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			=	~~London Interbank Offered Rate~~International Swaps and Derivatives Association
~~LTIP~~			=
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~~SOFR			=	Secured Overnight Financing Rate
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~~2022 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, 2022 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three and six months ended June 30, 2023 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 balances and 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~~

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

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

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~~Note 2—~~PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Recent Accounting Pronouncements

Except as discussed ~~below and~~ in our ~~2016~~2022 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 that are of significance or potential significance to us.

~~Accounting Standards Updates Adopted During the Period~~

Note 2—Revenues and Accounts Receivable

~~In March 2016, the FASB issued ASU 2016-09,~~ ~~Compensation — Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which simplified several aspects of the accounting for share-based payment~~

~~transactions, including the income tax consequences, forfeitures, classification of awards as either equity or liabilities~~Revenue Recognition

We disaggregate our revenues by segment 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) elected 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 to determine goodwill impairment by calculating the implied fair value of goodwill by hypothetically assigning the fair value of 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. This guidance is effective for interim and annual periods beginning after December 15, 2019, 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 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 have a material impact on our financial position, results of operations and cash flows.

~~In August 2017, the FASB issued ASU 2017-12,~~ ~~Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities~~ to better align an entity’s risk management activities 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 about the nature, amount, timing and uncertainty of revenue 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 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.activity. See Note 163 to our Consolidated Financial Statements included in Part IV of our ~~2016~~2022 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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Crude Oil segment revenues from contracts with customers
Sales	$	10,937	$	15,576	$	22,318	$	28,433
Transportation	255		175		505		330
Terminalling, Storage and Other	94		90		185		180
Total Crude Oil segment revenues from contracts with customers	$	11,286	$	15,841	$	23,008	$	28,943


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
NGL segment revenues from contracts with customers
Sales	$	232	$	499	$	885	$	1,344
Transportation	8		7		15		16
Terminalling, Storage and Other	23		20		52		45
Total NGL segment revenues from contracts with customers	$	263	$	526	$	952	$	1,405

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Reconciliation to Total Revenues of Reportable Segments. The following disclosures only include information regarding revenues associated with consolidated entities; revenues from entities accounted for by the equity method are not included. The following tables present the reconciliation of our ~~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 June 30, 2023	Crude Oil		NGL		Total
Revenues from contracts with customers	$	11,286	$	263	$	11,549
Other revenues	9		118		127
Total revenues of reportable segments	$	11,295	$	381	$	11,676
Intersegment revenues elimination					(74)
Total revenues					$	11,602

Three Months Ended June 30, 2022	Crude Oil		NGL		Total
Revenues from contracts with customers	$	15,841	$	526	$	16,367
Other revenues	99		44		143
Total revenues of reportable segments	$	15,940	$	570	$	16,510
Intersegment revenues elimination					(151)
Total revenues					$	16,359

Six Months Ended June 30, 2023	Crude Oil		NGL		Total
Revenues from contracts with customers	$	23,008	$	952	$	23,960
Other items in revenues	45		119		164
Total revenues of reportable segments	$	23,053	$	1,071	$	24,124
Intersegment revenues					(181)
Total revenues					$	23,943

Six Months Ended June 30, 2022	Crude Oil		NGL		Total
Revenues from contracts with customers	$	28,943	$	1,405	$	30,348
Other items in revenues	76		(101)		(25)
Total revenues of reportable segments	$	29,019	$	1,304	$	30,323
Intersegment revenues					(270)
Total revenues					$	30,053

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	June 30, 2023		December 31, 2022
Billed and collected	Other current liabilities	$	79	$	104
Unbilled (1)	N/A	1		1
Total		$	80	$	105

(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.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Contract Balances. Our contract balances consist of amounts received associated with services or sales for which we have not yet completed the related performance obligation. The following table presents the changes 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, 2022		$	229
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		(35)

Additions		20
Other		2
Balance at June 30, 2023		$	216

~~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 existed 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 contracts include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of June 30, 2023 (in millions):


	Remainder of 2023		2024		2025		2026		2027		2028 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	182	$	360	$	391	$	140	$	101	$	240
Terminalling, storage and other agreement revenues	137		217		134		106		96		771
Total	$	319	$	577	$	525	$	246	$	197	$	1,011

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

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

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

•Acreage dedications;

•Buy/sell arrangements with future committed volumes;

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

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

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

Trade Accounts Receivable and Other Receivables, Net

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of ~~NGL~~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.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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~~June 30, ~~2017~~2023 and December 31, ~~2016,~~2022, 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):


	June 30, 2023		December 31, 2022
Trade accounts receivable arising from revenues from contracts with customers	$	3,607	$	4,141
Other trade accounts receivables and other receivables (1)	5,926		7,216
Impact due to contractual rights of offset with counterparties	(6,313)		(7,450)
Trade accounts receivable and other receivables, net	$	3,220	$	3,907

(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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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 5—3—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.

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 2022 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 each of the three and six months ended June 30, 2023 and 2022 as the effect was antidilutive. 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 are deemed to be dilutive during the period are 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.

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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Basic and Diluted Net Income per Common Unit
Net income attributable to PAA	$	293	$	203	$	715	$	390
Distributions to Series A preferred unitholders	(44)		(37)		(85)		(74)
Distributions to Series B preferred unitholders	(18)		(12)		(36)		(25)
Amounts allocated to participating securities	(5)		(1)		(8)		(1)
Other	1		—		2		—
Net income allocated to common unitholders (1)	$	227	$	153	$	588	$	290

Basic and diluted weighted average common units outstanding	698		702		698		703

Basic and diluted net income per common unit	$	0.32	$	0.22	$	0.84	$	0.41

(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 4—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


	June 30, 2023						December 31, 2022
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	3,150	barrels	$	213	$	67.62	6,713	barrels	$	452	$	67.33
NGL	5,084	barrels	144		$	28.32	7,285	barrels	270		$	37.06

Other	N/A		10		N/A		N/A		7		N/A
Inventory subtotal			367						729

Linefill
Crude oil	15,226	barrels	898		$	58.98	15,480	barrels	906		$	58.53
NGL	2,168	barrels	68		$	31.37	1,876	barrels	55		$	29.32

Linefill subtotal			966						961

Long-term inventory
Crude oil	3,254	barrels	224		$	68.84	3,102	barrels	246		$	79.30
NGL	1,327	barrels	46		$	34.66	1,066	barrels	38		$	35.65
Long-term inventory subtotal			270						284

Total			$	1,603					$	1,974


⁽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~~various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products.

Table of ~~general and administrative expenses in our Condensed Consolidated Statements of Operations.~~Contents

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

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.NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~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—~~5—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


	June 30, 2023		December 31, 2022
SHORT-TERM DEBT



Senior notes:

2.85% senior notes due January 2023 (1)	$	—	$	400
3.85% senior notes due October 2023	700		700
Other	9		59
Total short-term debt	709		1,159

LONG-TERM DEBT
Senior notes, net of unamortized discounts and debt issuance costs of $44 and $46, respectively	7,239		7,237


Other	49		50
Total long-term debt	7,288		7,287
Total debt (2)	$	7,997	$	8,446

⁽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

(1)These senior notes were redeemed on January 31, 2023.

(2)Our fixed-rate senior notes had a face value of approximately $8.0 billion and $8.4 billion as of June 30, 2023 and December 31, 2022, respectively. We estimated the aggregate fair value of these notes as of June 30, 2023 and December 31, 2022 to be approximately $7.3 billion and $7.6 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. The fair value estimate 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⁾

Our fixed-rate senior notes (including current maturities) had a face value of approximately $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 is based upon observable market data and senior unsecured 364-day revolving credit facility to August 2022, August 2020 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 dateis 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~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022 were approximately ~~$52.6~~$1.5 billion and ~~$41.4~~$16.4 billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately ~~$52.7~~$1.5 billion and ~~$41.6~~$16.3 billion for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, 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.

On January 31, 2023, we redeemed our 2.85%, $400 million senior notes due January 2023.

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~~June 30, ~~2017~~2023 and December 31, ~~2016,~~2022, we had outstanding letters of credit of ~~$95~~$127 million and ~~$73~~$102 million, respectively.

~~Senior Notes Repayments~~

Table of Contents

~~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.~~PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 9—6—Partners’ Capital and Distributions

Units Outstanding

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


	Limited Partners
	Series A Preferred Units	Series B Preferred Units	Common Units
Outstanding at December 31, 2022	71,090,468	800,000	698,354,498

Issuances of common units under equity-indexed compensation plans	—	—	35,508
Outstanding at March 31, 2023 and June 30, 2023	71,090,468	800,000	698,390,006


	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
Repurchase and cancellation of common units under the Common Equity Repurchase Program	—	—	(4,876,062)
Issuances of common units under equity-indexed compensation plans	—	—	147,830
Outstanding at June 30, 2022	71,090,468	800,000	697,939,946

Distributions

Series A Preferred Unit Distributions. After the fifth anniversary of the January 28, 2016 issuance date of our Series A preferred units, ~~and common units:~~

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

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~~the holders of ~~Common Units~~

~~The following table summarizes~~ our ~~sales~~Series A preferred units, acting by majority vote, had the option to make a one-time election to reset the Series A preferred unit distribution rate to equal the then applicable rate of ~~common units during~~ten-year U.S. Treasury Securities plus 5.85% (the “Preferred Distribution Rate Reset Option”). In January 2023, the ~~nine months ended September 30, 2017, all of~~Series A preferred unitholders elected the Preferred Distribution Rate Reset Option which ~~occurred~~resulted in an increase in the ~~first four months~~quarterly distribution rate to approximately $0.615 per unit. This new distribution rate was effective on January 31, 2023. The quarterly distribution paid in May 2023 reflected a pro-rated amount of ~~the year (net proceeds in millions):~~

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 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 $1.20approximately $0.585 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.

unit. The following table details ~~the~~ distributions to our Series A preferred unitholders paid ~~in cash~~ during or pertaining to the first ~~nine~~six months of ~~2017~~2023 (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

August 14, 2023 (1)	$	44	$	0.615
May 15, 2023	$	42	$	0.585
February 14, 2023	$	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 July 31, 2023 for the period from April 1, 2023 through June 30, 2023. At June 30, 2023, such amount was accrued as distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

Table of Contents

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Series AB Preferred Unit Distributions. With respect to any quarter ending 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~~accumulate and are ~~cumulative from October 10, 2017, the date of original issue, and are~~ payable ~~semiannually 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~~November. See Note 12 to our Consolidated Financial Statements included in Part IV of ~~each year. The initial distribution rate~~our 2022 Annual Report on Form 10-K for ~~the~~additional information regarding our Series B preferred ~~units from and including October 10, 2017~~unit distributions. The following table details distributions paid or to ~~but not including, November 15, 2022 is 6.125% per year of the liquidation preference per unit (equal~~be paid to ~~$61.25 per unit per year). On and after November 15, 2022, distributions on the~~our Series B preferred ~~units will accumulate for each distribution period at a percentage of the liquidation preference equal~~unitholders (in millions, except per unit data):


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

August 15, 2023 (1)	$	19	$	24.10
May 15, 2023	$	18	$	22.18
February 15, 2023	$	18	$	22.27

(1)Payable 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 holders~~unitholders of record at the close of business on ~~November~~August 1, ~~2017 in an amount equal~~2023 for the period from May 15, 2023 through August 14, 2023. At June 30, 2023, approximately $10 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 six months of 2023 (in millions, except per unit data):


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

August 14, 2023 (1)	$	123	$	64	$	187	$	0.2675
May 15, 2023	$	122	$	65	$	187	$	0.2675
February 14, 2023	$	122	$	65	$	187	$	0.2675

(1)Payable to unitholders of record at the close of business on July 31, 2023 for the period from April 1, 2023 through June 30, 2023.

Noncontrolling Interests in ~~part, at~~Subsidiaries

As of June 30, 2023, noncontrolling interests in our subsidiaries consisted of (i) a ~~price~~35% interest in Plains Oryx Permian Basin LLC (the “Permian JV”), (ii) a 30% interest in Cactus II Pipeline LLC (“Cactus II”) and (iii) a 33% interest in Red River Pipeline Company LLC (“Red River”).

The following table details distributions paid to noncontrolling interests during the periods presented (in millions):


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Permian JV	$	53	$	58	$	111	$	112
Cactus II (1)	15		—		29		—
Red River	5		4		11		9
	$	73	$	62	$	151	$	121

(1)In November 2022, we acquired an additional interest in Cactus II which, combined with changes in the governance of ~~$1,020 (102%~~this entity, resulted in our obtaining control of the ~~liquidation preference) per Series B preferred unit plus an amount equal~~entity. Subsequent to ~~all accumulated and unpaid distributions thereon~~this transaction, we reflect Cactus II as a consolidated subsidiary. See Note 7 to ~~but not including,~~our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for additional information on the ~~date~~Cactus II transaction.

