾	13		(5)
Line 901 incident ⁽⁸⁾	—			—			(10		)	—

Significant acquisition-related expenses ⁽⁸⁾													Significant acquisition-related expenses ⁽⁸⁾	(3)		—
Depreciation and amortization	(156		)	(129		)	(439		)	(385		)	Depreciation and amortization	(168)		(136)
Gains/(losses) on asset sales and asset impairments, net	7			(2		)	7			79			Gains/(losses) on asset sales and asset impairments, net	(619)		(4)
Gain on investment in unconsolidated entities	4			210			271			210
Goodwill impairment losses													Goodwill impairment losses	(2,515)		—
Gain on/(impairment of) investments in unconsolidated entities, net													Gain on/(impairment of) investments in unconsolidated entities, net	(22)		267
Interest expense, net	(108		)	(110		)	(311		)	(327		)	Interest expense, net	(108)		(101)
Other income/(expense), net	5			(3		)	23			8			Other income/(expense), net	(31)		25
Income before tax	495			700			1,914			1,134
Income tax (expense)/benefit	(41		)	10			(42		)	(35		)
Net income	454			710			1,872			1,099
Income/(loss) before tax													Income/(loss) before tax	(2,824)		994
Income tax expense													Income tax expense	(21)		(24)
Net income/(loss)													Net income/(loss)	(2,845)		970
Net income attributable to noncontrolling interests	(5		)	—			(7		)	—			Net income attributable to noncontrolling interests	(2)		—
Net income attributable to PAA	$	449		$	710		$	1,865		$	1,099
Net income/(loss) attributable to PAA													Net income/(loss) attributable to PAA	$	(2,847)	$	970

⁽¹⁾

⁽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 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.

~~Represents adjustments utilized by our CODM in the evaluation of segment results.~~


⁽²⁾	~~Includes our proportionate share of the depreciation and amortization of, and gains and losses on significant asset sales by, unconsolidated entities.~~

⁽³⁾

We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify 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 writedowns of such inventory that result from price declines from Segment Adjusted EBITDA.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

⁽⁵⁾⁽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.

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 13~~ ~~for additional information regarding the Line 901 incident.~~

⁽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 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 three months ended March 31, 2020 as our CODM does not view such expenses as integral to understanding our core segment operating performance.

Note ~~15—Income Taxes~~

14—Acquisitions, Divestitures and Asset Impairments

~~All~~

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 determination of these values is preliminary and we expect to finalize our fair value determination in 2020. The assets acquired primarily consisted of property and equipment of $115 million and intangible assets of $187 million. The preliminary 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 preliminary 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 15% to 16%, based on our estimate of the risk that a theoretical market participant would assign to the respective intangible assets.

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, including working capital adjustments. 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 March 31, 2020, we classified approximately $333 million as assets held for sale on our Condensed Consolidated Balance Sheet (in “Other current assets”). The assets held for sale, which were valued based on fair value less costs to sell, are primarily property and equipment, are included in our Facilities segment and are related to transactions to sell our interests in:

•certain NGL terminals, which closed in April 2020 for proceeds of approximately $163 million, subject to certain adjustments; and

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

•certain Los Angeles Basin (“LA Basin”) terminals. In January 2020, we signed a definitive agreement to sell certain of our ~~Canadian operations are conducted by entities that are treated as corporations~~LA Basin crude oil terminals for ~~Canadian tax purposes (flow through for U.S. income tax purposes) and that are~~$195 million, subject to ~~Canadian federal and provincial taxes. During~~certain adjustments. We expect the transaction to close in the second ~~quarter~~half of ~~2019,~~2020, subject to customary closing conditions, including the ~~Alberta government enacted legislation that reduces the Alberta provincial corporate income tax rate from 12% to 8% over the period from July 1, 2019 through January 1, 2022.~~ receipt of regulatory approvals.

As a result ~~during~~of these reclassifications to assets held for sale, we recognized non-cash impairment losses of approximately $167 million. 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 ~~second~~first quarter of ~~2019,~~2020, we recognized ~~a reduction~~approximately $489 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 ~~deferred income tax liability~~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.

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 ~~$60 million~~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 (based on historical information and ~~a corresponding deferred tax benefit.~~

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~~

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 ~~2018~~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

•Outlook

•Liquidity and Capital Resources

•Off-Balance Sheet Arrangements

•Recent Accounting Pronouncements

•Critical Accounting Policies and Estimates

~~Other Items~~

•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~~—Operations—Analysis of Operating ~~Segments~~”Segments” for further discussion.

Recent Events & Outlook

During the quarter, COVID-19 escalated into a global pandemic, which led to widespread shelter-in-place or similar requirements throughout North American and global markets. The resulting energy demand destruction constitutes a significant near-term challenge facing the energy industry, specifically the uncertainty around not only the magnitude and duration of the demand destruction but also the timing and extent of a recovery. Industry estimates indicate that global demand for crude oil in the second quarter of 2020 could be in the range of 20% to 25% less than the second quarter of 2019.

In North American markets, these developments have resulted in an immediate industry response, led by the U.S. refining sector quickly reducing crude runs and producers quickly reducing drilling and completion activities and production levels. In addition, the Organization of Petroleum Exporting Countries (“OPEC”) and other countries responded with plans to curtail production. However, all of these actions have not been sufficient to balance the market. Demand reductions have been faster and deeper than supply reductions and the resulting over-supply of crude oil is impacting the entire energy supply chain, causing remaining storage capacity to fill and producers to significantly reduce activity and/or shut in production in most, if not all, key basins. While we do not believe all of these actions will rebalance the market in the near term, they should help with the longer-term process of rebalancing the market, which will depend heavily on the speed with which energy demand recovers, the ultimate level of demand recovery and the size of the global supply surplus at the point in time when demand levels begin to exceed supply additions.

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The situation continues to evolve on a daily basis and it is difficult to gauge the level of shut-ins, but at this time we expect storage in key market hubs to fill by June. With inventories for both crude oil and gasoline in the U.S. at historically high levels, the inventory overhang combined with the potential for a slow recovery of demand could result in a crude oil price environment that makes it difficult to achieve increased levels of drilling activity and production in the U.S. for the balance of 2020 and potentially into 2021. These market dynamics will have a negative impact on our business relative to pre-pandemic levels, with the impacts in 2021 potentially being more pronounced than in 2020. On May 5, 2020, we issued revised 2020 guidance reflecting our expectations for business performance in the current market environment. Our guidance represents estimates that we believe are reasonable based on market conditions and expectations at the time, but we can provide no assurance that our estimates will be accurate and our actual results could be materially worse than such estimates.

In response to these current dynamic and uncertain market conditions, on April 7, 2020, we issued a press release announcing a number of actions taken in order to further strengthen our balance sheet and further enhance our liquidity and long-term financial flexibility. These actions include significantly reducing and continuing to challenge our capital program, reducing the amount of our common distribution payable in May 2020, progressing asset sales, and reducing costs, while remaining focused on operating safely and responsibly.

Specifically, we announced the reduction of our 2020/2021 capital program by $750 million, or 33%, and we decreased our common unit distribution and PAGP’s Class A share distribution payable in May 2020 by 50%, which reflects a reduction of $525 million on an annualized basis. We completed an additional approximately $165 million asset sale on April 1, 2020, which resulted in year-to-date assets sale proceeds through such date of approximately $245 million (which amount excludes a previously announced approximately $195 million asset sale that remains under a definitive agreement and is expected to close later in the year). While all of these actions should contribute towards a stronger balance sheet and should enhance our liquidity and long-term financial security, we can provide no assurance that we will be able to effect certain future actions (such as capital reductions, asset sales and expense reductions) and additional actions may be necessary to achieve our balance sheet, liquidity and financial security objectives (see Part II, Item 1A. “Risk Factors”).

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 and responsible manner.

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 the first quarter as discussed further below. See “—Liquidity and Capital Resources” and Part II, Item 1A. “Risk Factors” for additional discussion of the expected and potential impact of COVID-19 and related market conditions on our business.

During the first ~~nine~~three months of ~~2019,~~2020, we recognized a net ~~income~~loss of ~~$1.872~~$2.8 billion as compared to net income of ~~$1.099 billion~~$970 million recognized during the first ~~nine~~three months of ~~2018.~~2019. The ~~increase~~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 $655 million related to the write-down of certain pipeline and other long-lived assets, certain of our investments in ~~net income over~~unconsolidated entities, and assets upon classification as held for sale. In addition, we recognized approximately $232 million of inventory valuation adjustments due to declines in commodity prices during the first quarter of 2020.

Our results for the comparative ~~periods was driven~~period were also impacted by:

~~Favorable~~•Less favorable results from our Supply and Logistics segment due to ~~the realization of~~less favorable crude oil differentials ~~primarily~~and lower NGL margins;

•Higher depreciation and amortization expense in the ~~Permian Basin~~2020 period primarily due to additional depreciation expense associated with the completion of various capital expansion projects and ~~Canada, higher NGL margins and more favorable~~an adjustment to the useful lives of certain assets;

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•Unfavorable foreign currency impacts of $59 million recognized in “Other income/(expense)” in the ~~2019 period from the mark-to-market of certain derivative instruments;~~2020 period; and

Favorable results from our Transportation segment, primarily from our pipelines in the Permian Basin region, driven by higher volumes from increased production and our recently completed capital expansion projects; and

•A ~~non-cash~~ gain of ~~$269~~$21 million recognized in the current period related to the sale of a portion of our interest in Saddlehorn Pipeline Company, LLC, compared to a non-cash gain of $267 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 compared to a gain of $210 million recognized in 2018 related to the sale of a portion of our interest in BridgeTex Pipeline Company LLC; partially offset by~~

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~~Higher depreciation and amortization expense primarily due to additional depreciation expense associated with the completion of various capital expansion projects; and~~

~~The unfavorable impact to the 2019 comparative period of a net gain on asset sales and asset impairments of $79 million for nine months ended September 30, 2018.~~

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

We invested ~~$988~~$352 million in midstream infrastructure projects during the ~~nine~~three months ended ~~September 30, 2019, and we expect expansion capital for the full year of 2019 to be approximately $1.35 billion,~~March 31, 2020, which primarily related to projects under development in the Permian Basin. Additionally, during the first quarter of 2020, we acquired approximately $308 million of assets, which primarily included a crude oil gathering system located in the Delaware Basin. See the “—Acquisitions and Capital ~~Projects~~”Projects” section below for additional information.

~~During 2019, we~~ We also ~~announced the formation of several strategic joint ventures, including Wink to Webster Pipeline LLC, Red Oak Pipeline LLC and Red River Pipeline Company LLC. See~~ ~~Note 7~~ ~~and~~ ~~Note 9~~ ~~to our Condensed Consolidated Financial Statements for additional information.~~

We paid approximately ~~$741~~$262 million of cash distributions to our common unitholders ~~during the nine months ended September 30, 2019. We also paid~~and $37 million of cash distributions ~~of approximately $112 million~~ to our Series A preferred unitholders and we paid a semi-annual cash distribution of $24.5 million to our Series B preferred unitholders. In October 2019, we declared (i) quarterly cash distributions of $0.36 per common unit (a total distribution of $262 million) and $0.525 per Series A preferred unit (a total distribution of $37 million) to be paid on November 14, 2019 and (ii)during the ~~semiannual cash distribution of $30.625 per Series B preferred unit (a total distribution of $24.5 million) to be paid on November 15, 2019.~~

three months ended March 31, 2020.

