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

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

(Exact name of registrant as specified in its charter)



Delaware		76-0582150
(State or other jurisdiction of	~~(I.R.S. Employer~~
incorporation or organization)	(I.R.S. Employer Identification No.)

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. ý☑ Yes o ☐ No

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ 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 ~~and post~~ such files). ý☑ Yes o☐ No

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

Large accelerated filerý

☑

Accelerated filero

☐

Non-accelerated filero

☐

Smaller reporting companyo

☐

~~(Do not check if a smaller reporting company)~~

Emerging growth companyo

☐

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. o☐

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

As of ~~October 31, 2017,~~April 29, 2022, there were ~~725,189,138~~702,668,178 Common Units outstanding.

PART I. FINANCIAL INFORMATION

Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

(in millions, except unit data)

September 30,
2017 December 31, 2016
(unaudited)
ASSETS

CURRENT ASSETS

Cash and cash equivalents $ 33
$ 47
Trade accounts receivable and other receivables, net 2,287
2,279
Inventory 884
1,343
Other current assets 811
603
Total current assets 4,015
4,272

PROPERTY AND EQUIPMENT 16,866
16,220
Accumulated depreciation (2,597 ) (2,348 )
Property and equipment, net 14,269
13,872

OTHER ASSETS

Goodwill 2,598
2,344
Investments in unconsolidated entities 2,671
2,343
Linefill and base gas 884
896
Long-term inventory 135
193
Other long-term assets, net 911
290
Total assets $ 25,483
$ 24,210

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES

Accounts payable and accrued liabilities $ 2,713
$ 2,588
Short-term debt 918
1,715
Other current liabilities 385
361
Total current liabilities 4,016
4,664

LONG-TERM LIABILITIES

Senior notes, net of unamortized discounts and debt issuance costs 9,881
9,874
Other long-term debt 608
250
Other long-term liabilities and deferred credits 698
606
Total long-term liabilities 11,187
10,730

COMMITMENTS AND CONTINGENCIES (NOTE 12)

PARTNERS’ CAPITAL

Series A preferred unitholders (68,329,949 and 64,388,853 units outstanding, respectively) 1,506
1,508
Common unitholders (725,189,138 and 669,194,419 units outstanding, respectively) 8,717
7,251
Total partners’ capital excluding noncontrolling interests 10,223
8,759
Noncontrolling interests 57
57
Total partners’ capital 10,280
8,816
Total liabilities and partners’ capital $ 25,483
$ 24,210


	March 31, 2022		December 31, 2021
	(unaudited)
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	114	$	449

Trade accounts receivable and other receivables, net	7,136		4,705
Inventory	527		783
Other current assets	320		200
Total current assets	8,097		6,137

PROPERTY AND EQUIPMENT	19,399		19,257
Accumulated depreciation	(4,535)		(4,354)
Property and equipment, net	14,864		14,903

OTHER ASSETS
Investments in unconsolidated entities	3,807		3,805
Intangible assets, net	1,901		1,960
Linefill	919		907
Long-term operating lease right-of-use assets, net	387		393
Long-term inventory	374		253
Other long-term assets, net	293		251
Total assets	$	30,642	$	28,609

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES
Trade accounts payable	$	6,867	$	4,810
Short-term debt	900		822
Other current liabilities	803		600
Total current liabilities	8,570		6,232

LONG-TERM LIABILITIES
Senior notes, net	7,931		8,329
Other long-term debt, net	55		69
Long-term operating lease liabilities	331		339
Other long-term liabilities and deferred credits	901		830
Total long-term liabilities	9,218		9,567

COMMITMENTS AND CONTINGENCIES (NOTE 10)	0		0

PARTNERS’ CAPITAL
Series A preferred unitholders (71,090,468 and 71,090,468 units outstanding, respectively)	1,505		1,505
Series B preferred unitholders (800,000 and 800,000 units outstanding, respectively)	787		787
Common unitholders (702,668,178 and 704,991,540 units outstanding, respectively)	7,751		7,680
Total partners’ capital excluding noncontrolling interests	10,043		9,972
Noncontrolling interests	2,811		2,838
Total partners’ capital	12,854		12,810
Total liabilities and partners’ capital	$	30,642	$	28,609

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

(in millions, except per unit data)

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
(unaudited) (unaudited)
REVENUES

Supply and Logistics segment revenues $ 5,573
$ 4,876
$ 17,749
$ 13,344
Transportation segment revenues 160
159
459
482
Facilities segment revenues 140
135
410
405
Total revenues 5,873
5,170
18,618
14,231

COSTS AND EXPENSES

Purchases and related costs 5,327
4,429
16,239
12,000
Field operating costs 283
289
876
893
General and administrative expenses 68
70
210
210
Depreciation and amortization 151
33
401
351
Total costs and expenses 5,829
4,821
17,726
13,454

OPERATING INCOME 44
349
892
777

OTHER INCOME/(EXPENSE)

Equity earnings in unconsolidated entities 80
46
201
133
Interest expense (net of capitalized interest of $11, $11, $26 and $37, respectively) (134 ) (113 ) (390 ) (339 )
Other income/(expense), net (1 ) 17
(6 ) 46

INCOME/(LOSS) BEFORE TAX (11 ) 299
697
617
Current income tax benefit/(expense) 1
(4 ) (9 ) (45 )
Deferred income tax benefit/(expense) 44
3
(21 ) 30

NET INCOME 34
298
667
602
Net income attributable to noncontrolling interests (1 ) (1 ) (2 ) (3 )
NET INCOME ATTRIBUTABLE TO PAA $ 33
$ 297
$ 665
$ 599

NET INCOME/(LOSS) PER COMMON UNIT (NOTE 3):

Net income/(loss) allocated to common unitholders — Basic $ (8 ) $ 162
$ 547
$ 110
Basic weighted average common units outstanding 725
401
714
399
Basic net income/(loss) per common unit $ (0.01 ) $ 0.40
$ 0.77
$ 0.27

Net income/(loss) allocated to common unitholders — Diluted $ (8 ) $ 162
$ 547
$ 110
Diluted weighted average common units outstanding 725
402
715
400
Diluted net income/(loss) per common unit $ (0.01 ) $ 0.40
$ 0.76
$ 0.27


	Three Months Ended March 31,
		2022		2021
	(unaudited)
REVENUES
Product sales revenues		$	13,381	$	8,083
Services revenues		313		300
Total revenues		13,694		8,383

COSTS AND EXPENSES
Purchases and related costs		12,785		7,392
Field operating costs		346		219
General and administrative expenses		82		67
Depreciation and amortization		230		177
(Gains)/losses on asset sales and asset impairments, net		(42)		2
Total costs and expenses		13,401		7,857

OPERATING INCOME		293		526

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities		97		88

Interest expense (net of capitalized interest of $1 and $5, respectively)		(107)		(107)
Other expense, net		(37)		(60)

INCOME BEFORE TAX		246		447
Current income tax expense		(19)		(1)
Deferred income tax expense		(2)		(23)

NET INCOME		225		423
Net income attributable to noncontrolling interests		(38)		(1)
NET INCOME ATTRIBUTABLE TO PAA		$	187	$	422

NET INCOME PER COMMON UNIT (NOTE 4):
Net income allocated to common unitholders — Basic and Diluted		$	137	$	371
Basic and diluted weighted average common units outstanding		705		722
Basic and diluted net income per common unit		$	0.19	$	0.51

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
(unaudited) (unaudited)
Net income $ 34
$ 298
$ 667
$ 602
Other comprehensive income/(loss) 145
(45 ) 256
—
Comprehensive income 179
253
923
602
Comprehensive income attributable to noncontrolling interests (1 ) (1 ) (2 ) (3 )
Comprehensive income attributable to PAA $ 178
$ 252
$ 921
$ 599


	Three Months Ended March 31,
		2022		2021
	(unaudited)
Net income		$	225	$	423
Other comprehensive income		74		108
Comprehensive income		299		531
Comprehensive income attributable to noncontrolling interests		(38)		(1)
Comprehensive income attributable to PAA		$	261	$	530


	Derivative Instruments		Translation Adjustments		Other		Total
	(unaudited)
Balance at December 31, 2021	$	(208)	$	(642)	$	(3)	$	(853)

Reclassification adjustments	3		—		—		3
Unrealized gain on hedges	32		—		—		32
Currency translation adjustments	—		40		—		40
Other	—		—		(1)		(1)
Total period activity	35		40		(1)		74
Balance at March 31, 2022	$	(173)	$	(602)	$	(4)	$	(779)

Derivative
Instruments

Translation
Adjustments
Other Total
(unaudited)
Balance at December 31, 2016 $ (228 ) $ (782 ) $ 1
$ (1,009 )

Reclassification adjustments 19
—
—
19
Deferred loss on cash flow hedges (15 ) —
—
(15 )
Currency translation adjustments —
252
—
252
Total period activity 4
252
—
256
Balance at September 30, 2017 $ (224 ) $ (530 ) $ 1
$ (753 )


	Three Months Ended March 31,
	2022		2021
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	225	$	423
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	230		177
(Gains)/losses on asset sales and asset impairments, net	(42)		2


Deferred income tax expense	2		23


Change in fair value of Preferred Distribution Rate Reset Option (Note 8)	44		67
Equity earnings in unconsolidated entities	(97)		(88)
Distributions on earnings from unconsolidated entities	96		110

Other	4		6
Changes in assets and liabilities, net of acquisitions	(122)		71
Net cash provided by operating activities	340		791

CASH FLOWS FROM INVESTING ACTIVITIES

Investments in unconsolidated entities	(3)		(35)
Additions to property, equipment and other	(101)		(97)
Proceeds from sales of assets	53		21


Cash paid for purchases of linefill	(39)		—
Other investing activities	9		3
Net cash used in investing activities	(81)		(108)

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) under commercial paper program (Note 6)	382		(410)

Net repayments under senior secured hedged inventory facility (Note 6)	—		(166)


Repayments of senior notes	(750)		—

Repurchase of common units (Note 7)	(25)		(3)
Distributions paid to Series A preferred unitholders (Note 7)	(37)		(37)

Distributions paid to common unitholders (Note 7)	(127)		(130)
Distributions paid to noncontrolling interests (Note 7)	(59)		(6)



Other financing activities	19		65
Net cash used in financing activities	(597)		(687)

Effect of translation adjustment	3		—

Net decrease in cash and cash equivalents and restricted cash	(335)		(4)
Cash and cash equivalents and restricted cash, beginning of period	453		60
Cash and cash equivalents and restricted cash, end of period	$	118	$	56

Cash paid for:
Interest, net of amounts capitalized	$	74	$	65
Income taxes, net of amounts refunded	$	23	$	24

Nine Months Ended
September 30,
2017 2016
(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES

Net income $ 667
$ 602
Reconciliation of net income to net cash provided by operating activities:

Depreciation and amortization 401
351
Equity-indexed compensation expense 33
40
Inventory valuation adjustments 35
3
Deferred income tax (benefit)/expense 21
(30 )
(Gain)/loss on foreign currency revaluation (20 ) 1
Settlement of terminated interest rate hedging instruments (29 ) (50 )
Change in fair value of Preferred Distribution Rate Reset Option (Note 10) —
(42 )
Equity earnings in unconsolidated entities (201 ) (133 )
Distributions on earnings from unconsolidated entities 222
151
Other 19
13
Changes in assets and liabilities, net of acquisitions 770
(258 )
Net cash provided by operating activities 1,918
648

CASH FLOWS FROM INVESTING ACTIVITIES

Cash paid in connection with acquisitions, net of cash acquired (1,282 ) (282 )
Investments in unconsolidated entities (356 ) (171 )
Additions to property, equipment and other (778 ) (1,030 )
Proceeds from sales of assets 407
638
Return of investment from unconsolidated entities 21
—
Cash received for sales of linefill and base gas 23
—
Other investing activities 2
(9 )
Net cash used in investing activities (1,963 ) (854 )

CASH FLOWS FROM FINANCING ACTIVITIES

Net repayments under commercial paper program (Note 8) (115 ) (617 )
Net borrowings under senior secured hedged inventory facility (Note 8) 7
424
Repayments of senior notes (Note 8) (400 ) (175 )
Net proceeds from the sale of Series A preferred units —
1,569
Net proceeds from the sale of common units (Note 9) 1,664
283
Contributions from general partner —
39
Distributions paid to common unitholders (Note 9) (1,168 ) (835 )
Distributions paid to general partner —
(464 )
Other financing activities 41
(18 )
Net cash provided by financing activities 29
206

Effect of translation adjustment on cash 2
4

Net increase/(decrease) in cash and cash equivalents (14 ) 4
Cash and cash equivalents, beginning of period 47
27
Cash and cash equivalents, end of period $ 33
$ 31

Cash paid for:

Interest, net of amounts capitalized $ 325
$ 313
Income taxes, net of amounts refunded $ 47
$ 78















	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, 2021	$	1,505	$	787	$	7,680	$	9,972	$	2,838	$	12,810
Net income	37		12		138		187		38		225
Distributions (Note 7)	(37)		(12)		(127)		(176)		(59)		(235)
Other comprehensive income	—		—		74		74		—		74
Repurchase of common units (Note 7)	—		—		(25)		(25)		—		(25)


Other	—		—		11		11		(6)		5
Balance at March 31, 2022	$	1,505	$	787	$	7,751	$	10,043	$	2,811	$	12,854

Limited Partners
Partners’
Capital
Excluding
Noncontrolling
Interests

Noncontrolling
Interests

Total
Partners’
Capital

Series A
Preferred
Unitholders

Common
Unitholders

(unaudited)
Balance at December 31, 2016 $ 1,508
$ 7,251
$ 8,759
$ 57
$ 8,816
Net income —
665
665
2
667
Cash distributions to partners —
(1,168 ) (1,168 ) (2 ) (1,170 )
Sales of common units —
1,664
1,664
—
1,664
Acquisition of interest in Advantage Joint Venture (Note 6) —
40
40
—
40
Other comprehensive income —
256
256
—
256
Other (2 ) 9
7
—
7
Balance at September 30, 2017 $ 1,506
$ 8,717
$ 10,223
$ 57
$ 10,280














	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, 2020	$	1,505	$	787	$	7,301	$	9,593	$	145	$	9,738
Net income	37		12		373		422		1		423
Distributions	(37)		(12)		(130)		(179)		(6)		(185)
Other comprehensive income	—		—		108		108		—		108
Repurchase of common units (Note 7)	—		—		(3)		(3)		—		(3)
Contributions from noncontrolling interests	—		—		—		—		1		1
Other	—		—		2		2		—		2
Balance at March 31, 2021	$	1,505	$	787	$	7,651	$	9,943	$	141	$	10,084

Limited Partners
General
Partner

Partners’ Capital
Excluding
Noncontrolling
Interests

Noncontrolling
Interests

Total
Partners’
Capital

Series A
Preferred
Unitholders

Common
Unitholders

(unaudited)
Balance at December 31, 2015 $ —
$ 7,580
$ 301
$ 7,881
$ 58
$ 7,939
Net income —
209
390
599
3
602
Cash distributions to partners —
(835 ) (464 ) (1,299 ) (3 ) (1,302 )
Sale of Series A preferred units 1,509
—
33
1,542
—
1,542
Sales of common units —
283
6
289
—
289
Other (1 ) 3
2
4
—
4
Balance at September 30, 2016 $ 1,508
$ 7,240
$ 268
$ 9,016
$ 58
$ 9,074

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

Table of Contents

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~(unaudited)~~

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~~Our business model integrates large-scale supply aggregation capabilities with the ownership and ~~operate~~operation of critical midstream ~~energy~~ infrastructure systems that connect major producing regions to key demand centers and ~~provide logistics services for crude oil, natural gas liquids (“NGL”), natural gas and refined products. We~~export terminals. As one of the largest midstream service providers in North America, we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and ~~NGL~~natural gas liquids (“NGL”) producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. Our ~~business activities~~assets and the services we provide are primarily focused on and conducted through ~~three~~2 operating segments: ~~Transportation, Facilities~~Crude Oil and ~~Supply and Logistics.~~NGL. See Note 1311 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, 2017,~~March 31, 2022, AAP also owned ~~an approximate 36%~~a limited partner interest in us ~~represented by~~through its ownership of approximately ~~286.8~~241.5 million of our common ~~units.~~units (approximately 31% of our total outstanding common units and Series A preferred units combined). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole and managing member of GP LLC, and, at ~~September 30, 2017,~~March 31, 2022, owned ~~directly and indirectly,~~ an approximate ~~54%~~81% 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 (“PMC”).~~ULC.

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

~~Simplification Transactions~~

On November 15, 2016, the Plains Entities closed a series of transactions and executed several organizational and ancillary documents (the “Simplification Transactions”) intended to simplify our capital structure, better align the interests of our stakeholders and improve our overall credit profile. The Simplification Transactions included, among other things:

Table of ~~directors of PAGP GP assumed oversight responsibility over both us and PAGP;~~Contents

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

the provision for annual PAGP shareholder meetings beginning in 2018 for the purpose of electing certain directors with expiring terms in 2018, and the participation of our common unitholders and Series A preferred unitholders in such elections through our ownership of newly issued Class C shares in PAGP, which provide us, as the sole holder of such Class C shares, the right to vote in elections of eligible PAGP directors together with the holders of PAGP Class A and Class B shares;NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

the execution by AAP of a reverse split to adjust the number of AAP Class A units (“AAP units”) such that the number of outstanding AAP units (assuming the conversion of AAP Class B units (the “AAP Management Units”) into AAP units) equaled the number of our common units received by AAP at the closing of the Simplification Transactions. Simultaneously, PAGP executed a reverse split to adjust the number of PAGP Class A and Class B shares outstanding

to equal the number of AAP units it owns following AAP’s reverse unit split. These reverse splits, along with the Omnibus Agreement, resulted in economic alignment between our common unitholders and PAGP’s Class A shareholders, such that the number of outstanding PAGP Class A shares equals the number of AAP units owned by PAGP, which in turn equals the number of our common units held by AAP that are attributable to PAGP’s interest in AAP. The Plains Entities also entered into an Omnibus Agreement, pursuant to which such one-to-one relationship will be maintained subsequent to the closing of the Simplification Transactions; and

~~the creation of a right for certain holders of the AAP units to cause AAP to redeem such AAP units in exchange for an equal number of our common units held by AAP.~~

The Simplification Transactions were between and among consolidated subsidiaries of PAGP that are considered entities under common control. These equity transactions did not result in a change in the carrying value of the underlying assets and liabilities.

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~~EBITDA			=	~~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
~~LIBOR~~ISDA			=	International Swaps and Derivatives Association
LIBOR			=	London Interbank Offered Rate
LTIP			=	Long-term incentive plan
Mcf			=	Thousand cubic feet
~~NGL~~MMbls			=	Million barrels
NGL			=	Natural gas liquids, including ethane, propane and butane
NYMEX			=	New York Mercantile Exchange
~~Oxy~~SEC			=	~~Occidental Petroleum Corporation or its subsidiaries~~
~~PLA~~	=	~~Pipeline loss allowance~~
~~SEC~~	=	United States Securities and Exchange Commission
~~USD~~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 ~~2016~~2021 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. The condensed consolidated balance sheet data as of December 31, 2021 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three months ended March 31, 2022 should not be taken as indicative of results to be expected for the entire year. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current ~~presentation. The condensed consolidated balance sheet data as of December 31, 2016 was derived from audited financial~~presentation, including the reclassifications discussed below.

statements, but does not include all disclosures required by GAAP. The results of operations for the three and nine months ended September 30, 2017 should not be taken as indicative of results to be expected for the entire year.

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

Table of Contents

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Reclassification of Prior Period Information

During the fourth quarter of 2021, we effected changes in the primary financial information provided to our CODM (our Chief Executive Officer) for assessing performance and allocating resources to present 2 operating segments, Crude Oil and NGL. Prior to the fourth quarter of 2021, this information was organized into 3 operating segments: Transportation, Facilities and Supply and Logistics. See Note 11 for further discussion of our operating segments. In connection with this change, we changed the presentation of Revenues on our Condensed Consolidated Statements of Operations. “Product sales revenues” include amounts that were previously presented as “Supply and Logistics segment revenues,” while “Services revenues” includes amounts previously presented as “Transportation segment revenues” and “Facilities segment revenues.”

Note 2—Summary of Significant Accounting Policies

Restricted Cash

Restricted cash includes cash held by us that is unavailable for general use and is comprised of amounts advanced to us by certain equity method investees related to the construction of fixed assets where we serve as construction manager. The following table presents a reconciliation of cash and cash equivalents and restricted cash reported on our Condensed Consolidated Balance Sheets that sum to the total of the amounts shown on our Condensed Consolidated Statements of Cash Flows (in millions):


	March 31, 2022		December 31, 2021
Cash and cash equivalents	$	114	$	449
Restricted cash (1)	4		4
Total cash and cash equivalents and restricted cash	$	118	$	453

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

Recent Accounting Pronouncements

Except as discussed below and in our ~~2016~~2021 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, 2017~~March 31, 2022 that are of significance or potential significance to us.