Table of redemption, whether or not declared. In addition, at any time on or after November 15, 2022, we may redeem 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 and unpaid distributions thereon to, but not including, the date of redemption, whether or not declared.Contents

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note ~~10—~~7—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)~~and 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 or interest 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 June 30, 2023 and December 31, 2022, 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:~~are described below.

~~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~~June 30, ~~2017,~~2023, net derivative positions related to these activities included:

•A net long position of ~~6.9~~5.0 million barrels associated with our crude oil purchases, which was unwound ratably during ~~October 2017~~July 2023 to match monthly average pricing.

•A net short time spread position of ~~3.5~~6.1 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through ~~December 2018.~~October 2024.

•A net crude oil ~~grade~~ basis spread position of ~~25.2~~1.9 million barrels at multiple locations through ~~December 2019.~~November 2024. These derivatives allow us to lock in grade and location basis differentials.

•A net short position of ~~14.4~~10.5 million barrels through ~~December 2020~~June 2024 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

Table 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.Contents

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

~~Natural Gas Processing/NGL Fractionation~~ — NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 hedgesJune 30, 2023:

Notional Volume

(Short)/Long

Remaining Tenor

Natural gas purchases

38.9 Bcf

December 2023

Propane sales

(7.5) MMbls

December 2023

Butane sales

(0.9) MMbls

December 2023

Condensate sales

(0.5) MMbls

December 2023

Fuel gas requirements (1)

4.4 Bcf

June 2024

Power supply requirements (1)

2.2 TWh

December 2030

(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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Product sales revenues	$	119	$	76	$	118	$	(136)
Field operating costs	6		8		(13)		21

Net gain/ (loss) from commodity derivative activity	$	125	$	84	$	105	$	(115)

~~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

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/(payable) (in millions):


	June 30, 2023		December 31, 2022
Initial margin	$	46	$	93
Variation margin returned	(177)		(236)
Letters of credit	(25)		(25)
Net broker payable	$	(156)	$	(168)

September 30,
2017 December 31, 2016
Initial margin $ 51
$ 119
Variation margin posted 143
291
Net broker receivable $ 194
$ 410

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.


	June 30, 2023								December 31, 2022
					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	$	221	$	(21)	$	(156)	$	44	$	300	$	(71)	$	(168)	$	61
Other long-term assets, net	3		—		—		3		9		(5)		—		4
Derivative Liabilities
Other current liabilities	—		(33)		—		(33)		2		(13)		—		(11)
Other long-term liabilities and deferred credits	2		(9)		—		(7)		—		—		—		—
Total	$	226	$	(63)	$	(156)	$	7	$	311	$	(89)	$	(168)	$	54

Interest Rate Risk Hedging

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

The following table summarizes the terms of our outstanding interest rate derivatives as of June 30, 2023 (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

6/15/2026

3.09

Cash flow hedge

Anticipated interest payments

4 forward starting swaps

(30-year)

100

6/14/2024

0.74

Cash flow hedge

During the three months ended June 30, 2023, we terminated $200 million of notional interest hedging instruments previously expected to terminate in June 2023 for proceeds of $80 million, of which $73 million was recorded in AOCI. As of ~~September~~June 30, ~~2017,~~2023, there was a net loss of ~~$224~~$100 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.~~2056 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of ~~September~~June 30, ~~2017;~~2023; 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/(loss) recognized in AOCI for derivatives (in millions):


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Interest rate derivatives, net	$	8	$	36	$	2	$	68

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

At ~~September~~June 30, ~~2017~~2023, the net fair value of our interest rate hedges, which were included in “Other current assets” and “Other long-term liabilities and deferred credits” on our Condensed Consolidated Balance Sheet, totaled $47 million and $5 million, respectively. At December 31, ~~2016, none~~2022, the net fair value of ~~our outstanding derivatives contained credit-risk related contingent features~~these hedges totaled $75 million and $45 million, which were included in “Other current assets” and “Other long-term assets, net,” respectively.

Preferred Distribution Rate Reset Option

In January 2023, we received notice that ~~would result~~the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option. Prior to this election, the Preferred Distribution Rate Reset Option was accounted for as an embedded derivative. A derivative feature embedded in a ~~material adverse impact~~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 ~~us upon any change~~those of the host contract. The Preferred Distribution Rate Reset Option embedded derivative was required to be bifurcated from the related host contract, our partnership agreement, and recorded at fair value on our Condensed Consolidated Balance Sheet. 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 Sheet, totaled $189 million at December 31, 2022. The Preferred Distribution Rate Reset Option was settled when we received notice that the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option. The fair value of the Preferred Distribution Rate Reset Option on the settlement date was $131 million. The Preferred Distribution Rate Reset Option embedded derivative was not designated in a hedging relationship for accounting purposes and corresponding changes in fair value were recognized in “Other income/(expense), net” in our ~~credit ratings. Although~~Condensed Consolidated Statements of Operations. For the three months ended June 30, 2022, we ~~may be required to post margin on our cleared derivatives as described above,~~recognized a loss of $103 million. For the six months ended June 30, 2023 and 2022, we ~~do not require our non-cleared derivative counterparties to post collateral with us.~~recognized a gain of $58 million and a net loss of $147 million, respectively. See Note 6 for additional information regarding 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 June 30, 2023								Fair Value as of December 31, 2022
Recurring Fair Value Measures (1)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivatives	$	9	$	154	$	—	$	163	$	(7)	$	229	$	—	$	222
Interest rate derivatives	—		42		—		42		—		120		—		120

Preferred Distribution Rate Reset Option	—		—		—		—		—		—		(189)		(189)
Total net derivative asset/(liability)	$	9	$	196	$	—	$	205	$	(7)	$	349	$	(189)	$	153


⁽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.

Level 2

Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives and over-the-counter commodity and 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.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Level 3

Level 3 of the fair value hierarchy includes ~~certain physical commodity contracts and~~ the Preferred Distribution Rate Reset Option contained in our partnership agreement which iswas classified as an embedded derivative.

~~The fair value of our Level 3 physical commodity contracts is based~~ As discussed above, the Preferred Distribution Rate Reset Option was settled on a valuation model utilizing timing estimates, which involve management judgment. Significant changes in timing could result in a material change in fair value to our physical commodity contracts. We report unrealized gains and losses associated with these physical commodity contracts in our Condensed Consolidated Statements of Operations as Supply and Logistics segment revenues.

January 31, 2023. The fair value of the ~~embedded derivative feature contained in our partnership agreement is~~Preferred Distribution Rate Reset Option was based on a Monte Carlo valuation model that ~~estimates~~estimated the fair value of the Series A preferred units with and without the Preferred Distribution Rate Reset Option. This model ~~contains inputs, including~~relied on assumptions for forecasts for the ten-year U.S. Treasury rate, our common unit price, ~~ten-year U.S. treasury rates,~~and default probabilities ~~and~~which impacted timing estimates ~~which involve management judgment. A significant increase or decrease in~~as to when 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.”option would be exercised.

~~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 June 30,				Six Months Ended June 30,
	2017			2016			2017			2016				2023		2022		2023		2022
Beginning Balance	$	(30	)	$	(35	)	$	(36	)	$	11		Beginning Balance	$	—	$	(44)	$	(189)	$	(2)
Net gains/(losses) for the period included in earnings	(8		)	17			(1		)	41			Net gains/(losses) for the period included in earnings	—		(103)		58		(147)
Settlements	(1		)	—			4			(10		)	Settlements	—		—		131		2
Derivatives entered into during the period	(2		)	1			(8		)	(59		)

Ending Balance	$	(41	)	$	(17	)	$	(41	)	$	(17	)	Ending Balance	$	—	$	(147)	$	—	$	(147)

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 gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period	$	—	$	(103)	$	—	$	(147)

Note ~~11—~~8—Related Party Transactions

See Note 1517 to our Consolidated Financial Statements included in Part IV of our ~~2016~~2022 Annual Report on Form 10-K for a complete discussion of related parties, including the determination of our related parties and nature of involvement with such related parties.

Promissory Notes with our General Partner

In March 2023, PAGP issued an unsecured promissory note to us with a face value of CAD$500 million (“related party note receivable”). Concurrently, we assigned PAGP our interest in an existing unsecured promissory note for the same face value amount due from a consolidated subsidiary (“related party note payable”). Both notes are due April 2027 and bear interest at a rate of 8.25% per annum, payable semi-annually.

Accrued and unpaid interest receivable/payable was $10 million as of June 30, 2023. Interest income/expense on the related party notes totaled $7 million and $10 million for the three and six months ended June 30, 2023, respectively.

As of June 30, 2023, our outstanding related party note receivable and related party note payable balances were as follows (in millions):


	June 30, 2023
Related party note receivable (1)	$	378
Related party note payable (1)	$	378

(1)We have elected to present our related party ~~transactions.~~

~~Omnibus Agreement~~

~~Pursuant to the Omnibus Agreement entered into by the Plains Entities in connection~~notes with the ~~Simplification Transactions,~~same counterparty on a net basis on our Condensed Consolidated Balance Sheet because there is a legal right to offset and we ~~issued approximately 1.8 million units~~intend to ~~AAP in connection~~offset with ~~PAGP’s issuance~~the counterparty.

Table 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.~~Contents

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Transactions with ~~Oxy~~Other Related Parties

~~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~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, we recognized sales and transportation revenues, ~~and~~ purchased petroleum products and utilized transportation and storage services from ~~Oxy.~~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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Revenues from related parties	$	12	$	10	$	23	$	22

Purchases and related costs from related parties	$	101	$	87	$	200	$	184


⁽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.~~

~~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):


	June 30, 2023		December 31, 2022
Trade accounts receivable and other receivables, net from related parties (1)	$	76	$	45

Trade accounts payable to related parties (1) (2)	$	72	$	79

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

(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.

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

Accounts payable $ 833
$ 836

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Note ~~12—~~9—Commitments and Contingencies

Loss Contingencies — General

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

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

Legal Proceedings — General

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

~~Taking into account what~~Accordingly, we believe to be all relevant known facts and circumstances, and based on what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing laws and regulations, we do not believecan provide no assurance that the outcome of the various legal proceedings ~~in which~~that we are currently involved ~~(including those described below)~~in, or will become involved with in the future, will not, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

Environmental — General

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

Although ~~over the course of the last several years~~ we have made significant investments in our maintenance and integrity programs, ~~and have hired additional personnel in those areas,~~ we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail, storage and other facility operations. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. We also may discover environmental impacts from past releases that were previously unidentified. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

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

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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~~both June 30, ~~2017,~~2023 and December 31, 2022, our estimated undiscounted reserve for environmental liabilities ~~(including~~(excluding liabilities related to the Line 901 incident, as discussed further below) totaled ~~$134~~$55 million, of which ~~$47~~$10 million was classified as short-term and ~~$87~~$45 million was classified as ~~long-term. At December 31, 2016, our estimated undiscounted reserve~~long-term for ~~environmental~~each period. Such short-term liabilities (including liabilities related to the Line 901 incident) totaled $147 million, of which $61 million was classified as short-term and $86 million was classified as long-term. The short- and long-term environmental liabilities referenced above are reflected in ~~“Accounts payable~~“Other current liabilities” and ~~accrued liabilities” and “Other~~long-term liabilities are reflected in “Other long-term liabilities and deferred credits” ~~respectively,~~ on our Condensed Consolidated Balance Sheets. At ~~September~~both June 30, ~~2017,~~2023 and December 31, 2022, we had recorded receivables (excluding receivables related to the Line 901 incident) totaling ~~$47~~$4 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.

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.

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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~~EPA, CDFW, the California Department of Parks and Recreation, the California State Lands Commission, the California Department of Forestry and Fire Protection’s Office of the State Fire Marshal, Central Coast Regional Water Quality Control Board, and Regents of the University of California. The Consent Decree was approved and entered by the Federal District Court for the Central District of California on October 14, 2020. Pursuant to the terms of the Consent Decree, Plains paid $24 million in civil penalties and $22.325 million as compensation for injuries to, destruction of, loss of, or loss of use of natural resources resulting from the Line 901 incident. The Consent Decree, which resolved all regulatory claims related to the incident, also contains requirements for implementing certain agreed-upon injunctive relief, as well as requirements for potentially restarting Line 901 and the Sisquoc to Pentland portion of Line 903. On October 13, 2022, Plains sold Line 901 and the Sisquoc to Pentland portion of Line 903 to Pacific Pipeline Company, an indirect wholly owned subsidiary of Exxon Mobil Corporation. As required by the terms of the Consent Decree, such purchaser assumed responsibility for compliance with ~~jurisdiction over~~ the Consent Decree as it relates to the future ownership and operation of Line 901 ~~as well as over a second stretch of pipeline extending from Gaviota Pump Station in Santa Barbara County~~and the Sisquoc to Emidio Pump Station in Kern County, California (Line 903), requiring us to shut down, purge, review, remediate and test Line 901. The corrective action order was subsequently amended on June 3, 2015; November 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 sectionPentland portion of Line ~~903 between Pentland Pump Station~~903.