~~Leverage Reduction Plan Completion and Financial Policy Update~~

In August 2017, we announced that we were implementing an action plan to strengthen our balance sheet, reduce leverage, enhance our distribution coverage, minimize new issuances of common equity and position the Partnership for future distribution growth. The action plan (“Leverage Reduction Plan”), which was endorsed by the PAGP GP Board, included our intent to achieve certain objectives. During 2017 and 2018, we made meaningful progress in executing our Leverage Reduction Plan and in April 2019, we announced our achievement of the remaining objectives. Concurrent with the completion of the Leverage Reduction Plan, we completed a review of our approach to our capital allocation process, targeted leverage metrics and distribution management policies. As part of the April 2019 announcement, we provided several updates regarding our financial policy, including the following actions:

~~Lowering our targeted long-term debt to Adjusted EBITDA leverage ratio by 0.5x to a range of 3.0x to 3.5x;~~

~~Establishing a long-term sustainable minimum annual distribution coverage level of 130% underpinned by predominantly fee-based cash flows; and~~

Our adoption of an annual cycle for setting the common unit distribution level and intention to increase common unit distributions in the future contingent on achieving and maintaining targeted leverage and coverage ratios and subject to an annual review process.

These actions reflect our dedication to optimizing sustainable unitholder value while also preserving and enhancing our financial flexibility, further reducing leverage and improving our credit profile, with an objective of achieving mid-BBB equivalent credit ratings over time. Consistent with those objectives, we announced that 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.

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Acquisitions and Capital Projects

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


	Nine Months Ended September 30,					Three Months Ended March 31,
	2019		2018			2020		2019
Acquisition capital	$	47	$	—	Acquisition capital	$	308	$	—
Expansion capital ^{(1) (2)}	988		1,370		Expansion capital ^{(1) (2)}	352		351
Maintenance capital ⁽²⁾	204		186		Maintenance capital ⁽²⁾	51		46
	$	1,239	$	1,556		$	711	$	397

⁽¹⁾Contributions to unconsolidated entities related to expansion projects of such entities are recognized in “Expansion capital.” We account for our investments in such entities under the equity method of accounting.

⁽²⁾Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as “Expansion 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.”

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Contributions to unconsolidated entities related to expansion projects of such entities are recognized in “Expansion capital.” We account for our investments in such entities under the equity method of accounting.


⁽²⁾	Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as expansion 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.

Expansion Capital Projects

On April 7, 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 expansion capital for 2020/2021 is now targeted to be approximately $1.55 billion, or $750 million (33%) lower than the previously targeted $2.3 billion capital program, and $1.35 billion (47%) lower when eliminating $600 million of assumed joint venture project financing (net to our share) for the Red Oak project, which has been deferred. The balance of the capital reductions relate to cancellations, cost savings and scope adjustments to other capital projects. The following table summarizes our notable projects in progress during ~~2019~~2020 and the estimated cost for the year ending December 31, ~~2019~~2020 (in millions):

Projects 2019
Permian Basin Takeaway Pipeline Projects $ 500
Complementary Permian Basin Projects 485
Other Long-Haul Pipeline Projects 100
Selected Facilities 100
Other Projects 165
Total Projected 2019 Expansion Capital Expenditures ⁽¹⁾
$ 1,350


⁽¹⁾Projects	~~Amounts reflect our expectation that certain projects will be owned in a joint venture structure with a proportionate share of the project cost dispersed among the partners.~~	2020
Long-haul Pipeline Projects		$	220
Permian Basin Takeaway Pipeline Projects		355
Complementary Permian Basin Projects		225
Selected Facilities/Downstream Projects		160
Other Projects		140
Total Projected 2020 Expansion Capital Expenditures		$	1,100

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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						Three Months Ended March 31,						Variance
	2019			2018			$			%		2019			2018			$			%			2020		2019		$		%
Transportation Segment Adjusted EBITDA ⁽¹⁾	$	462		$	388		$	74		19	%	$	1,271		$	1,083		$	188		17	%	Transportation Segment Adjusted EBITDA ⁽¹⁾	$	442	$	399	$	43	11	%
Facilities Segment Adjusted EBITDA ⁽¹⁾	173			173			—			—	%	529			530			(1		)	—	%	Facilities Segment Adjusted EBITDA ⁽¹⁾	210		184		26		14	%
Supply and Logistics Segment Adjusted EBITDA ⁽¹⁾	92			75			17			23	%	571			120			451			376	%	Supply and Logistics Segment Adjusted EBITDA ⁽¹⁾	141		278		(137)		(49)	%
Adjustments:																							Adjustments:
Depreciation and amortization of unconsolidated entities	(18		)	(15		)	(3		)	(20	)%	(45		)	(44		)	(1		)	(2	)%	Depreciation and amortization of unconsolidated entities	(17)		(12)		(5)		(42)	%
Selected items impacting comparability - Segment Adjusted EBITDA	34			113			(79		)	**		37			(140		)	177			**		Selected items impacting comparability - Segment Adjusted EBITDA	(137)		94		(231)		**
Depreciation and amortization	(156		)	(129		)	(27		)	(21	)%	(439		)	(385		)	(54		)	(14	)%	Depreciation and amortization	(168)		(136)		(32)		(24)	%
Gains/(losses) on asset sales and asset impairments, net	7			(2		)	9			450	%	7			79			(72		)	(91	)%	Gains/(losses) on asset sales and asset impairments, net	(619)		(4)		(615)		**
Gain on investment in unconsolidated entities	4			210			(206		)	(98	)%	271			210			61			29	%
Goodwill impairment losses																							Goodwill impairment losses	(2,515)		—		(2,515)		N/A
Gain on/(impairment of) investments in unconsolidated entities, net																							Gain on/(impairment of) investments in unconsolidated entities, net	(22)		267		(289)		(108)	%
Interest expense, net	(108		)	(110		)	2			2	%	(311		)	(327		)	16			5	%	Interest expense, net	(108)		(101)		(7)		(7)	%
Other income/(expense), net	5			(3		)	8			**		23			8			15			**		Other income/(expense), net	(31)		25		(56)		**
Income tax (expense)/benefit	(41		)	10			(51		)	**		(42		)	(35		)	(7		)	(20	)%
Net income	454			710			(256		)	(36	)%	1,872			1,099			773			70	%
Income tax expense																							Income tax expense	(21)		(24)		3		13	%
Net income/(loss)																							Net income/(loss)	(2,845)		970		(3,815)		(393)	%
Net income attributable to noncontrolling interests	(5		)	—			(5		)	N/A		(7		)	—			(7		)	N/A		Net income attributable to noncontrolling interests	(2)		—		(2)		N/A
Net income attributable to PAA	$	449		$	710		$	(261	)	(37	)%	$	1,865		$	1,099		$	766		70	%
Net income/(loss) attributable to PAA																							Net income/(loss) attributable to PAA	$	(2,847)	$	970	$	(3,817)	(394)	%

Basic net income per common unit	$	0.55		$	0.91		$	(0.36	)	**		$	2.35		$	1.30		$	1.05		**
Diluted net income per common unit	$	0.55		$	0.87		$	(0.32	)	**		$	2.28		$	1.30		$	0.98		**
Basic net income/(loss) per common unit																							Basic net income/(loss) per common unit	$	(3.98)	$	1.26	$	(5.24)	**
Diluted net income/(loss) per common unit																							Diluted net income/(loss) per common unit	$	(3.98)	$	1.20	$	(5.18)	**
Basic weighted average common units outstanding	728			726			2			**		727			726			1			**		Basic weighted average common units outstanding	728		727		1		**
Diluted weighted average common units outstanding	800			799			1			**		800			728			72			**		Diluted weighted average common units outstanding	728		800		(72)		**


^ ^Indicates that variance as a percentage is not meaningful.	~~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 14~~ ~~to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.~~

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⁽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.

Non-GAAP Financial Measures

To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future. The primary additional measures used by management are earnings before interest, taxes, depreciation and amortization (including our proportionate share of depreciation and amortization of ~~and gains and losses on significant asset sales by,~~ 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”) and implied distributable cash flow (“DCF”).

Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance and results of operations because these measures, when used to supplement related GAAP financial measures, (i) 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), ~~the mark-to-market related to our Preferred Distribution Rate Reset Option,~~ 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, expansion projects and numerous other factors as discussed, as applicable, in “Analysis of Operating Segments.”

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,~~Income/(Loss), the most directly comparable measure as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our Condensed Consolidated Financial Statements and ~~footnotes.~~accompanying notes.

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The following table sets forth the reconciliation of these non-GAAP financial performance measures from Net ~~income~~Income/(Loss) (in millions):


	Three Months Ended March 31,						Variance
	2020		2019		$		%
Net income/(loss)	$	(2,845)	$	970	$	(3,815)	(393)	%
Add/(Subtract):
Interest expense, net	108		101		7		7	%
Income tax expense	21		24		(3)		(13)	%
Depreciation and amortization	168		136		32		24	%
(Gains)/losses on asset sales and asset impairments, net	619		4		615		**
Goodwill impairment losses	2,515		—		2,515		N/A
(Gain on)/impairment of investments in unconsolidated entities, net	22		(267)		289		108	%
Depreciation and amortization of unconsolidated entities ⁽¹⁾	17		12		5		42	%
Selected Items Impacting Comparability:
(Gains)/losses from derivative activities, net of inventory valuation adjustments ⁽²⁾	30		(74)		104		**
Long-term inventory costing adjustments ⁽³⁾	115		(21)		136		**
Deficiencies under minimum volume commitments, net ⁽⁴⁾	(2)		(7)		5		**
Equity-indexed compensation expense ⁽⁵⁾	4		3		1		**
Net (gain)/loss on foreign currency revaluation ⁽⁶⁾	(13)		5		(18)		**

Significant acquisition-related expenses ⁽⁷⁾	3		—		3		**
Selected Items Impacting Comparability - Segment Adjusted EBITDA	137		(94)		231		**
Gains from derivative activities⁽²⁾	(26)		(23)		(3)		**
Net (gain)/loss on foreign currency revaluation ⁽⁶⁾	59		(1)		60		**
Selected Items Impacting Comparability - Adjusted EBITDA ⁽⁸⁾	170		(118)		288		**
Adjusted EBITDA⁽⁸⁾	$	795	$	862	$	(67)	(8)	%
Interest expense, net of certain non-cash items⁽⁹⁾	(103)		(97)		(6)		(6)	%
Maintenance capital ⁽¹⁰⁾	(51)		(46)		(5)		(11)	%
Current income tax expense	(6)		(30)		24		80	%
Distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings ⁽¹¹⁾	(2)		2		(4)		**

Implied DCF	$	633	$	691	$	(58)	(8)	%
Preferred unit distributions ⁽¹²⁾	(37)		(37)		—		—	%
Implied DCF Available to Common Unitholders	$	596	$	654	$	(58)	(9)	%
Common unit cash distributions ⁽¹³⁾	(262)		(218)
Implied DCF Excess ⁽¹⁴⁾	$	334	$	436

Three Months Ended
September 30, Variance Nine Months Ended
September 30, Variance
2019 2018 $ % 2019 2018 $ %
Net income $ 454
$ 710
$ (256 ) (36 )% $ 1,872
$ 1,099
$ 773
70 %
Add/(Subtract):

Interest expense, net 108
110
(2 ) (2 )% 311
327
(16 ) (5 )%
Income tax expense/(benefit) 41
(10 ) 51
**
42
35
7
20 %
Depreciation and amortization 156
129
27
21 % 439
385
54
14 %
(Gains)/losses on asset sales and asset impairments, net (7 ) 2
(9 ) (450 )% (7 ) (79 ) 72
91 %
Gain on investment in unconsolidated entities (4 ) (210 ) 206
98 % (271 ) (210 ) (61 ) (29 )%
Depreciation and amortization of unconsolidated entities ⁽¹⁾
18
15
3
20 % 45
44
1
2 %
Selected Items Impacting Comparability:

(Gains)/losses from derivative activities, net of inventory valuation adjustments ⁽²⁾
(29 ) (110 ) 81
**
(60 ) 107
(167 ) **
Long-term inventory costing adjustments ⁽³⁾
(1 ) (10 ) 9
**
3
(18 ) 21
**
Deficiencies under minimum volume commitments, net ⁽⁴⁾
(4 ) (4 ) —
**
(10 ) 9
(19 ) **
Equity-indexed compensation expense ⁽⁵⁾
5
14
(9 ) **
13
37
(24 ) **
Net (gain)/loss on foreign currency revaluation ⁽⁶⁾
(5 ) (3 ) (2 ) **
7
5
2
**
Line 901 incident ⁽⁷⁾
—
—
—
**
10
—
10
**
Selected Items Impacting Comparability - Segment Adjusted EBITDA (34 ) (113 ) 79
**
(37 ) 140
(177 ) **
(Gains)/losses from derivative activities⁽²⁾
(1 ) 2
(3 ) **
(16 ) (3 ) (13 ) **
Net (gain)/loss on foreign currency revaluation ⁽⁶⁾
—
1
(1 ) **
(1 ) (3 ) 2
**
Selected Items Impacting Comparability - Adjusted EBITDA ⁽⁸⁾
(35 ) (110 ) 75
**
(54 ) 134
(188 ) **
Adjusted EBITDA⁽⁸⁾
$ 731
$ 636
$ 95
15 % $ 2,377
$ 1,735
$ 642
37 %

~~Table of Contents~~

Three Months Ended
September 30, Variance Nine Months Ended
September 30, Variance
2019 2018 $ % 2019 2018 $ %
Interest expense, net of certain non-cash items⁽⁹⁾
(104 ) (106 ) 2
2 % (298 ) (318 ) 20
6 %
Maintenance capital ⁽¹⁰⁾
(85 ) (78 ) (7 ) (9 )% (204 ) (186 ) (18 ) (10 )%
Current income tax expense (19 ) (14 ) (5 ) (36 )% (72 ) (34 ) (38 ) (112 )%
Adjusted equity earnings in unconsolidated entities, net of distributions ⁽¹¹⁾
(13 ) (5 ) (8 ) **
(12 ) 9
(21 ) **
Distributions to noncontrolling interests ⁽¹²⁾
(4 ) —
(4 ) N/A
(4 ) —
(4 ) N/A
Implied DCF $ 506
$ 433
$ 73
17 % $ 1,787
$ 1,206
$ 581
48 %
Preferred unit distributions ⁽¹³⁾
(37 ) (37 ) —
— % (137 ) (99 ) (38 ) (38 )%
Implied DCF Available to Common Unitholders $ 469
$ 396
$ 73
18 % $ 1,650
$ 1,107
$ 543
49 %
Common unit cash distributions ⁽¹²⁾
(262 ) (218 ) (741 ) (653 )
Implied DCF Excess/(Shortage) ⁽¹⁴⁾
$ 207
$ 178
$ 909
$ 454

^**

^**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.

~~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, and gains and losses on significant asset sales by, 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, as well as the mark-to-market adjustment related to our Preferred Distribution Rate Reset Option. See ~~Note 10~~ ~~to our Condensed Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities and our Preferred Distribution Rate Reset Option.~~

⁽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 writedowns 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 2018 Annual Report on Form 10-K for additional inventory disclosures.

⁽⁴⁾

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⁽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 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⁾

⁽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 non-cash gains and losses that were not related to our core operating results for the period and were thus classified as a selected item impacting comparability. See Note 10to our Condensed Consolidated Financial Statements for discussion regarding our currency exchange rate risk hedging activities.

⁽⁷⁾Includes acquisition-related expenses associated with the Felix Midstream acquisition in February 2020. See Note 14 for additional information.

⁽⁸⁾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.

⁽⁹⁾Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.

⁽¹⁰⁾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.

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⁽¹¹⁾Comprised of cash distributions received from unconsolidated entities less equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization).

⁽¹²⁾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, which were issued in October 2017, 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.

⁽¹³⁾Cash distributions paid during the period presented.

⁽¹⁴⁾Excess DCF is retained to establish reserves for future distributions, capital expenditures and other partnership purposes.

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 17 to our Consolidated Financial Statements included in Part IV of our 2018 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 non-cash gains and losses that were not related to our core operating results for the period and were thus classified as a selected item impacting comparability. See ~~Note 10to 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 13~~ ~~to our Condensed Consolidated Financial Statements for additional information regarding the Line 901 incident.~~


⁽⁸⁾	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.


⁽⁹⁾	~~Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.~~


⁽¹⁰⁾	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.


⁽¹¹⁾	Comprised of cash distributions received from unconsolidated entities less equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization and gains and losses on significant asset sales).


⁽¹²⁾	~~Cash distributions paid during the period presented.~~

⁽¹³⁾

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, which were issued in October 2017, is payable semi-annually in arrears on May 15 and November 15. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2018 Annual Report on Form 10-K for additional information regarding our preferred units.


⁽¹⁴⁾	Excess DCF is retained to establish reserves for future distributions, capital expenditures and other partnership purposes. DCF shortages may be funded from previously established reserves, cash on hand or from borrowings under our credit facilities or commercial paper program.

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 ~~and gains and losses on significant asset sales by,~~ 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

~~Table of Contents~~

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 1413 to our Condensed Consolidated Financial Statements for a reconciliation of Segment Adjusted EBITDA to Net ~~income~~income/(loss) attributable to PAA.

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 ~~trucks~~ and ~~barges.~~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.

Table of Contents

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) 2019 2018 $ % 2019 2018 $ %
Revenues $ 597
$ 498
$ 99
20 % $ 1,712
$ 1,427
$ 285
20 %
Purchases and related costs (55 ) (49 ) (6 ) (12 )% (155 ) (141 ) (14 ) (10 )%
Field operating costs (172 ) (164 ) (8 ) (5 )% (532 ) (469 ) (63 ) (13 )%
Segment general and administrative expenses ⁽²⁾
(26 ) (28 ) 2
7 % (80 ) (86 ) 6
7 %
Equity earnings in unconsolidated entities 102
110
(8 ) (7 )% 274
281
(7 ) (2 )%

Adjustments⁽³⁾:

Depreciation and amortization of unconsolidated entities 18
15
3
20 % 45
44
1
2 %
(Gains)/losses from derivative activities (1 ) —
(1 ) **
1
(1 ) 2
**
Deficiencies under minimum volume commitments, net (4 ) (1 ) (3 ) **
(10 ) 8
(18 ) **
Equity-indexed compensation expense 3
7
(4 ) **
6
20
(14 ) **
Line 901 incident —
—
—
**
10
—
10
**
Segment Adjusted EBITDA $ 462
$ 388
$ 74
19 % $ 1,271
$ 1,083
$ 188
17 %
Maintenance capital $ 42
$ 41
$ 1
2 % $ 110
$ 102
$ 8
8 %
Segment Adjusted EBITDA per barrel $ 0.71
$ 0.70
$ 0.01
1 % $ 0.69
$ 0.69
$ —
— %


Operating Results ⁽¹⁾	Three Months Ended March 31,						Variance
(in millions, except per barrel data)	2020		2019		$		%
Revenues	$	579	$	556	$	23	4	%
Purchases and related costs	(79)		(52)		(27)		(52)	%
Field operating costs	(162)		(174)		12		7	%
Segment general and administrative expenses ⁽²⁾	(28)		(27)		(1)		(4)	%
Equity earnings in unconsolidated entities	108		89		19		21	%

Adjustments⁽³⁾:
Depreciation and amortization of unconsolidated entities	17		12		5		42	%
Inventory valuation adjustments	6		—		6		**
Deficiencies under minimum volume commitments, net	(4)		(7)		3		**
Equity-indexed compensation expense	2		2		—		**

Significant acquisition-related expenses	3		—		3		**
Segment Adjusted EBITDA	$	442	$	399	$	43	11	%
Maintenance capital	$	34	$	27	$	7	26	%
Segment Adjusted EBITDA per barrel	$	0.67	$	0.68	$	(0.01)	(1)	%

~~Table of Contents~~


Average Daily Volumes	Three Months Ended March 31,			Variance
(in thousands of barrels per day) ⁽⁴⁾	2020	2019	Volumes	%
Tariff activities volumes
Crude oil pipelines (by region):
Permian Basin ⁽⁵⁾	5,165	4,268	897	21	%
South Texas / Eagle Ford ⁽⁵⁾	458	460	(2)	—	%
Central ⁽⁵⁾	404	509	(105)	(21)	%
Gulf Coast	144	158	(14)	(9)	%
Rocky Mountain⁽⁵⁾	273	302	(29)	(10)	%
Western	203	182	21	12	%
Canada	327	322	5	2	%
Crude oil pipelines	6,974	6,201	773	12	%
NGL pipelines	187	210	(23)	(11)	%
Tariff activities total volumes	7,161	6,411	750	12	%
Trucking volumes	94	93	1	1	%
Transportation segment total volumes	7,255	6,504	751	12	%

Average Daily Volumes Three Months Ended
September 30, Variance Nine Months Ended
September 30, Variance
(in thousands of barrels per day) ⁽⁴⁾
2019 2018 Volumes % 2019 2018 Volumes %
Tariff activities volumes

Crude oil pipelines (by region):

Permian Basin ⁽⁵⁾
4,852
3,880
972
25 % 4,568
3,621
947
26 %
South Texas / Eagle Ford ⁽⁵⁾
429
451
(22 ) (5 )% 445
436
9
2 %
Central ⁽⁵⁾
538
480
58
12 % 524
456
68
15 %
Gulf Coast 176
171
5
3 % 160
182
(22 ) (12 )%
Rocky Mountain⁽⁵⁾
284
258
26
10 % 300
261
39
15 %
Western 212
184
28
15 % 196
180
16
9 %
Canada 316
322
(6 ) (2 )% 319
312
7
2 %
Crude oil pipelines 6,807
5,746
1,061
18 % 6,512
5,448
1,064
20 %
NGL pipelines 193
174
19
11 % 195
173
22
13 %
Tariff activities total volumes 7,000
5,920
1,080
18 % 6,707
5,621
1,086
19 %
Trucking volumes 81
95
(14 ) (15 )% 86
95
(9 ) (9 )%
Transportation segment total volumes 7,081
6,015
1,066
18 % 6,793
5,716
1,077
19 %

^**

^**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.

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⁽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.

~~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 14~~ ~~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.

~~Table of Contents~~

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 for~~region:


	Favorable/(Unfavorable) Variance Three Months Ended March 31, 2020-2019
(in millions)	Revenues		Purchases and Related Costs		Equity Earnings
Permian Basin region	$	45	$	(28)	$	31

Central region	(12)		(1)		(4)




Other regions, trucking and pipeline loss allowance revenue	(10)		2		(8)
Total variance	$	23	$	(27)	$	19

•Permian Basin region. The increase in revenues, net of purchases and related costs, of $17 million was primarily due to higher volumes on certain of our gathering systems, primarily due to increased crude oil production in the Delaware Basin and, to a lesser extent, from the gathering system we acquired from Felix Midstream in February 2020. In turn, the increased gathering volumes drove the increase in volumes on our intra-basin pipelines. These increases were partially offset by lower long-haul pipeline movements to Cushing.