~~Accounting Standards Updates Adopted During the Period~~

In ~~March 2016,~~August 2020, the FASB issued ASU ~~2016-09,~~ ~~Compensation — Stock Compensation (Topic 718)~~2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40): ~~Improvements to Employee Share-Based Payment~~ Accounting, for Convertible Instruments and Contracts in an Entity’s Own Equity, which ~~simplified several aspects~~simplifies accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity, by eliminating two of the three models that require separate accounting for ~~share-based payment~~

~~transactions, including~~embedded conversion features and the income tax consequences, forfeitures, classification of awards as either equity or liabilities and classification of certain related payments on the statement of cash flows. This guidance was effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We adopted the applicable provisions of the ASU on January 1, 2017 and (i) electedsettlement assessment that entities are required to account for forfeitures as they occur, utilizing the modified retrospective approach of adoption, and (ii) will classify cash paid for taxes when directly withholding units from an employee’s award for tax-withholding purposes as a financing activity on our Condensed Consolidated Statement of Cash Flows. Our adoption did not have a material impact on our financial position or results of operations for the periods presented. We reclassified approximately $6 million of cash outflows from operating activities to financing activities for the nine months ended September 30, 2016 related to cash paid for minimum statutory withholding requirements for which we withheld units from employees’ awards.

~~In January 2017, the FASB issued ASU 2017-04,~~ ~~Intangibles — Goodwill and Other (Topic 350):Simplifying the Test for Goodwill Impairment. The amendments within this ASU eliminate Step 2 from the goodwill impairment test, which currently requires an entity~~perform to determine ~~goodwill impairment by calculating the implied fair value of goodwill by hypothetically assigning the fair value of~~whether a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Under the amended standard, goodwill impairment will instead be measured using Step 1 of the goodwill impairment test with goodwill impairment being equal to the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value of goodwill.contract qualifies for equity classification. This guidance is effective for interim and annual periods beginning after December 15, ~~2019,~~2021, with early adoption permitted. We ~~early~~ adopted this ~~ASU in the first quarter of 2017 and applied the amendments therein to our 2017 annual goodwill impairment test.~~

~~Accounting Standards Updates Issued During the Period~~

~~In January 2017, the FASB issued ASU 2017-01,~~ ~~Business Combinations (Topic 805): Clarifying the Definition of a Business, which improves the~~ guidance ~~for determining whether a transaction involves the purchase or disposal of a business or an asset. This guidance is~~ effective ~~for interim and annual periods beginning after December 15, 2017, with early adoption permitted, and prospective application required. We plan to adopt this guidance on~~ January 1, ~~2018~~2022, and ~~will apply the new guidance to applicable transactions occurring after that date.~~

~~In February 2017, the FASB issued ASU 2017-05,~~ Other Income — Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. The update includes the following clarifications: (i) nonfinancial assets within the scope of Subtopic 610-20 may include nonfinancial assets transferred within a legal entity to a counterparty, (ii) an entity should allocate consideration to each distinct asset by applying the guidance in Topic 606 on allocating the transaction price to performance obligations and (iii) requires entities to derecognize a distinct nonfinancial asset or distinct in substance nonfinancial asset in a partial sale transaction when it (1) does not have (or ceases to have) a controlling financial interest in the legal entity that holds the asset in accordance with Subtopic 810-10 and (2) transfers control of the asset in accordance with Topic 606. This guidance is effective for interim and annual periods beginning after December 15, 2017, and must be adopted at the same time as Topic 606. We will adopt this guidance on January 1, 2018 and are currently evaluating the impact of the adoption on our financial position, results of operations and cash flows.

~~In May 2017, the FASB issued ASU 2017-09,~~ ~~Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting~~ to provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. Under the new guidance, modification accounting is required only if the fair value (or calculated value or intrinsic value, if such alternative method is used), the vesting conditions, or the classification of the award (equity or liability) changes as a result of the change in terms or conditions. This guidance is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted, and prospective application required. We expect to adopt this guidance on January 1, 2018, and we do not currently anticipate that our adoption ~~will~~did not have a material impact on our financial position, results of operations ~~and~~or cash flows.

~~In August 2017, the FASB issued ASU 2017-12,~~ ~~Derivatives~~

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 3—Revenues and ~~Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities~~ ~~to better align an entity’s risk management activities~~Accounts Receivable

Revenue Recognition

We disaggregate our revenues by segment and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. Under the new guidance, (i) more financial and nonfinancial hedging strategies will be eligible for hedge accounting, (ii) presentation and disclosure requirements are amended and (iii) companies will change the way they assess effectiveness. This guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. We expect to adopt this guidance on January 1, 2019 and are currently evaluating the impact of the adoption on our financial position, results of operations and cash flows.

~~Other Accounting Standards Updates~~

~~In May 2014, the FASB issued ASU 2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606)~~ with the underlying principle that an entity will recognize revenue to reflect amounts expected to be received in exchange for the provision of goods and services to customers upon the transfer of those goods or services. This ASU also requires additional disclosures. This ASU can be adopted either with a full retrospective approach or a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption and is effective for interim and annual periods beginning after December 15, 2017. We implemented a process to evaluate the impact of adopting this ASU on each type of revenue contract entered into with customers and our implementation team is in the process of determining appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We have not identified any significant revenue recognition timing differences for types of revenue streams assessed to date; however, our evaluation is not complete. In addition, we are assessing the impact of changes to disclosures and expect an increase in disclosures aboutactivity. These categories depict how the nature, amount, timing and uncertainty of ~~revenue~~revenues and ~~the related~~ cash ~~flows. We will adopt this guidance on January 1, 2018, and currently anticipate that we will apply the modified retrospective approach.~~

~~Note 3—Net Income/(Loss) Per Common Unit~~

~~We calculate basic and diluted net income/(loss) per common unit~~flows are affected by dividing net income attributable to PAA (after deducting amounts allocated to the preferred unitholders and participating securities, and for periods prior to the closing of the Simplification Transactions, the 2% general partner’s interest and IDRs) 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.

Diluted net income/(loss) per common unit 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, (ii) our LTIP awards and (iii) common units that are issuable to AAP when certain AAP Management Units become earned. When applying the if-converted method prescribed by FASB guidance, the possible conversion of our Series A preferred units was excluded from the calculation of diluted net income/(loss) per common unit for the three and nine months ended September 30, 2017 and 2016 as the effect was antidilutive. Our LTIP awards that contemplate the issuance of common units and certain AAP Management Units that contemplate the issuance of common units to AAP when such AAP Management Units become earned are considered dilutive unless (i) they become vested or earned only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that were deemed to be dilutive 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. LTIP awards were excluded from the computation of diluted net loss per common unit for the three months ended September 30, 2017 as the effect was antidilutive. As none of the necessary conditions for the remaining AAP Management Units to become earned had been satisfied by September 30, 2017, no common units issuable to AAP were contemplated in the calculation of diluted net income/(loss) per common unit for any period presented.economic factors. See Note 163 to our Consolidated Financial Statements included in Part IV of our ~~2016~~2021 Annual Report on Form 10-K for ~~a complete discussion~~additional information regarding our types of revenues and policies for revenue recognition.

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


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


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

Reconciliation to Total Revenues of Reportable Segments. The following disclosures only include information regarding revenues associated with consolidated entities; revenues from entities accounted for by the equity method are not included. The following tables present the reconciliation of our ~~LTIP awards including specific discussion regarding DERs.~~revenues from contracts with customers to total revenues of reportable segments and total revenues as disclosed in our Condensed Consolidated Statements of Operations (in millions):


Three Months Ended March 31, 2022	Crude Oil		NGL		Total
Revenues from contracts with customers	$	13,102	$	879	$	13,981
Other items in revenues	(23)		(144)		(167)
Total revenues of reportable segments	$	13,079	$	735	$	13,814
Intersegment revenue elimination					(120)
Total revenues					$	13,694

Three Months Ended March 31, 2021	Crude Oil		NGL		Total
Revenues from contracts with customers	$	7,946	$	801	$	8,747
Other items in revenues	(93)		(162)		(255)
Total revenues of reportable segments	$	7,853	$	639	$	8,492
Intersegment revenue elimination					(109)
Total revenues					$	8,383

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Minimum Volume Commitments. We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. The following table ~~sets forth~~presents counterparty deficiencies associated with contracts with customers and buy/sell arrangements that include minimum volume commitments for which we had remaining performance obligations and the ~~computation of basic and diluted net income/(loss) per common unit~~customers still had the ability to meet their obligations (in ~~millions, except per unit data)~~millions):

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Basic Net Income/(Loss) per Common Unit

Net income attributable to PAA $ 33
$ 297
665
599
Distributions to Series A preferred unitholders ⁽¹⁾
(36 ) (33 ) (105 ) (88 )
Distributions to general partner ⁽¹⁾
—
(102 ) —
(412 )
Distributions to participating securities⁽¹⁾
(1 ) (1 ) (2 ) (3 )
Undistributed loss allocated to general partner⁽¹⁾
—
1
—
14
Other (4 ) —
(11 ) —
Net income/(loss) allocated to common unitholders $ (8 ) $ 162
$ 547
$ 110

Basic weighted average common units outstanding 725
401
714
399

Basic net income/(loss) per common unit $ (0.01 ) $ 0.40
$ 0.77
$ 0.27

Diluted Net Income/(Loss) per Common Unit

Net income attributable to PAA $ 33
$ 297
$ 665
$ 599
Distributions to Series A preferred unitholders ⁽¹⁾
(36 ) (33 ) (105 ) (88 )
Distributions to general partner ⁽¹⁾
—
(102 ) —
(412 )
Distributions to participating securities⁽¹⁾
(1 ) (1 ) (2 ) (3 )
Undistributed loss allocated to general partner⁽¹⁾
—
1
—
14
Other (4 ) —
(11 ) —
Net income/(loss) allocated to common unitholders $ (8 ) $ 162
$ 547
$ 110

Basic weighted average common units outstanding 725
401
714
399
Effect of dilutive securities:
LTIP units —
1
1
1
Diluted weighted average common units outstanding 725
402
715
400

Diluted net income/(loss) per common unit $ (0.01 ) $ 0.40
$ 0.76
$ 0.27


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

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

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


⁽¹⁾	We calculate net income/(loss) allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (“undistributed loss”), if any, are allocated to the general partner, common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and	Contract Liabilities
Balance at December 31, 2021		$	141
Amounts recognized as further prescribed under the two-class method. The Simplification Transactions, which closed on November 15, 2016, simplified our governance structure and permanently eliminated our IDRs and the economic rights associated with our 2% general partner interest. Therefore, beginning with the distribution pertaining to the fourth quarter of 2016, our general partner is no longer entitled to receive distributions or allocations on such interests.revenue		(20)

Additions		16

Balance at March 31, 2022		$	137

~~Note 4—~~Remaining Performance Obligations. The information below includes the amount of consideration allocated to partially and wholly unsatisfied remaining performance obligations under contracts that exist as of the end of the periods and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These arrangements include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of March 31, 2022 (in millions):


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

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

•Acreage dedications;

•Buy/sell arrangements with future committed volumes;

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

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

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

Trade Accounts Receivable and Other Receivables, Net

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of ~~NGL~~NGL. These purchasers include, but are not limited to, refiners, producers, marketing and ~~natural gas.~~ trading companies and financial institutions. The majority of our accounts receivable relate to our crude oil merchant activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes.

To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions and perform credit reviews of each customer to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit, credit insurance or parental guarantees. As of September 30, 2017 and December 31, 2016, we had received $120 million and $89 million, respectively, of advance cash payments from third parties to mitigate credit risk. We also received $60 million and $66 million as of September 30, 2017 and December 31, 2016, respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. ~~Furthermore,~~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) ~~for a majority of net-cash settled arrangements.~~.

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, 2017~~March 31, 2022 and December 31, ~~2016,~~2021, 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, 2017 and December 31, 2016.~~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, 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, 2022		December 31, 2021
Trade accounts receivable arising from revenues from contracts with customers	$	5,496	$	4,031
Other trade accounts receivables and other receivables (1)	9,620		5,126
Impact due to contractual rights of offset with counterparties	(7,980)		(4,452)
Trade accounts receivable and other receivables, net	$	7,136	$	4,705

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 4—Net Income Per Common Unit

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

The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units and (ii) our equity-indexed compensation plan awards. See Note 12 and Note 18 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for a discussion of our Series A preferred units and equity-indexed compensation plan awards. When applying the if-converted method prescribed by FASB guidance, the possible conversion of approximately 71 million Series A preferred units, on a weighted-average basis, were excluded from the calculation of diluted net income per common unit for the three months ended March 31, 2022 and 2021 as the effect was antidilutive for both periods. Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that were deemed to be dilutive during the period 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. For the three months ended March 31, 2022, approximately 0.7 million equity-indexed compensation plan awards, on a weighted-average basis, were dilutive, but did not change the presentation of diluted net income per common unit or diluted weighted average common units outstanding. For the three months ended March 31, 2021, there were no potentially dilutive equity-indexed compensation awards as a result of the hypothetical common unit repurchase.

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


	Three Months Ended March 31,
		2022		2021
Basic and Diluted Net Income per Common Unit
Net income attributable to PAA		$	187	$	422
Distributions to Series A preferred unitholders		(37)		(37)
Distributions to Series B preferred unitholders		(12)		(12)
Distributions to participating securities		(1)		(1)
Other		—		(1)
Net income allocated to common unitholders (1)		$	137	$	371

Basic and diluted weighted average common units outstanding		705		722

Basic and diluted net income per common unit		$	0.19	$	0.51

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

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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, 2017 December 31, 2016
Volumes Unit of
Measure Carrying
Value
Price/
Unit ⁽¹⁾
Volumes Unit of
Measure Carrying
Value
Price/
Unit ⁽¹⁾
Inventory

Crude oil 10,632
barrels $ 480
$ 45.15
23,589
barrels $ 1,049
$ 44.47
NGL 16,604
barrels 390
$ 23.49
13,497
barrels 242
$ 17.93
Natural gas —
Mcf —
N/A
14,540
Mcf 32
$ 2.20
Other N/A
14
N/A
N/A
20
N/A
Inventory subtotal
884

1,343

Linefill and base gas

Crude oil 12,477
barrels 729
$ 58.43
12,273
barrels 710
$ 57.85
NGL 1,630
barrels 47
$ 28.83
1,660
barrels 45
$ 27.11
Natural gas 24,976
Mcf 108
$ 4.32
30,812
Mcf 141
$ 4.58
Linefill and base gas subtotal
884

896

Long-term inventory

Crude oil 1,800
barrels 86
$ 47.78
3,279
barrels 163
$ 49.71
NGL 2,120
barrels 49
$ 23.11
1,418
barrels 30
$ 21.16
Long-term inventory subtotal
135

193

Total
$ 1,903

$ 2,432


	March 31, 2022						December 31, 2021
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	4,711	barrels	$	420	$	89.15	8,041	barrels	$	544	$	67.65
NGL	2,329	barrels	102		$	43.80	6,982	barrels	234		$	33.51

Other	N/A		5		N/A		N/A		5		N/A
Inventory subtotal			527						783

Linefill
Crude oil	15,160	barrels	872		$	57.52	15,199	barrels	862		$	56.71
NGL	1,667	barrels	47		$	28.19	1,633	barrels	45		$	27.56

Linefill subtotal			919						907

Long-term inventory
Crude oil	3,289	barrels	325		$	98.81	2,973	barrels	209		$	70.30
NGL	1,071	barrels	49		$	45.75	1,135	barrels	44		$	38.77
Long-term inventory subtotal			374						253

Total			$	1,820					$	1,943


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

At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Condensed Consolidated Statements of Operations. We recorded a charge of $35 million during the nine months ended September 30, 2017 primarily related to the writedown of our crude oil inventory due to a decline in prices. Substantially all 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 inventory. Such gains were recorded to “Supply and Logistics segment revenues” in our accompanying Condensed Consolidated Statements of Operations. See Note 10 for discussion of our derivative and risk management activities. We recorded an inventory valuation adjustment of $3 million during the nine months ended September 30, 2016.

~~Note 6—Acquisitions and Dispositions~~

~~Acquisitions~~

The following acquisitions were accounted for using the acquisition method of accounting and the determination of the fair value of the assets and liabilities acquired has been estimated in accordance with the applicable accounting guidance.

~~Alpha Crude Connector Acquisition~~

On February 14, 2017, we acquired all of the issued and outstanding membership interests in Alpha Holding Company, LLC for cash consideration of approximately $1.217 billion, subject to working capital and other adjustments (the “ACC Acquisition”). The ACC Acquisition was initially funded through borrowings under our senior unsecured revolving credit facility. Such borrowings were subsequently repaid with proceeds from our March 2017 issuance of common units to AAP pursuant to the Omnibus Agreement and in connection with a PAGP underwritten equity offering. See ~~Note 9~~ ~~for additional information.~~

Upon completion of the ACC Acquisition, we became the owner of a crude oil gathering system known as the “Alpha Crude Connector” (the “ACC System”) located in the Northern Delaware Basin in Southeastern New Mexico and West Texas. The ACC System comprises approximately 515 miles of gathering and transmission lines and five market interconnects, including to our Basin Pipeline at Wink. We intend to make additional interconnects to our existing Northern Delaware Basin systems as well as additional enhancements intended to increase the ACC System capacity to approximately 350,000 barrels per day, depending on the level of volume at each delivery point. The ACC System is supported by acreage dedications covering approximately 315,000 gross acres, including a significant acreage dedication from one of the largest producers in the region. The ACC System complements our other Permian Basin assets and enhances the services available to the producers in the Northern Delaware Basin.

The determination of the acquisition-date fair value of the assets acquired and liabilities assumed is preliminary. We expect to finalize our fair value determination in 2017. The following table reflects the preliminary fair value determination (in millions):

Identifiable assets acquired and liabilities assumed: Estimated Useful Lives (Years) Recognized amount
Property and equipment 3 - 70 $ 299
Intangible assets 20 646
Goodwill N/A 271
Other assets and liabilities, net (including $4 million of cash acquired) N/A 1
$ 1,217

~~Intangible assets are included in “Other long-term assets, net” on our Condensed Consolidated Balance Sheets. The preliminary determination of fair value to intangible assets above~~ is comprised of ~~five acreage dedication contracts and associated customer relationships that will be amortized over~~ a ~~remaining~~ weighted average useful life of approximately 20 years. The value assigned to such intangible assets will be amortized to earnings using methods that closely resemble the pattern in which the economic benefits will be consumed. Amortization expense was approximately $7 million for the period from February 14, 2017 through September 30, 2017, and the future amortization expense is estimated as follows for the next five years (in millions):

Remainder of 2017 $ 3
2018 $ 25
2019 $ 34
2020 $ 42
2021 $ 48

Goodwill is an intangible asset representing the future economic benefits expected to be derived from other assets acquired that are not individually identified and separately recognized. The goodwill arising from the ACC Acquisition, which is tax deductible, represents the anticipated opportunities to generate future cash flows from undedicated acreage and the synergies created between the ACC System and our existing assets. The assets acquired in the ACC Acquisition, as well as the associated goodwill, are primarily included in our Transportation segment.

~~During the nine months ended September 30, 2017, we incurred approximately $6 million of acquisition-related costs~~ associated with ~~the ACC Acquisition. Such costs are reflected as a component of general~~various grades, qualities and ~~administrative expenses in our Condensed Consolidated Statements of Operations.~~locations. Accordingly, these prices may not coincide with any published benchmarks for such products.

Pro forma financial information assuming the ACC Acquisition had occurred as of the beginning of the calendar year prior to the year of acquisition, as well as the revenues and earnings generated during the period since the acquisition date, were not material for disclosure purposes.

~~Other Acquisitions~~

In February 2017, we acquired a propane marine terminal for cash consideration of approximately $41 million. The assets acquired are included in our Facilities segment. We did not recognize any goodwill related to this acquisition.

~~Investment Acquisition~~

On April 3, 2017, we and an affiliate of Noble Midstream Partners LP (“Noble”) completed the acquisition of Advantage Pipeline, L.L.C. (“Advantage”) for a purchase price of $133 million through a newly formed 50/50 joint venture (the “Advantage Joint Venture”). For our 50% share ($66.5 million), we contributed approximately 1.3 million common units with a value of approximately $40 million and approximately $26 million in cash. We account for our interest in the Advantage Joint Venture under the equity method of accounting.

Advantage owns a 70-mile, 16-inch crude oil pipeline located in the southern Delaware Basin (the “Advantage Pipeline”), which is contractually supported by a third-party acreage dedication and a volume commitment from our wholly-owned marketing subsidiary. Noble serves as operator of Advantage Pipeline. During the third quarter of 2017, Noble completed construction of a pipeline to deliver crude oil to the Advantage Pipeline from its central gathering facility in the southern Delaware Basin, and we completed construction of a pipeline to connect our Wolfbone Ranch facility to the Advantage Pipeline near Highway 285 in Reeves County, Texas.