Following an investigation 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 out of the release. Excavation and removal of the affected section of the pipeline was completed on May 28, 2015. Line 901 and Line 903 have been purged and are not currently operational, with the exception of the Pentland to Emidio segment of Line 903, which remainsgrand jury proceedings, in ~~service under a pressure restriction. No timeline has been established for the restart of Line 901 or Line 903.~~

On February 17, 2016, PHMSA issued a Preliminary Factual Report of the Line 901 failure, which contains PHMSA’s preliminary findings regarding factual information about the events leading up to the accident and the technical analysis that has been conducted to date. On May 19, 2016, PHMSA issued its final Failure Investigation Report regarding the Line 901 incident. PHMSA’s findings indicate that the direct cause of the Line 901 incident was external corrosion that thinned the pipe wall to a level where it ruptured suddenly and released crude oil. PHMSA also concluded that there were numerous contributory causes of the Line 901 incident, including ineffective protection against external corrosion, failure to detect and mitigate the corrosion and a lack of timely detection and response to the rupture. The report also included copies of various engineering and technical reports regarding the incident. By virtue 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, 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 one felony discharge count and eight misdemeanor counts (which included one reporting count, one strict liability discharge count and six strict liability animal takings counts) and (ii) found not guilty on one strict liability animal takings count. The remaining counts were subsequently dismissed by the Court. On April 25, 2019, PAA was sentenced to ~~all counts.~~pay fines and penalties in the aggregate amount of just under $3.35 million for the convictions covered by the September 2018 jury verdict (the “2019 Sentence”). The fines and penalties imposed in connection with the 2019 Sentence have been paid. In September 2021, the Superior Court concluded a series of hearings on the issue of whether there were any “direct victims” of the spill that are entitled to restitution under applicable criminal law. Through a series of final orders issued at the trial court level and without affecting any rights of the claimants under civil law, the Court dismissed the vast majority of the claims and ruled that the claimants were not entitled to restitution under applicable criminal laws. The Court did award an aggregate amount of less than $150,000 to a handful of claimants and we settled with approximately 40 claimants before the hearings for aggregate consideration that is not material. The prosecution and certain separately represented claimants have appealed the Court’s rulings.

~~Also~~We also received several individual lawsuits and claims from companies, governmental agencies and individuals alleging damages arising out of the Line 901 incident. These lawsuits and claims generally seek restitution, compensatory and punitive damages, and/or injunctive relief. The majority of these lawsuits have been settled or dismissed by the court. In addition to the other lawsuits disclosed herein, the following lawsuits remain: (i) a lawsuit filed in ~~late May of 2015,~~ the United States ~~Attorney~~District Court for the ~~Department of Justice,~~ Central District of California ~~Environmental Crimes Section (“DOJ”) began an investigation into whether there were any violations of federal criminal statutes~~that was remanded to the California Superior Court in ~~connection with~~Santa Barbara County 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, including potential violations~~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 costs related to the ~~federal Clean Water Act. We are cooperating~~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 the DOJ’s investigation by responding to their requests for documents and access to our employees. The DOJ has already spoken to several 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 date and we will continue to do so in the future in cooperation with the EPA. While to date no civil or criminal charges with respect tooil production activities they claim were disrupted following the Line 901 ~~release, other than those brought pursuant to the May 2016 Indictment,~~incident. We are vigorously defending these remaining lawsuits and believe we have been brought against PAA or any of its affiliates, officers or employees by PHMSA, DOJ, EPA, the California Attorney General, the Santa Barbara District Attorney or the California Department of Fish and Wildlife, and no fines or penalties have been imposed by such governmental agencies, the investigations being conducted by such agencies are still open and we may have fines or penalties imposed upon us, our officers or our employees, or civil or criminal charges brought against us, our officers or our employees in the future, whether by those or other governmental agencies.strong defenses.

~~Shortly~~Furthermore, 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. Nine 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~~two proceedings remained pending in the United States District Court for the Central District of California.

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In ~~general,~~the first proceeding, the plaintiffs ~~are seeking~~seek a declaratory judgment that Plains’ right-of-way agreements would not allow Plains to ~~establish~~lay a new pipeline to replace Line 901 and/or the non-operating segment of Line 903 without paying additional compensation. The purchaser of Line 901 and the Sisquoc to Pentland portion of Line 903 has joined this proceeding as a co-defendant with respect to its interest in such acquired pipelines.

In the second proceeding, the plaintiffs claimed 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 and/~~residential beachfront properties, or ~~beachfront property on~~properties with a private easement to a beach, where plaintiffs claim oil from the ~~Pacific Coast~~spill washed up.

In 2022, in order to fully and finally resolve all claims and litigation for both classes, we reached an agreement to settle this case in exchange for a payment of ~~California, and other classes of individuals and businesses that were allegedly impacted~~$230 million (the “Class Action Settlement”). The Class Action Settlement was formally approved by the ~~release.~~trial court on September 20, 2022, and we made the $230 million settlement payment on October 27, 2022. Plains formally submitted claims for reimbursement of the Class Action Settlement to our insurance carriers on November 7, 2022. To date, ~~only~~we have received payment of approximately $3.6 million from one insurer, which represents the ~~commercial fisherman~~final payment obligation of such insurer and ~~seafood reseller class has been certified~~brings the total amount collected from all insurers under such program to $275 million of the $500 million policy limits as of June 30, 2023. Insurers responsible for $185 million of the remaining $225 million of coverage formally communicated a denial of coverage for the Class Action Settlement generally alleging that some or all damages encompassed by the ~~court. We~~Class Action Settlement are ~~also defending a separate class action lawsuit proceeding in~~not covered by their policies and that all or some portion of the ~~United States District Court~~$275 million for which Plains has already received insurance reimbursement does not properly exhaust the underlying policies that paid those sums. The insurer responsible for the ~~Central District~~final $40 million of ~~California brought on behalf~~coverage under such insurance program has not yet responded to our reimbursement demand. We have initiated arbitration proceedings against the insurers responsible for $175 million of coverage and intend to vigorously pursue recovery from our insurers of all amounts for which we have claimed reimbursement. We believe that our claim for reimbursement from our insurers of the ~~Line 901~~Class Action Settlement payment is strong and ~~Line 903 easement holders seeking injunctive relief as well as compensatory damages.~~

~~There have also been two securities law class action lawsuits filed on behalf~~that our ultimate recovery of ~~certain purported investors in the Partnership and/or PAGP against the Partnership, PAGP and/or certain~~such amounts is probable. Our belief is based on: (i) our analysis 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~~underlying insurance policies as applied to the facts and circumstances that comprise our claim for reimbursement, (ii) our experience with ~~such underwriters.~~

~~In addition, four unitholder derivative lawsuits have been filed by certain purported investors in~~ the ~~Partnership against the Partnership, certain~~cost submissions and timely collection of ~~its affiliates and certain officers and directors. Two of these lawsuits were filed in the United States District Court~~claims for the ~~Southern District of Texas and were administratively consolidated into one action and later dismissed on~~$275 million collected to date for this incident under the ~~basis that Plains Partnership agreements require that derivative suits be filed in Delaware Chancery Court. Following~~same insurance program as 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 oversightdenied claims, including from some of the ~~Partnership during the period of time leading up to~~same insurers who are now denying claims, (iii) our extensive legal review and ~~following the Line 901 release. The plaintiffs in the two remaining lawsuits claim that the Partnership suffered unspecified damages as a result~~assessment of the ~~actions~~insurer’s claimed basis for denial of coverage, which review and assessment includes the ~~various defendants and seek to hold the defendants liable for such damages, in addition to other remedies. The defendants deny the allegations~~advice of external legal counsel experienced in these ~~lawsuits~~type of matters and ~~have responded accordingly. Consistent with and subject~~solidly supports our belief that our insurers are required to provide coverage based on the terms of the policies and the nature of our ~~governing organizational documents~~

(claims, and (iv) the financial strength of the insurance carriers as determined by an independent credit ratings agency. Various factors could impact the timing and amount of recovery of our insurance receivable, including future developments that adversely impact our assessment of the strength of our coverage claims, the outcome of any dispute resolution proceedings with respect to our coverage claims and the extent ~~applicable, insurance policies), we are indemnifying and funding~~to which insurers may become insolvent in the ~~defense costs~~future. An unfavorable resolution could have a material impact on our results of ~~our officers and directors in~~operations.

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In connection with ~~these lawsuits.~~

Wethe foregoing, including the Class Action Settlement and the Derivative Settlement, we have ~~also received several other individual lawsuits and complaints from companies and individuals alleging damages arising out of the~~made adjustments to our total estimated Line 901 ~~incident. These lawsuits and claims generally seek compensatory and punitive damages, and in some cases permanent injunctive relief.~~

~~In addition to the foregoing, as the “responsible party” for the Line 901 incident we are liable for various~~ costs and ~~for certain natural resource damages under~~ the Oil Pollution Act, 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~~June 30, ~~2017,~~2023, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately ~~$300~~$740 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.

During the six months ended June 30, 2022, we recognized costs, net of amounts probable of recovery from insurance carriers, of $85 million. We did not recognize any such costs during the six months ended June 30, 2023. As of ~~September~~June 30, ~~2017,~~2023, we had a remaining undiscounted gross liability of ~~$64~~approximately $98 million related to ~~this event, of~~the Line 901 incident, which ~~approximately $36 million~~aggregate amount is ~~presented as a current liability~~reflected in ~~“Accounts payable and accrued~~“Current liabilities” on our Condensed Consolidated Balance ~~Sheet, with the remainder presented in “Other long-term liabilities and deferred credits”. We~~Sheet. As discussed above, we maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such ~~environmental~~ liabilities. ~~Subject~~As of June 30, 2023, our incurred costs for the Line 901 incident have exceeded our insurance coverage limit of $500 million related to ~~such exclusions and deductibles, we believe that~~ our ~~coverage is adequate~~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 by $240 million. Through ~~September~~June 30, ~~2017,~~2023, we had collected, subject to customary reservations, ~~$166~~approximately $280 million out of the ~~approximate $205~~$505 million of release costs that we believe are probable of recovery from insurance carriers (including the 2015 insurance program and our directors and officers (D&O) insurance policies), net of deductibles. Therefore, as of ~~September~~June 30, ~~2017,~~2023, we have recognized a long-term receivable of approximately ~~$39~~$225 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~~We anticipate that the process to enforce our coverage claims with respect to the Class Action Settlement will take time and, accordingly, have recognized such amount ~~approximately $18 million is recognized~~ as a ~~current~~long-term asset in ~~“Trade accounts receivable and other receivables, net”~~“Other assets” 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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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Other Litigation Matters. On July 19, 2022 Hartree Natural Gas Storage, LLC (“Hartree”) filed a lawsuit under seal in the Superior Court for the State of Delaware asserting claims against PAA Natural Gas Storage, L.P. and PAA arising out of a Membership Interest Purchase Agreement relating to the 2021 sale of the Pine Prairie Energy Center natural gas storage facility to Hartree. We believe the claims are without merit and that the outcome of the lawsuit will not have a material adverse effect on our financial condition, results of operations or cash flows. We intend to vigorously defend against the claims asserted in this lawsuit.

Insurance

Pipelines, terminals, trucks or other facilities or equipment may experience damage as a result of an accident, natural disaster, terrorist attack, cyber event or other event. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. Consistent with insurance coverage generally available in the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences. We maintain various types and varying levels of insurance coverage to cover our operations and properties, and we self-insure certain risks, including gradual pollution, cybersecurity and named windstorms. To the extent we do maintain insurance coverage, 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 insurance or 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.

Note ~~13—Operating Segments~~10—Segment Information

We manage our operations through ~~three~~two operating segments, which are also our reportable segments: ~~Transportation, Facilities~~Crude Oil and ~~Supply~~NGL. See Note 20 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for a summary of the types of products and ~~Logistics.~~services from which each segment derives its revenues. 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.