The increase in equity earnings over the comparative ~~periods presented:~~

Favorable/(Unfavorable) Variance
Three Months Ended September 30,
2019-2018 Favorable/(Unfavorable) Variance
Nine Months Ended September 30,
2019-2018
(in millions) Revenues Purchases and
Related Costs Equity
Earnings Revenues Purchases and
Related Costs Equity
Earnings
Permian Basin region $ 71
$ (7 ) $ (11 ) $ 192
$ (11 ) $ (40 )
South Texas / Eagle Ford region (1 ) —
3
(2 ) —
27
Central region 10
(1 ) 1
32
(1 ) 8
Gulf Coast region —
—
(4 ) 1
—
(14 )
Rocky Mountain region 1
—
2
(5 ) —
11
Canada region 6
—
—
19
—
—
Other regions, trucking and pipeline loss allowance revenue 12
2
1
48
(2 ) 1
Total variance $ 99
$ (6 ) $ (8 ) $ 285
$ (14 ) $ (7 )

•

~~Permian Basin region.~~ The increase in revenues, net of purchases and related costs, of approximately $64 million and $181 million for the three and nine months ended September 30, 2019, respectively, compared to the three and nine months ended September 30, 2018 was primarily due to higher volumes from increased production and our recently completed capital expansion projects. These increases for the three and nine-month comparative periods included (i) higher volumes on our gathering systems of approximately 328,000 and 303,000 barrels per day, respectively, (ii) higher volumes of approximately 291,000 and 396,000 barrels per day, respectively, on our intra-basin pipelines and (iii) a volume increase of approximately 353,000 and 248,000, respectively, on our long-haul pipelines, including our Sunriseperiod was primarily from our 65% interest in the Cactus II pipeline, which was placed in ~~service in the fourth quarter of 2018, and the Cactus II Pipeline, which was placed into service in the third quarter of 2019, as discussed below.~~

The decrease in equity earnings for the three and nine months ended September 30, 2019 compared to the three and nine months ended September 30, 2018 was primarily due to the sale of a 30% interest in BridgeTex Pipeline Company, LLC at the end of the third quarter of 2018, partially offset by equity earnings from our 65% interest in Cactus II Pipeline, which was placed into service in the third quarter of 2019.


•	~~South Texas / Eagle Ford region.~~ The increase in equity earnings for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 was from our 50% interest in Eagle Ford Pipeline LLC and was primarily due to higher volumes and the recognition of revenue associated with deficiencies under minimum volume commitments.


•	~~Central region.~~ The increase in revenues for the three and nine months ended September 30, 2019 compared to the three and nine months ended September 30, 2018 was primarily due to higher volumes on certain of our pipelines in the Central region, including our Red River pipeline, and the recognition of previously deferred revenue in 2019.


•	~~Gulf Coast region.~~ The decrease in volumes in the Gulf Coast region for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 were associated with (i) the Capline pipeline being taken out of service in the fourth quarter of 2018 and (ii) a lower tariff pipeline, which did not result in a significant impact on revenue.

~~Table~~•Central region. The decrease in revenues, net of ~~Contents~~

~~In the first quarter~~purchases and related costs, was primarily due to lower volumes as a result of ~~2019, the owners of the Capline pipeline system contributed their undivided joint interests~~lower production and competition in the system for equity interests in a legal entity. As a result, revenues and expenses from the Capline pipeline system that were previously consolidated are reflected as equity earnings. The unfavorable equity earnings variance for the three and nine months ended September 30, 2019 compared to the three and nine months ended September 30, 2018 was due to our share of operating costs from our 54.13% interest in Capline Pipeline Company LLC reflected in equity earnings in the 2019 periods, whereas such costs were reflected in field operating costs in the 2018 periods.

region.

~~In the third quarter of 2019, the owners of Capline Pipeline Company LLC sanctioned the reversal of the Capline pipeline system and a connection to Diamond Pipeline.~~

•

~~Rocky Mountain region.~~ The favorable volume and equity earnings variances for the three and nine months ended September 30, 2019 compared to the three and nine months ended September 30, 2018 were primarily driven by favorable results from our 40% interest in Saddlehorn Pipeline Company, LLC due to higher volumes from committed shippers, partially offset by a decrease from our 35.7% interest in White Cliffs Pipeline, LLC due to lower volumes as one crude oil line was taken out of service in May 2019 for conversion to NGL service.

The decrease in ~~revenues for the nine-month comparative period~~equity earnings was primarily due to the ~~sale~~impact of refinery downtime on certain of ~~our assets~~the demand pull pipelines out of Cushing, Oklahoma, in ~~the Rocky Mountain region in May of 2018.~~which we own a 50% interest.


•	~~Canada region.~~ The increase in revenues for the three and nine months ended September 30, 2019 compared to the three and nine months ended September 30, 2018 was primarily due to higher tariffs on certain of our Canadian crude oil pipelines and related system assets, partially offset by unfavorable foreign exchange impacts.

•

~~Other regions, trucking and pipeline loss allowance revenue.~~ ~~The increase~~•Other regions, trucking and pipeline loss allowance revenue. The decrease in other revenues for the three and nine months ended September 30, 2019 compared to the three and nine months ended September 30, 2018 was primarily due to greater loss allowance revenue in the 2019 periods driven by higher volumes and, to a lesser extent, higher prices.

~~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, 2019 and~~ the three months ended ~~September 30, 2018,~~March 31, 2020 compared to the three months ended March 31, 2019 was primarily due to lower pipeline loss allowance revenue in 2020 due to lower prices, as well as the recognition of ~~previously deferred revenue exceeded amounts billed to counterparties associated with deficiencies under minimum volume commitments. For~~an inventory valuation adjustment (which impacts revenues but is excluded from Segment Adjusted EBITDA and thus is reflected as an “Adjustment” in the ~~nine months ended September 30, 2018, amounts billed to counterparties exceeded revenue recognized during the period that was previously deferred.~~“Operating Results” table above).

Field Operating Costs. The ~~increase~~decrease in field operating costs for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 compared to the ~~three and nine months ended September 30, 2018~~same period in 2019 was primarily due to a decrease in the ~~continued expansion~~use of drag reducing agents in our ~~transportation segment operations including costs associated with personnel, power related costs~~pipelines and ~~property taxes. The expansion activities included projects placed~~a decreased reliance on generators as additional pipeline capacity was in service induring the ~~fourth~~first quarter of ~~2018, including our Sunrise II pipeline expansion within the Permian Basin region. For the nine-month comparative period, field operating~~2020. In addition, equity-based compensation costs ~~were also impacted by an increase of estimated costs recognized associated with the Line 901 incident~~on liability-classified awards (which ~~impact our field operating costs but~~ are ~~excluded from Segment Adjusted EBITDA and thus are reflected~~not included as an “Adjustment” in the table above) ~~(see~~ ~~Note 13~~were lower due to a decrease in our Condensed Consolidated Financial Statements for additional information regarding the Line 901 incident). The increase in field operating costs for the three and nine months ended September 30, 2019 compared to the three and nine months ended September 30, 2018 was partially offset by the favorable impact of reflecting operating costs associated with the Capline pipeline system in equity earnings for the 2019 periods that were included in field operating costs for the 2018 periods, as discussed above.common unit price.

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Segment ~~general~~General and ~~administrative expenses.~~Administrative Expenses. The ~~decrease~~increase in segment general and administrative expenses for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 compared to the ~~three and nine months ended September 30, 2018~~same period in 2019 was primarily due to ~~a decrease in equity-indexed compensation expense due to fewer awards outstanding in 2019. A portion of equity-indexed compensation expense was~~acquisition-related expenses associated with ~~awards that will or may be settled in common units~~the Felix Midstream acquisition (which impact ~~our~~ segment general and administrative expenses but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above)., partially offset by a 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.

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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 increase in maintenance capital for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 compared to the same ~~periods~~period in ~~2018~~2019 was primarily due to the timing of projects in our integrity management program.

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 and processing arrangements.~~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					Operating Results ⁽¹⁾	Three Months Ended March 31,						Variance
(in millions, except per barrel data)	2019			2018			$			%		2019			2018			$			%		(in millions, except per barrel data)	2020		2019		$		%
Revenues	$	291		$	289		$	2		1	%	$	880		$	866		$	14		2	%	Revenues	$	313	$	299	$	14	5	%
Purchases and related costs	(3		)	(3		)	—			—	%	(10		)	(12		)	2			17	%	Purchases and related costs	(2)		(4)		2		50	%
Field operating costs	(92		)	(95		)	3			3	%	(267		)	(271		)	4			1	%	Field operating costs	(88)		(86)		(2)		(2)	%
Segment general and administrative expenses ⁽²⁾	(21		)	(18		)	(3		)	(17	)%	(62		)	(59		)	(3		)	(5	)%	Segment general and administrative expenses ⁽²⁾	(19)		(21)		2		10	%
Equity earnings in unconsolidated entities																							Equity earnings in unconsolidated entities	2		—		2		N/A

Adjustments⁽³⁾:																							Adjustments⁽³⁾:
Gains from derivative activities	(3		)	—			(3		)	**		(15		)	(2		)	(13		)	**

(Gains)/losses from derivative activities																							(Gains)/losses from derivative activities	1		(4)		5		**
Deficiencies under minimum volume commitments, net	—			(3		)	3			**		—			1			(1		)	**		Deficiencies under minimum volume commitments, net	2		—		2		**

Equity-indexed compensation expense	1			3			(2		)	**		3			7			(4		)	**		Equity-indexed compensation expense	1		—		1		**
Segment Adjusted EBITDA	$	173		$	173		$	—		—	%	$	529		$	530		$	(1	)	—	%	Segment Adjusted EBITDA	$	210	$	184	$	26	14	%
Maintenance capital	$	28		$	33		$	(5	)	(15	)%	$	74		$	74		$	—		—	%	Maintenance capital	$	14	$	17	$	(3)	(18)	%
Segment Adjusted EBITDA per barrel	$	0.46		$	0.47		$	(0.01	)	(2	)%	$	0.47		$	0.48		$	(0.01	)	(2	)%	Segment Adjusted EBITDA per barrel	$	0.55	$	0.49	$	0.06	12	%


	Three Months Ended September 30,		Variance				Nine Months Ended September 30,		Variance					Three Months Ended March 31,			Variance
Volumes⁽⁴⁾	2019	2018	Volumes		%		2019	2018	Volumes		%		Volumes⁽⁴⁾	2020	2019	Volumes	%
Liquids storage (average monthly capacity in millions of barrels) ⁽⁵⁾	110	109	1		1	%	109	109	—		—	%	Liquids storage (average monthly capacity in millions of barrels) ⁽⁵⁾	111	109	2	2	%
Natural gas storage (average monthly working capacity in billions of cubic feet) ⁽⁶⁾	63	65	(2	)	(3	)%	63	66	(3	)	(5	)%
Natural gas storage (average monthly working capacity in billions of cubic feet)													Natural gas storage (average monthly working capacity in billions of cubic feet)	63	63	—	—	%
NGL fractionation (average volumes in thousands of barrels per day)	140	115	25		22	%	145	128	17		13	%	NGL fractionation (average volumes in thousands of barrels per day)	154	157	(3)	(2)	%
Facilities segment total volumes (average monthly volumes in millions of barrels) ⁽⁷⁾	125	123	2		2	%	124	124	—		—	%
Facilities segment total volumes (average monthly volumes in millions of barrels) ⁽⁶⁾													Facilities segment total volumes (average monthly volumes in millions of barrels) ⁽⁶⁾	127	124	3	2	%

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^**

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

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

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

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⁽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.