~~Dispositions, Divestitures and Assets Held for Sale~~

~~During the nine months ended September 30, 2017, we received proceeds of approximately $407 million from the sale of certain non-core assets, including:~~

~~our Bluewater natural gas storage facility located in Michigan;~~

~~non-core pipeline segments primarily located in the Midwestern United States; and~~

a 40% undivided interest in a segment of our Red River Pipeline extending from Cushing, Oklahoma to the Hewitt Station near Ardmore, Oklahoma (the “Hewitt Segment”) for our net book value. We retained a 60% undivided

~~interest in the Hewitt Segment and a 100% interest in the remaining portion of the Red River Pipeline that extends from Ardmore to Longview, Texas.~~

~~Our Bluewater natural gas storage facility was reported in our Facilities segment, and the pipeline segments were reported in our Transportation segment.~~

As of September 30, 2017, we classified approximately $630 million of assets as held for sale on our Condensed Consolidated Balance Sheet (in “Other current assets”). The assets held for sale are primarily property and equipment, are included in our Facilities and Transportation segments and are related to transactions to sell our interests in:

~~certain non-core pipelines in the Rocky Mountain and Bakken regions, which closed during the fourth quarter of 2017; and~~

certain of our West Coast terminal assets located in California. During the third quarter of 2017, in order to avoid continued uncertainty and costs associated with efforts by the Attorney General for the State of California to block the proposed transaction, our previously disclosed definitive agreement for the potential sale of California terminal assets was jointly terminated by us and the potential third party purchaser. During the fourth quarter of 2017, we entered into definitive agreements to sell these assets to another third-party purchaser.

In the aggregate, including non-cash impairment losses recognized upon reclassification to assets held for sale, we recognized net losses related to pending or completed asset sales of approximately $15 million and $15 million for the three and nine months ended September 30, 2017, respectively, which are included in “Depreciation and amortization” on our Condensed Consolidated Statements of Operations. For the three-month period, such amount is comprised of gains of $5 million and losses of $20 million. For the nine-month 2017 period, such amount is comprised of gains of $42 million, primarily related to the sale of the non-core pipeline segments, including the write-off of a portion of the remaining book value, and losses of $57 million.

During the fourth quarter of 2017, we and an affiliate of CVR Refining, LP (“CVR Refining”) formed a 50/50 joint venture, Midway Pipeline LLC, which acquired from us the Cushing to Broome crude oil pipeline system. The Cushing to Broome pipeline system connects CVR Refining’s Coffeyville, Kansas refinery to the Cushing, Oklahoma oil hub. We will continue to serve as operator of the pipeline.

Note ~~7—Goodwill~~

~~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, 2016 $ 806
$ 1,034
$ 504
$ 2,344
Acquisitions ⁽¹⁾
271
—
—
271
Foreign currency translation adjustments 17
8
4
29
Dispositions and reclassifications to assets held for sale (13 ) (33 ) —
(46 )
Balance at September 30, 2017 $ 1,081
$ 1,009
$ 508
$ 2,598


⁽¹⁾	~~Goodwill is recorded at the acquisition date based on a preliminary fair value determination. This preliminary goodwill balance may be adjusted when the fair value determination is finalized.~~

We completed our goodwill impairment test as of June 30, 2017 using a qualitative assessment. We determined that it was more likely than not that the fair value of each reporting unit was greater than its respective book value; therefore, additional impairment testing was not necessary and goodwill was not considered impaired.

~~Note 8—~~6—Debt

Debt consisted of the following (in millions):

September 30,
2017 December 31, 2016
SHORT-TERM DEBT

Commercial paper notes, bearing a weighted-average interest rate of 2.4% and 1.6%, respectively⁽¹⁾
$ 93
$ 563
Senior secured hedged inventory facility, bearing a weighted-average interest rate of 2.3% and 1.8%, respectively⁽¹⁾
753
750
Senior notes:

6.13% senior notes due January 2017 —
400
Other 72
2
Total short-term debt ⁽²⁾
918
1,715

LONG-TERM DEBT
Senior notes, net of unamortized discounts and debt issuance costs of $69 and $76, respectively ⁽³⁾
9,881
9,874
Commercial paper notes, bearing a weighted-average interest rate of 2.4% and 1.6%, respectively ⁽³⁾
605
247
Other 3
3
Total long-term debt 10,489
10,124
Total debt ⁽⁴⁾
$ 11,407
$ 11,839


	March 31, 2022		December 31, 2021
SHORT-TERM DEBT
Commercial paper notes, bearing a weighted-average interest rate of 0.8% (1)	$	382	$	—


Senior notes:
3.65% senior notes due June 2022 (2)	—		750
2.85% senior notes due January 2023	400		—
Other	118		72
Total short-term debt	900		822

LONG-TERM DEBT
Senior notes, net of unamortized discounts and debt issuance costs of $52 and $54, respectively	7,931		8,329


Other	55		69
Total long-term debt	7,986		8,398
Total debt (3)	$	8,886	$	9,220


⁽¹⁾	We classified these commercial paper notes and credit facility borrowings as short-term as of September 30, 2017 and December 31, 2016, as these notes and borrowings were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.


⁽²⁾	As of September 30, 2017 and December 31, 2016, balance includes borrowings of $194 million and $410 million, respectively, for cash margin deposits with NYMEX and ICE, which are associated with financial derivatives used for hedging purposes.


⁽³⁾	As of September 30, 2017, we have classified our $600 million, 6.50% senior notes due May 2018 as long-term and as of both September 30, 2017 and December 31, 2016, we have classified a portion of our commercial paper notes as long-term based on our ability and intent to refinance such amounts on a long-term basis.

⁽⁴⁾

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

(3)Our fixed-rate senior notes ~~(including current maturities)~~ had a face value of approximately $8.4 billion and $9.1 billion as of March 31, 2022 and December 31, 2021, respectively. We estimated the aggregate fair value of these notes as of March 31, 2022 and December 31, 2021 to be approximately $8.4 billion and $9.9 billion and $10.3 billion as of September 30, 2017 and December 31, 2016, respectively. We estimated the aggregate fair value of these notes as of September 30, 2017 and December 31, 2016 to be approximately $10.0 billion and $10.4 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 and~~ commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for ~~our senior notes, credit facilities and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy.~~

~~Credit Facilities~~

~~In August 2017, we extended the maturity dates of~~ our senior ~~unsecured revolving credit facility, senior secured hedged inventory facility~~notes and ~~senior unsecured 364-day revolving credit facility to August 2022, August 2020~~commercial paper notes are based upon observable market data and August 2018, respectively, for each extending lender. Additionally, a provision was added to the 364-day revolving credit facility agreement whereby we may elect to have the entire principal balance of any loans outstanding on the maturity dateare classified in Level 2 of the ~~364-day revolving credit facility converted into a non-revolving term loan with a maturity date of August 2019.~~fair value hierarchy.

Borrowings and Repayments

Total borrowings under our credit facilities and commercial paper program for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2022 and ~~2016~~2021 were approximately ~~$52.6~~$5.6 billion and ~~$41.4~~$14.2 billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately ~~$52.7~~$5.2 billion and ~~$41.6~~$14.8 billion for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2022 and ~~2016,~~2021, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.

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

Letters of Credit

In connection with our ~~supply and logistics~~merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil ~~NGL~~ and ~~natural gas.~~NGL. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At ~~September 30, 2017~~March 31, 2022 and December 31, ~~2016,~~2021, we had outstanding letters of credit of ~~$95~~$34 million and ~~$73~~$98 million, respectively.

~~Senior Notes Repayments~~

~~Our $400 million, 6.13% senior notes were repaid in January 2017. We utilized cash on hand and available capacity under our commercial paper program and credit facilities to repay these notes.~~

Note 9—7—Partners’ Capital and Distributions

Units Outstanding

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


	Limited Partners
	Series A Preferred Units	Series B Preferred Units	Common Units
Outstanding at December 31, 2021	71,090,468	800,000	704,991,540
Repurchase and cancellation of common units under the Common Equity Repurchase Program	—	—	(2,375,299)
Issuances of common units under equity-indexed compensation plans	—	—	51,937
Outstanding at March 31, 2022	71,090,468	800,000	702,668,178


	Limited Partners
	Series A Preferred Units	Series B Preferred Units	Common Units
Outstanding at December 31, 2020	71,090,468	800,000	722,380,416

Repurchase and cancellation of common units under the Common Equity Repurchase Program	—	—	(350,000)
Issuances of common units under equity-indexed compensation plans	—	—	25,431
Outstanding at March 31, 2021	71,090,468	800,000	722,055,847

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Limited Partners
Preferred Units Common Units
Outstanding at December 31, 2016 64,388,853
669,194,419
Issuances of Series A preferred units in connection with in-kind distributions 3,941,096
—
Sales of common units —
54,119,893
Issuance of common units in connection with acquisition of interest in Advantage Joint Venture (Note 6) —
1,252,269
Issuances of common units under LTIP —
622,557
Outstanding at September 30, 2017 68,329,949
725,189,138

Common Equity Repurchase Program

Limited Partners
Preferred Units Common Units
Outstanding at December 31, 2015 —
397,727,624
Sale of Series A preferred units 61,030,127
—
Issuance of Series A preferred units in connection with in-kind distribution 2,096,204
—
Sales of common units —
9,922,733
Issuance of common units under LTIP —
457,289
Outstanding at September 30, 2016 63,126,331
408,107,646

~~Sales of Common Units~~

~~The following table summarizes our sales of~~We repurchased 2.4 million and 0.4 million common units under our Common Equity Repurchase Program (the “Program”) through open market purchases that settled during the ~~nine~~three months ended ~~September 30, 2017, all~~March 31, 2022 and 2021, respectively, for a total purchase price of ~~which occurred~~$25 million and $3 million, respectively, including commissions and fees. The repurchased common units were canceled immediately upon acquisition, as were the PAGP Class C shares held by us associated with the repurchased common units. At March 31, 2022, the remaining available capacity under the Program was $247 million. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for additional information regarding the ~~first four months of the year (net proceeds in millions):~~ Program.

Type of Offering Common Units Issued
Net Proceeds ⁽¹⁾

Continuous Offering Program 4,033,567
$ 129
(2 )
Omnibus Agreement ⁽³⁾
50,086,326
(4 ) 1,535

54,119,893
$ 1,664


⁽¹⁾	~~Amounts are net of costs associated with the offerings.~~


⁽²⁾	We pay commissions to our sales agents in connection with common units issuances under our Continuous Offering Program. We paid $1 million of such commissions during the nine months ended September 30, 2017.

⁽³⁾

Pursuant to the Omnibus Agreement entered into by the Plains Entities in connection with the Simplification Transactions, PAGP has agreed to use the net proceeds from any public or private offering and sale of Class A shares, after deducting the sales agents’ commissions and offering expenses, to purchase from AAP a number of AAP units equal to the number of Class A shares sold in such offering at a price equal to the net proceeds from such offering. The Omnibus Agreement also provides that immediately following such purchase and sale, AAP will use the net proceeds it receives from such sale of AAP units to purchase from us an equivalent number of our common units.


⁽⁴⁾	Includes (i) approximately 1.8 million common units issued to AAP in connection with PAGP’s issuance of Class A shares under its Continuous Offering Program and (ii) 48.3 million common units issued to AAP in connection with PAGP’s March 2017 underwritten offering.

Distributions

~~Common~~Series A Preferred Unit Distributions. During the third quarter of 2017, we engaged in discussions with the PAGP GP Board regarding a reassessment of our approach to distributions, with a focus on resetting our common unit distribution to a level supported by the distributable cash flow from our fee-based Transportation and Facilities segments. On August 25, 2017, we announced our intention to reset our annualized distribution to $1.20 per common unit, beginning with the third-quarter distribution payable November 14, 2017. On October 10, 2017, the PAGP GP Board declared a distribution of $1.20 (annualized) per common unit payable on November 14, 2017 to common unitholders of record as of October 31, 2017.

The following table details ~~the~~ distributions to our Series A preferred unitholders paid ~~in cash~~ during or pertaining to the first ~~nine~~three months of ~~2017~~2022 (in millions, except per unit data):

Distributions Cash Distribution per Common Unit
Common Unitholders Total Cash Distribution
Distribution Payment Date Public AAP
November 14, 2017 ⁽¹⁾
$ 132
$ 86
$ 218
$ 0.30
August 14, 2017 $ 240
$ 159
$ 399
$ 0.55
May 15, 2017 $ 240
$ 159
$ 399
$ 0.55
February 14, 2017 $ 237
$ 134
$ 371
$ 0.55


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


May 13, 2022 (1)	$	37	$	0.525
February 14, 2022	$	37	$	0.525


⁽¹⁾	~~Payable to unitholders of record at the close of business on October 31, 2017 for the period July 1, 2017 through September 30, 2017.~~

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

Series AB Preferred Unit Distributions. ~~With respect to any quarter ending~~Distributions on or prior to December 31, 2017 (the “Initial Distribution Period”), we may elect to pay distributions on the Series A preferred units in additional preferred units, in cash or a combination of both. With respect to any quarter ending after the Initial Distribution Period, we must pay distributions on the Series A preferred units in cash. On February 14, 2017, we issued 1,287,773 Series A preferred units in lieu of a cash distribution of $34 million on our Series A preferred units outstanding as of the record date for such distribution. On May 15, 2017, we issued 1,313,527 Series A preferred units in lieu of a cash distribution of $34 million on our Series A preferred units outstanding as of the record date for such distribution. On August 14, 2017, we issued 1,339,796 Series A preferred units in lieu of a cash distribution of $35 million on our Series A preferred units outstanding as of the record date for such distribution.

On November 14, 2017, we will issue 1,366,593 Series A preferred units in lieu of a cash distribution of $36 million on our Series A preferred units outstanding as of October 31, 2017, the record date for such distribution. Since the November 14, 2017 Series A preferred unit distribution was declared as payment-in-kind, this distribution payable was accrued to partners’ capital as of September 30, 2017 and thus had no net impact on the Series A preferred unitholders’ capital account.

~~Issuance of Series B Preferred Units~~

On October 10, 2017, we issued 800,000 Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in us (the “Series B preferred units”) at a price to the public of $1,000 per unit. We used the net proceeds of $788 million, after deducting the underwriters’ discounts and offering expenses, from the issuance of the Series B preferred units to repay amounts outstanding under our credit facilities and commercial paper program and for general partnership purposes.

The Series B preferred units represent perpetual equity interests in us, and they have no stated maturity or mandatory redemption date and are not redeemable at the option of the holders under any circumstances. Holders of the Series B preferred units generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our partnership agreement that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series B preferred units, (ii) the creation or issuance of any parity securities if the cumulative distributions payable on then outstanding Series B preferred units are in arrears, (iii) the creation or issuance of any senior securities and (iv) the payment of distributions to our common unitholders out of capital surplus. The Series B preferred units rank, as to the payment of distributions and amounts payable on a liquidation event, on par with our outstanding Series A preferred units.

~~The Series B preferred units have a liquidation preference of $1,000 per unit. Holders of~~ our Series B preferred units are entitled to receive, when, as and if declared by our general partner out of legally available funds for such purpose, cumulative semiannual or quarterly cash distributions, as applicable. Distributions on the Series B preferred units accrue and are cumulative from October 10, 2017, the date of original issue, and are payable ~~semiannually~~semi-annually in arrears on the 15th day of May and ~~November through and including November 15, 2022, and after November 15, 2022, quarterly in arrears on the 15th day of February, May, August and November of each year.~~November. The ~~initial distribution rate for the~~following table details distributions paid to our Series B preferred ~~units from and including October 10, 2017 to, but not including, November 15, 2022 is 6.125% per year of the liquidation preference~~unitholders (in millions, except per unit ~~(equal~~data):


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

May 16, 2022 (1)	$	24.5	$	30.625

(1)Payable to $61.25 per unit per year). On and after November 15, 2022, distributions on the Series B preferred units will accumulate for each distribution period at a percentage of the liquidation preference equal to the then-current three-month LIBOR plus a spread of 4.11%. We will pay a pro-rated initial distribution on the Series B preferred units on November 15, 2017 to holdersunitholders of record at the close of business on May 2, 2022 for the period from November ~~1, 2017 in an amount equal~~15, 2021 through May 14, 2022.

At March 31, 2022, approximately $18 million of accrued distributions payable to ~~approximately $5.9549 per unit (a total distribution of approximately $5 million).~~

~~Upon the occurrence of certain rating agency events, we may redeem the~~our Series B preferred ~~units,~~unitholders was included in ~~whole but not~~“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 three months of 2022 (in millions, except per unit data):


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


May 13, 2022 (1)	$	100	$	53	$	153	$	0.2175
February 14, 2022	$	84	$	43	$	127	$	0.1800

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

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Noncontrolling Interests in ~~part, at~~Subsidiaries

As of March 31, 2022, noncontrolling interests in our subsidiaries consisted of (i) a ~~price of $1,020 (102% of~~35% interest in Plains Oyrx Permian Basin LLC (the “Permian JV”) and (ii) a 33% interest in Red River Pipeline Company LLC (“Red River LLC”).

During the liquidation preference) per Series B preferred unit plus an amount equal to all accumulated and unpaid distributions thereon to, but not including, the date of redemption, whether or not declared. In addition, at any time on or after November 15,three months ended March 31, 2022, we ~~may redeem~~paid distributions of $54 million and $5 million to noncontrolling interests in the ~~Series B preferred units, at our option, in whole or in part, at a redemption price of $1,000 per Series B preferred unit plus an amount equal to all accumulated~~Permian JV and ~~unpaid distributions thereon to, but not including, the date of redemption, whether or not declared.~~Red River LLC, respectively.

Note ~~10—~~8—Derivatives and Risk Management Activities

We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. ~~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~~optimize our profits while managing 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. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on changes in commodity prices, interest rates or currency exchange rates. When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. ~~Both at~~At the inception of ~~the hedge and throughout~~ the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions.

Throughout the hedging relationship, retrospective and prospective hedge effectiveness is assessed on a qualitative basis.

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

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

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

Commodity Price Risk Hedging

Our core business activities involve certain commodity price-related risks that we manage in various ways, including through the use of derivative instruments. Our policy is to (i) only purchase inventory for which we have a sales market, (ii) structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold material physical inventory or derivatives for the purpose of speculating on commodity price changes. The material commodity-related risks inherent in our business activities can be divided into the following general categories:

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2017,~~March 31, 2022, net derivative positions related to these activities included:

•A net long position of ~~6.9~~6.6 million barrels associated with our crude oil purchases, which was unwound ratably during ~~October 2017~~April 2022 to match monthly average pricing.

•A net short time spread position of ~~3.5~~5.3 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through ~~December 2018.~~May 2023.

•A net crude oil ~~grade~~ basis spread position of ~~25.2~~1.2 million barrels at multiple locations through ~~December 2019.~~November 2023. These derivatives allow us to lock in grade and location basis differentials.

•A net short position of ~~14.4~~11.0 million barrels through December ~~2020~~2023 related to anticipated net sales of ~~our~~ crude oil and NGL inventory.

~~Pipeline Loss Allowance Oil~~ — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We utilize derivative instruments to hedge a portion of the anticipated sales of the loss allowance oil that is to be collected under our tariffs. As of September 30, 2017, our PLA hedges included a long call option position of 1.0 million barrels through December 2019.

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. ~~As of September 30, 2017, we had a long natural gas position of 63.9 Bcf which hedges~~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 ~~operational needs through December 2020. We also had a short propane position~~NGL fractionation activities as of 10.0 million barrels through December 2018, a short butane position of 3.0 million barrels through December 2018 and a short WTI position of 1.0 million barrels through December 2018. In addition, we had a long power position of 0.4 million megawatt hours, which hedgesMarch 31, 2022:

Notional Volume

(Short)/Long

Remaining Tenor

Natural gas purchases

82.6 Bcf

December 2024

Propane sales

(15.5) MMbls

December 2024

Butane sales

(3.8) MMbls

December 2024

Condensate sales

(1.5) MMbls

December 2024

Fuel gas requirements (1)

8.8 Bcf

December 2023

Power supply requirements (1)

0.5 TWh

December 2023

(1)Positions to hedge a portion of our power supply and fuel gas requirements at our Canadian natural gas processing and fractionation ~~plants through December 2019.~~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 risk 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. TheseOur commodity derivatives are not designated in a hedging relationship for accounting purposes; as ~~cash flow hedges. As~~ such, changes in the fair value are ~~deferred~~reported in ~~AOCI and are reclassified to interest expense as we incur the interest expense associated with the underlying debt.~~

earnings. The following table summarizes the ~~terms~~impact of our ~~outstanding interest derivatives as of September 30, 2017 (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 16 forward starting swaps (30-year) $ 400
6/15/2018 2.86 % Cash flow hedge
Anticipated interest payments 8 forward starting swaps (30-year) $ 200
6/14/2019 2.83 % Cash flow hedge

~~Currency Exchange Rate Risk Hedging~~

Because a significant portion of our Canadian business is conducted in CAD and, at times, a portion of our debt is denominated 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.