The measure of Segment Adjusted EBITDA forms the basis of our internal financial reporting and is the primary performance measure used by our CODM in assessing performance and allocating resources among our operating segments. 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 (including write-downs related to cancelled projects and ~~gains or losses on significant asset sales~~impairments) 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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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 June 30, 2023
Revenues (1):
Product sales	$	10,925	$	346	$	(70)	$	11,201
Services	370		35		(4)		401
Total revenues	$	11,295	$	381	$	(74)	$	11,602
Equity earnings in unconsolidated entities	$	89	$	—			$	89
Segment Adjusted EBITDA	$	529	$	62			$	591

Maintenance capital expenditures	$	36	$	26			$	62





Three Months Ended June 30, 2022
Revenues (1):
Product sales	$	15,625	$	525	$	(143)	$	16,007
Services	315		45		(8)		352
Total revenues	$	15,940	$	570	$	(151)	$	16,359
Equity earnings in unconsolidated entities	$	104	$	—			$	104
Segment Adjusted EBITDA	$	494	$	120			$	614

Maintenance capital expenditures	$	25	$	18			$	43





Six Months Ended June 30, 2023
Revenues (1):
Product sales	$	22,333	$	982	$	(170)	$	23,145
Services	720		89		(11)		798
Total revenues	$	23,053	$	1,071	$	(181)	$	23,943
Equity earnings in unconsolidated entities	$	178	$	—			$	178
Segment Adjusted EBITDA	$	1,046	$	254			$	1,300

Maintenance capital expenditures	$	67	$	42			$	109





Six Months Ended June 30, 2022
Revenues (1):
Product sales	$	28,435	$	1,207	$	(254)	$	29,388
Services	584		97		(16)		665
Total revenues	$	29,019	$	1,304	$	(270)	$	30,053
Equity earnings in unconsolidated entities	$	201	$	—			$	201
Segment Adjusted EBITDA	$	946	$	281			$	1,227

Maintenance capital expenditures	$	45	$	25			$	70

⁽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.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Transportation revenues from external customers include inventory exchanges that are substantially similar to tariff-like arrangements with our customers. Under these arrangements, our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See Note 2 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for a discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenue presented above and adjusted those revenues out such that Total revenue from External customers reconciles to our Condensed Consolidated Statements of Operations. This presentation is consistent with the information provided to our CODM.


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

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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Segment Adjusted EBITDA	$	591	$	614	$	1,300	$	1,227
Adjustments: (1)
Depreciation and amortization of unconsolidated entities (2)	(24)		(17)		(47)		(37)
Derivative activities and inventory valuation adjustments (3)	86		75		(6)		(13)
Long-term inventory costing adjustments (4)	(2)		13		(31)		105
Deficiencies under minimum volume commitments, net (5)	2		(10)		9		(15)
Equity-indexed compensation expense (6)	(8)		(7)		(17)		(15)
Foreign currency revaluation (7)	(19)		(3)		(15)		(1)
Line 901 incident (8)	—		—		—		(85)

Adjusted EBITDA attributable to noncontrolling interests (9)	103		89		200		166
Depreciation and amortization	(259)		(242)		(515)		(473)
Gains/(losses) on asset sales and asset impairments, net	(3)		3		150		46

Interest expense, net	(95)		(99)		(193)		(206)
Other income/(expense), net	20		(118)		85		(155)
Income before tax	392		298		920		544
Income tax expense	(43)		(47)		(96)		(68)
Net income	349		251		824		476
Net income attributable to noncontrolling interests	(56)		(48)		(109)		(86)
Net income attributable to PAA	$	293	$	203	$	715	$	390

⁽¹⁾

(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 and impairments) of unconsolidated entities.

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

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

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(5)We, and certain of our equity method investees, 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.~~


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

⁽³⁾

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

⁽⁴⁾

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

⁽⁵⁾

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⁾	~~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.~~


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

⁽⁹⁾

Includes acquisition-related expenses associated with the ACC Acquisition. See Note 6 for additional discussion. An adjustment for these non-recurring expenses is included in the calculation of segment adjusted EBITDA for the three and nine months ended September 30, 2017 as our CODM does not view such expenses as integral to understanding our core segment operating performance. Acquisition-related expenses for the 2016 period were not significant to segment adjusted EBITDA.

(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 2022 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 9 for additional information regarding the Line 901 incident.

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

Note 11— Acquisitions and Divestitures

Acquisitions

OMOG Acquisition. On July 28, 2023, we acquired the remaining 43% interest in OMOG JV LLC (“OMOG”) for approximately $225 million ($145 million net to our 65% interest in the Permian JV). As a result of this transaction, we now own 100% of OMOG and its subsidiaries and such entities will be reflected as consolidated subsidiaries in our consolidated financial statements. Prior to this transaction, our 57% interest in OMOG was accounted for as an equity method investment.

Divestitures

Keyera Fort Saskatchewan Divestiture. In February 2023, we sold our 21% non-operated/undivided joint interest in the Keyera Fort Saskatchewan facility for approximately $270 million. As of December 31, 2022, we classified the assets related to this transaction (primarily “Property and equipment” in our NGL segment), valued at the lower of the carrying amount or fair value less costs to sell, of approximately $130 million as assets held for sale, which is reflected in “Other current assets” on our Condensed Consolidated Balance Sheet. Upon the sale of this facility, we recognized a gain of approximately $140 million which is included in “(Gains)/losses on asset sales and asset impairments, net” on our Condensed Consolidated Statement of Operations.

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

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

Introduction

The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical Consolidated Financial Statements and accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations as presented in our ~~2016~~2022 Annual Report on Form 10-K. For more detailed information regarding the basis of presentation for the following financial information, see the Condensed Consolidated Financial Statements and related notes that are contained in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Our discussion and analysis includes the following:

•Executive Summary

~~Acquisitions and Capital Projects~~

•Results of Operations

~~Outlook~~

•Liquidity and Capital Resources

~~Off-Balance Sheet Arrangements~~

•Recent Accounting Pronouncements

~~Critical Accounting Policies and Estimates~~

•Forward-Looking Statements

Executive Summary

Company Overview

~~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 and transportation corridors and at major market hubs in the United States and Canada. ~~We were formed in 1998,~~Our assets and ~~our operations~~the services we provide are ~~conducted directly~~primarily focused on crude oil and ~~indirectly through our operating subsidiaries and are managed through three operating segments: Transportation, Facilities and Supply and Logistics. See “—Results of Operations~~—~~Analysis of Operating Segments” for further discussion.~~NGL.

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

During the first ~~nine~~six months of ~~2017,~~2023, we recognized net income attributable to PAA of ~~$665~~$715 million as compared to ~~net income attributable to PAA of $599~~$390 million ~~recognized~~ during the first ~~nine~~six months of ~~2016. Our financial~~2022. The increase in operating results for the first six months of 2023 over the comparable 2022 period was driven primarily by more favorable results in our Crude Oil segment resulting from higher volumes on our pipelines and market-based opportunities. In addition, the 2022 comparative ~~periods were~~period was impacted ~~by:~~by an increase in the accrual for estimated costs associated with the Line 901 incident.

~~The~~Additionally, net income for the first six months of 2023 compared to the first six months of 2022 includes more favorable ~~impact of contributions~~impacts from ~~our recently completed acquisitions and capital expansion projects and~~ gains on ~~certain derivative instruments,~~asset sales and the mark-to-market adjustment of the Preferred Distribution Rate Reset Option, partially offset by less favorable ~~crude oil and NGL market conditions and margin compression caused by continued intense competition;~~impacts of long-term inventory costing adjustments.

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

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Results of Operations

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

Higher depreciation and amortization expense largely driven by (i) recently acquired assets, (ii) the completion of various capital expansion projects and (iii) net losses from non-core assets sales and joint venture formations recognized in the 2017 period, compared to net gains from such activities in 2016, all partially offset by impairment losses recognized during the 2016 period; and

~~The mark-to-market of our Preferred Distribution Rate Reset Option, resulting in a smaller gain in the current period compared to the prior period.~~

~~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:

Reset our annualized distribution per common unit to $1.20, starting with the third-quarter distribution payable in November 2017, which would reduce annual distribution outflow by approximately $725 million per year, representing approximately $1.1 billion over 6 quarters;

~~Complete pending and/or in-progress non-core/strategic asset sales totaling approximately $700 million;~~

~~Reduce our hedged crude oil and NGL inventory volumes and related debt by approximately $300 million (based on current prices);~~

~~Fund our second-half 2017 and full-year 2018 expansion capital program with a combination of non-convertible, perpetual preferred equity and a portion of the non-core asset sales proceeds; and~~

~~Apply retained cash flows and remaining asset sales proceeds to steadily reduce our total debt as of June 30, 2017 by approximately $1.4 billion through March 31, 2019.~~

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:~~

~~Resetting our annualized distribution per common unit to $1.20 for the third-quarter distribution payable in November 2017;~~

Reducing hedged inventory related borrowings at the end of the third quarter by approximately $200 million (as compared to the end of the second quarter), with the expectation to reduce these borrowings by an additional $100 million or more over the next quarter or two, assuming current commodity prices;

~~Completing the issuance of 800,000 Series B preferred units for net proceeds of $788 million; and~~

Completing sales of assets or joint venture formations for aggregate proceeds of approximately $385 million, and entering into definitive agreements for additional asset sales, which are expected to close by the end of 2017 or early 2018 and substantially complete our $700 million targeted program.

~~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


⁽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.

~~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~~


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

~~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 June 30,				Variance				Six Months Ended June 30,				Variance
	2023		2022		$		%		2023		2022		$		%
Product sales revenues	$	11,201	$	16,007	$	(4,806)	(30)	%	$	23,145	$	29,388	$	(6,243)	(21)	%
Services revenues	401		352		49		14	%	798		665		133		20	%
Purchases and related costs	(10,544)		(15,324)		4,780		31	%	(21,867)		(28,109)		6,242		22	%
Field operating costs	(333)		(307)		(26)		(8)	%	(690)		(653)		(37)		(6)	%
General and administrative expenses	(85)		(78)		(7)		(9)	%	(171)		(160)		(11)		(7)	%
Depreciation and amortization	(259)		(242)		(17)		(7)	%	(515)		(473)		(42)		(9)	%
Gains/(losses) on asset sales and asset impairments, net	(3)		3		(6)		(200)	%	150		46		104		226	%
Equity earnings in unconsolidated entities	89		104		(15)		(14)	%	178		201		(23)		(11)	%

Interest expense, net	(95)		(99)		4		4	%	(193)		(206)		13		6	%
Other income/(expense), net	20		(118)		138		117	%	85		(155)		240		155	%
Income tax expense	(43)		(47)		4		9	%	(96)		(68)		(28)		(41)	%
Net income	349		251		98		39	%	824		476		348		73	%
Net income attributable to noncontrolling interests	(56)		(48)		(8)		(17)	%	(109)		(86)		(23)		(27)	%
Net income attributable to PAA	$	293	$	203	$	90	44	%	$	715	$	390	$	325	83	%

Basic and diluted net income per common unit	$	0.32	$	0.22	$	0.10	**		$	0.84	$	0.41	$	0.43	**

Basic and diluted weighted average common units outstanding	698		702		(4)		**		698		703		(5)		**

^**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. 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.

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A majority of our sales and purchases are indexed to WTI. The following table presents the range of NYMEX WTI benchmark prices of crude oil (in dollars per barrel):


	NYMEX WTI Crude Oil Price
	Low		High		Average
Three Months Ended June 30, 2023	$	67	$	83	$	74
Three Months Ended June 30, 2022	$	94	$	122	$	109

Six Months Ended June 30, 2023	$	67	$	83	$	75
Six Months Ended June 30, 2022	$	76	$	124	$	102

Product sales revenues and purchases decreased for the three and six months ended June 30, 2023 compared to the same periods in 2022 primarily due to lower commodity prices in the 2023 periods. The decrease for the six-month period was partially offset by higher volumes in the 2023 period.

Revenues from services increased for the three and six months ended June 30, 2023 compared to the same periods in 2022 primarily due to higher volumes and tariff escalations in the 2023 periods, as well as the impact of the consolidation of Cactus II resulting from our acquisition of an additional interest in November 2022.

See further discussion of our net revenues (revenues less purchases and related costs) 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 and six months ended June 30, 2023 compared to the same periods in 2022 was primarily due to (i) higher information systems costs due to ongoing systems integration work and (ii) higher 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), partially offset by (iii) lower transition costs associated with the formation of the Permian JV and (iv) the impact of exchange rate fluctuations.

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

The net gains on asset sales and asset impairments for the six months ended June 30, 2023 was primarily comprised of a gain of approximately $140 million related to the sale of our Keyera Fort Saskatchewan facility in the first quarter of 2023. See Note 11 to our Condensed Consolidated Financial Statements for additional discussion of this transaction.

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 and six months ended June 30, 2023 compared to the same periods in 2022 was largely driven by our acquisition of an additional interest in Cactus II, for which our ownership interest is now consolidated. See Note 7 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for additional information.

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Interest Expense, Net

The decrease in interest expense for the three and six months ended June 30, 2023 compared to the three and six months ended June 30, 2022 was primarily due to a lower weighted average debt balance during the 2023 periods largely driven by the repayment of $750 million of senior notes in March 2022 and $400 million of senior notes in January 2023.

Other Income/(Expense), Net

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Gain/(loss) on mark-to-market adjustment of Preferred Distribution Rate Reset Option embedded derivative (1)	$	—	$	(103)	$	58	$	(147)
Net gain/(loss) on foreign currency revaluation (2)	14		(16)		14		(9)
Other	6		1		13		1
	$	20	$	(118)	$	85	$	(155)


⁽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 7 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 USD to CAD exchange rate on the portion of our intercompany net investment that is not long-term in nature.