~~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 14~~ ~~to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.~~


⁽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⁾	The decrease in average monthly working capacity of natural gas storage facilities was driven by adjustments for the net capacity change between capacity additions from fill and dewater operations and capacity losses from salt creep.

⁽⁷⁾

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 for the periods indicated.~~results.

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

•NGL Operations. Revenues ~~net of purchases and related costs,~~from our NGL operations were ~~relatively flat~~favorably impacted for the ~~three-month comparative period. The following summarizes~~three months ended March 31, 2020 compared to the ~~significant drivers~~three months ended March 31, 2019 by the receipt of ~~variances in~~a deficiency payment of approximately $20 million upon the expiration of a multi-year contract and from higher fees at certain of our NGL storage facilities. Such favorable impacts were partially offset by lower revenues ~~purchases and related costs and volumes~~from certain of our NGL fractionation facilities.

•Crude Oil Storage. Revenues from our crude oil storage operations increased by $6 million for the ~~nine-month comparative period:~~ three months ended March 31, 2020 compared to three months ended March 31, 2019 primarily due to (i) the addition of an aggregate of 1.8 million barrels of storage capacity at our Midland, Cushing and St. James terminals and (ii) increased activity at certain of our West Coast terminals.

•

~~Crude Oil Storage.~~ ~~Revenues increased by $12 million for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 due to increased~~

•Rail Terminals. Revenues from our rail terminals decreased by $5 million for the three months ended March 31, 2020 compared to three months ended March 31, 2019 primarily due to decreased activity at certain of our terminals, primarily our Cushing terminal, and the addition of 1.0 million barrels of storage capacity at our Midland terminal placed into service in the fourth quarter of 2018 and the first quarter of 2019.

•

~~Rail Terminals.~~ Revenues increased by $9 million for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. Revenues were favorably impacted by increased activity at certain of our terminals and agreements that were entered into related to usage of our railcars. These favorable impacts were partially offset by the recognition of previously deferred revenue associated with deficiencies under minimum volume commitments in the 2018 period.


•	~~Natural Gas Storage.~~ Revenues, net of purchases and related costs, increased by $8 million for the nine months ended September 30, 2019, respectively, compared to the nine months ended September 30, 2018, primarily due to expiring contracts replaced by contracts with higher rates and increased hub activity.


•	~~NGL Operations.~~ Revenues decreased by $13 million for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 primarily due to a net unfavorable foreign exchange impact of $11 million and the sale of a natural gas processing facility in the second quarter of 2018, partially offset by higher fees at certain of our facilities.

~~Field Operating Costs.~~ The decrease in field operating costs for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 was primarily due to a decrease in power related costs associated with derivative activities (which impact our field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above), partially offset by higher costs at our rail terminals as a result of ~~increased activity.~~less favorable market conditions.

~~Segment General and Administrative Expenses.~~ The increase in segment general and administrative expenses for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 was primarily due to various higher costs, including personnel costs.

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Maintenance Capital. For the three months ended ~~September 30, 2019 as~~March 31, 2020 compared to the ~~three months ended September 30, 2018,~~same period in 2019, maintenance capital spending decreased primarily due to the impact of lower ~~turnaround costs~~expenditures related to cavern maintenance at ~~certain of~~ our ~~NGL~~gas storage facilities.

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.

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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					Operating Results ⁽¹⁾	Three Months Ended March 31,						Variance
(in millions, except per barrel data)	2019			2018			$			%		2019			2018			$			%		(in millions, except per barrel data)	2020		2019		$		%
Revenues	$	7,542		$	8,483		$	(941	)	(11	)%	$	23,480		$	24,376		$	(896	)	(4	)%	Revenues	$	7,908	$	8,022	$	(114)	(1)	%
Purchases and related costs	(7,337		)	(8,191		)	854			10	%	(22,599		)	(24,076		)	1,477			6	%	Purchases and related costs	(7,813)		(7,562)		(251)		(3)	%
Field operating costs	(56		)	(70		)	14			20	%	(195		)	(200		)	5			3	%	Field operating costs	(58)		(69)		11		16	%
Segment general and administrative expenses ⁽²⁾	(27		)	(28		)	1			4	%	(83		)	(87		)	4			5	%	Segment general and administrative expenses ⁽²⁾	(22)		(28)		6		21	%

Adjustments ⁽³⁾:																							Adjustments ⁽³⁾:
(Gains)/losses from derivative activities, net of inventory valuation adjustments	(25		)	(110		)	85			**		(46		)	110			(156		)	**		(Gains)/losses from derivative activities, net of inventory valuation adjustments	23		(70)		93		**
Long-term inventory costing adjustments	(1		)	(10		)	9			**		3			(18		)	21			**		Long-term inventory costing adjustments	115		(21)		136		**
Equity-indexed compensation expense	1			4			(3		)	**		4			10			(6		)	**		Equity-indexed compensation expense	1		1		—		**
Net (gain)/loss on foreign currency revaluation	(5		)	(3		)	(2		)	**		7			5			2			**		Net (gain)/loss on foreign currency revaluation	(13)		5		(18)		**
Segment Adjusted EBITDA	$	92		$	75		$	17		23	%	$	571		$	120		$	451		376	%	Segment Adjusted EBITDA	$	141	$	278	$	(137)	(49)	%
Maintenance capital	$	15		$	4		$	11		275	%	$	20		$	10		$	10		100	%	Maintenance capital	$	3	$	2	$	1	50	%
Segment Adjusted EBITDA per barrel	$	0.79		$	0.66		$	0.13		20	%	$	1.57		$	0.35		$	1.22		349	%	Segment Adjusted EBITDA per barrel	$	1.00	$	2.12	$	(1.12)	(53)	%


Average Daily Volumes ⁽⁴⁾	Three Months Ended September 30,		Variance				Nine Months Ended September 30,		Variance				Average Daily Volumes ⁽⁴⁾	Three Months Ended March 31,			Variance
(in thousands of barrels per day)	2019	2018	Volumes		%		2019	2018	Volumes		%		(in thousands of barrels per day)	2020	2019	Volumes	%
Crude oil lease gathering purchases	1,146	1,042	104		10	%	1,126	1,034	92		9	%	Crude oil lease gathering purchases	1,318	1,128	190	17	%
NGL sales	124	195	(71	)	(36	)%	202	243	(41	)	(17	)%	NGL sales	220	328	(108)	(33)	%
Supply and Logistics segment total volumes	1,270	1,237	33		3	%	1,328	1,277	51		4	%	Supply and Logistics segment total volumes	1,538	1,456	82	6	%


^Indicates that variance as a percentage is not meaningful. ⁽¹⁾Revenues and costs include intersegment amounts. ⁽²⁾^	~~Indicates that variance as a percentage is not meaningful.~~


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


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

~~Table~~ of ~~Contents~~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.

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


⁽³⁾	~~Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See~~ ~~Note 14~~ ~~to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.~~


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

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, 2019 $ 52
$ 62
Three months ended September 30, 2018 $ 65
$ 74

Nine months ended September 30, 2019 $ 46
$ 66
Nine months ended September 30, 2018 $ 59
$ 74


	NYMEX WTI Crude Oil Price
	Low		High



Three months ended March 31, 2020	$	14	$	63
Three months ended March 31, 2019	$	47	$	60

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.

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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 operating results~~Segment Adjusted EBITDA:

•Crude Oil Operations. Revenues, net of purchases and related costs, (“net revenues”) from our crude oil operations decreased for the ~~comparative periods:~~three months ended March 31, 2020 compared to the three months ended March 31, 2019, primarily due to less favorable differentials in the Permian Basin, partially offset by more favorable arbitrage opportunities in Canada.


•	~~Crude Oil Operations.~~ Net revenues from our crude oil supply and logistics operations increased for the three and nine months ended September 30, 2019 compared to the three and nine months ended September 30, 2018 largely due to the realization of more favorable differentials, primarily in the Permian Basin and, for the nine-month comparative period, more favorable differentials in Canada.


•	NGL Operations. Net revenues from our NGL operations decreased for the three months ended September 30, 2019 compared to the three months ended September 30, 2018 primarily due to decreased sales volumes and margins.

Net revenues from our NGL operations ~~increased~~decreased for the ~~nine~~three months ended September 30, 2019 compared to the nine months ended September 30, 2018 primarily due to the streamlining of our NGL activities by focusing on our equity supply from our gathering and processing facilities, favorable regional differentials and the favorable impact of certain non-recurring items recorded in the second quarter of 2019. These favorable impacts were partially offset by decreased sales volumes and margins in the third quarter of 2019 compared to the third quarter of 2018.

•

~~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, resulting in foreign exchange gains and losses on U.S. denominated net assets within our Canadian operations. 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, 2019 compared to the three and nine months ended September 30, 2018 was primarily driven by a decrease in vehicle expense related to the adoption of the new lease accounting standard and, for the three-month comparative period, a decrease in trucking costs due to a shift in volumes to pipelines. Trucking costs were higher for the nine-month comparative period due to higher third-party hauled volumes in certain regions during the first half of 2019.

~~Maintenance Capital.~~ ~~For the three and nine months ended September 30, 2019~~March 31, 2020 compared to the three ~~and nine~~ months ended ~~September 30, 2018, maintenance capital spending increased~~March 31, 2019, primarily due to ~~new tractor trailer leases.~~weaker fractionation spreads, narrower sales differentials and lower sales volumes.

•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 10to our Condensed Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities. These gains and losses impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.

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

•Foreign Exchange Impacts. Our net revenues are impacted by fluctuations in the value of CAD to USD, resulting in foreign exchange gains and losses on U.S. denominated net assets within our Canadian operations. 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 months ended March 31, 2020 compared to the same period 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 quarter of 2019.

•Segment General and Administrative Expenses. The decrease in segment general and administrative expenses for the three months ended March 31, 2020 compared to the same period in 2019 was primarily driven 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.

Other Income and Expenses

Depreciation and Amortization

Depreciation and amortization expense increased for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 compared to the three ~~and nine~~ months ended ~~September 30, 2018~~March 31, 2019 largely driven by (i) additional depreciation expense associated with the completion of various capital expansion projects and (ii) ~~an adjustment to~~a reduction in the useful lives of certain assets.

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Gains/Losses on Asset Sales and Asset Impairments, Net

The net ~~gain~~loss on asset sales and asset impairments for the ~~nine~~three months ended ~~September 30, 2018~~March 31, 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.

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 months ended March 31, 2020, we recognized a loss of $43 million related to the write-down of certain of our investments in unconsolidated entities. Additionally, during the three months ended March 31, 2020, we recognized a gain ~~on the sale~~ of ~~certain pipelines in the Rocky Mountain region, partially offset by a loss on the~~$21 million related to our sale of a ~~non-core asset under construction.~~

~~Gain on Investment~~10% interest in ~~Unconsolidated Entities~~

Saddlehorn Pipeline Company, LLC. See Note 7 to our Condensed Consolidated Financial Statements for additional information. During the ~~nine~~three months ended ~~September 30,~~March 31, 2019, we recognized a non-cash gain of ~~$269~~$267 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. ~~See~~ ~~Note 7~~ to our Condensed Consolidated Financial Statements for additional information. During the nine months ended September 30, 2018, we recognized a gain of $210 million related to our sale of a 30% interest in BridgeTex Pipeline Company, LLC.