As of September 30, 2017, our outstanding foreign currency derivatives include derivatives we use to hedge currency exchange risk (i) associated with USD-denominated commodity purchases and sales in Canada and (ii) created by the use of USD-denominated commodity derivatives ~~to hedge commodity price risk associated with CAD-denominated commodity purchases and sales.~~

~~The following table summarizes our open forward exchange contracts as of September 30, 2017~~recognized in earnings (in millions):

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

2017 $ 174
$ 215
$1.00 - $1.24
2018 $ 12
$ 15
$1.00 - $1.22

Forward exchange contracts that exchange USD for CAD:

2017 $ 307
$ 385
$1.00 - $1.26
2018 $ 118
$ 147
$1.00 - $1.25


	Three Months Ended March 31,
		2022		2021
Product sales revenues		$	(213)	$	(314)
Field operating costs		13		39

Net loss from commodity derivative activity		$	(200)	$	(275)

~~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. Corresponding changes in fair value are recognized in “Other income/(expense), net” in our Condensed Consolidated Statement of Operations. At September 30, 2017 and December 31, 2016, the fair value of this embedded derivative was a liability of approximately $33 million and $32 million, respectively. We recognized a gain of approximately $2 million during the three months ended September 30, 2017 and a net gain of less than $1 million during the nine months ended September 30, 2017. We recognized gains of approximately $17 million and $42 million during the three and nine months ended September 30, 2016. See Note 11 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for additional information regarding the 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 that qualify as cash flow hedges, changes in fair value of the effective portion of the hedges are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions are recognized in earnings. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of the hedged items 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.

~~A summary of the impact of our derivative activities recognized in earnings is as follows (in millions):~~

Three Months Ended September 30, 2017 Three Months Ended September 30, 2016
Location of Gain/(Loss)
Derivatives in
Hedging
Relationships ⁽¹⁾
Derivatives
Not Designated
as a Hedge Total
Derivatives in
Hedging
Relationships ⁽¹⁾
Derivatives
Not Designated
as a Hedge Total
Commodity Derivatives

Supply and Logistics segment revenues $ —
$ (226 ) $ (226 ) $ 1
$ 10
$ 11

Transportation segment revenues —
—
—
—
1
1

Field operating costs —
(4 ) (4 ) —
(2 ) (2 )

Interest Rate Derivatives

Interest expense, net (10 ) —
(10 ) (2 ) —
(2 )

Foreign Currency Derivatives

Supply and Logistics segment revenues —
3
3
—
(1 ) (1 )

Preferred Distribution Rate Reset Option

Other income/(expense), net —
2
2
—
17
17

Total Gain/(Loss) on Derivatives Recognized in Net Income $ (10 ) $ (225 ) $ (235 ) $ (1 ) $ 25
$ 24

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016
Location of Gain/(Loss)
Derivatives in
Hedging
Relationships ⁽¹⁾
Derivatives
Not Designated
as a Hedge Total
Derivatives in
Hedging
Relationships ⁽¹⁾
Derivatives
Not Designated
as a Hedge Total
Commodity Derivatives

Supply and Logistics segment revenues $ —
$ (31 ) $ (31 ) $ 1
$ (118 ) $ (117 )

Transportation segment revenues —
—
—
—
4
4

Field operating costs —
(8 ) (8 ) —
(2 ) (2 )

Depreciation and amortization (3 ) —
(3 ) —
—
—

Interest Rate Derivatives

Interest expense, net (16 ) —
(16 ) (8 ) —
(8 )

Foreign Currency Derivatives

Supply and Logistics segment revenues —
5
5
—
4
4

Preferred Distribution Rate Reset Option

Other income/(expense), net —
—
—
—
42
42

Total Gain/(Loss) on Derivatives Recognized in Net Income $ (19 ) $ (34 ) $ (53 ) $ (7 ) $ (70 ) $ (77 )

⁽¹⁾

During the three and nine months ended September 30, 2017, we reclassified losses of approximately $8 million and $10 million to Interest expense, net, respectively, due to anticipated hedged transactions being probable of not occurring. During the nine months ended September 30, 2016 we reclassified losses of approximately $2 million and $2 million to Supply and Logistics segment revenues and Interest expense, net, respectively, due to anticipated hedged transactions being probable of not occurring.

~~The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of September 30, 2017 (in millions):~~

Asset Derivatives Liability Derivatives
Balance Sheet
Location Fair
Value Balance Sheet
Location Fair
Value
Derivatives designated as hedging instruments:

Interest rate derivatives Other current liabilities $ 2
Other current liabilities $ (26 )

Other long-term liabilities and deferred credits (10 )
Total derivatives designated as hedging instruments $ 2
$ (36 )

Derivatives not designated as hedging instruments:

Commodity derivatives Other current assets $ 74
Other current assets $ (184 )
Other long-term assets, net 1
Other current liabilities (97 )
Other current liabilities 10
Other long-term liabilities and deferred credits (19 )
Other long-term liabilities and deferred credits 5

Foreign currency derivatives Other current assets 6
Other current assets (2 )

Other current liabilities (2 )

Preferred Distribution Rate Reset Option —
Other long-term liabilities and deferred credits (33 )
Total derivatives not designated as hedging instruments $ 96
$ (337 )

Total derivatives $ 98
$ (373 )

~~The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of December 31, 2016 (in millions):~~

Asset Derivatives Liability Derivatives
Balance Sheet
Location Fair
Value Balance Sheet
Location Fair
Value
Derivatives designated as hedging instruments:

Interest rate derivatives $ —
Other current liabilities $ (23 )

Other long-term liabilities and deferred credits (27 )
Total derivatives designated as hedging instruments $ —
$ (50 )

Derivatives not designated as hedging instruments:

Commodity derivatives Other current assets $ 101
Other current assets $ (344 )
Other long-term assets, net 2
Other long-term assets, net (1 )
Other long-term liabilities and deferred credits 2
Other current liabilities (14 )

Other long-term liabilities and deferred credits (34 )

Foreign currency derivatives Other current liabilities 3
Other current liabilities (6 )

Preferred Distribution Rate Reset Option —
Other long-term liabilities and deferred credits (32 )
Total derivatives not designated as hedging instruments $ 108
$ (431 )

Total derivatives $ 108
$ (481 )

Our derivative transactions are governed through ISDA (International Swaps and Derivatives Association) 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.

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:~~receivable (in millions):


	September 30, 2017		December 31, 2016			March 31, 2022		December 31, 2021
Initial margin	$	51	$	119	Initial margin	$	102	$	133
Variation margin posted	143		291		Variation margin posted	296		173
Letters of credit					Letters of credit	(25)		(47)
Net broker receivable	$	194	$	410	Net broker receivable	$	373	$	259

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

Interest Rate Risk Hedging

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

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

September 30, 2017 December 31, 2016
Derivative
Asset Positions Derivative
Liability Positions Derivative
Asset Positions Derivative
Liability Positions
Netting Adjustments:

Gross position - asset/(liability) $ 98
$ (373 ) $ 108
$ (481 )
Netting adjustment (203 ) 203
(350 ) 350
Cash collateral paid 194
—
410
—
Net position - asset/(liability) $ 89
$ (170 ) $ 168
$ (131 )

Balance Sheet Location After Netting Adjustments:

Other current assets $ 88
$ —
$ 167
$ —
Other long-term assets, net 1
—
1
—
Other current liabilities —
(113 ) —
(40 )
Other long-term liabilities and deferred credits —
(57 ) —
(91 )
$ 89
$ (170 ) $ 168
$ (131 )

Hedged Transaction

Number and Types of
Derivatives Employed

Notional
Amount

Expected
Termination Date

Average Rate
Locked

Accounting
Treatment

Anticipated interest payments

8 forward starting swaps

(30-year)

200��

6/15/2023

1.38

Cash flow hedge

Anticipated interest payments

8 forward starting swaps

(30-year)

200

6/14/2024

0.73

Cash flow hedge

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As of ~~September 30, 2017,~~March 31, 2022, there was a net loss of ~~$224~~$173 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 transaction or (ii)~~ interest expense accruals associated with underlying debt instruments. OfWe estimate that substantially all of the ~~total net loss deferred in AOCI at September 30, 2017, we expect to reclassify a net loss of $8 million to earnings in the next twelve months. The~~ remaining deferred loss ~~of $216 million is expected to~~will be reclassified to earnings through ~~2049.~~2054 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of ~~September 30, 2017;~~March 31, 2022; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Interest rate derivatives, net $ (3 ) $ (20 ) $ (15 ) $ (178 )


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

At March 31, 2022, the net fair value of our interest rate hedges, which were included in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet, totaled $97 million. At December 31, 2021, the net fair value of these hedges totaled $65 million and was included in “Other long-term assets, net.”

Preferred Distribution Rate Reset Option

~~At September 30, 2017~~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 in a hedging relationship for accounting purposes and corresponding changes in fair value are recognized in “Other expense, net” in our Condensed Consolidated Statement of Operations. For the three months ended March 31, 2022 and 2021, we recognized losses of $44 million and $67 million, respectively. The fair value of the Preferred Distribution Rate Reset Option, which was included in “Other long-term liabilities and deferred credits” on our Condensed Consolidated Balance Sheets, totaled $44 million and less than $1 million at March 31, 2022 and December 31, ~~2016, none~~2021, respectively. See Note 12 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~~2021 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.

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, 2017 Fair Value as of December 31, 2016
Recurring Fair Value Measures ⁽¹⁾
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Commodity derivatives $ (4 ) $ (198 ) $ (8 ) $ (210 ) $ (113 ) $ (171 ) $ (4 ) $ (288 )
Interest rate derivatives —
(34 ) —
(34 ) —
(50 ) —
(50 )
Foreign currency derivatives —
2
—
2
—
(3 ) —
(3 )
Preferred Distribution Rate Reset Option —
—
(33 ) (33 ) —
—
(32 ) (32 )
Total net derivative liability $ (4 ) $ (230 ) $ (41 ) $ (275 ) $ (113 ) $ (224 ) $ (36 ) $ (373 )


	Fair Value as of March 31, 2022								Fair Value as of December 31, 2021
Recurring Fair Value Measures (1)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivatives	$	(76)	$	(73)	$	—	$	(149)	$	(17)	$	(124)	$	(2)	$	(143)
Interest rate derivatives	—		97		—		97		—		65		—		65

Preferred Distribution Rate Reset Option and Other	—		—		(44)		(44)		—		—		—		—
Total net derivative asset/(liability)	$	(76)	$	24	$	(44)	$	(96)	$	(17)	$	(59)	$	(2)	$	(78)


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

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

Level 1

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

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 ~~value~~values of these derivatives ~~is based on broker price quotations which~~ 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 ~~value~~values of our Level 3 physical commodity and other contracts isand over-the-counter options are based on a valuation ~~model~~models utilizing significant timing estimates, which involve management ~~judgment.~~judgment, and pricing inputs from observable and unobservable markets with less volume and transaction frequency than active markets. Significant ~~changes in timing~~deviations from these estimates and inputs could result in a material change in fair ~~value to our physical commodity contracts.~~value. We report unrealized gains and losses associated with these ~~physical commodity~~ contracts in our Condensed Consolidated Statements of Operations as ~~Supply and Logistics segment~~Product sales 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~~Treasury rates, default probabilities and timing estimates, some of which involve management judgment. A significant ~~increase or decrease~~change in ~~the value of~~ 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 as “Other income/(expense), net.”~~

~~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,							Three Months Ended March 31,
	2017			2016			2017			2016					2022		2021
Beginning Balance	$	(30	)	$	(35	)	$	(36	)	$	11		Beginning Balance		$	(2)	$	(29)
Net gains/(losses) for the period included in earnings	(8		)	17			(1		)	41
Net losses for the period included in earnings													Net losses for the period included in earnings		(44)		(67)
Settlements	(1		)	—			4			(10		)	Settlements		2		4
Derivatives entered into during the period	(2		)	1			(8		)	(59		)

Ending Balance	$	(41	)	$	(17	)	$	(41	)	$	(17	)	Ending Balance		$	(44)	$	(92)

Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period	$	(10	)	$	18		$	(8	)	$	43
Change in unrealized losses included in earnings relating to Level 3 derivatives still held at the end of the period													Change in unrealized losses included in earnings relating to Level 3 derivatives still held at the end of the period		$	(44)	$	(67)

See Note 1517 to our Consolidated Financial Statements included in Part IV of our ~~2016~~2021 Annual Report on Form 10-K for a complete discussion of related parties, including the determination of our related ~~party transactions.~~parties and nature of involvement with such related parties.

~~Omnibus Agreement~~

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

Pursuant to the Omnibus Agreement entered into by the Plains Entities in connection with the Simplification Transactions, we issued approximately 1.8 million units to AAP in connection with PAGP’s issuance of Class A shares under its Continuous Offering Program and 48.3 million units to AAP in connection with PAGP’s March 2017 underwritten offering. See Note 9 for additional information.NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~Transactions with Oxy~~

~~As of September 30, 2017, Oxy had a representative on the board of directors of PAGP GP and owned approximately 10% of the limited partner interests in AAP.~~ During the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2022 and ~~2016,~~2021, we recognized sales and transportation revenues, ~~and~~ purchased petroleum products and utilized transportation and storage services from ~~Oxy.~~our related parties. 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 ~~those~~these transactions is included below (in millions):

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Revenues $ 204
$ 171
$ 657
$ 424

Purchases and related costs ⁽¹⁾
$ (68 ) $ 4
$ (169 ) $ (46 )


	Three Months Ended March 31,
		2022		2021
Revenues from related parties		$	12	$	7

Purchases and related costs from related parties		$	97	$	90

~~We currently have a netting arrangement with Oxy.~~ Our ~~gross~~ receivable and payable amounts with ~~Oxy~~these related parties as reflected on our Condensed Consolidated Balance Sheets were as follows (in millions):

September 30,
2017 December 31, 2016
Trade accounts receivable and other receivables $ 877
$ 789

Accounts payable $ 833
$ 836


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

Trade accounts payable to related parties (1) (2)	$	75	$	72

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

(2)We have agreements to store crude oil at facilities and transport crude oil or utilize capacity on pipelines that are owned by equity method investees. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities.

Loss Contingencies — General

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

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

Legal Proceedings — General

In the ordinary course of business, we are involved in various legal proceedings, including those arising from regulatory and environmental matters. In connection with determining the probability of loss associated with such legal proceedings and whether any potential losses associated therewith are estimable, we take into account what we believe to be all relevant known facts and circumstances, and what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing agreements, laws and regulations. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully protect us from losses arising from current or future legal proceedings.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

Environmental — General

~~Although over~~We currently own or lease, and in the ~~course~~past have owned and leased, properties where hazardous liquids, including hydrocarbons, are or have been handled. These properties and the hazardous liquids or associated wastes disposed thereon may be subject to the U.S. federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, and the U.S. federal Resource Conservation and Recovery Act, as amended, as well as state and Canadian federal and provincial laws and regulations. Under such laws and regulations, we could be required to remove or remediate hazardous liquids or associated wastes (including wastes disposed of or released by prior owners or operators) and to clean up contaminated property (including contaminated groundwater). Assets we have acquired or will acquire in the ~~last several years~~future may have environmental remediation liabilities for which we are not indemnified.

Although 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. We also may discover environmental impacts from past releases that were previously unidentified. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

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

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

At ~~September 30, 2017,~~March 31, 2022, our estimated undiscounted reserve for environmental liabilities ~~(including~~(excluding liabilities related to the Line 901 incident, as discussed further below) totaled ~~$134~~$59 million, of which ~~$47~~$9 million was classified as short-term and ~~$87~~$50 million was classified as long-term. At December 31, ~~2016,~~2021, our estimated undiscounted reserve for environmental liabilities ~~(including~~(excluding liabilities related to the Line 901 incident) totaled ~~$147~~$57 million, of which ~~$61~~$11 million was classified as short-term and ~~$86~~$46 million was classified as long-term. ~~The short- and long-term environmental~~Such short-term liabilities ~~referenced above~~ are reflected in ~~“Accounts payable~~“Other current liabilities” and ~~accrued liabilities” and~~long-term liabilities are reflected in “Other long-term liabilities and deferred ~~credits,” respectively,~~credits” on our Condensed Consolidated Balance Sheets. At ~~September 30, 2017,~~both March 31, 2022 and December 31, 2021, we had recorded receivables (excluding receivables related to the Line 901 incident) totaling ~~$47~~$11 million, for amounts probable of recovery under insurance and from third parties under indemnification agreements, $1 million of which ~~$26 million was~~for each period is reflected in “Other long-term assets, net” and the remainder is reflected in “Trade accounts receivable and other receivables, net” ~~and $21 million was reflected in “Other long-term assets, net”~~ on our Condensed Consolidated Balance Sheet. At December 31, 2016, we had recorded $56 million of such receivables, of which $39 million was reflected in “Trade accounts receivable and other receivables, net” and $17 million was reflected in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet.Sheets.

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

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Specific Legal, Environmental or Regulatory Matters

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

As a result of the Line 901 incident, several governmental agencies and regulators initiated investigations into the Line 901 incident, various claims have been made against us and a number of lawsuits have been filed against ~~us. We may be subject to additional claims, investigations and lawsuits,~~us, the majority of which ~~could materially impact the liabilities and costs we currently expect to incur as a result of the Line 901 incident.~~have been resolved. Set forth below is a brief summary of actions and matters that are currently ~~pending:~~pending or recently resolved:

As the “responsible party” for the Line 901 incident we are liable for various costs and for certain natural resource damages under the Oil Pollution Act. In this regard, following the Line 901 incident, we entered into a cooperative Natural Resource Damage Assessment (“NRDA”) process with the federal and state agencies designated or authorized by law to act as trustees for the natural resources of the United States and the State of California (collectively, the “Trustees”). Additionally, various government agencies sought to collect civil fines and penalties under applicable state and federal regulations. On ~~May 21, 2015, we received~~March 13, 2020, the United States and the People of the State of California filed a ~~corrective action order from~~civil complaint against Plains All American Pipeline, L.P. and Plains Pipeline L.P. along with a pre-negotiated settlement agreement in the form of a Consent Decree (the “Consent Decree”) that was signed by the United States Department of ~~Transportation’s~~Justice, Environmental and Natural Resources Division, the United States Department of Transportation, Pipeline and Hazardous Materials Safety Administration, ~~(“PHMSA”),~~ the ~~governmental agency with jurisdiction over~~EPA, CDFW, the ~~operation~~California Department of ~~Line 901 as well as over a second stretch~~Parks and Recreation, the California State Lands Commission, the California Department 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~~Forestry and test Line 901. The corrective action order was subsequently amended on June 3, 2015; November 13, 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 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 outFire Protection’s Office of the ~~release. Excavation~~State Fire Marshal, Central Coast Regional Water Quality Control Board, and ~~removal~~Regents of the ~~affected section~~University of California. The Consent Decree was approved and entered by the Federal District Court for the Central District of California on October 14, 2020. Pursuant to the terms of the ~~pipeline was completed on May 28, 2015. Line 901~~Consent Decree, Plains paid $24 million in civil penalties and ~~Line 903 have been purged and are not currently operational, with the exception~~$22.325 million as compensation for injuries to, destruction of, ~~the Pentland to Emidio segment~~loss of, ~~Line 903, which remains in service under a pressure restriction. No timeline has been established for the restart~~or loss of ~~Line 901 or Line 903.~~

~~On February 17, 2016, PHMSA issued a Preliminary Factual Report~~use 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 regardingnatural resources resulting from the Line 901 incident. ~~PHMSA’s findings indicate that the direct cause of the~~The Consent Decree also contains requirements for implementing certain agreed-upon injunctive relief, as well as requirements for potentially restarting Line 901 ~~incident was external corrosion that thinned~~and the ~~pipe wall~~Sisquoc to ~~a level where it ruptured suddenly and released crude oil. PHMSA also concluded that there were numerous contributory causes~~Pentland portion 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~~903. The Consent Decree resolved all regulatory claims related to the ~~rupture. The report also included copies of various engineering~~incident.

Following an investigation and technical reports regarding the incident. By virtue 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 any such civil or criminal charges with respect to the Line 901 release, their investigation is still open and we may have fines or penalties imposed upon us, or civil or criminal charges brought against us,grand jury proceedings, in ~~the future.~~

On September 11, 2015, we received a Notice of Probable Violation and Proposed Compliance Order from PHMSA arising out of its inspection of Lines 901 and 903 in August, September and October of 2013 (the “2013 Audit NOPV”). The 2013 Audit NOPV alleges that the Partnership committed probable violations of various federal pipeline safety regulations by failing to document, or inadequately documenting, certain activities. On October 12, 2015, the Partnership filed a response to the 2013 Audit NOPV. By letter dated September 21, 2017, PHMSA issued a Final Order in this matter withdrawing one alleged violation and affirming a second. With regard to the second violation, PHMSA further determined that compliance had been achieved and included no compliance terms related to it in the Final Order. We therefore consider this matter closed.