Income Tax (Expense)/Benefit

The net unfavorable income tax variance for the six months ended June 30, 2023 compared to the same period in 2022 was primarily a result of increased activity within our Canadian operations including the tax impact of the Keyera Fort Saskatchewan divestiture in the first quarter of 2023.

Noncontrolling Interests

The increase in amounts attributable to noncontrolling interests for the three and six months ended June 30, 2023 compared to the same periods in 2022 was primarily due to (i) the consolidation of Cactus II in November 2022 and (ii) higher results from the Permian JV in the 2023 periods. See Note 7 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for additional information on the Cactus II transaction.

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Non-GAAP Financial Measures

To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the ~~future.~~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, including write-downs related to cancelled projects and impairments, of unconsolidated entities), gains and losses on ~~significant~~ asset sales and asset impairments 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—Non-GAAP Financial Liquidity Measures” for additional information regarding Free Cash Flow and Free Cash Flow after Distributions.

Non-GAAP Financial 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 financial performance 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 ~~from~~Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF to Net Income (in millions):


	Three Months Ended June 30,				Variance				Six Months Ended June 30,				Variance
	2023		2022		$		%		2023		2022		$		%

Net income	$	349	$	251	$	98	39	%	$	824	$	476	$	348	73	%
Interest expense, net	95		99		(4)		(4)	%	193		206		(13)		(6)	%
Income tax expense	43		47		(4)		(9)	%	96		68		28		41	%
Depreciation and amortization	259		242		17		7	%	515		473		42		9	%
(Gains)/losses on asset sales and asset impairments, net	3		(3)		6		200	%	(150)		(46)		(104)		(226)	%

Depreciation and amortization of unconsolidated entities (1)	24		17		7		41	%	47		37		10		27	%
Selected Items Impacting Comparability:
Derivative activities and inventory valuation adjustments	(86)		(75)		(11)		**		6		13		(7)		**
Long-term inventory costing adjustments	2		(13)		15		**		31		(105)		136		**
Deficiencies under minimum volume commitments, net	(2)		10		(12)		**		(9)		15		(24)		**
Equity-indexed compensation expense	8		7		1		**		17		15		2		**
Foreign currency revaluation	19		3		16		**		15		1		14		**
Line 901 incident	—		—		—		**		—		85		(85)		**

Selected Items Impacting Comparability - Segment Adjusted EBITDA (2)	(59)		(68)		9		**		60		24		36		**
Mark-to-market adjustment of Preferred Distribution Rate Reset Option embedded derivative (3)	—		103		(103)		**		(58)		147		(205)		**
Foreign currency revaluation (4)	(14)		16		(30)		**		(14)		9		(23)		**

Selected Items Impacting Comparability - Adjusted EBITDA (5)	(73)		51		(124)		**		(12)		180		(192)		**
Adjusted EBITDA (5)	$	700	$	704	$	(4)	(1)	%	$	1,513	$	1,394	$	119	9	%
Adjusted EBITDA attributable to noncontrolling interests (6)	(103)		(89)		(14)		(16)	%	(201)		(166)		(35)		(21)	%
Adjusted EBITDA attributable to PAA	$	597	$	615	$	(18)	(3)	%	$	1,312	$	1,228	$	84	7	%

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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 June 30,				Variance				Six Months Ended June 30,				Variance
	2023		2022		$		%		2023		2022		$		%
Adjusted EBITDA (5)	$	700	$	704	$	(4)	(1)	%	$	1,513	$	1,394	$	119	9	%
Interest expense, net of certain non-cash items (7)	(90)		(97)		7		7	%	(183)		(199)		16		8	%
Maintenance capital (8)	(62)		(43)		(19)		(44)	%	(109)		(70)		(39)		(56)	%
Investment capital of noncontrolling interests (9)	(17)		(15)		(2)		(13)	%	(40)		(30)		(10)		(33)	%
Current income tax expense	(20)		(30)		10		33	%	(81)		(48)		(33)		(69)	%
Distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings (10)	(8)		5		(13)		**		(20)		(26)		6		**
Distributions to noncontrolling interests (11)	(73)		(62)		(11)		(18)	%	(151)		(121)		(30)		(25)	%
Implied DCF	$	430	$	462	$	(32)	(7)	%	$	929	$	900	$	29	3	%
Preferred unit distributions (11)	(59)		(62)		3		5	%	(115)		(99)		(16)		(16)	%
Implied DCF Available to Common Unitholders	$	371	$	400	$	(29)	(7)	%	$	814	$	801	$	13	2	%
Common unit cash distributions (11)	(187)		(153)						(374)		(280)
Implied DCF Excess (12)	$	184	$	247					$	440	$	521

^**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 (including write-downs related to cancelled projects and ~~gains or losses on significant asset sales~~impairments) 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~~

(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 10 to our Condensed Consolidated Financial Statements.

(3)The Preferred Distribution Rate Reset Option of our Series A preferred units was 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 137 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 income/(expense), net on 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, Cactus II and Red River.

~~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).

Table of Contents

(11)Cash distributions paid during the period presented.

(12)Excess DCF is retained to establish reserves for debt repayment, future distributions, common equity 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 10 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~~2022 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 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 our assets or third-party 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 manage exposure to commodity prices and, at times, to provide upside opportunities.

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 primarily impacted by (i) increases or decreases in our ~~Supply and Logistics segment volumes (which consist of~~ lease gathering crude oil purchases volumes ~~NGL sales volumes~~ and ~~waterborne cargos),~~ (ii) volatility in commodity prices, as well as grade and regional price differentials and time spreads. The segment results also include the ~~effects~~direct fixed and variable field costs of ~~competition on our lease gathering and NGL margins and (iii)~~operating the ~~overall volatility and strength or weakness of market conditions and the~~crude oil assets, as well as an allocation of ~~our assets among our various risk management strategies. In addition, the execution~~indirect operating costs.

Table of our risk management strategies in conjunction with our assets can provide upside in certain markets. Although segment profit may be adversely affected during certain transitional periods as discussed further below, our crude oil and NGL supply, logistics and distribution operations are not directly affected by the absolute level 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.Contents

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 June 30,				Variance				Six Months Ended June 30,				Variance
(in millions)	2023		2022		$		%		2023		2022		$		%
Revenues	$	11,295	$	15,940	$	(4,645)	(29)	%	$	23,053	$	29,019	$	(5,966)	(21)	%
Purchases and related costs	(10,490)		(15,163)		4,673		31	%	(21,430)		(27,556)		6,126		22	%
Field operating costs	(256)		(233)		(23)		(10)	%	(513)		(515)		2		—	%
Segment general and administrative expenses (2)	(66)		(59)		(7)		(12)	%	(133)		(122)		(11)		(9)	%
Equity earnings in unconsolidated entities	89		104		(15)		(14)	%	178		201		(23)		(11)	%

Adjustments (3):
Depreciation and amortization of unconsolidated entities	24		17		7		**		47		37		10		**
Derivative activities and inventory valuation adjustments	5		(29)		34		**		(7)		30		(37)		**
Long-term inventory costing adjustments	10		(13)		23		**		31		(98)		129		**
Deficiencies under minimum volume commitments, net	(2)		10		(12)		**		(9)		15		(24)		**
Equity-indexed compensation expense	8		7		1		**		17		15		2		**
Foreign currency revaluation	15		2		13		**		12		1		11		**
Line 901 incident	—		—		—		**		—		85		(85)		**

Adjusted EBITDA attributable to noncontrolling interests	(103)		(89)		(14)		**		(200)		(166)		(34)		**
Segment Adjusted EBITDA	$	529	$	494	$	35	7	%	$	1,046	$	946	$	100	11	%

Maintenance capital expenditures	$	36	$	25	$	11	44	%	$	67	$	45	$	22	49	%


	Three Months Ended June 30,		Variance			Six Months Ended June 30,		Variance
Average Volumes	2023	2022	Volumes	%		2023	2022	Volumes	%

Crude oil pipeline tariff (by region) (4)
Permian Basin (5)	6,304	5,434	870	16	%	6,299	5,324	975	18	%






Other (5)	2,088	1,983	105	5	%	2,037	1,965	72	4	%
Total crude oil pipeline tariff	8,392	7,417	975	13	%	8,336	7,289	1,047	14	%

Commercial crude oil storage capacity (5)(6)	72	72	—	—	%	72	72	—	—	%

Crude oil lease gathering purchases (4)	1,408	1,368	40	3	%	1,418	1,364	54	4	%

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

⁽¹⁾

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

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

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(3)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 10 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.

(4)Average volumes in thousands of barrels per day calculated as the total volumes (attributable to our interest for assets owned by unconsolidated entities or through undivided joint interests) for the period divided by the number of days in the period. Volumes associated with assets acquired during the periods 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 calculated as total volumes for the period divided by the number of months in the period.

~~Revenues and costs 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.~~

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

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 and purchases, revenues and costs related to purchases will fluctuate with market prices. However, the margins related to those sales and purchases will not necessarily have a corresponding increase or decrease. The absolute amount of our revenues and purchasesCrude Oil Segment Adjusted EBITDA increased for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 compared to the same periods in ~~2016~~2022 primarily due to higher volumes on our pipeline systems, particularly on our Permian Basin and Capline assets, tariff escalations and favorable Canadian market-based opportunities. These items were partially offset by the impact of increased operating expenses, minimum volume commitment deficiency payments received in the first half of 2022 and lower commodity prices.

The following is a more detailed discussion of the significant factors impacting Segment Adjusted EBITDA for the three and six months ended June 30, 2023 compared to the same periods in 2022.

•Pipeline Revenue. Our Permian Basin pipelines were favorably impacted by higher gathering volumes, which were underpinned by increased production and new well connections, the acquisition of an additional interest in Cactus II in November of 2022 and tariff escalations. Increased volumes on the Capline system also contributed to increased earnings in the 2023 periods. These benefits were partially offset by the impact of minimum volume commitment deficiency payments received in the first half of 2022, as well as lower commodity prices in the 2023 periods impacting pipeline loss allowance revenues.

A majority of our Permian Basin gathering and intra-basin pipelines are owned by the Permian JV, a consolidated entity in which we own a 65% interest, and our Permian Basin long-haul pipelines include Cactus II, in which we own a 70% interest. We deduct the portion of the financial results attributable to noncontrolling interests in the Permian JV and Cactus II in determining Segment Adjusted EBITDA.

•Market Opportunities. Our results for the three and six months ended June 30, 2023 include the impact of favorable Canadian crude oil ~~prices. Additionally, revenues~~market-based opportunities. This was partially offset by the favorable impact to the 2022 periods of the sale of excess linefill in a higher crude oil price environment.

•Field Operating Costs. Field operating costs were lower for the six months ended June 30, 2023 compared to the same period in 2022 due to the recognition of additional estimated costs associated with the Line 901 incident in the first quarter of 2022 (which impact field operating costs but are excluded from Segment Adjusted EBITDA and ~~purchases were impacted by net gains~~thus are reflected as an “Adjustment” in the table above). For the three and six months ended June 30, 2023 compared to the same periods in 2022, we had higher expenses associated with (i) utilities costs due to a combination of higher volumes and prices and an increase in the amount of drag reducing agents used, (ii) incremental consolidated operating costs in connection with our acquisition of an additional interest in Cactus II, (iii) employee-related costs primarily resulting from higher average headcount and salaries, (iv) chemical treatment costs and (v) unrealized mark-to-market losses on power hedges for the six-month period (which impact our field operating costs but are excluded from ~~certain derivative activities during~~Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the ~~periods.~~table above).

Maintenance Capital. The increase in maintenance capital spending for the three and six months ended June 30, 2023 compared to the same periods in 2022 was primarily due to timing of routine integrity and tank maintenance.

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NGL Segment

~~Historically, we expected~~Our NGL segment operations involve natural gas processing and NGL fractionation, storage, transportation and terminalling. Our NGL revenues are primarily derived from a ~~base level~~combination of ~~earnings from our Supply~~(i) providing gathering, fractionation, storage, and/or terminalling services to third-party customers for a fee, and ~~Logistics segment~~(ii) extracting NGL mix from the ~~assets employed by this segment. However, over~~gas stream processed at our Empress straddle plant facility as well as acquiring NGL mix, which is then transported, stored and fractionated into finished products and sold to customers. Our management of our commodity exposure is subject to our risk management policies and may include the ~~last 18~~use of derivative instruments to ~~24 months, competition has increased significantly~~mitigate the risk of such exposure 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 abilityat times, to ~~generate earnings in this segment is reduced and~~provide upside opportunities.