Interest Expense

The ~~decrease~~increase in interest expense for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 compared to the three ~~and nine~~ months ended ~~September 30, 2018~~March 31, 2019 was primarily due to (i) lower capitalized interest in the 2020 period driven by fewer capital projects under construction and (ii) a ~~lower~~higher weighted average debt balance during the ~~2019 periods~~2020 period from ~~lower~~higher commercial paper and credit facility borrowings. ~~The nine-month comparative period was further favorably impacted by higher capitalized interest in the 2019 period due to additional projects under construction.~~

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Other Income/(Expense), Net

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


											Three Months Ended March 31,
	Three Months Ended September 30,					Nine Months Ended September 30,					2020		2019
	2019		2018			2019		2018
Gain/(loss) related to mark-to-market adjustment of our Preferred Distribution Rate Reset Option ⁽¹⁾	$	1	$	(2	)	$	16	$	3
Gain related to mark-to-market adjustment of our Preferred Distribution Rate Reset Option ⁽¹⁾										Gain related to mark-to-market adjustment of our Preferred Distribution Rate Reset Option ⁽¹⁾	$	26	$	23
Net gain/(loss) on foreign currency revaluation ⁽²⁾										Net gain/(loss) on foreign currency revaluation ⁽²⁾	(59)		1
Other	4		(1		)	7		5		Other	2		1
	$	5	$	(3	)	$	23	$	8		$	(31)	$	25


⁽¹⁾ ⁽¹⁾See Note 10 to our Condensed Consolidated Financial Statements for additional information. ⁽²⁾The net loss during the first quarter of 2020 was related to the impact that the change in in the U.S. dollar to Canadian dollar exchange rate had on the portion of our intercompany net investment that is not long-term in nature.	~~See~~ ~~Note 10~~ ~~to our Condensed Consolidated Financial Statements for additional information.~~

Income Tax Expense

~~For~~Income tax expense decreased for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 compared to the three ~~and nine~~ months ended ~~September 30, 2018, the increase in income tax expense was primarily~~March 31, 2019 due to ~~(i) higher deferred income tax expense as~~ a ~~result of higher year-over-year income as impacted by fluctuations~~net loss in the ~~derivative mark-to-market valuations~~first quarter of 2020 as compared to net income in ~~our Canadian operations~~the previous period.

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In response to the COVID-19 pandemic, many governments have enacted or are contemplating measures to provide aid and ~~(ii) higher current~~economic stimulus. These measures may include deferring the due dates of tax payments or other changes to their income and non-income-based tax ~~expense as a result of higher taxable earnings from our Canadian operations. These unfavorable~~laws. The Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), which was enacted on March 27, 2020 in the U.S., includes measures to assist companies, including temporary changes to income and non-income-based tax laws. There were no material tax impacts to ~~income tax expense~~our financial statements as it relates to COVID-19 measures. We continue to monitor additional guidance issued by the U.S. Treasury Department, the Internal Revenue Service and others.

Outlook

Market Overview and Outlook

See “—Executive Summary—Recent Events & Outlook.”

Outlook for Certain Investments in Unconsolidated Entities

As of March 31, 2020, we owned a 50% undivided joint interest in Red Oak Pipeline LLC (“Red Oak”), which was in the process of developing a new pipeline that would provide crude oil transportation service from Cushing, Oklahoma, and the Permian Basin in West Texas to multiple destinations along the Texas Gulf Coast, including Corpus Christi, Ingleside, Houston and Beaumont, Texas. In March 2020, the partners announced they were ~~partially offset~~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 ~~nine-month comparative period by~~project in light of recent market developments. If the ~~recognition~~partners decide not to move forward with the pipeline project, we may recognize an impairment of ~~a deferred tax benefit~~the carrying value of ~~$60~~our interest in Red Oak, which was $54 million as ~~a result~~ of ~~the reduction~~March 31, 2020 ($122 million including our estimate of ~~the provincial tax rate~~committed costs incurred in ~~Alberta, Canada enacted during~~ the second ~~quarter of 2019.~~quarter).

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~~.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) expansion and maintenance 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 expansion 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, 2019,~~March 31, 2020, although we had a working capital deficit of ~~$196~~$286 million, we had approximately ~~$3.5~~$2.5 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, 2019
Availability under senior unsecured revolving credit facility ^(1) (2)
$ 1,462
Availability under senior secured hedged inventory facility ^(1) (2)
1,389
Subtotal 2,851
Cash and cash equivalents 609
Total $ 3,460


⁽¹⁾			Represents availability prior to giving effect to borrowings outstanding under our commercial paper program, which reduce available capacity under the facilities. There were no commercial paper borrowings outstanding asAs of ~~September 30, 2019.~~

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March 31, 2020


⁽²⁾	~~Available capacity~~Availability under ~~our~~ senior unsecured revolving credit facility ~~and~~^(1) (2)	$	1,583
Availability under senior secured hedged inventory facility ~~was reduced by outstanding letters of credit of $138 million~~^(1) (2)	897

Subtotal	2,480
Cash and ~~$11 million, respectively.~~cash equivalents	38
Total	$	2,518

⁽¹⁾Represents availability prior to giving effect to borrowings outstanding under our commercial paper program, which reduce available capacity under the facilities. There were no commercial paper borrowings outstanding as of March 31, 2020.

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⁽²⁾Available capacity under our senior unsecured revolving credit facility and senior secured hedged inventory facility was reduced by outstanding letters of credit of $97 million and $9 million, respectively.

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 the 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, 2019,~~March 31, 2020, we were in compliance with all such covenants. Also, see Item 1A. “Risk Factors” included in our ~~2018~~2019 Annual Report on Form 10-K and Item 1A. “Risk Factors” below in Part II of this Form 10-Q 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 ~~2018~~2019 Annual Report on Form 10-K.

Net cash provided by operating activities for the first ~~nine~~three months of 2020 and 2019 was $890 million and ~~2018 was $1.778 billion and $1.294 billion,~~$1,033 million, 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~~three months ended ~~September 30,~~March 31, 2020 and 2019, our cash provided by operating activities was positively impacted by decreases in the ~~proceeds from the sale~~volume of inventory that we held, primarily due to the sale of NGL and crude oil 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.

During the nine months ended September 30, 2018, we increased the volume of crude oil and NGL inventory that we held, which was funded by proceeds from asset sales and short-term debt. The cash outflows associated with these inventory purchases resulted in a decrease to our cash provided by operating activities. However, this decrease was partially offset by approximately $300 million of cash received for transactions for which the revenue has been deferred pending the completion of future performance obligations. See Note 3 to our Condensed Consolidated Financial Statements for additional information.

Acquisitions and Capital Expenditures

In addition to our operating needs discussed above, we also use cash for our acquisition activities and expansion 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, expansion capital projects and maintenance activities. However, in the near term we do not plan to issue common equity to fund such activities.

Acquisitions. ~~During the nine months ended September 30, 2019,~~In February 2020, we ~~paid an aggregate of $47 million to acquire assets, including~~acquired a crude oil ~~storage terminal.~~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 ~~approximately $988~~$352 million in midstream infrastructure during the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, and we expect to invest approximately ~~$1.35~~$1.1 billion during the full year ending December 31, ~~2019.~~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~~”Projects” for ~~detail of our projected capital expenditures for the year ending December 31, 2019.~~additional information. We expect to fund our ~~2019~~2020 capital program with retained cash flow, proceeds from assets sold as part of our divestiture program or debt.

Divestitures. In January 2020, we entered into a definitive agreement to sell certain of our Los Angeles Basin crude oil terminals for $195 million, subject to certain adjustments and expect the ~~first quarter~~transaction to close in the second half of ~~2019,~~2020. In April 2020, we ~~announced the formation of W2W Pipeline,~~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 ~~joint venture with subsidiaries of ExxonMobil and Lotus Midstream, LLC. During the third quarter of 2019, three additional entities joined as partners in W2W Pipeline. As a result, our~~10% ownership interest in ~~W2W~~Saddlehorn Pipeline decreased from 20% to 16%. W2W Pipeline is currently developing a new pipeline system that will originate in the Permian Basin in West Texas and transport crude oil to the Texas Gulf Coast. The pipeline system will provideCompany, LLC for proceeds of approximately ~~1.5 million barrels per day of crude oil and condensate capacity, and the project is targeted to commence operations in 2021.~~$78 million. See Note 7 to our Condensed Consolidated Financial Statements for additional information.

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During the second quarter of 2019, we announced the formation of Red Oak, a joint venture with a subsidiary of Phillips 66. We own a 50% interest in Red Oak, which is currently developing a new pipeline that will provide crude oil transportation service from Cushing, Oklahoma, and the Permian Basin in West Texas to Corpus Christi, Ingleside, Houston and Beaumont, Texas. Initial service from Cushing to the Gulf Coast is targeted to commence in 2021, subject to receipt of applicable permits and regulatory approvals. See ~~Note 7~~ ~~to our Condensed Consolidated Financial Statements for additional information.~~

~~Divestitures.~~ During the second quarter of 2019, we formed a joint venture, Red River LLC, with Delek on our Red River pipeline system. We received approximately $128 million for Delek’s 33% interest in Red River LLC. See ~~Note 9~~ ~~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 ~~2018~~2019 Annual Report on Form 10-K for further discussion regarding risks related to our acquisitions and divestitures.

Equity and Debt Financing Activities

Our financing activities primarily relate to funding expansion 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, 2019,~~March 31, 2020, we had approximately $1.1 billion of unsold securities available under the Traditional Shelf. 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 issuance of $1.0 billion, 3.55% senior notes in September 2019, as discussed further below, was conducted under our WKSI Shelf.~~ We did not conduct any offerings under our Traditional Shelf or WKSI Shelf during the ~~nine~~three months ended ~~September 30, 2019.~~March 31, 2020.

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, 2019,~~March 31, 2020, we were in compliance with the covenants contained in our credit agreements and indentures.

Our fixed-rate senior notes had a face value of approximately $9.0 billion at both March 31, 2020 and December 31, 2019. We estimated the aggregate fair value of these notes as of March 31, 2020 and December 31, 2019 to be approximately $7.2 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. The decrease in the fair value of our fixed-rate senior notes is attributable to widening credit spreads in the secondary market for the debt of oil and gas industry participants in general, and our debt and many of our peers in the United States midstream sector specifically. This widening has occurred due to a number of external forces, such as the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply.

During the three months ended March 31, 2020, we had net repayments on our credit agreements and commercial paper program of $4 million. The net repayments resulted primarily from cash flow from operating activities and proceeds from asset sales, which offset borrowings during the period related to funding needs for capital investments, inventory purchases and other general partnership purposes.

As of ~~September 30,~~March 31, 2019 and December 31, 2018, we had no outstanding borrowings under our credit agreements or commercial paper program. However, during the ~~nine~~three months ended ~~September 30,~~March 31, 2019, we borrowed and repaid ~~$10.5~~$0.5 billion under ~~credit agreements and~~ our commercial paper program. ~~These~~The repayments resulted primarily from cash flow from operating ~~activities and proceeds from senior notes issuances.~~activities.

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During the nine months ended September 30, 2018, we had net repayments on our credit facilities and commercial paper program of $542 million. The net repayments resulted primarily from cash flow from operating activities and proceeds from asset sales, partially offset by borrowings during the period related to funding needs for inventory purchases and related margin activities.

In September 2019, we completed the issuance of $1.0 billion, 3.55% senior notes due December 2029 at a public offering price of 99.801%. Interest payments are due on June 15 and December 15 of each year, commencing on June 15, 2020. We intend to use the net proceeds from this offering of $989 million, after deducting the underwriting discount and offering expenses, to partially repay the principal amounts of our 2.60% senior notes due December 2019 and 5.75% senior notes due January 2020 and, pending such repayment, have used a portion of the proceeds to repay outstanding borrowings under our commercial paper program and for general partnership purposes.