~~In late~~ May of 2015, the California Attorney General’s Office and the District Attorney’s office for the County of Santa Barbara began investigating the Line 901 incident to determine whether any applicable state or local laws had been violated. On May 16, 2016, PAA ~~and one of its employees were~~was charged by a California state grand jury, pursuant to an indictment filed in California Superior Court, Santa Barbara County (the “May 2016 Indictment”), with alleged violations of California law in connection with the Line 901 incident. ~~The~~Fifteen charges from the May 2016 Indictment ~~included~~were the subject of a total of 46 counts, 36 of which were misdemeanor charges relating to wildlife allegedly taken as a result of the accidental release. The remaining 10 counts relate to the release of crude oil or reporting of the release. PAA believes that the criminal charges (including the three felony

charges) are unwarranted and that neither PAA nor any of its employees engaged in any criminal behavior at any time in connection with this accident. PAA intends to continue to vigorously defend itself against the charges. On July 28, 2016, at an arraignment hearing heldjury trial in California Superior Court in Santa Barbara County, ~~PAA pled~~and 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 remaining counts were subsequently dismissed by the Court. On April 25, 2019, PAA was sentenced to ~~all counts.~~

~~Also~~pay fines and penalties in ~~late May~~the aggregate amount of ~~2015, the United States Attorney~~just under $3.35 million for the ~~Department~~convictions covered by the September 2018 jury verdict (the “2019 Sentence”). The fines and penalties imposed in connection with the 2019 Sentence have been paid. In September 2021, the Superior Court concluded a series of ~~Justice, Central District~~hearings on the issue 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~~“direct victims” of the ~~federal Clean Water Act. We~~spill that are ~~cooperating with~~entitled to restitution under applicable criminal law. Through a series of final orders issued at the ~~DOJ’s investigation by responding~~trial court level and without affecting any rights of the claimants under civil law, the Court dismissed the vast majority of the claims and ruled that the claimants were not entitled to ~~their requests for documents and access~~restitution under applicable criminal laws. The Court did award an aggregate amount of less than $150,000 to ~~our employees. The DOJ has already spoken to several~~a handful of our employees and has expressed an interest in talking to other 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 dateclaimants and we ~~will continue to do so in~~settled with approximately 40 claimants before the ~~future in cooperation with~~hearings for aggregate consideration that is not material. The prosecution and certain separately represented claimants have appealed the ~~EPA. While to date no civil or criminal charges with respect to the Line 901 release, other than those brought pursuant to the May 2016 Indictment, have been brought against PAA or any~~Court’s rulings.

Shortly following the Line 901 incident, we established a claims line and encouraged any parties that were damaged by the release to contact us to discuss their damage claims. We ~~have~~ received a number of claims through the claims line and we ~~are processing~~have processed those claims ~~for payment~~and made payments as ~~we receive them. In addition, we have also had nine~~appropriate. NaN class action lawsuits were filed against ~~us, six of which have been administratively~~us; however, after various claims were either dismissed or consolidated, ~~into a single proceeding~~2 proceedings remain pending in the United States District Court for the Central District of California. In ~~general,~~the first proceeding, the plaintiffs ~~are seeking to establish~~claim two different classes of claimants ~~that have allegedly been~~were damaged by the ~~release, including potential classes such as~~release: (i) commercial fishermen who landed fish in certain specified fishing blocks in the waters ~~adjacent to Santa Barbara County~~off the coast of Southern California or ~~from~~ persons or businesses who resold commercial seafood ~~landed~~caught in ~~such areas, certain~~those areas; and (ii) owners and lessees of ~~oceanfront~~residential beachfront properties, or properties with a private easement to a beach, where plaintiffs claim oil from the spill washed up. In order to fully and finally resolve all claims and litigation for both classes, we have reached an agreement in principle to settle this case in exchange for a payment of $230 million (the “Class Action Settlement”). The Class Action Settlement is subject to negotiation of final documentation and approval of the trial court. In the second proceeding, the plaintiffs seek a declaratory judgment that Plains’ right-of-way agreements would not allow Plains to lay a new pipeline to replace Line 901 and/or ~~beachfront property on~~ the ~~Pacific Coast~~non-operating segment of ~~California, and other classes of individuals and businesses that were allegedly impacted by the release. To~~Line 903 without paying additional compensation. No trial date ~~only the commercial fisherman and seafood reseller class~~ has been ~~certified by the court. We are also defending a separate class action lawsuit proceeding~~set 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.~~that action.

There have also been two 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 have been consolidated into a single proceeding in the United States District Court for the Southern District of Texas. In general, these lawsuits allege 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 facts and concealing of the true extent of the spill. The plaintiffs claim unspecified damages as a result of the reduction in value of their investments in the Partnership and PAGP, which they attribute 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 have refiled their complaint and we are opposing their claims. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we are indemnifying and funding the defense costs of our officers and directors in connection with these lawsuits; we are also indemnifying and funding the defense costs of our underwriters pursuant to the terms of the underwriting agreements we previously entered into with such underwriters.

In addition, ~~four~~after various other unitholder derivative lawsuits ~~have been filed by certain purported investors in the Partnership against the Partnership, certain of its affiliates and certain officers and directors. Two of these lawsuits~~ were ~~filed in the United States District Court for the Southern District of Texas and were administratively~~either dismissed or consolidated, ~~into one action and later dismissed on the basis that Plains Partnership agreements require that derivative suits be filed~~1 proceeding remains pending in Delaware Chancery Court. ~~Following~~Generally, the order dismissing the Texas Federal Court suits, a new derivative suit brought by different plaintiffs was filed in Delaware Chancery Court. The other remaining lawsuit was filed in State District Court in Harris County, Texas. In general, these lawsuits allege that the various defendants breached their fiduciary duties, engaged in gross mismanagement and made false and misleading statements, among other similar allegations, in connection with their management and oversight of the Partnership during the period of time leading up to and following the Line 901 release. The plaintiffs in the ~~two~~ remaining ~~lawsuits~~derivative lawsuit claim that PAGP’s Board of Directors failed to exercise proper oversight over PAA’s pipeline integrity efforts. In April 2022, Plains entered into a settlement agreement to settle this lawsuit, subject to court approval and notice to all PAA unitholders (the “Derivative Settlement”). Following court approval, we intend to effect notice to all PAA unitholders by filing a Current Report on Form 8-K with the ~~Partnership suffered unspecified damages as a result~~SEC. The key terms of the ~~actions~~Derivative Settlement include a payment of Plaintiff’s attorneys’ fees by our insurers in the amount of approximately $2.0 million and the agreement of Plains to comply with various ~~defendants and seek~~covenants regarding the implementation or continuation of certain Board oversight practices with respect to hold the defendants liable for such damages, in addition to other remedies. The defendants deny the allegations in these lawsuits and have responded accordingly. Consistent with and subject to the terms of our governing organizational documentspipeline integrity.

~~(and to the extent applicable, insurance policies), we are indemnifying and funding the defense costs of our officers and directors in connection with these lawsuits.~~

We ~~have~~ also received several other individual lawsuits and ~~complaints~~claims from companies, governmental agencies and individuals alleging damages arising out of the Line 901 incident. These lawsuits and claims generally seek restitution, compensatory and punitive damages, ~~and in some cases permanent~~and/or injunctive relief.

~~In addition to~~ The majority of these lawsuits have been settled or dismissed by the ~~foregoing, as~~court. The following lawsuits remain: (i) a lawsuit pending in the ~~“responsible party”~~United States District Court for the Central District of California for lost revenue or profit asserted by a former oil producer that declared bankruptcy and shut in its offshore production platform following the Line 901 ~~incident~~incident; (ii) a lawsuit filed by the California State Land Commission in California Superior Court in Santa Barbara County, seeking lost royalties following the shut-down of Line 901, as well as cost related to the decommissioning of such platform, and (iii) lawsuits filed in California Superior Court in Santa Barbara County, by various companies and individuals who provided labor, goods, or services associated with oil production activities they claim were disrupted following the Line 901 incident. We are vigorously defending these remaining lawsuits and believe we ~~are liable for various~~have strong defenses, including a lack of duty owed to the claimants to keep Line 901 in service.

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In connection with the foregoing, including the Class Action Settlement and the Derivative Settlement, we have made adjustments to our total estimated Line 901 costs and ~~for certain natural resource damages under~~ the Oil Pollution Act, and we also have exposure to the payment of additional fines, penalties and costs under other applicable federal, state and local laws, statutes and regulations. To the extent any such costs are reasonably estimable, we have included an estimateportion of such costs ~~in the loss accrual described below.~~

~~Taking the foregoing into account,~~that we believe are probable of recovery from insurance carriers, net of deductibles. Effective as of ~~September 30, 2017,~~March 31, 2022, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately ~~$300~~$725 million, which ~~estimate~~ includes actual and projected emergency response and clean-up costs, natural resource damage assessments, fines and penalties payable pursuant to the Consent Decree, certain third party claims settlements (including the Class Action Settlement and the Derivative Settlement), and estimated costs associated with our remaining Line 901 lawsuits and claims as described above, as well as estimates for ~~fines, penalties and~~ certain legal ~~fees.~~fees and statutory interest where applicable. We ~~accrued~~accrue such ~~estimate~~estimates of aggregate total costs to “Field operating costs” ~~primarily during 2015.~~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 and reasonably estimable and (iv)~~(ii) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. Our estimate does not include any lost revenue associated with the shutdown of Line 901 or 903 and does not include any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, with respect to potential losses that we regard as only reasonably possible or remote, we have made assumptions regarding the strength of our legal position based on our assessment of the relevant facts and applicable law and precedent; if our assumptions regarding such matters turn out to be inaccurate (i.e., we are found to be liable under circumstances where we regard the likelihood of loss as being only reasonably possible or remote), we could be responsible for significant costs and expenses that are not currently included in our estimates and accruals. In addition, for any potential losses that we regard as probable and for which we have accrued an estimate of the potential losses, our estimates regarding damages, legal fees, court costs and interest could turn out to be inaccurate and the actual losses we incur could be significantly higher than the amounts included in our estimates and accruals. Also, the amount of time it takes for us to resolve all of the current and future lawsuits ~~claims~~ and ~~investigations~~claims that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated. 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.

As of ~~September 30, 2017,~~March 31, 2022, we had a remaining undiscounted gross liability of ~~$64~~$335 million related to this event, of which ~~approximately $36 million~~aggregate amount is ~~presented as a~~reflected in “Trade accounts payable” and “Other current ~~liability in “Accounts payable and accrued~~ liabilities” on our Condensed Consolidated Balance ~~Sheet, with the remainder presented in “Other long-term liabilities and deferred credits”.~~Sheet. We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such environmental ~~liabilities. Subject~~liabilities; however, after giving effect to ~~such exclusions~~the settlements described above and assuming full collection of costs that we believe are probable of recovery from insurance providers, net of deductibles, we ~~believe that~~will reach the limit of our ~~coverage is adequate~~$500 million 2015 insurance program applicable 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.Line 901 incident. Through ~~September 30, 2017,~~March 31, 2022, we had collected, subject to customary reservations, ~~$166~~approximately $260 million out of the ~~approximate $205~~$500 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of ~~September 30, 2017,~~March 31, 2022, we have recognized a receivable of approximately ~~$39~~$240 million for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected. ~~Of this~~Such amount ~~approximately $18 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”.~~Sheet. We have completed the required clean-up and remediation work as determined by the Unified Command and the Unified Command has been dissolved; however, we expect to make payments for additional costs associated with restoration of the impacted areas, as well as ~~natural resource damage assessment and compensation,~~ legal, professional and regulatory costs ~~in addition to fines and penalties,~~ during future periods. Taking into account the costs that we have included in our total estimate of costs for the Line 901 incident and considering what we regard as very strong defenses to the claims made in our remaining Line 901 lawsuits, we do not believe the ultimate resolution of such remaining lawsuits will have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

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Pipelines, terminals, trucks or other facilities or equipment may experience damage as a result of an accident, natural disaster, terrorist attack, cyber event or other event. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. Consistent with insurance coverage generally available in the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences. We maintain various types and varying levels of insurance coverage to cover our operations and properties, and we self-insure certain risks, including gradual pollution, cybersecurity and named windstorms. However, such insurance does not cover every potential risk that might occur, associated with operating pipelines, terminals and other facilities and equipment, including the potential loss of significant revenues and cash flows.

The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. While we strive to maintain adequate insurance coverage, our actual costs may exceed our coverage levels and insurance will not cover many types of interruptions that might occur, will not cover amounts up to applicable deductibles and will not cover all risks associated with certain of our assets and operations. With respect to our insurance coverage, our policies are subject to deductibles and retention levels that we consider reasonable and not excessive. Additionally, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable. As a result, we may elect to self-insure or utilize higher deductibles in certain other insurance programs. In addition, although we believe that we have established adequate reserves and liquidity to the extent such risks are not insured, costs incurred in excess of these reserves may be higher or we may not receive insurance proceeds in a timely manner, which may potentially have a material adverse effect on our financial conditions, results of operations or cash flows.

~~We manage~~During the fourth quarter of 2021, we effected changes in the primary financial information provided to our ~~operations through three~~CODM for assessing performance and allocating resources to present 2 operating segments, Crude Oil and NGL. Prior to the fourth quarter of 2021, this information was organized into 3 operating segments: Transportation, Facilities and Supply and Logistics. All segment data and related disclosures for earlier periods presented herein have been recast to reflect the new segment reporting structure. Our CODM ~~(our Chief Executive Officer)~~ evaluates segment performance based on measures including ~~segment adjusted~~Segment Adjusted EBITDA (as defined below) and maintenance ~~capital investment.~~capital. During the fourth quarter of 2021, we modified our definition of Segment Adjusted EBITDA to exclude amounts attributable to noncontrolling interests. In connection with the Permian JV formation in October 2021, our CODM determined this modification resulted in amounts that were more meaningful to evaluate segment performance. Amounts attributable to noncontrolling interests for earlier periods presented herein have been recast to reflect this modification. See Note 20 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for additional information regarding the modifications to our segment reporting and for a full discussion of our basis for segmentation and performance measures.

We define ~~segment adjusted~~Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus (d) our proportionate share of the depreciation and amortization expense ~~and gains or losses on significant asset sales~~ of unconsolidated entities, ~~and~~ further adjusted (e) for certain selected items including (i) gains orand losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating ~~performance.~~

~~Segment adjusted~~performance and (f) to exclude the portion of all preceding items that is attributable to noncontrolling interests (“Adjusted EBITDA ~~excludes depreciation and amortization. Maintenance capital consists of capital expenditures for the replacement of partially or fully depreciated assets in order~~attributable to ~~maintain the operating and/or earnings capacity of our existing assets.~~noncontrolling interests”).

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

Three Months Ended September 30, 2017 Transportation Facilities Supply and
Logistics
Intersegment Adjustment ⁽¹⁾
Total
Revenues:

External customers ⁽¹⁾
$ 274
$ 140
$ 5,573
$ (114 ) $ 5,873
Intersegment ⁽²⁾
172
151
1
114
438
Total revenues of reportable segments $ 446
$ 291
$ 5,574
$ —
$ 6,311
Equity earnings in unconsolidated entities $ 80
$ —
$ —
$ 80
Segment adjusted EBITDA $ 363
$ 182
$ (56 ) $ 489
Maintenance capital $ 32
$ 28
$ 3
$ 63

Three Months Ended September 30, 2016 Transportation Facilities Supply and
Logistics
Intersegment Adjustment ⁽¹⁾
Total
Revenues:

External customers ⁽¹⁾
$ 227
$ 135
$ 4,876
$ (68 ) $ 5,170
Intersegment ⁽²⁾
174
147
3
68
392
Total revenues of reportable segments $ 401
$ 282
$ 4,879
$ —
$ 5,562
Equity earnings in unconsolidated entities $ 46
$ —
$ —
$ 46
Segment adjusted EBITDA $ 308
$ 171
$ (17 ) $ 462
Maintenance capital $ 29
$ 15
$ 3
$ 47

Nine Months Ended September 30, 2017 Transportation Facilities Supply and
Logistics
Intersegment Adjustment ⁽¹⁾
Total
Revenues:

External customers ⁽¹⁾
$ 757
$ 410
$ 17,749
$ (298 ) $ 18,618
Intersegment ⁽²⁾
503
463
8
298
1,272
Total revenues of reportable segments $ 1,260
$ 873
$ 17,757
$ —
$ 19,890
Equity earnings in unconsolidated entities $ 201
$ —
$ —
$ 201
Segment adjusted EBITDA $ 933
$ 550
$ (32 ) $ 1,451
Maintenance capital $ 89
$ 94
$ 11
$ 194

Nine Months Ended September 30, 2016 Transportation Facilities Supply and
Logistics
Intersegment Adjustment ⁽¹⁾
Total
Revenues:

External customers ⁽¹⁾
$ 711
$ 405
$ 13,344
$ (229 ) $ 14,231
Intersegment ⁽²⁾
477
412
9
229
1,127
Total revenues of reportable segments $ 1,188
$ 817
$ 13,353
$ —
$ 15,358
Equity earnings in unconsolidated entities $ 133
$ —
$ —
$ 133
Segment adjusted EBITDA $ 863
$ 497
$ 208
$ 1,568
Maintenance capital $ 86
$ 32
$ 10
$ 128


	Crude Oil		NGL		Intersegment Revenues Elimination		Total
Three Months Ended March 31, 2022
Revenues (1):
Product sales	$	12,811	$	682	$	(112)	$	13,381
Services	268		53		(8)		313
Total revenues	$	13,079	$	735	$	(120)	$	13,694
Equity earnings in unconsolidated entities	$	97	$	—			$	97
Segment Adjusted EBITDA	$	453	$	161			$	614

Maintenance capital expenditures	$	19	$	8			$	27





Three Months Ended March 31, 2021
Revenues (1):
Product sales	$	7,586	$	600	$	(103)	$	8,083
Services	267		39		(6)		300
Total revenues	$	7,853	$	639	$	(109)	$	8,383
Equity earnings in unconsolidated entities	$	88	$	—			$	88
Segment Adjusted EBITDA	$	474	$	69			$	543

Maintenance capital expenditures	$	28	$	7			$	35

⁽¹⁾

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

Table of Contents

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Segment Adjusted EBITDA Reconciliation

The following table reconciles ~~segment adjusted~~Segment Adjusted EBITDA to ~~net~~Net income attributable to PAA (in millions):

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Segment adjusted EBITDA $ 489
$ 462
$ 1,451
$ 1,568
Adjustments ⁽¹⁾:

Depreciation and amortization of unconsolidated entities ⁽²⁾
(13 ) (13 ) (31 ) (38 )
Gains/(losses) from derivative activities net of inventory valuation adjustments ⁽³⁾
(216 ) 52
86
(189 )
Long-term inventory costing adjustments ⁽⁴⁾
16
(38 ) 2
6
Deficiencies under minimum volume commitments, net ⁽⁵⁾
(8 ) (25 ) (5 ) (59 )
Equity-indexed compensation expense ⁽⁶⁾
(7 ) (8 ) (18 ) (23 )
Net gain/(loss) on foreign currency revaluation ⁽⁷⁾
14
(2 ) 27
(4 )
Line 901 incident ⁽⁸⁾
—
—
(12 ) —
Significant acquisition-related expenses ⁽⁹⁾
—
—
(6 ) —
Depreciation and amortization (151 ) (33 ) (401 ) (351 )
Interest expense, net (134 ) (113 ) (390 ) (339 )
Other income/(expense), net (1 ) 17
(6 ) 46
Income/(loss) before tax (11 ) 299
697
617
Income tax benefit/(expense) 45
(1 ) (30 ) (15 )
Net income 34
298
667
602
Net income attributable to noncontrolling interests (1 ) (1 ) (2 ) (3 )
Net income attributable to PAA $ 33
$ 297
$ 665
$ 599


	Three Months Ended March 31,
		2022		2021
Segment Adjusted EBITDA		$	614	$	543
Adjustments: (1)
Depreciation and amortization of unconsolidated entities (2)		(20)		(20)
Gains/(losses) from derivative activities and inventory valuation adjustments (3)		(88)		198
Long-term inventory costing adjustments (4)		92		41
Deficiencies under minimum volume commitments, net (5)		(6)		32
Equity-indexed compensation expense (6)		(7)		(5)
Net gain on foreign currency revaluation (7)		2		1
Line 901 incident (8)		(85)		—

Adjusted EBITDA attributable to noncontrolling interests (9)		76		3
Depreciation and amortization		(230)		(177)
Gains/(losses) on asset sales and asset impairments, net		42		(2)

Interest expense, net		(107)		(107)
Other expense, net		(37)		(60)
Income before tax		246		447
Income tax expense		(21)		(24)
Net income		225		423
Net income attributable to noncontrolling interests		(38)		(1)
Net income attributable to PAA		$	187	$	422

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

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

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

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

Table of Contents

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(5)We, and certain of our equity method investments, have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the ~~evaluation of segment results.~~

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~~Segment Adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.