Generally, our segment ~~earnings can be adversely~~results are impacted by ~~activities designed to increase utilization~~(i) increases or decreases in our NGL sales volumes, (ii) volatility in commodity prices, the differential between the price of ~~certain~~natural gas and the extracted NGL (“frac spread”), as well as location differentials and time spreads, and (iii) the volume of natural gas transported on third-party assets through 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. Empress straddle plant.

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.~~performance as well as the impact of comparative performance between financial reporting periods that bisect the five-month peak heating season.

The following ~~is a discussion of items impacting Supply and Logistics segment~~tables set forth our 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:

Crude Oil Operations — Net revenues from our crude oil supply and logistics activities decreased for the three and nine months ended September 30, 2017 as compared to the same periods in 2016, primarily due to lower unit margins from continued and intensifying competition, largely due to overbuilt infrastructure underwritten with volume commitments, and the effect of such on differentials, which reduced arbitrage opportunities. See the “Outlook” section below for additional discussion of recent market conditions.

~~NGL Operations — Net revenues~~ from our NGL ~~operations increased slightly for the three months ended September 30, 2017 compared~~segment:


Operating Results (1)	Three Months Ended June 30,				Variance				Six Months Ended June 30,				Variance
(in millions)	2023		2022		$		%		2023		2022		$		%
Revenues	$	381	$	570	$	(189)	(33)	%	$	1,071	$	1,304	$	(233)	(18)	%
Purchases and related costs	(128)		(312)		184		59	%	(618)		(823)		205		25	%
Field operating costs	(77)		(74)		(3)		(4)	%	(177)		(138)		(39)		(28)	%
Segment general and administrative expenses (2)	(19)		(19)		—		—	%	(38)		(38)		—		—	%

Adjustments (3):
Derivative activities	(91)		(46)		(45)		**		13		(17)		30		**
Long-term inventory costing adjustments	(8)		—		(8)		**		—		(7)		7		**

Foreign currency revaluation	4		1		3		**		3		—		3		**
Segment Adjusted EBITDA	$	62	$	120	$	(58)	(48)	%	$	254	$	281	$	(27)	(10)	%

Maintenance capital expenditures	$	26	$	18	$	8	44	%	$	42	$	25	$	17	68	%


	Three Months Ended June 30,		Variance			Six Months Ended June 30,		Variance
Average Volumes (in thousands of barrels per day) (4)	2023	2022	Volumes	%		2023	2022	Volumes	%
NGL fractionation	83	137	(54)	(39)	%	113	136	(23)	(17)	%

NGL pipeline tariff	147	187	(40)	(21)	%	170	182	(12)	(7)	%

Propane and butane sales (5)	39	58	(19)	(33)	%	89	96	(7)	(7)	%

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

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

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

(3)Represents adjustments included in ~~2016 due to higher propane sales margins, which are primarily timing-related within~~ the ~~2017-2018 heating season, partially offset~~performance measure utilized by ~~higher storage and processing fees for~~our CODM in the ~~2017 period, which were largely offset in our Facilities segment results.~~

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 Facilitiesevaluation of 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 10 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.

(4)Average daily volumes are calculated as total volumes (attributable to our interest for assets owned through undivided joint interests) for the period divided by the number of days in the period.

(5)During the fourth quarter of 2022, we modified our sales volumes reported to include only propane and butane sales. Prior to the fourth quarter of 2022, our reported sales volumes included other NGL products, primarily ethane, that represented a ~~comprehensive discussion regarding~~significant portion of our ~~derivatives~~total NGL sales volumes but did not contribute significantly to Segment Adjusted EBITDA. Sales volumes for earlier periods presented herein have been recast to include only propane and ~~risk management activities.~~ butane.

Segment Adjusted EBITDA

NGL Segment Adjusted EBITDA decreased for the three months ended June 30, 2023 compared to the same period in 2022 primarily due to lower propane sales volumes, impacted by turnarounds and deferring sales due to market structure, and the absence of weather events that benefited the 2022 period.

These ~~gains~~unfavorable impacts were partially offset for the six months ended June 30, 2023 compared to the same period in 2022 by the favorable impact during the first quarter of 2023 of higher butane sales volumes combined with favorable NGL basis differentials.

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

Net Revenues. Net revenues include the impact of derivative activities and ~~losses impact our net revenues but~~long-term inventory costing adjustments, which are excluded from ~~segment adjusted~~Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.

~~Long-Term Inventory Costing Adjustments — Our~~ Excluding such impacts, net revenues ~~are~~decreased for the three months ended June 30, 2023 compared to the same period in 2022 primarily due to (i) lower propane sales volumes impacted by ~~changes~~turnarounds at our facilities and by third-party asset turnarounds and outages, (ii) the impact of deferring sales for the 2023 period to winter months due to market structure, (iii) the absence of weather events that benefited the 2022 period, (iv) higher gains at certain of our NGL facilities in 2022 and (v) the sale of our ownership interest in the ~~weighted average cost~~Keyera Fort Saskatchewan facility in the first quarter of 2023, partially offset by (vi) higher processing revenues at our ~~crude oil and NGL inventory pools that result~~Empress straddle plants resulting from ~~price movements~~a commercial agreement executed in conjunction with the increase in our Empress ownership in the fourth quarter of 2022.

These unfavorable impacts were partially offset for the six months ended June 30, 2023 compared to the same period in 2022 by the favorable impact during the ~~periods. These costing adjustments related to long-term inventory necessary to meet our minimum inventory requirements in~~first quarter of 2023 of higher butane sales volumes resulting from higher production and increased third-party assets and other working inventory that was needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. These costing adjustments impact our net revenues but are excluded from segment adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.demand, combined with favorable NGL basis differentials.

Foreign Exchange Impacts — Our net revenues are impacted by fluctuations in the value of CAD to USD, resulting in foreign exchange gains and losses on U.S. denominated net assets within our Canadian operations. These gains and losses impact our net revenues but are excluded from segment adjusted EBITDA and thus are reflected as an “Adjustment” in the table above.

Field Operating Costs. The ~~decrease~~increase in field operating costs ~~(excluding equity-indexed compensation expense)~~ for the ~~three and nine~~six months ended ~~September~~June 30, ~~2017 compared to the three and nine months ended September 30, 2016 was primarily due to lower trucking costs as pipeline expansion projects were placed into service.~~

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

~~Other Income and Expenses~~

~~Depreciation and Amortization~~

Depreciation and amortization expense increased for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 primarily due to (i) additional depreciation and amortization expense associated with recently acquired assets, (ii) the completion of various capital expansion projects during the comparative periods, (iii) an acceleration of depreciation on certain pipeline and rail assets to reflect a change in their estimated useful lives and (iv) the write-off of approximately $6 million and $13 million of costs during 2017 and 2016, respectively, resulting from the discontinuation of certain capital projects. Depreciation and amortization expense was further impacted by net losses for the three and nine months ended September 30, 2017 of approximately $15 million and $15 million, respectively, and net gains for the three and nine months ended September 30, 2016 of approximately $84 million and $100 million, respectively, associated with sales of non-core assets and joint venture formations during the periods. For the nine-month comparative periods, such increases were partially offset by the impact during the second quarter of 2016 of impairment losses of approximately $80 million associated with certain of our rail and other terminal assets and an $18 million charge related to assets taken out of service.

~~Interest Expense~~

The increase in interest expense for the three and nine months ended September 30, 2017 over the three and nine months ended September 30, 2016 was primarily due to (i) a higher weighted average debt balance during the 2017 periods and (ii) losses of $8 million and $10 million recognized during the three and nine months ended September 30, 2017, respectively, due to anticipated hedged transactions being probable of not occurring. The nine-month comparative period was further impacted by lower capitalized interest in the 2017 period driven by fewer capital projects under construction.

~~Other Income/(Expense), Net~~

~~The decrease in Other income/(expense), net for the three and nine months ended September 30, 2017~~2023 compared to the same periods in ~~2016~~2022 was primarily related to the mark-to-market adjustment of our Preferred Distribution Rate Reset Option, which was a gain of $2 million and a gain of less than $1 million for the three and nine months ended September 30, 2017, respectively, compared to gains of $17 million and $42 million for the three and nine months ended September 30, 2016, respectively. See ~~Note 10~~ to our Condensed Consolidated Financial Statements for additional information. Excluding such impacts, Other income/(expense), net for the periods presented was primarily comprised of gains or losses from the revaluation of foreign currency transactions and monetary assets and liabilities.

~~Income Tax Expense~~

The net income tax benefit for the three months ended September 30, 2017 resulted primarily from derivative mark-to-market losses in our Canadian operations and was a favorable variance from the income tax expense in the comparable 2016 period. Income tax expense increased for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 primarily due to increased utilities-related costs largely as a result of higher ~~year-over-year income~~prices, as ~~impacted by fluctuations in derivative mark-to-market valuations in~~well as our ~~Canadian operations.~~

~~Outlook~~

~~Market Overview and Outlook~~

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Market Overview and Outlook” included in Item 7 of our 2016 Annual Report on Form 10-K for a discussion of historical crude oil market conditions and our view on potential drilling and production activity levels. The increase in crude oil prices during the fourth quarter of 2016 and early 2017 led to increased rig activity in areas where we anticipated production levels to increase, most notably the Permian Basin and the STACK resource play in Oklahoma. In the third quarter of 2017, crude oil prices trended in line with the second quarter average.

Rig activity during the third quarter continued to increase for the Lower 48 onshore producing basins in aggregate, but at a much slower rate than the second quarter. This aggregate increase includes reduced rig activity in certain of the Lower 48 onshore producing basins, which was offset by an 8% increase in rig activityownership in the Permian Basin by adding approximately 28 rigs over the ensuing three month period. However, we expect a continuation of a time lag between increased drilling activity and increased production as producers shift to multiple well pad operations and delayed scheduling of completion activities. These trends have led to a rising inventory of drilled but uncompleted (“DUC”) wells in the Permian Basin. According to the U.S. Energy Information Administration, in the Permian Basin alone, DUC inventory has increased by nearly 1,200 DUCs since the beginning of 2016, with total current inventory of approximately 2,400 DUCs. Approximately 80% of this increase in DUC inventory accumulated within the first nine months of 2017, during which DUC additions averaged approximately 100 per month. While the timing of DUC completion activity is difficult to forecast, DUC inventory and increases in well productivity could have a positive impact on either the rate of production growth or the ability of producers to maintain production at current levels in the event rig activity slows.

~~Taking all of these factors into account, we continue to expect production levels to increase~~Empress straddle plants effective in the fourth quarter of ~~this year and during 2018.~~2022. The ~~increased production levels should continue~~increase in utilities-related costs was partially offset by the benefit to increase pipeline utilization in our Transportation segment. Longer term, we believe rising production levels will also provide some potential relief on the margin compression we have been experiencing within our Supply and Logistics segment. However, we can provide no assurance that an improvement in production levels and other market conditions will be achieved or that we will not be negatively impacted by declining crude oil supply, lower commodity prices, reduced producer activity levels, competition for incremental volumes, reduced margins, low levelsnet revenues of volatility, challenging capital markets conditions or other related factors. A low crude oil price environment could have a material adverse impact on drilling and completion activity. Additionally, construction of additional infrastructure by us and our competitors could lead to even greater levels of excess takeaway capacity in certain areas for the

near- to medium-term, which could further reduce unit margins in our various segments, and which could be exacerbated by declining levels of crude oil producer activity. Specifically, our Supply and Logistics segment has been most heavily impacted by margin compression driven by factors such as these. Within our Supply and Logistics segment, our crude oil activities were the first to experience significant margin compression, and recently, our NGL activities have become adversely impacted by margin compressionoperating cost recoveries realized through commercial agreements, as well ~~substantially driven by increased competition~~as the impact of exchange rate fluctuations.

Maintenance Capital. The increase in supply areas and tighter differentials between Canadian and U.S. markets. In addition, in the current environment of increased competition, relatively flat to slightly backwardated futures price curves, narrow grade differentials and low regional basis differentials in many areas, the prospects for capturing arbitrage opportunities of the type and amount that we have historically been able to capture is significantly reduced. The near-term outlook for our Supply and Logistics segment is that such conditions are likely to continue; accordingly, our earnings from our Supply and Logistics segment are difficult to forecast and we can provide no assurance that conditions will improve or that we will be able to achieve our earnings objectives in this segment. Finally, we cannot be certain that our expansion efforts will generate targeted returns or that any recently completed or future acquisition activities will be successful. See “Risk Factors—Risks Related to Our Business” discussed in Item 1A of our 2016 Annual Report on Form 10‑K.

~~Outlook for Certain Idled and Underutilized Assets~~

During 2015, we shut down Line 901 and a portion of Line 903 in California following the release of crude oil from Line 901 (see Note 12 to our Condensed Consolidated Financial Statements for additional information). During the period since these pipelines were idled, we have been assessing potential alternatives in order to return them to operation. Some of the alternatives under consideration could result in incurring costs associated with retiring certain assets or an impairment of some or all of the carrying value of the idled property and equipment, which was approximately $124 million as of September 30, 2017.