In October 2019, we sent notice to the holders of our $500 million, 2.60% senior notes due December 2019 that we will redeem the notes on November 15, 2019. We also intend to redeem our $500 million, 5.75% senior notes due January 2020 during the fourth quarter of 2019.

Distributions to Our Unitholders

Distributions to our Series A preferred unitholders. On ~~November 14, 2019,~~May 15, 2020, we will pay a cash distribution of $37 million ($0.525 per unit) on our Series A preferred units outstanding as of ~~October 31, 2019,~~May 1, 2020, the record date for such distribution for the period from ~~July~~January 1, ~~2019~~2020 through ~~September 30, 2019.~~March 31, 2020. See Note 9 to our Condensed Consolidated Financial Statements for details of distributions made during or pertaining to the first ~~nine~~three months of ~~2019.~~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~~May 15, ~~2019,~~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~~May 1, ~~2019~~2020 for the period from ~~May~~November 15, 2019 to ~~November~~May 14, ~~2019.~~2020. See Note 9 to our Condensed Consolidated Financial Statements for ~~details of distributions made during the first nine months of 2019.~~additional information.

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 14, 2019,~~May 15, 2020, we will pay a quarterly distribution of $0.18 per common unit ($0.72 per common unit on an annualized basis), which 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) onpaid in February 2020. This reduction was made in response to the current dynamic and uncertain market conditions to further reinforce our ~~common units outstanding as of October 31, 2019, the record date~~commitment to maintaining a solid capital structure and strong liquidity. See “—Executive Summary—Recent Events & Outlook” for ~~such distribution for the period from July 1, 2019 through September 30, 2019.~~further discussion. See Note 9 to our Condensed Consolidated Financial Statements for details of distributions paid during or pertaining to the first ~~nine~~three months of ~~2019.~~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 ~~2018~~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.~~capacity and cost of borrowing.

Contingencies

For a discussion of contingencies that may impact us, see Note 1312 to our Condensed Consolidated Financial Statements.

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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 ~~ten~~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, 2019~~March 31, 2020 (in millions):


	Remainder of 2019		2020		2021		2022		2023		2024 and Thereafter		Total			Remainder of 2020		2021		2022		2023		2024		2025 and Thereafter		Total
Long-term debt and related interest payments ⁽¹⁾	$	1,114	$	412	$	985	$	1,115	$	1,636	$	9,807	$	15,069	Long-term debt and related interest payments ⁽¹⁾	$	311	$	1,026	$	1,312	$	1,636	$	1,055	$	8,753	$	14,093
Leases ⁽²⁾	36		131		102		88		61		257		675		Leases ⁽²⁾	97		99		93		70		58		305		722
Other obligations ⁽³⁾	279		1,065		675		301		279		1,373		3,972		Other obligations ⁽³⁾	619		477		301		304		279		1,189		3,169
Subtotal	1,429		1,608		1,762		1,504		1,976		11,437		19,716		Subtotal	1,027		1,602		1,706		2,010		1,392		10,247		17,984
Crude oil, NGL and other purchases ⁽⁴⁾	3,822		9,417		8,806		8,444		7,487		19,676		57,652		Crude oil, NGL and other purchases ⁽⁴⁾	5,830		6,440		6,182		5,849		5,454		14,024		43,779
Total	$	5,251	$	11,025	$	10,568	$	9,948	$	9,463	$	31,113	$	77,368	Total	$	6,857	$	8,042	$	7,888	$	7,859	$	6,846	$	24,271	$	61,763

⁽¹⁾

⁽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 capital expansion projects, including projected contributions for our share of the capital spending of our equity method investments. The storage, processing and transportation agreements include approximately $1.8 billion associated with agreements to store, process 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 March 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.

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 11~~ ~~to our Condensed Consolidated Financial Statements 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 capital expansion 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, process 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 2019. 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, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, we had outstanding letters of credit of approximately ~~$149~~$106 million and ~~$184~~$157 million, respectively.

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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 ~~2018~~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:

•the continuation of a swift and material decline in global crude oil demand and crude oil prices for an uncertain period of time that correspondingly may 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 slow the spread of the COVID-19 virus to the point where applicable authorities are comfortable easing current restrictions on various commercial and economic activities and the extent to which consumer demand and demand for crude oil rebound once such restrictions are lifted; such restrictions are designed to protect public health but also have the effect of significantly reducing demand for crude oil;

•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;

•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 ~~declines~~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, which may in ~~production from existing~~turn make it more challenging to retain or recruit talented labor;

•disruptions to futures markets for crude oil, NGL and ~~gas reserves, reduced demand, failure~~other petroleum products, which may impair our ability to ~~develop~~execute our commercial and hedging strategies;

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

Table of ~~additional oil and gas reserves, whether from reduced cash flow to fund drilling or~~ Contents

•the inability to ~~access capital,~~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;

~~market distortions caused by over-commitments to infrastructure projects,~~•negative societal sentiment regarding the hydrocarbon energy industry and the continued development and consumption of hydrocarbons, which ~~impacts volumes, margins, returns~~could influence consumer preferences and ~~overall earnings;~~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 expansion 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;~~interpretations, including legislation or regulatory initiatives that prohibit, restrict or regulate hydraulic fracturing;

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tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion 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, ~~acquisition~~divestitures, joint ventures, acquisitions or ~~combination~~other strategic opportunities;

the successful integration and future performance of acquired assets or businesses and the risks associated with operating in lines of business that are distinct and separate from our historical operations;

•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;

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•non-utilization of our assets and facilities;

•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

~~general economic, market or business conditions and the amplification of other risks caused by volatile financial markets, capital constraints and pervasive liquidity concerns; 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 ~~NGL.~~ 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 ~~2018~~2019 Annual Report on Form 10-K. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

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

•Crude oil

We utilize crude oil derivatives to hedge commodity price risk inherent in our Supply and Logistics and Transportation segments. Our objectives for these derivatives include hedging anticipated purchases and sales, stored inventory, basis differentials and storage capacity utilization. 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, 2019~~March 31, 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				Fair Value		Effect of 10% Price Increase		Effect of 10% Price Decrease
Crude oil	$	166	$	(35	)	$	46		Crude oil	$	145	$	(23)	$	23
Natural gas	1		$	8		$	(8	)	Natural gas	2		$	5	$	(5)
NGL and other	170		$	(26	)	$	26		NGL and other	105		$	(7)	$	7
Total fair value	$	337							Total fair value	$	252

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, 2019,~~March 31, 2020, approximately ~~$200~~$614 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~~three months ended ~~September 30, 2019~~March 31, 2020 was ~~3.1%~~2.2%, based upon rates in effect during such period. The fair value of our interest rate derivatives was a liability of ~~$64~~$124 million as of ~~September 30, 2019.~~March 31, 2020. A 10% increase in the forward LIBOR curve as of ~~September 30, 2019~~March 31, 2020 would have resulted in an increase of $8$14 million to the fair value of our interest rate derivatives. A 10% decrease in the forward LIBOR curve as of ~~September 30, 2019~~March 31, 2020 would have resulted in a decrease of $8$14 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 $1$5 million as of ~~September 30, 2019.~~March 31, 2020. A 10% increase in the exchange rate (USD-to-CAD) would have resulted in a decrease of $6$17 million to the fair value of our foreign currency derivatives. A 10% decrease in the exchange rate (USD-to-CAD) would have resulted in an increase of $6$17 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 U.S. 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 ~~$19~~$8 million as of ~~September 30, 2019.~~March 31, 2020. A 10% increase or decrease in the fair value would have an impact of $2$1 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, 2019,~~March 31, 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~~first quarter of ~~2019~~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 1312 to our Condensed Consolidated Financial Statements, and is incorporated herein by reference thereto.

Item 1A. RISK FACTORS

For a discussion regarding our risk factors, see Item 1A. of our ~~2018~~2019 Annual Report on Form 10-K. Those risks and uncertainties are not the only ones facing us and there may be additional matters of which we are unaware or that we currently consider immaterial. All of those risks and uncertainties could adversely affect our business, financial condition and/or results of ~~operations.~~operations, as could the following:

Our business, results of operations, financial condition, cash flows and unit price can be adversely affected by pandemics, epidemics or other public health emergencies, such as the recent outbreak of COVID-19. The COVID-19 pandemic has given rise to and/or heightened a variety of risks and uncertainties inherent in our business, many of which are described in our 2019 Annual Report. Such risks and uncertainties, which in some cases have been exacerbated by events and circumstances that are not related to the COVID-19 pandemic, have either already begun to adversely impact our business or are reasonably likely to adversely impact our business in the future. These risks, uncertainties and other factors include the following:

•The pandemic has resulted in a swift and material decline in global crude oil demand and crude oil prices, which we anticipate will 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, the inability of producers to access capital, the unavailability of pipeline and/or storage capacity, the shutting-in of production by producers, government-mandated pro-ration orders or other factors), which in turn could result in significant declines in the actual or expected volume of crude oil and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets and/or the reduction of commercial opportunities that might otherwise be available to us.

•The significant decline in global crude oil demand has contributed to an oversupply of crude oil that has been exacerbated by the actions of foreign oil producers (most notably Saudi Arabia and Russia), who significantly increased crude oil production during the first quarter of 2020 and then subsequently announced in early April a temporary production cut of approximately ten million barrels per day.

•Because global demand for crude oil has declined more rapidly than supply, storage facilities have been filling at an accelerated rate and will likely reach levels at or near maximum operating capacity during the second quarter of 2020. This will lead to an “overhang” of significant amounts of crude oil inventory stored in the United States and elsewhere, a factor that has contributed to a material decline in crude oil prices.

•The resulting macroeconomic environment of reduced crude oil demand, excess crude oil supply and low crude oil prices has caused producers throughout North America, including many of our customers in the Permian Basin and elsewhere, to begin cutting back on production levels and may eventually lead to the shutting in of production by such producers. This could have a material adverse effect on the demand for the midstream services we offer and the commercial opportunities that are available to us.In turn, such factors could have a material adverse impact on our financial performance during the current year and future periods. A turnaround of these adverse macroeconomic

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factors depends largely on an increase in global demand for crude oil, which will be driven primarily by the length of time it takes for the United States, Canada, and the rest of the world to slow the spread of the COVID-19 virus to the point where applicable authorities are comfortable easing current restrictions on various commercial and economic activities and the extent to which consumer demand and demand for crude oil rebound once such restrictions are lifted. The timing of any such easing of restrictions and resulting market recovery is highly uncertain and depends on a wide variety of factors that are outside of our control, including the development and effectiveness of COVID-19 testing protocols, treatments and vaccines; the capacity of our healthcare systems and public health infrastructure to manage current and future outbreaks; the availability and impact of new epidemiological information about the virus; and various political and economic considerations. Even once such restrictions are lifted, it is unknown whether consumption of petroleum products will return to pre-COVID levels, due to changes in consumer habits or preferences. As a result, we are unable to predict the timing of any such market recovery, including a return to market conditions that are more conducive to an increase in drilling and production activities in the United States and Canada.

•We anticipate an increased risk of nonpayment and nonperformance by customers or other counterparties. Our customers or counterparties may refuse or be unable 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 bankruptcy proceedings, 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.

•We may face additional challenges maintaining our investment grade credit rating, which could in turn reduce our borrowing capacity and cause our counterparties to reduce the amount of open credit we receive from them. Disruptions to futures markets for crude oil, NGL and other petroleum products may also impair our ability to execute our commercial and hedging strategies.

•Many of our support functions are operating remotely, which presents technical and communication challenges. As a result, we may be more vulnerable to cybersecurity breaches, risk management oversights or other delays in, or disruptions to, communications, which may in turn affect our ability to effectively manage our business.