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

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

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

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

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

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 ~~2016~~2021 Annual Report on Form 10-K. For more detailed information regarding the basis of presentation for the following financial information, see the Condensed Consolidated Financial Statements and related notes that are contained in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Our discussion and analysis includes the following:

•Executive Summary

~~Acquisitions and Capital Projects~~

~~Off-Balance Sheet Arrangements~~

~~Critical Accounting Policies and Estimates~~

~~We own~~Our business model integrates large-scale supply aggregation capabilities with the ownership and ~~operate~~operation of critical midstream ~~energy~~ infrastructure systems that connect major producing regions to key demand centers and ~~provide logistics services primarily for crude oil, NGL and natural gas. We~~export terminals. As one of the largest midstream service providers in North America, we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. ~~We were formed in 1998,~~Our assets and the services we provide are primarily focused on crude oil and NGL.

During the fourth quarter of 2021, we reorganized our ~~operations are conducted directly and indirectly through our~~historical operating ~~subsidiaries and are managed through three~~segments into two operating segments: ~~Transportation, Facilities~~Crude Oil and ~~Supply~~NGL. Additionally, during the fourth quarter of 2021, we modified our definition of Segment Adjusted EBITDA to exclude amounts attributable to noncontrolling interests. See Note 20 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for additional information. All segment data and ~~Logistics. See “—Results~~related disclosures for earlier periods presented herein have been recast to reflect the new segment reporting structure and the modification to our definition of ~~Operations~~—~~Analysis of Operating Segments” for further discussion.~~Segment Adjusted EBITDA.

Overview of Operating Results ~~Capital Investments and Other Significant Activities~~

During the first ~~nine~~three months of ~~2017,~~2022, we recognized net income attributable to PAA of ~~$665~~$187 million as compared to net income attributable to PAA of ~~$599~~$422 million recognized during the first ~~nine~~three months of ~~2016. Our financial results~~2021. Results for the ~~comparative periods were impacted by:~~

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

~~Higher interest expense primarily related to financing activities associated with our capital investments;~~Consolidated Results

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

We invested $893 million in midstream infrastructure projects during the nine months ended September 30, 2017, and we expect expansion capital for the full year of 2017 to be approximately $1.050 billion. Additionally, in February 2017, we acquired a crude oil gathering system located in the Northern Delaware Basin for approximately $1.217 billion and a marine propane terminal for $41 million. In April 2017, we completed the formation of a 50/50 joint venture, which subsequently acquired a crude oil pipeline located in the Southern Delaware Basin for $133 million. For our 50% share ($66.5 million), we contributed approximately 1.3 million common units and approximately $26 million in cash. To fund such capital activities, we sold approximately 54.1 million common units for net proceeds of approximately $1.7 billion. In addition, we have continued to advance our divestiture program, completing non-core asset sales during the first nine months of 2017 for cash proceeds of approximately $407 million. We also paid approximately $1.168 billion of cash distributions to our common unitholders during the nine months ended September 30, 2017.

On August 25, 2017, we announced that we were implementing an action plan to strengthen our balance sheet and reduce leverage, adopt a distribution approach underpinned by fee-based business activities and position ourself for future distribution growth. The action plan, which was endorsed by the PAGP GP Board, includes our intent to:

There can be no assurance that we will achieve these objectives, or that they will be achieved within our desired time frame or in the desired amounts. Achievement of these objectives is subject to risks and uncertainties, many of which are outside of our control. Please see “Risk Factors—Risks Related to Our Business” discussed in Item 1A of our 2016 Annual Report on Form 10-K.

~~Over the last several months, we have taken a number of steps toward the achievement of our objective to strengthen our balance sheet and reduce leverage, including:~~

~~Other Recent Developments - Assets Placed in Service~~. Construction on the Diamond Pipeline, in which we own a 50% interest, was substantially completed in late October, and will commence linefill operations in early to mid-November 2017. We expect to begin commercial operations in December 2017. We have also completed our new STACK JV pipeline project, in which we own a 50% interest, which will be placed into service in early to mid-November 2017.

~~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,
2017 2016
Acquisition capital ^{(1) (2)}
$ 1,325
$ 289
Expansion capital ^(2) (3)
893
1,065
Maintenance capital ⁽³⁾
194
128
$ 2,412
$ 1,482

~~ExpansionCapital Projects~~

~~The following table summarizes our notable projects in progress during 2017 and the estimated cost for the year ending December 31, 2017 (in millions):~~



~~Projects~~		~~2017~~
~~Diamond Pipeline~~ ⁽¹⁾		~~$300~~
~~Permian Basin Area Systems Projects~~		~~235~~
~~Fort Saskatchewan Facility Projects~~		75
~~STACK Projects~~ ⁽¹⁾		55
~~Cushing Terminal Expansions~~		40
~~Corpus Christi JV Dock~~ ⁽¹⁾		30
~~St. James Terminal Projects~~		10
~~Other Projects~~		~~305~~
~~Total Projected 2017 Expansion Capital Expenditures~~		~~$1,050~~

~~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
2017 2016 $ % 2017 2016 $ %
Transportation segment adjusted EBITDA ⁽¹⁾
$ 363
$ 308
$ 55
18 % $ 933
$ 863
$ 70
8 %
Facilities segment adjusted EBITDA ⁽¹⁾
182
171
11
6 % 550
497
53
11 %
Supply and Logistics segment adjusted EBITDA ⁽¹⁾
(56 ) (17 ) (39 ) (229 )% (32 ) 208
(240 ) (115 )%
Adjustments:
Depreciation and amortization of unconsolidated entities (13 ) (13 ) —
— % (31 ) (38 ) 7
18 %
Selected items impacting comparability - segment adjusted EBITDA (201 ) (21 ) (180 ) **
74
(269 ) 343
**
Depreciation and amortization (151 ) (33 ) (118 ) (358 )% (401 ) (351 ) (50 ) (14 )%
Interest expense, net (134 ) (113 ) (21 ) (19 )% (390 ) (339 ) (51 ) (15 )%
Other income/(expense), net (1 ) 17
(18 ) (106 )% (6 ) 46
(52 ) (113 )%
Income tax benefit/(expense) 45
(1 ) 46
**
(30 ) (15 ) (15 ) (100 )%
Net income 34
298
(264 ) (89 )% 667
602
65
11 %
Net income attributable to noncontrolling interests (1 ) (1 ) —
— % (2 ) (3 ) 1
33 %
Net income attributable to PAA $ 33
$ 297
$ (264 ) (89 )% $ 665
$ 599
$ 66
11 %

Basic net income/(loss) per common unit $ (0.01 ) $ 0.40
$ (0.41 ) **
$ 0.77
$ 0.27
$ 0.50
**
Diluted net income/(loss) per common unit $ (0.01 ) $ 0.40
$ (0.41 ) **
$ 0.76
$ 0.27
$ 0.49
**
Basic weighted average common units outstanding 725
401
324
**
714
399
315
**
Diluted weighted average common units outstanding 725
402
323
**
715
400
315
**


	Three Months Ended March 31,	Variance
		2022		2021		$		%
Product sales revenues		$	13,381	$	8,083	$	5,298	66	%
Services revenues		313		300		13		4	%
Purchases and related costs		(12,785)		(7,392)		(5,393)		(73)	%
Field operating costs		(346)		(219)		(127)		(58)	%
General and administrative expenses		(82)		(67)		(15)		(22)	%
Depreciation and amortization		(230)		(177)		(53)		(30)	%
Gains/(losses) on asset sales and asset impairments, net		42		(2)		44		**
Equity earnings in unconsolidated entities		97		88		9		10	%

Interest expense, net		(107)		(107)		—		—	%
Other expense, net		(37)		(60)		23		38	%
Income tax expense		(21)		(24)		3		13	%
Net income		225		423		(198)		(47)	%
Net income attributable to noncontrolling interests		(38)		(1)		(37)		**
Net income attributable to PAA		$	187	$	422	$	(235)	(56)	%

Basic and diluted net income per common unit		$	0.19	$	0.51	$	(0.32)	**

Basic and diluted weighted average common units outstanding		705		722		(17)		**

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

Revenues and Purchases

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

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


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

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

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

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

Field Operating Costs

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

General and Administrative Expenses

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

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

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

Depreciation and Amortization

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

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


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

		$	(37)	$	(60)


⁽¹⁾			Segment adjusted EBITDA is the measure of segment performance that is utilized by our Chief Operating Decision Maker (“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.

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

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

Noncontrolling Interests

The increase in amounts attributable to noncontrolling interests for the three months ended March 31, 2022 compared to the same period in 2021 was primarily due to the formation of the Permian JV in October 2021. See Note 7 to our Consolidated Financial Statements included in Part IV of our 2021 Annual Report on Form 10-K for additional information.

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.~~future and to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. The primary additional measures used by management are Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied distributable cash flow (“DCF”), Free Cash Flow and Free Cash Flow after Distributions.

Adjusted EBITDA is defined as earnings before interest, taxes, depreciation and amortization (including our proportionate share of depreciation and amortization, ~~and~~including write-downs related to cancelled projects, of unconsolidated entities), gains and losses on ~~significant~~ asset sales and asset impairments, goodwill impairment losses and gains on and impairments of investments in unconsolidated ~~entities) and~~entities, adjusted for certain selected items impacting ~~comparability (“~~comparability. Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted ~~EBITDA”)~~EBITDA, Adjusted EBITDA attributable to PAA and ~~implied distributable cash flow (“DCF”).~~Implied DCF are reconciled to Net Income, and Free Cash Flow and Free Cash Flow after Distributions are reconciled to Net Cash Provided by Operating Activities, the most directly comparable measures as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our Condensed Consolidated Financial Statements and accompanying notes. See “—Liquidity and Capital Resources—Liquidity Measures” for additional information regarding Free Cash Flow and Free Cash Flow after Distributions.

Performance Measures

Management believes that the presentation of ~~such additional financial measures~~Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF provides useful information to investors regarding our performance and results of operations because these measures, when used to supplement related GAAP financial measures, (i) provide additional information about our core operating performance and ability to fund distributions to

our unitholders through cash generated by our operations, (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions and (iii) present ~~measurements~~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 orand 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 either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (iii) long-term inventory costing adjustments, (iv) items that are not indicative of our core operating results ~~and 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 ~~“Accounts payable and accrued~~“Other current liabilities” in our Condensed Consolidated Financial Statements. We also adjust for amounts billed by our equity method investees related to deficiencies under minimum volume commitments. Such amounts are presented net of applicable amounts subsequently recognized into revenue. We have defined all such items as “selected items impacting comparability.” We do not necessarily consider all of our selected items impacting comparability to be non-recurring, infrequent or unusual, but we believe that an understanding of these selected items impacting comparability is material to the evaluation of our operating results and prospects.

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~~divestitures, investment capital projects and numerous other factors as discussed, as applicable, in ~~“Analysis~~“—Analysis of Operating Segments.”

~~Our definition and calculation~~

Table 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, 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.Contents

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

Three Months Ended
September 30, Variance Nine Months Ended
September 30, Variance
2017 2016 $ % 2017 2016 $ %
Net income $ 34
$ 298
$ (264 ) (89 )% $ 667
$ 602
$ 65
11 %
Add/(Subtract):

Interest expense, net 134
113
21
19 % 390
339
51
15 %
Income tax expense/(benefit) (45 ) 1
(46 ) **
30
15
15
100 %
Depreciation and amortization 151
33
118
358 % 401
351
50
14 %
Depreciation and amortization of unconsolidated entities ⁽¹⁾
13
13
—
— % 31
38
(7 ) (18 )%
Selected Items Impacting Comparability - Adjusted EBITDA:

(Gains)/losses from derivative activities net of inventory valuation adjustments⁽²⁾
216
(52 ) 268
**
(86 ) 189
(275 ) **
Long-term inventory costing adjustments ⁽³⁾
(16 ) 38
(54 ) **
(2 ) (6 ) 4
**
Deficiencies under minimum volume commitments, net ⁽⁴⁾
8
25
(17 ) **
5
59
(54 ) **
Equity-indexed compensation expense ⁽⁵⁾
7
8
(1 ) **
18
23
(5 ) **
Net (gain)/loss on foreign currency revaluation ⁽⁶⁾
(14 ) 2
(16 ) **
(27 ) 4
(31 ) **
Line 901 incident ⁽⁷⁾
—
—
—
**
12
—
12
**
Significant acquisition-related expenses ⁽⁸⁾
—
—
—
**
6
—
6
**
Selected Items Impacting Comparability - segment adjusted EBITDA 201
21
180
**
(74 ) 269
(343 ) **
Losses from derivative activities ⁽²⁾
(2 ) (17 ) 15
**
—
(42 ) 42
**
Net (gain)/loss on foreign currency revaluation ⁽⁶⁾
3
1
2
**
7
(3 ) 10
**
Selected Items Impacting Comparability - Adjusted
EBITDA ⁽⁹⁾
$ 202
$ 5
$ 197
**
$ (67 ) $ 224
$ (291 ) **
Adjusted EBITDA ⁽⁹⁾
489
463
26
6 % 1,452
1,569
(117 ) (7 )%
Interest expense, net ⁽¹⁰⁾
(121 ) (109 ) (12 ) (11 )% (367 ) (327 ) (40 ) (12 )%
Maintenance capital ⁽¹¹⁾
(63 ) (47 ) (16 ) (34 )% (194 ) (128 ) (66 ) (52 )%
Current income tax benefit/(expense) 1
(4 ) 5
125 % (9 ) (45 ) 36
80 %
Adjusted equity earnings in unconsolidated entities, net of distributions ⁽¹²⁾
(7 ) (9 ) 2
**
11
(20 ) 31
**
Distributions to noncontrolling interests ⁽¹³⁾
—
(1 ) 1
100 % (1 ) (3 ) 2
67 %
Implied DCF ⁽¹⁴⁾
$ 299
$ 293
$ 6
2 % $ 892
$ 1,046
$ (154 ) (15 )%
Distributions paid ⁽¹³⁾
(218 ) (328 ) (1,016 ) (1,194 )
DCF Excess/(Shortage) ⁽¹⁵⁾
$ 81
$ (35 ) $ (124 ) $ (148 )


	Three Months Ended March 31,	Variance
		2022		2021		$		%

Net income		$	225	$	423	$	(198)	(47)	%
Interest expense, net		107		107		—		—	%
Income tax expense		21		24		(3)		(13)	%
Depreciation and amortization		230		177		53		30	%
(Gains)/losses on asset sales and asset impairments, net		(42)		2		(44)		**

Depreciation and amortization of unconsolidated entities (1)		20		20		—		—	%
Selected Items Impacting Comparability:
(Gains)/losses from derivative activities and inventory valuation adjustments		88		(198)		286		**
Long-term inventory costing adjustments		(92)		(41)		(51)		**
Deficiencies under minimum volume commitments, net		6		(32)		38		**
Equity-indexed compensation expense		7		5		2		**
Net gain on foreign currency revaluation		(2)		(1)		(1)		**
Line 901 incident		85		—		85		**

Selected Items Impacting Comparability - Segment Adjusted EBITDA (2)		92		(267)		359		**
Losses from derivative activities (3)		44		67		(23)		**
Net gain on foreign currency revaluation (4)		(7)		(7)		—		**

Selected Items Impacting Comparability - Adjusted EBITDA (5)		129		(207)		336		**
Adjusted EBITDA (5)		$	690	$	546	$	144	26	%
Adjusted EBITDA attributable to noncontrolling interests (6)		(76)		(3)		(73)		**
Adjusted EBITDA attributable to PAA		$	614	$	543	$	71	13	%

Adjusted EBITDA (5)		$	690	$	546	$	144	26	%
Interest expense, net of certain non-cash items (7)		(101)		(101)		—		—	%
Maintenance capital (8)		(27)		(35)		8		23	%
Investment capital of noncontrolling interests (9)		(15)		—		(15)		N/A
Current income tax expense		(19)		(1)		(18)		**
Distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings (10)		(31)		5		(36)		**
Distributions to noncontrolling interests (11)		(59)		(6)		(53)		**
Implied DCF		$	438	$	408	$	30	7	%
Preferred unit distributions (11)		(37)		(37)		—		—	%
Implied DCF Available to Common Unitholders		$	401	$	371	$	30	8	%
Common unit cash distributions (11)		(127)		(130)
Implied DCF Excess (12)		$	274	$	241

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


⁽¹⁾	Over the past several years, we have increased our participation in pipeline strategic joint ventures, which are accounted for under the equity method of accounting. We exclude our proportionate share of the depreciation and

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

⁽²⁾

We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results of operations, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining Adjusted EBITDA. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable, 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~~

Table of Contents

(2)For a more detailed 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 4 to our Consolidated Financial Statements included in Part IV of our 2016 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⁾

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 16 to our Consolidated Financial Statements included in Part IV of our 2016 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 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 12 to our Condensed Consolidated Financial Statements for additional information.


⁽⁸⁾	~~Includes acquisition-related expenses associated with the ACC Acquisition. See Note 6 to our Condensed Consolidated Financial Statements for additional information.~~


⁽⁹⁾	~~Adjusted EBITDA includes Other income/(expense), net adjusted for selected items impacting comparability. Segment adjusted EBITDA is exclusive of such amounts.~~


⁽¹⁰⁾	~~Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.~~


⁽¹¹⁾	Maintenance capital expenditures are defined as capital expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets.


⁽¹²⁾	Represents the difference between non-cash equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization) and cash distributions received from such entities.


⁽¹³⁾	~~Includes cash distributions that pertain to the current period’s net income and are paid in the subsequent period.~~


⁽¹⁴⁾	Including net costs recognized during the periods related to the Line 901 incident that occurred in May 2015, Implied DCF would have been $880 million for the nine months ended September 30, 2017, respectively. See Note 12 to our Condensed Consolidated Financial Statements for additional information regarding the Line 901 incident.


⁽¹⁵⁾	Excess DCF is retained to establish reserves for future distributions, capital expenditures and other partnership purposes. DCF shortages are 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 and gains or losses on significant asset sales of unconsolidated entities, and further adjusted for certain selected items ~~including (i)~~impacting comparability, see the ~~mark-to-market~~footnotes to the Segment Adjusted EBITDA Reconciliation table in Note 11 to our Condensed Consolidated Financial Statements.

(3)The Preferred Distribution Rate Reset Option of our Series A preferred units is accounted for as an embedded derivative ~~instruments that are related to underlying activities~~and recorded at fair value in ~~another period (or the reversal of such adjustments from a prior period),~~our Condensed Consolidated Financial Statements. The associated gains and losses ~~on derivatives that~~ are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes arenot integral to ~~understanding~~ our ~~core segment operating performance.~~results and were thus classified as a selected item impacting comparability. See Note 138 to our Condensed Consolidated Financial Statements for ~~a reconciliation~~additional information regarding the Preferred Distribution Rate Reset Option.

(4)During the periods presented, there were fluctuations in the value of ~~segment adjusted EBITDA~~CAD to ~~net income attributable to PAA.~~

~~Revenues~~USD, resulting in the realization of foreign exchange gains 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. The Transportation segment generates revenue through a combination of tariffs, third-party pipeline capacity agreements and other transportation fees.