We own a 54% undivided joint interest in the Capline Pipeline (“Capline”) system, which originates in St. James, Louisiana and terminates in Patoka, Illinois. We anticipate the construction of new crude oil pipeline infrastructure and the ongoing changing crude oil flows in the United States may result in a decline in volumes on the Capline system in future years to levels that cannot sustain operations. The owners of the Capline system are considering various alternativesmaintenance capital spending for the ~~use~~three and six months ended June 30, 2023 compared to the same periods in 2022 was primarily due to timing of ~~the pipeline system, including an assessment~~routine integrity maintenance and periodic scheduled outages.

Table of the commercial potential to reverse the pipeline direction within the next several years. In early October, the operator of Capline announced that the owners of the pipeline system are launching a non-binding open season to gauge shipper interest in a possible reversal of Capline. Developments in the commercial outlook for the Capline system could result in incurring costs associated with retiring certain assets or an impairment of the carrying value of our interest in the Capline system, which was $196 million as of September 30, 2017.Contents

Liquidity and Capital Resources

General

Our primary sources of liquidity are (i) cash flow from operating activities and (ii) borrowings under our credit facilities or commercial paper ~~program~~program. In addition, we may supplement these primary sources of liquidity with proceeds from asset sales, and ~~(iii)~~in the past have utilized funds received from sales of equity and debt securities. In addition, we may supplement these sources of liquidity with proceeds from our non-core asset sales program, as further discussed below in the section entitled “—Acquisitions, Investments, Expansion Capital Expenditures and Divestitures.” Our primary cash requirements include, but are not limited to, (i) ordinary course of business uses, such as the payment of amounts related to the purchase of crude oil, NGL and other products, ~~and~~payment of other expenses and interest payments on outstanding debt, (ii) ~~expansion~~investment and maintenance capital activities, (iii) acquisitions of assets or businesses, (iv) repayment of principal on our long-term debt and (v) distributions to our ~~unitholders.~~unitholders and noncontrolling interests. In addition, we may use cash for repurchases of common equity. We generally expect to fund our short-term cash requirements through cash flow generated from operating activities and/or borrowings under our credit facilities or commercial paper ~~program or credit facilities.~~program. In addition, we generally expect to fund our long-term needs, such as those resulting from ~~expansion~~investment capital activities, or acquisitions ~~and~~or refinancing our long-term debt, through a variety of sources, ~~(either separately or in combination),~~ which may include any or a combination of the sources ~~mentioned above as funding for short-term needs and/or the issuance of additional equity or debt securities and the sale of non-core assets.~~ listed above.

As of ~~September~~June 30, ~~2017,~~2023, we had ~~a working capital deficit of $1 million and~~ approximately ~~$2.5~~$3.5 billion of liquidity available to meet our ongoing operating, investing and financing needs, subject to continued covenant compliance, as noted below (in millions):

As of
September 30, 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


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

	As of June 30, 2023
⁽²⁾		~~Available capacity was reduced by outstanding letters of credit of $95 million, comprised of $16 million~~Availability under ~~the~~ senior unsecured revolving credit facility ~~and $79 million~~(1) (2)	$	1,272
Availability under ~~the~~ senior secured hedged inventory ~~facility.~~facility (1) (2)		1,301
Amounts outstanding under commercial paper program		—
Subtotal		2,573
Cash and cash equivalents (3)		915
Total		$	3,488

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

(2)Available capacity under our senior unsecured revolving credit facility and senior secured hedged inventory facility was reduced by outstanding letters of credit of $78 million and $49 million, respectively.

(3)Excludes restricted cash of $18 million.

Usage of our credit facilities, and, in turn, our commercial paper program, is subject to ongoing compliance with covenants. The credit agreements for our revolving credit facilities (which impact our ability to access our commercial paper program because they provide the financial backstop that supports our short-term credit ratings) and the indentures governing our senior notes contain cross-default provisions. A default under our credit agreements or indentures would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with the provisions in our credit agreements, our ability to make distributions of available cash is not restricted. We were in compliance with the covenants contained in our credit agreements and indentures as of June 30, 2023.

We believe that we have, and will continue to have, the ability to access ~~the~~our commercial paper program ~~and/or~~and credit facilities, which we use to meet our short-term cash needs. We believe that our financial position remains ~~solid~~strong and we have sufficient ~~liquidity;~~liquid assets, cash flow from operating activities and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow, including extended disruptions in the financial markets and/or energy price volatility ~~that adversely affect~~resulting from current macroeconomic and geopolitical conditions, including actions by the Organization of Petroleum Exporting Countries (“OPEC”). A prolonged material decrease in our ~~business may have a materially~~cash flows would likely produce an adverse effect on our ~~financial condition, results~~borrowing capacity and cost of ~~operations or cash flows. Also, see~~borrowing. Our borrowing capacity and borrowing costs are also impacted by our credit rating. See Item 1A. “Risk Factors” ofincluded in our ~~2016~~2022 Annual Report on Form 10-K for further discussion regarding ~~such~~ risks that may impact our liquidity and capital resources. ~~Usage~~

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Non-GAAP Financial Liquidity Measures

Management uses the non-GAAP financial liquidity measures Free Cash Flow and Free Cash Flow after Distributions to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. Free Cash Flow is defined as Net cash provided by operating activities, less Net cash provided by/(used in) investing activities, which primarily includes acquisition, investment and maintenance capital expenditures, investments in unconsolidated entities and the impact from the purchase and sale of linefill, net of proceeds from the sales of assets and further impacted by distributions to and contributions from and proceeds from the sale of noncontrolling interests. Free Cash Flow is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Free Cash Flow after Distributions. Also see “Results of Operations–Non-GAAP Financial Measures” above for more information about our non-GAAP measures.

The following table sets forth the reconciliation of the ~~credit facilities, which provide~~non-GAAP financial liquidity measures Free Cash Flow and Free Cash Flow after Distributions to Net Cash Provided by Operating Activities (in millions):


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Net cash provided by operating activities	$	888	$	792	$	1,631	$	1,132
Adjustments to reconcile Net cash provided by operating activities to Free Cash Flow:
Net cash used in investing activities	(165)		(42)		(6)		(123)

Cash distributions paid to noncontrolling interests (1)	(73)		(62)		(151)		(121)

Free Cash Flow	$	650	$	688	$	1,474	$	888
Cash distributions (2)	(246)		(215)		(489)		(379)
Free Cash Flow after Distributions	$	404	$	473	$	985	$	509

(1)Cash distributions paid during the ~~backstop for~~period presented.

(2)Cash distributions paid to our preferred and common unitholders during the ~~commercial paper program, is subject to ongoing compliance with covenants. As of September 30, 2017, we were in compliance with all such covenants.~~period presented.

Cash Flow from Operating Activities

For a comprehensive discussion of the primary drivers of cash flow from operating activities, including the impact of varying market conditions and the timing of settlement of our derivatives, see Item 7. “Liquidity and Capital Resources—Cash Flow from Operating Activities” included in our ~~2016~~2022 Annual Report on Form 10-K.

Net cash provided by operating activities for the first ~~nine~~six months of ~~2017~~2023 and ~~2016~~2022 was ~~$1.918~~$1.631 billion and ~~$648 million,~~$1.132 billion, respectively, and primarily resulted from earnings from our operations.

~~Net cash provided by operating activities for~~ In addition, the ~~2017~~2023 period was ~~positively~~favorably impacted by ~~decreases~~net positive changes in (i) the volume of crude oil inventory that we held and (ii) the margin balances required as part of our hedging activities, both of which had been funded by short-term debt. This was consistent with our plan to reduce our hedged inventory volumes, and the cash inflowsworking capital items, largely associated with these items resulted in a favorable impact on our cash provided by operating activities. However, the favorable effects from such activities were partially offset by higher weighted average prices and volumes for NGL inventory that was purchased and stored at the end of the 2017 period in anticipation of the 2017-2018 heating season.

~~During the nine months ended September 30, 2016, we increased our~~reducing inventory levels ~~and margin balances required as part~~during the period.

Table of ~~our hedging activities that were funded by short-term debt, resulting in an unfavorable impact on our cash provided by operating activities.~~Contents

Investing Activities

Capital Expenditures

~~Minimum Volume Commitments.~~ We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. 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 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. Deferred revenue associated with non-performance under minimum volume contracts could be significant and could adversely affect our profitability and earnings, but generally does not impact our liquidity.

At September 30, 2017 and December 31, 2016, counterparty deficiencies associated with agreements that include minimum volume commitments totaled $58 million and $66 million, respectively, of which $41 million and $54 million, respectively, was recorded as deferred revenue. The remaining balance of $17 million and $12 million at September 30, 2017

and December 31, 2016, respectively, was related to deficiencies for which the counterparties had not met their contractual minimum commitments and were not reflected in our Condensed Consolidated Financial Statements as we had not yet billed or collected such amounts.

~~Acquisitions, Investments, Expansion Capital Expenditures and Divestitures~~

In addition to our operating needs, ~~discussed above,~~ we also use cash for our ~~acquisition~~investment capital projects, maintenance capital activities and ~~expansion capital projects. Historically, we have financed~~acquisition activities. We fund these expenditures ~~primarily~~ with cash generated by operating activities, ~~and the~~ financing activities ~~discussed in “—Equity and Debt Financing Activities”below. In the near term, we also intend to use~~and/or proceeds from asset sales. The following table summarizes our ~~asset sales program, as discussed further below. We have made~~investment and ~~will continue to make~~maintenance capital expenditures (in millions):


	Six Months Ended June 30,
	2023		2022
Investment capital (1) (2) (3)	$	182	$	181
Maintenance capital (1) (3)	109		70

	$	291	$	251

(1)Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as “Investment capital”. Capital expenditures made to replace and/or refurbish partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as “Maintenance capital”.

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

(3)Investment capital and maintenance capital, net to our interest, was approximately $141 million and $103 million, respectively, for the six months ended June 30, 2023, and approximately $151 million and $67 million, respectively, for the six months ended June 30, 2022.

2023 Investment and Maintenance Capital. Total investment capital for the year ending December 31, 2023 is projected to be approximately $420 million ($325 million net to our interest). Approximately half of our projected investment capital expenditures are expected to be invested in the Permian JV assets. Additionally, maintenance capital for 2023 is projected to be $205 million ($195 million net to our interest). We expect to fund our 2023 investment and maintenance capital expenditures primarily with retained cash flow.

Divestitures

Proceeds from the sale of assets have generally been used to fund our investment capital projects and ~~maintenance activities.~~reduce debt levels. The following table summarizes the proceeds received during the first six months of 2023 and 2022 from sales of assets (in millions):

~~Acquisitions. During~~


	Six Months Ended June 30,
	2023		2022
Proceeds from divestitures (1)	$	284	$	57

(1)Represents proceeds, including working capital adjustments, net of transaction costs. The proceeds from divestitures for the ~~nine~~six months ended ~~September~~June 30, ~~2017 and 2016, we paid cash~~2023 are primarily from the sale of $1.282 billion (net of cash acquired of $4 million) and $282 million (net of cash acquired of $7 million), respectively, for acquisitions. The acquisitions completed during the nine months ended September 30, 2017 primarily included the ACC System locatedour 21% non-operated/undivided joint interest in the ~~Northern Delaware Basin~~Keyera Fort Saskatchewan facility in ~~Southeastern New Mexico and West Texas.~~February 2023. See Note 611 to our Condensed Consolidated Financial Statements for additional information regarding 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 issuancediscussion of ~~common units~~this transaction.

Ongoing Activities Related to AAP pursuant to the Omnibus Agreement and in connection with a PAGP underwritten equity offering. Additionally, we and an affiliate of Noble Midstream Partners LP completed the acquisition of Advantage Pipeline, L.L.C. for a purchase price of $133 million through a newly formed 50/50 joint venture. For our 50% share ($66.5 million), we contributed approximately 1.3 million common units and approximately $26 million in cash.Strategic Transactions

~~CapitalProjects.~~ We invested approximately $893 million in midstream infrastructure during the nine months ended September 30, 2017, and we expect to invest approximately $1.050 billion during the full year ended December 31, 2017. See “—~~Acquisitions and Capital Projects” for detail of our projected capital expenditures for the year ending December 31, 2017. Our preliminary forecast for our 2018 expansion capital program is $700 million.~~

We funded a majority of our 2017 capital program with proceeds from our common unit issuances during the first quarter of 2017, and we expect to fund our remaining 2017 program and our 2018 program with proceeds from our October 2017 Series B preferred unit offering, retained cash flow and the sale of various non-core assets.

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

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We ~~received proceeds of $407 million from the sale of non-core assets during the nine months ended September 30, 2017, and during the fourth quarter of 2017,~~typically do not announce a transaction until after we ~~sold our interests in~~have executed a definitive agreement. In certain non-core pipelines in the Rocky Mountain, Bakken and Mid-Continent regions for aggregate proceeds of approximately $385 million. See Note 6 to our Condensed Consolidated Financial Statements for additional information regarding these asset sales and divestitures.