•We may face operational difficulties due to physical distancing restrictions. Such restrictions may also place additional demands on our employees, which may in turn make it more challenging to retain or recruit talented labor.

•We may have additional difficulties performing our obligations under our contracts, whether due to non-performance by third parties, including our customers or counterparties, market constraints, third-party constraints, legal constraints (including governmental orders or guidance), or other factors.

•The COVID-19 pandemic has caused widespread supply chain disruptions, which may make it more challenging to obtain sufficient quantities of high quality materials at acceptable prices and in a timely manner. If we are unable to source such materials, it could materially and adversely affect our ability to construct new infrastructure and maintain our existing assets.

In April 2020, we announced certain actions in response to the COVID-19 pandemic, including a reduction in distributions on our common units, planned reductions in capital expenditures, asset divestitures and other cost reductions throughout the organization and supply chain. However, we may be unable to reduce capital expenditures to the extent forecasted, effectively divest assets at attractive prices or realize anticipated cost savings. Even if we are able to execute our planned actions, they may be insufficient to maintain our liquidity and capital structure.

For all of these reasons, we cannot reasonably estimate with any degree of certainty the future impact COVID-19 may have on our results of operations, financial position, and liquidity.

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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, 2019, we issued 15,186 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. None.

Item 3. DEFAULTS UPON SENIOR SECURITIES

None.

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

Item 5. OTHER INFORMATION

None.

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Item 6. EXHIBITS


Exhibit No.				Description

~~Exhibit No.~~3.1			—	~~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).

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).

~~3.8~~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).

~~3.9~~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).

~~3.10~~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).

~~3.11~~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).

~~3.12~~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).

~~3.13~~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).

~~3.14~~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).

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~~3.15~~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).

~~3.16~~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).

~~Table of Contents~~



~~3.17~~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).

~~3.18~~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).

~~3.19~~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).

~~3.20~~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).

~~3.21~~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).

~~4.1~~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			—	Seventeenth Supplemental Indenture (5.75% Senior Notes due 2020) dated September 4, 2009 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 September 4, 2009).

~~4.5~~	—	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).

~~4.6~~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).

~~4.7~~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).

~~4.8~~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).

~~4.9~~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).

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~~4.10~~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).

~~4.11~~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).

~~Table of Contents~~


4.11
~~4.12~~	—	Twenty-Sixth Supplemental Indenture (3.60% Senior Notes due 2024) dated September 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed September 11, 2014).

~~4.13~~4.12			—	Twenty-Seventh Supplemental Indenture (2.60% Senior Notes due 2019) 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 4.1 to our Current Report on Form 8-K filed December 11, 2014).

~~4.14~~	—	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).

~~4.15~~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).

~~4.16~~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).

~~4.17~~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).

~~4.18~~4.16			—	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).

~~4.19~~4.17			—	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).

~~4.20~~4.18			—	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).

~~10.1 *†~~4.19			—	~~Amendment No. 2 dated August 15, 2019~~Description of Our Securities (incorporated by reference to ~~Harry Pefanis Amended and Restated Employment Agreement.~~Exhibit 4.19 to our Annual Report on Form 10-K for the year ended December 31, 2019).

~~10.2 *†~~31.1 †			—	~~Form of LTIP Grant Letter dated August 15, 2019 (Officers)~~

~~10.3 *†~~	—	~~Form of LTIP Grant Letter dated August 15, 2019 (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

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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

~~Table of Contents~~



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


†	~~Filed herewith.~~


††	~~Furnished herewith.~~

* Management compensatory plan or arrangement.†Filed herewith.

††Furnished herewith.

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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 7, 2019~~May 8, 2020

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

~~November 7, 2019~~May 8, 2020

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

~~November 7, 2019~~May 8, 2020



Three Months Ended September 30, 2018	Transportation		Facilities		Supply and Logistics			Total
Revenues from contracts with customers	$	496	$	285	$	8,534		$	9,315
Other items in revenues	2		4		(51		)	(45		)
Total revenues of reportable segments	$	498	$	289	$	8,483		$	9,270
Intersegment revenues								(478		)
Total revenues								$	8,792



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



Nine Months Ended September 30, 2018	Transportation		Facilities		Supply and Logistics			Total
Revenues from contracts with customers	$	1,416	$	845	$	24,832		$	27,093
Other items in revenues	11		21		(456		)	(424		)
Total revenues of reportable segments	$	1,427	$	866	$	24,376		$	26,669
Intersegment revenues								(1,400		)
Total revenues								$	25,269



		Ownership Interest at	Investment Balance
Entity ⁽¹⁾	Type of Operation	September 30, 2019	September 30, 2019		December 31, 2018
Advantage Pipeline Holdings LLC	Crude Oil Pipeline	50%	$	74	$	72
BridgeTex Pipeline Company, LLC	Crude Oil Pipeline	20%	432		435
Cactus II Pipeline LLC	Crude Oil Pipeline	65%	666		455
Caddo Pipeline LLC	Crude Oil Pipeline	50%	66		65
Capline Pipeline Company LLC	Crude Oil Pipeline ⁽²⁾	54%	462		—
Cheyenne Pipeline LLC	Crude Oil Pipeline	50%	44		44
Diamond Pipeline LLC	Crude Oil Pipeline	50%	476		479
Eagle Ford Pipeline LLC	Crude Oil Pipeline	50%	386		383
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”)	Crude Oil Terminal and Dock	50%	124		108
Midway Pipeline LLC	Crude Oil Pipeline	50%	76		78
Red Oak Pipeline LLC (“Red Oak”)	Crude Oil Pipeline ⁽³⁾	50%	3		—
Saddlehorn Pipeline Company, LLC	Crude Oil Pipeline	40%	227		215
Settoon Towing, LLC	Barge Transportation Services	50%	58		58
STACK Pipeline LLC	Crude Oil Pipeline	50%	116		120
White Cliffs Pipeline, LLC	Crude Oil Pipeline	36%	196		190
Wink to Webster Pipeline LLC (“W2W Pipeline”)	Crude Oil Pipeline ⁽³⁾	16%	79		—
Total investments in unconsolidated entities			$	3,485	$	2,702



	Three Months Ended September 30, 2019
Location of Gain/(Loss)	Commodity Derivatives		Foreign Currency Derivatives			Preferred Distribution Rate Reset Option		Interest Rate Derivatives			Total
Supply and Logistics segment revenues ⁽¹⁾	$	149	$	(1	)	$	—	$	—		$	148
Field operating costs ⁽¹⁾	4		—			—		—			4
Interest expense, net ⁽²⁾	—		—			—		(2		)	(2		)
Other income/(expense), net ⁽¹⁾	—		—			1		—			1
Total gain/(loss) on derivatives recognized in net income	$	153	$	(1	)	$	1	$	(2	)	$	151



	Derivatives Not Designated As Hedging Instruments
Balance Sheet Location	Commodity Derivatives			Foreign Currency Derivatives			Preferred Distribution Rate Reset Option			Total			Interest Rate Derivatives ⁽¹⁾			Total Derivatives
Derivative Assets
Other current assets	$	376		$	—		$	—		$	376		$	—		$	376
Other long-term assets, net	59			—			—			59			—			59
Other current liabilities	2			—			—			2			—			2
Total Derivative Assets	$	437		$	—		$	—		$	437		$	—		$	437

Derivative Liabilities
Other current assets	$	(67	)	$	—		$	—		$	(67	)	$	—		$	(67	)
Other long-term assets, net	(5		)	—			—			(5		)	—			(5		)
Other current liabilities	(14		)	(1		)	—			(15		)	(64		)	(79		)
Other long-term liabilities and deferred credits	(14		)	—			(19		)	(33		)	—			(33		)
Total Derivative Liabilities	$	(100	)	$	(1	)	$	(19	)	$	(120	)	$	(64	)	$	(184	)



	September 30, 2019						December 31, 2018
	Derivative Asset Positions			Derivative Liability Positions			Derivative Asset Positions			Derivative Liability Positions
Netting Adjustments:
Gross position - asset/(liability)	$	437		$	(184	)	$	480		$	(262	)
Netting adjustment	(74		)	74			(192		)	192
Cash collateral received	(110		)	—			(80		)	—
Net position - asset/(liability)	$	253		$	(110	)	$	208		$	(70	)

Balance Sheet Location After Netting Adjustments:
Other current assets	$	199		$	—		$	181		$	—
Other long-term assets, net	54			—			27			—
Other current liabilities	—			(77		)	—			(20		)
Other long-term liabilities and deferred credits	—			(33		)	—			(50		)
	$	253		$	(110	)	$	208		$	(70	)



Lease Cost	Three Months Ended September 30, 2019			Nine Months Ended September 30, 2019
Operating lease cost	$	32		$	95
Short-term lease cost	11			32
Other ⁽¹⁾	(1		)	—
Total lease cost	$	42		$	127



	Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	101
Financing cash flows for finance leases	$	13

Non-cash change in lease liabilities arising from obtaining new right of use assets or modifications:
Operating leases	$	16
Finance leases	$	10



Leases	Balance Sheet Location	September 30, 2019
Assets
Operating lease right-of-use assets	Long-term operating lease right-of-use assets, net	$	443

Finance lease right-of-use assets	Property and equipment	$	110
	Accumulated depreciation	(15		)
	Property and equipment, net	$	95

Total lease right-of-use assets		$	538

Liabilities
Operating lease liabilities
Current	Other current liabilities	$	103
Noncurrent	Long-term operating lease liabilities	348
Total operating lease liabilities		$	451

Finance lease liabilities
Current	Short-term debt	$	19
Noncurrent	Other long-term debt, net	37
Total finance lease liabilities		$	56

Total lease liabilities		$	507



	Operating			Finance
Future minimum lease payments⁽¹⁾:
Remainder of 2019	$	31		$	5
2020	113			18
2021	93			9
2022	78			10
2023	54			7
Thereafter	247			10
Total	616			59
Less: Present value discount	(165		)	(3		)
Lease liabilities	$	451		$	56



	Remainder of 2019		2020		2021		2022		2023		Thereafter
Lease revenue	$	5	$	19	$	22	$	25	$	21	$	226



Projects	2019
Permian Basin Takeaway Pipeline Projects	$	500
Complementary Permian Basin Projects	485
Other Long-Haul Pipeline Projects	100
Selected Facilities	100
Other Projects	165
Total Projected 2019 Expansion Capital Expenditures ⁽¹⁾	$	1,350



	Favorable/(Unfavorable) Variance Three Months Ended September 30, 2019-2018									Favorable/(Unfavorable) Variance Nine Months Ended September 30, 2019-2018
(in millions)	Revenues			Purchases and Related Costs			Equity Earnings			Revenues			Purchases and Related Costs			Equity Earnings
Permian Basin region	$	71		$	(7	)	$	(11	)	$	192		$	(11	)	$	(40	)
South Texas / Eagle Ford region	(1		)	—			3			(2		)	—			27
Central region	10			(1		)	1			32			(1		)	8
Gulf Coast region	—			—			(4		)	1			—			(14		)
Rocky Mountain region	1			—			2			(5		)	—			11
Canada region	6			—			—			19			—			—
Other regions, trucking and pipeline loss allowance revenue	12			2			1			48			(2		)	1
Total variance	$	99		$	(6	)	$	(8	)	$	285		$	(14	)	$	(7	)



	As of September 30, 2019
Availability under senior unsecured revolving credit facility ^(1) (2)	$	1,462
Availability under senior secured hedged inventory facility ^(1) (2)	1,389
Subtotal	2,851
Cash and cash equivalents	609
Total	$	3,460