~~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) 2017 2016 $ % 2017 2016 $ %
Revenues $ 446
$ 401
$ 45
11 % $ 1,260
$ 1,188
$ 72
6 %
Purchases and related costs (29 ) (24 ) (5 ) (21 )% (74 ) (69 ) (5 ) (7 )%
Field operating costs⁽²⁾
(134 ) (133 ) (1 ) (1 )% (427 ) (406 ) (21 ) (5 )%
Equity-indexed compensation expense - field operating costs (2 ) (3 ) 1
**
(9 ) (9 ) —
**
Segment general and administrative expenses ^(2) (3)
(22 ) (22 ) —
— % (70 ) (67 ) (3 ) (4 )%
Equity-indexed compensation expense - general and administrative (3 ) (4 ) 1
**
(8 ) (10 ) 2
**
Equity earnings in unconsolidated entities 80
46
34
74 % 201
133
68
51 %

Adjustments ⁽⁴⁾:

Depreciation and amortization of unconsolidated entities 13
13
—
— % 31
38
(7 ) (18 )%
Deficiencies under minimum volume commitments, net 11
30
(19 ) **
2
54
(52 ) **
Equity-indexed compensation expense 3
4
(1 ) **
9
11
(2 ) **
Line 901 incident —
—
—
**
12
—
12
**
Significant acquisition-related expenses —
—
—
**
6
—
6
**
Segment adjusted EBITDA $ 363
$ 308
$ 55
18 % $ 933
$ 863
$ 70
8 %
Maintenance capital $ 32
$ 29
$ 3
10 % $ 89
$ 86
$ 3
3 %
Segment adjusted EBITDA per barrel $ 0.74
$ 0.73
$ 0.01
1 % $ 0.67
$ 0.68
$ (0.01 ) (1 )%

Average Daily Volumes Three Months Ended
September 30, Variance Nine Months Ended
September 30, Variance
(in thousands of barrels per day)⁽⁵⁾
2017 2016 Volumes % 2017 2016 Volumes %
Tariff activities volumes

Crude oil pipelines (by region):

Permian Basin ⁽⁶⁾
2,963
2,162
801
37 % 2,732
2,129
603
28 %
South Texas / Eagle Ford ⁽⁶⁾
362
263
99
38 % 341
283
58
20 %
Western 190
194
(4 ) (2 )% 186
193
(7 ) (4 )%
Rocky Mountain ⁽⁶⁾
426
475
(49 ) (10 )% 418
448
(30 ) (7 )%
Gulf Coast 359
423
(64 ) (15 )% 362
538
(176 ) (33 )%
Central ⁽⁶⁾
424
403
21
5 % 419
393
26
7 %
Canada 351
379
(28 ) (7 )% 359
384
(25 ) (7 )%
Crude oil pipelines 5,075
4,299
776
18 % 4,817
4,368
449
10 %
NGL pipelines 172
185
(13 ) (7 )% 169
182
(13 ) (7 )%
Tariff activities total volumes 5,247
4,484
763
17 % 4,986
4,550
436
10 %
Trucking volumes 94
118
(24 ) (20 )% 102
113
(11 ) (10 )%
Transportation segment total volumes 5,341
4,602
739
16 % 5,088
4,663
425
9 %

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


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


⁽²⁾	~~Field operating costs and Segment general and administrative expenses exclude equity-indexed compensation expense, which is presented separately in the table above.~~


⁽³⁾	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.


⁽⁴⁾	~~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.~~


⁽⁵⁾	~~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.~~


⁽⁶⁾	~~Region includes volumes (attributable to our interest) from pipelines owned by unconsolidated entities.~~

~~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~~losses on the ~~volumes transported on the pipeline and the level~~settlement of ~~the tariff and other fees charged,~~foreign currency transactions as well as the ~~fixed~~revaluation of monetary assets and ~~variable field costs of operating the pipeline. As is common~~liabilities denominated in ~~the pipeline transportation industry, our tariffs incorporate~~ a loss allowance factor that is intended to offset losses due to evaporation, measurement and other losses in transit. We value the variance of allowance volumes to actual losses at the estimated net realizable value (including the impact offoreign currency. The associated gains and losses ~~from derivative-related activities) at the time the variance occurred~~are not integral to our results and ~~the result is recorded~~were thus classified as ~~either an increase or decrease to tariff activities revenues.~~a selected item impacting comparability.

~~The following is a discussion~~(5)Other expense, net per our Condensed Consolidated Statements of Operations, adjusted for selected items impacting ~~Transportation segment operating results for the periods indicated.~~comparability (“Adjusted Other income/(expense), net”) is included in Adjusted EBITDA and excluded from Segment Adjusted EBITDA.

~~Revenues, Equity Earnings in Unconsolidated Entities and Volumes.~~ ~~The following table presents variances in revenues and equity earnings in unconsolidated entities by region for the comparative periods presented:~~

Favorable/(Unfavorable) Variance
Three Months Ended September 30,
2017-2016 Favorable/(Unfavorable) Variance
Nine Months Ended September 30,
2017-2016
(in millions) Revenues Equity Earnings Revenues Equity Earnings
Tariff and trucking activities:

Permian Basin region $ 60
$ 9
$ 129
$ 17
South Texas / Eagle Ford region —
20
(6 ) 31
Rocky Mountain region —
4
(13 ) 10
Gulf Coast region (3 ) —
(20 ) —
Other (including trucking and pipeline loss allowance revenue) (12 ) 1
(18 ) 10
Total variance $ 45
$ 34
$ 72
$ 68

~~Permian Basin region — The increase in revenues for the comparative 2017 periods presented was largely driven by (i) higher volumes on our Cactus pipeline due~~(6)Reflects amounts attributable to stronger demand in the Corpus Christi market and to third-party terminals, which also favorably impacted volumes on our McCamey pipeline system, (ii) results from the ACC System, which we acquired in February 2017, and (iii) increased production and new lease connections to our gathering systemsnoncontrolling interests in the Permian ~~Basin.~~JV and Red River LLC.

~~Equity earnings increased due to higher earnings from our 50% interest in BridgeTex Pipeline Company, LLC resulting from higher volumes in the 2017 periods.~~

South Texas / Eagle Ford region — Equity earnings from our 50% interest in Eagle Ford Pipeline LLC increased over the periods presented primarily due to higher volumes from our Cactus pipeline related to stronger demand in the Corpus Christi market and to third-party terminals.

Rocky Mountain region — The decrease in revenues for the nine-month comparative period was largely driven by (i) lower volumes due to downtime on our Wahsatch pipeline, which we proactively shut down for approximately 30 days during the first quarter of 2017 as a precautionary measure in response to indications of soil movement identified by our monitoring systems, and (ii) the sale of 50% of our investment in Cheyenne Pipeline in June 2016, subsequent to which it was accounted for under the equity method of accounting.

Equity earnings for the nine-month comparative period increased primarily due to contributions from (i) our 40% investment in Saddlehorn Pipeline Company, LLC, which began operations in the third quarter of 2016, and (ii) our 50% investment in Cheyenne Pipeline, as discussed above. Such increases were partially offset by decreased equity earnings from our 35.67% interest in White Cliffs Pipeline LLC due to lower volumes on the joint venture pipeline.

Gulf Coast region — Revenues and volumes decreased for the comparative three-month period primarily due to lower refinery demand on our Pascagoula pipeline and fewer spot shippers on Capline pipeline for the 2017 period. The nine-month comparative period was further impacted by the sale of(7)Excludes certain ~~of our Gulf Coast pipelines in March 2016 and July 2016.~~

~~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, based on an expectation of continued production growth, agreed to either: (i) ship and pay for certain stated volumes or (ii) pay the agreed upon price for a minimum contract quantity. During the 2016 and 2017 periods presented in the table above, we had net collections for deficiencies under minimum volume commitments resulting in deferred revenues and an increase to Segment adjusted EBITDA. However, such net collections in the 2017 periods were partially offset by (i) shippers utilizing credits associated with previous deficiencies or (ii) credits expiring, which resulted in the recognition of previously deferred revenue.

~~Field Operating Costs.~~ The increase in field operating costs (excluding equity-indexed compensation expense) for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 was primarily due to an increase in estimated costs associated with the Line 901 incident (which impact our field operating costs but are excluded from segment adjusted EBITDA and thus are reflected as an “Adjustment” in the table above), an increase in power costs resulting from higher volumes and incremental operating costs from the Alpha Crude Connector acquisition in February 2017, partially offset by cost reduction efforts and decreased costs due to the sale of certain Gulf Coast pipelines as noted above.

~~Equity-Indexed Compensation Expense.~~ ~~The following table presents total equity-indexed compensation expense by segment (in millions):~~

Three Months Ended
September 30, Variance Nine Months Ended
September 30, Variance
Operating Segment 2017 2016 2017 2016
Transportation $ 5
$ 7
$ (2 ) $ 17
$ 19
$ (2 )
Facilities 3
3
—
7
10
(3 )
Supply and Logistics 2
4
(2 ) 9
11
(2 )
$ 10
$ 14
$ (4 ) $ 33
$ 40
$ (7 )

Across all segments, equity-indexed compensation expense decreased by $4 million and $7 million for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016, primarily due to a decrease in unit price for both the three and nine months ended September 30, 2017, compared to an increase in unit price for the same periods in 2016, partially offset by more probable awards outstanding during the three and nine months ended September 30, 2017 compared to the same periods in 2016. See Note 16 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for additional information regarding our equity-indexed compensation plans.

~~Facilities Segment~~

Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products, 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.

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

Operating Results ⁽¹⁾
Three Months Ended
September 30, Variance Nine Months Ended
September 30, Variance
(in millions, except per barrel data) 2017 2016 $ % 2017 2016 $ %
Revenues $ 291
$ 282
$ 9
3 % $ 873
$ 817
$ 56
7 %
Natural gas related costs (3 ) (6 ) 3
50 % (19 ) (17 ) (2 ) (12 )%
Field operating costs ⁽²⁾
(88 ) (85 ) (3 ) (4 )% (256 ) (258 ) 2
1 %
Equity-indexed compensation expense - field operating costs (1 ) (1 ) —
**
(2 ) (3 ) 1
**
Segment general and administrative expenses ^(2) (3)
(16 ) (15 ) (1 ) (7 )% (50 ) (44 ) (6 ) (14 )%
Equity-indexed compensation expense - general and administrative (2 ) (2 ) —
**
(5 ) (7 ) 2
**

Adjustments⁽⁴⁾:

Deficiencies under minimum volume commitments, net (3 ) (5 ) 2
**
3
5
(2 ) **
(Gains)/losses from derivative activities net of inventory valuation adjustments 2
1
1
**
3
—
3
**
Net (gain)/loss on foreign currency revaluation —
—
—
**
—
(1 ) 1
**
Equity-indexed compensation expense 2
2
—
**
3
5
(2 ) **
Segment adjusted EBITDA $ 182
$ 171
$ 11
6 % $ 550
$ 497
$ 53
11 %
Maintenance capital $ 28
$ 15
$ 13
87 % $ 94
$ 32
$ 62
194 %
Segment adjusted EBITDA per barrel $ 0.47
$ 0.43
$ 0.04
9 % $ 0.47
$ 0.43
$ 0.04
9 %

Three Months Ended
September 30, Variance Nine Months Ended
September 30, Variance
Volumes⁽⁵⁾
2017 2016 Volumes % 2017 2016 Volumes %
Crude oil, refined products and NGL terminalling and storage (average monthly capacity in millions of barrels) 112
109
3
3 % 112
106
6
6 %
Rail load / unload volumes (average volumes in thousands of barrels per day) 30
73
(43 ) (59 )% 38
97
(59 ) (61 )%
Natural gas storage (average monthly working capacity in billions of cubic feet) ⁽⁶⁾
67
97
(30 ) (31 )% 87
97
(10 ) (10 )%
NGL fractionation (average volumes in thousands of barrels per day) 131
119
12
10 % 125
113
12
11 %
Facilities segment total volumes (average monthly volumes in millions of barrels) ⁽⁷⁾
128
131
(3 ) (2 )% 131
129
2
2 %

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


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


⁽²⁾	~~Field operating costs and Segment general and administrative expenses exclude equity-indexed compensation expense, which is presented separately in the table above.~~


⁽³⁾	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.


⁽⁴⁾	~~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.~~


⁽⁵⁾	~~Average monthly volumes are calculated as total volumes for the period divided by the number of months in the period.~~


⁽⁶⁾	The decrease in average monthly working capacity of natural gas storage facilities was driven by adjustments for (i) the sale of our Bluewater facility in June 2017, (ii) changes in base gas and (iii) 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) crude oil, refined products and NGL terminalling and storage capacity; (ii) rail load and unload volumes multiplied by the number of days in the period and divided by the number of months in the period; (iii) 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 (iv) 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~~non-cash items impacting ~~Facilities segment operating results for the periods indicated.~~interest expense such as amortization of debt issuance costs and terminated interest rate swaps.

~~Revenues and Volumes.~~ ~~Variances in revenues and average monthly volumes for the comparative periods were driven by:~~

NGL Storage, NGL Fractionation and Canadian Natural Gas Processing — Revenues increased by $23 million and $82 million for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016 primarily due to contributions from the Western Canada NGL assets we acquired in August 2016 and increased storage capacity at our Fort Saskatchewan facility, as well as higher fees at certain of our NGL storage and fractionation facilities, which were largely incurred in our Supply and Logistics segment results.

Rail Terminals — Revenues decreased by $9 million and $25 million for the three and nine months ended September 30, 2017, respectively, compared to the three and nine months ended September 30, 2016 primarily due to lower volumes at our U.S. terminals resulting from less favorable market conditions. The decrease for the nine-month period was partially offset by revenues and volumes from our Fort Saskatchewan rail terminal that came on line in April 2016.

Crude Oil Storage — Revenues increased by $1 million for the three months ended September 30, 2017 compared to the three months ended September 30, 2016 and decreased by $3 million for the nine months ended September 30, 2017 compared to the same 2016 period. Both of the 2017 periods were positively impacted by increased revenues from our Cushing terminal due to capacity expansions of approximately 2 million barrels and increased terminal throughput. These positive results were offset (i) for the three-month comparative period, by decreased marine activity and (ii) for the nine-month comparative period, by decreased utilization at certain of our West Coast terminals and the sale of certain of our East Coast terminals in April 2016.

~~Field Operating Costs.~~ The decrease in field operating costs (excluding equity-indexed compensation expense) for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 was primarily due to reduced rail activity, cost reduction efforts and the sales of our Bluewater natural gas storage facility in June 2017 and certain of our East Coast terminals in April 2016. Such decreases were largely offset by an increase in operating costs associated with the Western Canada NGL assets acquired in August 2016 and increased power costs. The three-month comparative period was also impacted by property tax refunds received during the third quarter of 2016.

~~Equity-indexed compensation expense.~~ ~~See “—Analysis of Operating Segments—Transportation Segment” for discussion of equity-indexed compensation expense for the periods presented.~~

~~Maintenance Capital.~~(8)Maintenance capital ~~consists of~~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. ~~The increase~~

(9)Investment capital expenditures attributable to noncontrolling interests that reduce Implied DCF available to PAA common unitholders.

(10)Comprised of cash distributions received from unconsolidated entities less equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization, including write-downs related to cancelled projects, and selected items impacting comparability of unconsolidated entities).

(11)Cash distributions paid during the period presented.

(12)Excess DCF is retained to establish reserves for debt repayment, future distributions, common unit repurchases, capital expenditures and other partnership purposes.

Analysis of Operating Segments

We manage our operations through two operating segments: Crude Oil and NGL. Our CODM (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Adjusted EBITDA, segment volumes and maintenance capital investment. See Note 11 to our Condensed Consolidated Financial Statements for ~~the three~~our definition of Segment Adjusted EBITDA and ~~nine months ended September 30, 2017 compared~~a reconciliation of Segment Adjusted EBITDA to ~~the same periods~~Net income attributable to PAA. See Note 20 to our Consolidated Financial Statements included in ~~2016 was primarily due to increased investment in~~Part IV of our ~~integrity management program, primarily~~2021 Annual Report on ~~assets at~~Form 10-K for our ~~Southern California terminals.~~definition of maintenance capital.

~~Supply and Logistics~~Crude Oil Segment

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

Our Crude Oil segment generates revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees, month-to-month and multi-year storage and terminalling agreements and the sale of gathered and bulk-purchased crude ~~oil, as well as sales of NGL~~oil. Tariffs and other fees on our pipeline systems are typically based on volumes ~~purchased~~transported and vary by receipt point and delivery point. Fees for our terminalling and storage services are based on capacity leases and throughput volumes. Generally, results from ~~suppliers and natural gas sales attributable to the~~our merchant activities ~~that were previously performed by our natural gas storage commercial optimization group. Generally, our segment profit is~~are impacted by (i) increases or decreases in our ~~Supply and Logistics segment volumes (which consist of~~ lease gathering crude

Table of Contents

oil purchases volumes ~~NGL sales volumes~~ and ~~waterborne cargos),~~ (ii) the ~~effects of competition on our lease gathering~~overall strength, weakness and ~~NGL margins and (iii) the overall~~ volatility ~~and strength or weakness~~ of market conditions, including regional differentials and ~~the allocation of our assets among our various risk management strategies.~~time spreads. In addition, the execution of our risk management strategies in conjunction with our assets can provide upside in certain markets. ~~Although~~The segment ~~profit may be adversely affected during certain transitional periods as discussed further below, our~~results also include the direct fixed and variable field costs of operating the crude oil ~~and NGL supply, logistics and distribution operations are not directly affected by the absolute level~~assets, as well as an allocation of ~~prices, but are affected by overall levels of supply and demand for crude oil and NGL, market structure and relative fluctuations in market-related indices and regional differentials.~~indirect operating costs.

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

Operating Results ⁽¹⁾
Three Months Ended
September 30, Variance Nine Months Ended
September 30, Variance
(in millions, except per barrel data) 2017 2016 $ % 2017 2016 $ %
Revenues $ 5,574
$ 4,879
$ 695
14 % $ 17,757
$ 13,353
$ 4,404

33 %
Purchases and related costs (5,729 ) (4,788 ) (941 ) (20 )% (17,407 ) (13,031 ) (4,376 ) (34 )%
Field operating costs ⁽²⁾
(62 ) (70 ) 8
11 % (193 ) (226 ) 33
15 %
Equity-indexed compensation expense - field operating costs —
—
—
**
—
(1 ) 1
**
Segment general and administrative expenses ^(2) (3)
(23 ) (23 ) —
— % (68 ) (72 ) 4
6 %
Equity-indexed compensation expense - general and administrative (2 ) (4 ) 2
**
(9 ) (10 ) 1
**

Adjustments ⁽⁴⁾:

(Gains)/losses from derivative activities net of inventory valuation adjustments 214
(53 ) 267
**
(89 ) 189
(278 ) **
Long-term inventory costing adjustments (16 ) 38
(54 ) **
(2 ) (6 ) 4
**
Net (gain)/loss on foreign currency revaluation (14 ) 2
(16 ) **
(27 ) 5
(32 ) **
Equity-indexed compensation expense 2
2
—
**
6
7
(1 ) **
Segment adjusted EBITDA $ (56 ) $ (17 ) $ (39 ) (229 )% $ (32 ) $ 208
$ (240 ) (115 )%
Maintenance capital $ 3
$ 3
$ —
— % $ 11
$ 10
$ 1
10 %
Segment adjusted EBITDA per barrel $ (0.54 ) $ (0.16 ) $ (0.38 ) (238 )% $ (0.10 ) $ 0.67
$ (0.77 ) (115 )%

Average Daily Volumes Three Months Ended
September 30, Variance Nine Months Ended
September 30, Variance
(in thousands of barrels per day) 2017 2016 Volumes % 2017 2016 Volumes %
Crude oil lease gathering purchases 929
883
46
5 % 929
894
35
4 %
NGL sales 202
207
(5 ) (2 )% 254
230
24
10 %
Waterborne cargos —
8
(8 ) **
2
7
(5 ) **
Supply and Logistics segment total 1,131
1,098
33
3 % 1,185
1,131
54
5 %


Operating Results (1)	Three Months Ended March 31,	Variance
(in millions)		2022		2021		$		%
Revenues		$	13,079	$	7,853	$	5,226	67	%
Purchases and related costs		(12,393)		(7,047)		(5,346)		(76)	%
Field operating costs		(282)		(165)		(117)		(71)	%
Segment general and administrative expenses (2)		(63)		(50)		(13)		(26)	%
Equity earnings in unconsolidated entities		97		88		9		10	%

Adjustments (3):
Depreciation and amortization of unconsolidated entities		20		20		—		—	%
(Gains)/losses from derivative activities and inventory valuation adjustments		59		(159)		218		137	%
Long-term inventory costing adjustments		(85)		(35)		(50)		(143)	%
Deficiencies under minimum volume commitments, net		6		(32)		38		119	%
Equity-indexed compensation expense		7		5		2		40	%
Net gain on foreign currency revaluation		(1)		(1)		—		—	%
Line 901 incident		85		—		85		N/A

Adjusted EBITDA attributable to noncontrolling interests		(76)		(3)		(73)		**
Segment Adjusted EBITDA		$	453	$	474	$	(21)	(4)	%

Maintenance capital		$	19	$	28	$	(9)	(32)	%


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

Commercial crude oil storage capacity (5) (6)		72	73	(1)	(1)	%

Crude oil lease gathering purchases (4)		1,361	1,174	187	16	%

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

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

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

~~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.~~

~~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, 2017 $ 44
$ 52
Three months ended September 30, 2016 $ 40
$ 49

Nine months ended September 30, 2017 $ 43
$ 54
Nine months ended September 30, 2016 $ 26
$ 51

~~Because the commodities that we buy and sell are generally indexed~~ to the ~~same pricing indices for both sales~~segments. The proportional allocations by segment require judgment by management and ~~purchases, revenues and costs related to purchases will fluctuate with market prices. However,~~are based on the ~~margins related to those sales and purchases will not necessarily have a corresponding increase or decrease. The absolute amount~~business activities that exist during each period.

(3)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of our revenues and purchases increased for the three and nine months ended September 30, 2017 compared to the same periods in 2016 primarily due to higher crude oil prices. Additionally, revenues and purchases were impacted by net gains and losses from certain derivative activities during the periods.

Historically, we expected a base level of earnings from our Supply and Logistics segment from the assets employed by this segment. However, over the last 18 to 24 months, competition has increased significantly and, combined with recent and current market conditions, predicting such base level of earnings has been difficult. Our Supply and Logistics segment earnings may be optimized and enhanced when there is a high level of market volatility, favorable basis differentials and/or a steep contango market structure. During certain transitional periods, such as the current extended period of lower crude oil prices, increased competition, low volatility and tight differentials, our ability to generate earnings in this segment is reduced and our segment earnings can be adversely impacted by activities designed to increase utilization of certain of our pipeline and facilities assets. These factors, in combination with overcapacity of midstream assets in certain regions and increased competition that currently exists in most crude oil producing regions, make predicting and then generating baseline-level performance challenging. Our NGL operations are also impacted by similar competitive pressures. In addition, 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.

~~The following is a discussion of items impacting Supply and Logistics segment operating results for the periods indicated.~~

~~Net Revenues and Volumes.~~ Our Supply and Logistics segment revenues, net of purchases and related costs, decreased by $246 million for the three months ended September 30, 2017 compared to the three months ended September 30, 2016 and increased by $28 million for the nine months ended September 30, 2017 compared to the same period in 2016. The nine-month comparative period was impacted by gains from certain derivative activities (as discussed further below) that more than offset lower results from less favorable market conditions. The following summarizes the significant items impacting the comparative periods:

Net revenues from our NGL operations decreased for the nine months ended September 30, 2017 as compared to the same period in 2016, largely due to (i) higher supply costs and tighter differentials driven by competition, which more than offset higher sales volume from the Western Canada NGL assets acquired in August 2016, (ii) warmer weather during the 2016-2017 heating season and (iii) higher storage and processing fees for the 2017 period, which were largely offset in our Facilities segment results. ~~These decreases were partially offset by higher propane sales margins in the third quarter of 2017, as discussed above.~~

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) and inventory valuation adjustments, as applicable. See Note 1011 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.

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

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

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

Segment Adjusted EBITDA

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

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

Revenues, Net of Purchases and Related Costs (“net revenues”) and Equity Earnings in Unconsolidated Entities. The following is a ~~comprehensive~~ discussion ~~regarding our derivatives and risk management activities. These gains and losses impact our~~of the significant factors impacting net revenues and equity earnings in unconsolidated entities that contributed to the variance in Segment Adjusted EBITDA for the first quarter of 2022 compared to the first quarter of 2021.

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

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

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

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



333 Clay Street, Suite 1600 ~~Houston, Texas~~		~~77002~~
~~(Address of principal executive offices)~~		~~(Zip Code)~~


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Units	PAA	Nasdaq



		Page
PART I. FINANCIAL INFORMATION
Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
Condensed Consolidated Balance Sheets: As of ~~September 30, 2017~~March 31, 2022 and December 31, ~~2016~~2021		3
Condensed Consolidated Statements of Operations: For the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2022 and ~~2016~~2021		4
Condensed Consolidated Statements of Comprehensive Income: For the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2022 and ~~2016~~2021		5
Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss): For the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2022 and ~~2016~~2021		5
Condensed Consolidated Statements of Cash Flows: For the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2022 and ~~2016~~2021		6
Condensed Consolidated Statements of Changes in Partners’ Capital: For the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2022 and ~~2016~~2021		7
Notes to the Condensed Consolidated Financial Statements:
1. Organization and Basis of Consolidation and Presentation		8
2. ~~Recent~~Summary of Significant Accounting ~~Pronouncements~~Policies		10
3. Revenues and Accounts Receivable		11
4. Net ~~Income/(Loss)~~ Income Per Common Unit		1114
~~4. Accounts Receivable, Net~~		13
5. Inventory, Linefill ~~and Base Gas~~ and Long-term Inventory	1315
6. ~~Acquisitions and Dispositions~~Debt		1415
7. ~~Goodwill~~		16
~~8. Debt~~	17
9. Partners’ Capital and Distributions	1816
~~10.~~8. Derivatives and Risk Management Activities		2018
~~11.~~9. Related Party Transactions		2922
~~12.~~10. Commitments and Contingencies		2923
~~13. Operating Segments~~11. Segment Information		3428


Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		3832
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		6350
Item 4. CONTROLS AND PROCEDURES		6551

PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS		6652
Item 1A. RISK FACTORS		6652
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		6652
Item 3. DEFAULTS UPON SENIOR SECURITIES		6652
Item 4. MINE SAFETY DISCLOSURES		6652
Item 5. OTHER INFORMATION		6652
Item 6. EXHIBITS		6653
SIGNATURES		6757



	Limited Partners						Partners’ Capital Excluding Noncontrolling Interests			Noncontrolling Interests			Total Partners’ Capital
	Series A Preferred Unitholders			Common Unitholders			Partners’ Capital Excluding Noncontrolling Interests			Noncontrolling Interests			Total Partners’ Capital
	(unaudited)
Balance at December 31, 2016	$	1,508		$	7,251		$	8,759		$	57		$	8,816
Net income	—			665			665			2			667
Cash distributions to partners	—			(1,168		)	(1,168		)	(2		)	(1,170		)
Sales of common units	—			1,664			1,664			—			1,664
Acquisition of interest in Advantage Joint Venture (Note 6)	—			40			40			—			40
Other comprehensive income	—			256			256			—			256
Other	(2		)	9			7			—			7
Balance at September 30, 2017	$	1,506		$	8,717		$	10,223		$	57		$	10,280



	Limited Partners						General Partner			Partners’ Capital Excluding Noncontrolling Interests			Noncontrolling Interests			Total Partners’ Capital
	Series A Preferred Unitholders			Common Unitholders			General Partner			Partners’ Capital Excluding Noncontrolling Interests			Noncontrolling Interests			Total Partners’ Capital
	(unaudited)
Balance at December 31, 2015	$	—		$	7,580		$	301		$	7,881		$	58		$	7,939
Net income	—			209			390			599			3			602
Cash distributions to partners	—			(835		)	(464		)	(1,299		)	(3		)	(1,302		)
Sale of Series A preferred units	1,509			—			33			1,542			—			1,542
Sales of common units	—			283			6			289			—			289
Other	(1		)	3			2			4			—			4
Balance at September 30, 2016	$	1,508		$	7,240		$	268		$	9,016		$	58		$	9,074



	September 30, 2017						December 31, 2016
	Volumes	Unit of Measure	Carrying Value		Price/ Unit ⁽¹⁾		Volumes	Unit of Measure	Carrying Value		Price/ Unit ⁽¹⁾
Inventory
Crude oil	10,632	barrels	$	480	$	45.15	23,589	barrels	$	1,049	$	44.47
NGL	16,604	barrels	390		$	23.49	13,497	barrels	242		$	17.93
Natural gas	—	Mcf	—		N/A		14,540	Mcf	32		$	2.20
Other	N/A		14		N/A		N/A		20		N/A
Inventory subtotal			884						1,343

Linefill and base gas
Crude oil	12,477	barrels	729		$	58.43	12,273	barrels	710		$	57.85
NGL	1,630	barrels	47		$	28.83	1,660	barrels	45		$	27.11
Natural gas	24,976	Mcf	108		$	4.32	30,812	Mcf	141		$	4.58
Linefill and base gas subtotal			884						896

Long-term inventory
Crude oil	1,800	barrels	86		$	47.78	3,279	barrels	163		$	49.71
NGL	2,120	barrels	49		$	23.11	1,418	barrels	30		$	21.16
Long-term inventory subtotal			135						193

Total			$	1,903					$	2,432



Identifiable assets acquired and liabilities assumed:	Estimated Useful Lives (Years)	Recognized amount
Property and equipment	3 - 70	$	299
Intangible assets	20	646
Goodwill	N/A	271
Other assets and liabilities, net (including $4 million of cash acquired)	N/A	1
		$	1,217



	Transportation			Facilities			Supply and Logistics		Total
Balance at December 31, 2016	$	806		$	1,034		$	504	$	2,344
Acquisitions ⁽¹⁾	271			—			—		271
Foreign currency translation adjustments	17			8			4		29
Dispositions and reclassifications to assets held for sale	(13		)	(33		)	—		(46		)
Balance at September 30, 2017	$	1,081		$	1,009		$	508	$	2,598



	Limited Partners
	Preferred Units	Common Units
Outstanding at December 31, 2016	64,388,853	669,194,419
Issuances of Series A preferred units in connection with in-kind distributions	3,941,096	—
Sales of common units	—	54,119,893
Issuance of common units in connection with acquisition of interest in Advantage Joint Venture (Note 6)	—	1,252,269
Issuances of common units under LTIP	—	622,557
Outstanding at September 30, 2017	68,329,949	725,189,138



Type of Offering	Common Units Issued			Net Proceeds ⁽¹⁾
Continuous Offering Program	4,033,567			$	129	(2	)
Omnibus Agreement ⁽³⁾	50,086,326	(4	)	1,535
	54,119,893			$	1,664



		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2017	$	174	$	215	$1.00 - $1.24
	2018	$	12	$	15	$1.00 - $1.22

Forward exchange contracts that exchange USD for CAD:
	2017	$	307	$	385	$1.00 - $1.26
	2018	$	118	$	147	$1.00 - $1.25



	Three Months Ended September 30, 2017									Three Months Ended September 30, 2016
Location of Gain/(Loss)	Derivatives in Hedging Relationships ⁽¹⁾			Derivatives Not Designated as a Hedge			Total			Derivatives in Hedging Relationships ⁽¹⁾			Derivatives Not Designated as a Hedge			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	—		$	(226	)	$	(226	)	$	1		$	10		$	11

Transportation segment revenues	—			—			—			—			1			1

Field operating costs	—			(4		)	(4		)	—			(2		)	(2		)

Interest Rate Derivatives

Interest expense, net	(10		)	—			(10		)	(2		)	—			(2		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			3			3			—			(1		)	(1		)

Preferred Distribution Rate Reset Option

Other income/(expense), net	—			2			2			—			17			17

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(10	)	$	(225	)	$	(235	)	$	(1	)	$	25		$	24



	Nine Months Ended September 30, 2017									Nine Months Ended September 30, 2016
Location of Gain/(Loss)	Derivatives in Hedging Relationships ⁽¹⁾			Derivatives Not Designated as a Hedge			Total			Derivatives in Hedging Relationships ⁽¹⁾			Derivatives Not Designated as a Hedge			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	—		$	(31	)	$	(31	)	$	1		$	(118	)	$	(117	)

Transportation segment revenues	—			—			—			—			4			4

Field operating costs	—			(8		)	(8		)	—			(2		)	(2		)

Depreciation and amortization	(3		)	—			(3		)	—			—			—

Interest Rate Derivatives

Interest expense, net	(16		)	—			(16		)	(8		)	—			(8		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			5			5			—			4			4

Preferred Distribution Rate Reset Option

Other income/(expense), net	—			—			—			—			42			42

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(19	)	$	(34	)	$	(53	)	$	(7	)	$	(70	)	$	(77	)



	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments:
Interest rate derivatives	Other current liabilities	$	2	Other current liabilities	$	(26	)
				Other long-term liabilities and deferred credits	(10		)
Total derivatives designated as hedging instruments		$	2		$	(36	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	74	Other current assets	$	(184	)
	Other long-term assets, net	1		Other current liabilities	(97		)
	Other current liabilities	10		Other long-term liabilities and deferred credits	(19		)
	Other long-term liabilities and deferred credits	5

Foreign currency derivatives	Other current assets	6		Other current assets	(2		)
				Other current liabilities	(2		)

Preferred Distribution Rate Reset Option		—		Other long-term liabilities and deferred credits	(33		)
Total derivatives not designated as hedging instruments		$	96		$	(337	)

Total derivatives		$	98		$	(373	)



	September 30, 2017						December 31, 2016
	Derivative Asset Positions			Derivative Liability Positions			Derivative Asset Positions			Derivative Liability Positions
Netting Adjustments:
Gross position - asset/(liability)	$	98		$	(373	)	$	108		$	(481	)
Netting adjustment	(203		)	203			(350		)	350
Cash collateral paid	194			—			410			—
Net position - asset/(liability)	$	89		$	(170	)	$	168		$	(131	)

Balance Sheet Location After Netting Adjustments:
Other current assets	$	88		$	—		$	167		$	—
Other long-term assets, net	1			—			1			—
Other current liabilities	—			(113		)	—			(40		)
Other long-term liabilities and deferred credits	—			(57		)	—			(91		)
	$	89		$	(170	)	$	168		$	(131	)



	Fair Value as of September 30, 2017												Fair Value as of December 31, 2016
Recurring Fair Value Measures ⁽¹⁾	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Commodity derivatives	$	(4	)	$	(198	)	$	(8	)	$	(210	)	$	(113	)	$	(171	)	$	(4	)	$	(288	)
Interest rate derivatives	—			(34		)	—			(34		)	—			(50		)	—			(50		)
Foreign currency derivatives	—			2			—			2			—			(3		)	—			(3		)
Preferred Distribution Rate Reset Option	—			—			(33		)	(33		)	—			—			(32		)	(32		)
Total net derivative liability	$	(4	)	$	(230	)	$	(41	)	$	(275	)	$	(113	)	$	(224	)	$	(36	)	$	(373	)


⁽¹⁾	~~Purchases and related costs include crude oil buy/sell transactions that are accounted for as inventory exchanges and are presented net in our Condensed Consolidated Statements of Operations.~~


⁽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 sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated.


⁽²⁾	~~Includes our proportionate share of the depreciation and amortization and gains or losses on significant asset sales of equity method investments.~~


⁽⁶⁾	~~Includes equity-indexed compensation expense associated with awards that will or may be settled in units.~~


⁽⁷⁾	~~Includes gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities.~~


~~Item 2.~~	~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~


⁽¹⁾	Acquisition capital for the first nine months of 2017 primarily relates to the ACC Acquisition. See Note 6 to our Condensed Consolidated Financial Statements for further discussion regarding our acquisition activities.


⁽²⁾	Acquisitions of initial investments or additional interests in unconsolidated entities are included in “Acquisition capital.” Subsequent 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.


⁽³⁾	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 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.


⁽¹⁾	~~Represents contributions related to our 50% investment interest.~~



	Three Months Ended September 30,						Variance					Nine Months Ended September 30,						Variance
	2017			2016			$			%		2017			2016			$			%
Transportation segment adjusted EBITDA ⁽¹⁾	$	363		$	308		$	55		18	%	$	933		$	863		$	70		8	%
Facilities segment adjusted EBITDA ⁽¹⁾	182			171			11			6	%	550			497			53			11	%
Supply and Logistics segment adjusted EBITDA ⁽¹⁾	(56		)	(17		)	(39		)	(229	)%	(32		)	208			(240		)	(115	)%
Adjustments:
Depreciation and amortization of unconsolidated entities	(13		)	(13		)	—			—	%	(31		)	(38		)	7			18	%
Selected items impacting comparability - segment adjusted EBITDA	(201		)	(21		)	(180		)	**		74			(269		)	343			**
Depreciation and amortization	(151		)	(33		)	(118		)	(358	)%	(401		)	(351		)	(50		)	(14	)%
Interest expense, net	(134		)	(113		)	(21		)	(19	)%	(390		)	(339		)	(51		)	(15	)%
Other income/(expense), net	(1		)	17			(18		)	(106	)%	(6		)	46			(52		)	(113	)%
Income tax benefit/(expense)	45			(1		)	46			**		(30		)	(15		)	(15		)	(100	)%
Net income	34			298			(264		)	(89	)%	667			602			65			11	%
Net income attributable to noncontrolling interests	(1		)	(1		)	—			—	%	(2		)	(3		)	1			33	%
Net income attributable to PAA	$	33		$	297		$	(264	)	(89	)%	$	665		$	599		$	66		11	%

Basic net income/(loss) per common unit	$	(0.01	)	$	0.40		$	(0.41	)	**		$	0.77		$	0.27		$	0.50		**
Diluted net income/(loss) per common unit	$	(0.01	)	$	0.40		$	(0.41	)	**		$	0.76		$	0.27		$	0.49		**
Basic weighted average common units outstanding	725			401			324			**		714			399			315			**
Diluted weighted average common units outstanding	725			402			323			**		715			400			315			**



Operating Results ⁽¹⁾	Three Months Ended September 30,						Variance					Nine Months Ended September 30,						Variance
(in millions, except per barrel data)	2017			2016			$			%		2017			2016			$			%
Revenues	$	446		$	401		$	45		11	%	$	1,260		$	1,188		$	72		6	%
Purchases and related costs	(29		)	(24		)	(5		)	(21	)%	(74		)	(69		)	(5		)	(7	)%
Field operating costs⁽²⁾	(134		)	(133		)	(1		)	(1	)%	(427		)	(406		)	(21		)	(5	)%
Equity-indexed compensation expense - field operating costs	(2		)	(3		)	1			**		(9		)	(9		)	—			**
Segment general and administrative expenses ^(2) (3)	(22		)	(22		)	—			—	%	(70		)	(67		)	(3		)	(4	)%
Equity-indexed compensation expense - general and administrative	(3		)	(4		)	1			**		(8		)	(10		)	2			**
Equity earnings in unconsolidated entities	80			46			34			74	%	201			133			68			51	%

Adjustments ⁽⁴⁾:
Depreciation and amortization of unconsolidated entities	13			13			—			—	%	31			38			(7		)	(18	)%
Deficiencies under minimum volume commitments, net	11			30			(19		)	**		2			54			(52		)	**
Equity-indexed compensation expense	3			4			(1		)	**		9			11			(2		)	**
Line 901 incident	—			—			—			**		12			—			12			**
Significant acquisition-related expenses	—			—			—			**		6			—			6			**
Segment adjusted EBITDA	$	363		$	308		$	55		18	%	$	933		$	863		$	70		8	%
Maintenance capital	$	32		$	29		$	3		10	%	$	89		$	86		$	3		3	%
Segment adjusted EBITDA per barrel	$	0.74		$	0.73		$	0.01		1	%	$	0.67		$	0.68		$	(0.01	)	(1	)%



Average Daily Volumes	Three Months Ended September 30,		Variance				Nine Months Ended September 30,		Variance
(in thousands of barrels per day)⁽⁵⁾	2017	2016	Volumes		%		2017	2016	Volumes		%
Tariff activities volumes
Crude oil pipelines (by region):
Permian Basin ⁽⁶⁾	2,963	2,162	801		37	%	2,732	2,129	603		28	%
South Texas / Eagle Ford ⁽⁶⁾	362	263	99		38	%	341	283	58		20	%
Western	190	194	(4	)	(2	)%	186	193	(7	)	(4	)%
Rocky Mountain ⁽⁶⁾	426	475	(49	)	(10	)%	418	448	(30	)	(7	)%
Gulf Coast	359	423	(64	)	(15	)%	362	538	(176	)	(33	)%
Central ⁽⁶⁾	424	403	21		5	%	419	393	26		7	%
Canada	351	379	(28	)	(7	)%	359	384	(25	)	(7	)%
Crude oil pipelines	5,075	4,299	776		18	%	4,817	4,368	449		10	%
NGL pipelines	172	185	(13	)	(7	)%	169	182	(13	)	(7	)%
Tariff activities total volumes	5,247	4,484	763		17	%	4,986	4,550	436		10	%
Trucking volumes	94	118	(24	)	(20	)%	102	113	(11	)	(10	)%
Transportation segment total volumes	5,341	4,602	739		16	%	5,088	4,663	425		9	%



	Favorable/(Unfavorable) Variance Three Months Ended September 30, 2017-2016					Favorable/(Unfavorable) Variance Nine Months Ended September 30, 2017-2016
(in millions)	Revenues			Equity Earnings		Revenues			Equity Earnings
Tariff and trucking activities:
Permian Basin region	$	60		$	9	$	129		$	17
South Texas / Eagle Ford region	—			20		(6		)	31
Rocky Mountain region	—			4		(13		)	10
Gulf Coast region	(3		)	—		(20		)	—
Other (including trucking and pipeline loss allowance revenue)	(12		)	1		(18		)	10
Total variance	$	45		$	34	$	72		$	68


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


	Three Months Ended March 31,	Variance
Average Volumes (in thousands of barrels per day) (4)		2022	2021	Volumes	%
NGL fractionation		134	144	(10)	(7)	%

NGL pipeline tariff		176	183	(7)	(4)	%

NGL sales		168	220	(52)	(24)	%



	As of September 30, 2017
Availability under senior unsecured revolving credit facility ^(1) (2)	$	1,584
Availability under senior secured hedged inventory facility ^(1) (2)	568
Availability under senior unsecured 364-day revolving credit facility	1,000
Amounts outstanding under commercial paper program	(698		)
Subtotal	2,454
Cash and cash equivalents	33
Total	$	2,487