~~During the third quarter of 2017,~~cases, in order to ~~avoid continued uncertainty~~protect our business interests or for other reasons, we may defer public announcement of a transaction until closing or a later date. Past experience has demonstrated that discussions and ~~costs associated with efforts by~~negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the ~~Attorney General~~closing of any transaction for ~~the State of California to block the proposed transaction, our previously disclosed~~which we have entered into a definitive agreement ~~for the potential sale of terminal assets located~~may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future efforts with respect to any such transactions will be successful, and we can provide no assurance that our financial expectations with respect to such transactions will ultimately be realized. See Item 1A. “Risk Factors—Risks Related to Our Business—Acquisitions and divestitures involve risks that may adversely affect our business” included in Northern California 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.our 2022 Annual Report on Form 10-K.

~~Equity and Debt~~ Financing Activities

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

Borrowings and Repayments Under Credit Agreements

We had no net borrowings ~~and~~or repayments under our credit facilities or commercial paper program during the six months ended June 30, 2023.

During the six months ended June 30, 2022, we had net borrowings under our credit facilities and commercial paper program of approximately $115 million. The net borrowings resulted primarily from borrowings during the period related to funding needs for capital investments, inventory purchases, senior notes repayments and other general partnership purposes, partially offset by cash flow from operating activities and proceeds from asset sales.

Repayment of Senior Notes

On January 31, 2023, we redeemed our 2.85%, $400 million senior notes. We utilized a combination of cash on hand and borrowings under our commercial paper program to repay these senior notes. We also intend to utilize a combination of cash flow from operating activities, proceeds from asset sales and borrowings under our commercial paper program to repay our 3.85%, $700 million senior notes due October 2023.

Common Equity Repurchase Program

We repurchased 7.3 million common units under the Common Equity Repurchase Program (the “Program”) during the six months ended June 30, 2022 for a total purchase price of $74 million, including commissions and fees. There were no repurchases under the Program during the six months ended June 30, 2023. The remaining available capacity under the Program as ~~well as payment~~ of ~~distributions to our unitholders.~~June 30, 2023 was $198 million.

Registration Statements.

We periodically access the capital markets for both equity and debt financing. We have filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to ~~an aggregate of $2.0 billion~~a specified amount of debt or equity securities (“Traditional Shelf”)~~. Our issuances of equity securities associated with our Continuous Offering Program have been issued pursuant to the Traditional Shelf. At September 30, 2017,~~, under which we had approximately $1.1 billion of unsold securities available ~~under the Traditional Shelf.~~at June 30, 2023. We also have access to a universal shelf registration statement (“WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. We did not conduct any offerings under our Traditional Shelf or WKSI Shelf during the ~~nine~~six months ended ~~September~~June 30, ~~2017; however, our October 2017 Series B preferred unit offering was conducted~~2023.

~~under our WKSI Shelf. See~~ ~~Note 9~~ ~~to our Condensed Consolidated Financial Statements for further discussion of our Series B preferred unit offering.~~

~~Sales of Common Units.~~ ~~The following table summarizes our sales of common units during the nine months ended September 30, 2017, all of which occurred in the first four months of the year (net proceeds in millions):~~

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⁾


⁽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.

~~Issuance of Series B Preferred Units.~~ On October 10, 2017, we issued 800,000 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, including expenditures for our capital program. See Note 9 to our Condensed Consolidated Financial Statements for further discussion of our Series B preferred unit offering.

~~Credit Agreements, Commercial Paper Program and Indentures.~~ Our credit agreements (which impact our ability to access our commercial paper program because they provide the backstop that supports our short-term credit ratings) and the indentures governing our senior notes contain cross-default provisions. A default under our credit agreements would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with the provisions in our credit agreements, our ability to make distributions of available cash is not restricted. As of September 30, 2017, we were in compliance with the covenants contained in our credit agreements and indentures.

During the nine months ended September 30, 2017, we had net repayments on our credit facilities and commercial paper program of $108 million. The net repayments resulted primarily from cash flow from operating activities and cash received from our equity activities, which offset borrowings during the period related to funding needs for (i) acquisition and capital investments, (ii) repayment of our $400 million, 6.13% senior notes in January 2017 and (iii) other general partnership purposes.

During the nine months ended September 30, 2016, we had net repayments under our credit facilities and commercial paper program of $193 million. The net repayments resulted primarily from cash flow from operating activities and cash received from our equity activities, which offset borrowings during the period related to funding needs for (i) inventory purchases and related margin balances required as part of our hedging activities, (ii) capital investments, (iii) repayment of our $175 million senior notes in August 2016 and (iv) other general partnership purposes.

In August 2017, we extended the maturity dates of our senior unsecured revolving credit facility, senior secured hedged inventory facility and senior unsecured 364-day revolving credit facility to August 2022, August 2020 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 date of the 364-day revolving credit facility converted into a non-revolving term loan with a maturity date of August 2019.

As part of our action plan announced on August 25, 2017, we intend to reduce our total debt to approximately $9.7 billion by March 31, 2019 by utilizing retained cash flows from reduced distributions and proceeds from remaining asset sales. See “—Executive Summary—Overview of Operating Results, Capital Investments and Other Significant Activities” for further discussion. Accordingly, we intend to redeem a total of $950 million of senior notes before year end 2017, which are our two nearest maturities and among the most expensive of our senior note issues and are comprised of (i) our $600 million of 6.50% senior notes maturing in May 2018 and (ii) our $350 million of 8.75% senior notes maturing in May 2019.

Distributions to Our Unitholders

~~Distributions to our~~ Series A preferred unitholders. On ~~November~~August 14, ~~2017,~~2023, we will ~~issue 1,366,593 additional~~pay a quarterly cash distribution of approximately $0.615 per unit to Series A preferred ~~units in lieu of paying a cash distribution of $36 million. See~~ ~~Note 9~~ ~~to our Condensed Consolidated Financial Statements for details of distributions made during or pertaining to the first nine months of 2017.~~

~~Distributions to Series B unitholders.~~ Holders of our Series B preferred units, which were issued on October 10, 2017, 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. 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 ~~November~~July 31, 2023 for the period from April 1, ~~2017 in an amount equal to approximately $5.9549 per unit (a total~~2023 through June 30, 2023.

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Series B preferred unitholders. On August 15, 2023, we will pay a quarterly cash distribution of approximately ~~$5 million). See~~ ~~Note 9~~$24.10 per unit to ~~our Condensed Consolidated Financial Statements for further discussion of our~~ Series B preferred ~~units, including~~unitholders of record at the close of business on August 1, 2023 for the period from May 15, 2023 through August 14, 2023.

Common Unitholders. On August 14, 2023, we will pay a quarterly cash distribution ~~rates and payment dates.~~

~~Distributions to our~~of $0.2675 per common ~~unitholders.~~ ~~In accordance with our partnership agreement, after making distributions to holders of our outstanding preferred units, we distribute the remainder of our available cash~~unit ($1.07 per unit on an annualized basis) to common unitholders of record ~~within 45 days following the end of each quarter. Available cash is generally defined as all of our cash and cash equivalents on hand~~ at the ~~end~~close of ~~each quarter less reserves established in~~business on July 31, 2023 for the ~~discretion of our general partner for future requirements. Our available cash also includes cash on hand resulting~~period from ~~borrowings made after~~April 1, 2023 through June 30, 2023, which is unchanged from the ~~end of the quarter. On November 14, 2017, we will pay a quarterly~~ distribution ~~of $0.30~~ per ~~common~~ unit ($1.20 per common unit on an annualized basis), which equates to a reduction of approximately 45% compared to the quarterly distribution of $0.55 per common unit ($2.20 per common unit on an annualized basis) paid in ~~August 2017. This reduction is part~~May of our action plan to adopt a distribution approach underpinned by fee-based business activities, to reduce our leverage thereby improving our credit metrics and to position ourself for future distribution growth. Cash retained will be used to reduce indebtedness. 2023.

See ~~“—Executive Summary—Overview of Operating Results, Capital Investments and Other Significant Activities” for further discussion. See~~ Note 96 to our Condensed Consolidated Financial Statements for details of distributions paid during or pertaining to the first ~~nine~~six months of ~~2017. Also, see Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases~~2023, including distributions to our preferred unitholders.

Distributions to Noncontrolling Interests

Distributions to noncontrolling interests represent amounts paid on interests in consolidated entities that are not owned by us. As of ~~Equity Securities—Cash Distribution Policy” included~~June 30, 2023, noncontrolling interests in our ~~2016 Annual Report on Form 10-K~~subsidiaries consisted of (i) a 35% interest in the Permian JV, (ii) a 30% interest in Cactus II and (iii) a 33% interest in Red River. See Note 6 to our Condensed Consolidated Financial Statements for ~~additional discussion regarding distributions.~~details of distributions paid to noncontrolling interests during the six months ended June 30, 2023.

We believe that we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow. A prolonged material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity.

Contingencies

For a discussion of contingencies that may impact us, see Note 129 to our Condensed Consolidated Financial Statements.

Commitments

~~Contractual~~Purchase Obligations. In the ordinary course of doing business, we purchase crude oil and NGL from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years, with a limited number of contracts with remaining terms extending up to ~~approximately ten~~11 years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. The table below includes purchase obligations related to these activities. Where applicable, the amounts presented represent the net obligations associated with our counterparties (including giving effect to netting buy/sell contracts and those subject to a net settlement arrangement). We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy or who have provided credit support we consider adequate.

The following table includes our best estimate of the amount and timing of these payments as ~~well as others due under the specified contractual obligations as~~ of ~~September~~June 30, ~~2017~~2023 (in millions):

Remainder of 2017 2018 2019 2020 2021 2022 and Thereafter Total
Long-term debt, including current maturities and related interest payments ⁽¹⁾
$ 725
$ 1,054
$ 1,271
$ 870
$ 941
$ 11,056
$ 15,917
Leases and rights-of-way easements ⁽²⁾
48
173
143
120
102
433
1,019
Other obligations ⁽³⁾
105
230
168
136
132
564
1,335
Subtotal 878
1,457

1,582

1,126

1,175

12,053

18,271
Crude oil, NGL and other purchases ⁽⁴⁾
2,688
4,682
3,950
3,236
2,968
9,224
26,748
Total $ 3,566
$ 6,139

$ 5,532

$ 4,362

$ 4,143

$ 21,277

$ 45,019


	Remainder of 2023		2024		2025		2026		2027		2028 and Thereafter		Total
Crude oil, NGL and other purchases (1)	$	10,541	$	17,947	$	16,685	$	15,565	$	13,612	$	37,916	$	112,266

⁽¹⁾

Includes debt service payments, interest payments due on senior notes and the commitment fee on assumed available capacity under our credit facilities and long-term borrowings under our commercial paper program. Although there may be short-term borrowings under our credit facilities and commercial paper program, we historically repay and borrow at varying amounts. As such, we have included only the maximum commitment fee (as if no short-term borrowings were outstanding on the facilities or commercial paper program) in the amounts above.


⁽²⁾	Leases are primarily for (i) surface rentals, (ii) office rent, (iii) pipeline assets and (iv) trucks, trailers and railcars. Includes capital and operating leases as defined by FASB guidance, as well as obligations for rights-of-way easements.

⁽³⁾

Includes (i) other long-term liabilities, (ii) storage, processing and transportation agreements and (iii) non-cancelable commitments related to our capital expansion projects, including projected contributions for our share of the capital spending of our equity method investments. The transportation agreements include approximately $780 million associated with an agreement to transport crude oil on a pipeline that is owned by an equity method investee, in which we own a 50% interest. Our commitment to transport is supported by crude oil buy/sell agreements with third parties (including Oxy) with commensurate quantities.

⁽⁴⁾

Amounts are primarily based on estimated volumes and market prices based on average activity during September 2017. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.

(1)Amounts are primarily based on estimated volumes and market prices based on average activity during June 2023. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.

Letters of Credit. In connection with ~~supply and logistics~~our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the product is purchased. Generally, these letters of credit are issued for periods of up to 70 days and are terminated upon completion of each transaction. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016,~~2022, we had outstanding letters of credit of approximately ~~$95~~$127 million and ~~$73~~$102 million, respectively.

~~Off-Balance Sheet Arrangements~~

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

Recent Accounting Pronouncements

See Note 21 to our Condensed Consolidated Financial Statements.

~~Critical Accounting Policies and Estimates~~

~~For a discussion regarding our critical accounting policies and estimates, see “Critical Accounting Policies and Estimates” under Item 7~~Table of ~~our 2016 Annual Report on Form 10-K.~~Contents

FORWARD-LOOKING STATEMENTS

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

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

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

~~the effects of competition;~~

~~market distortions caused by producer over-commitments to infrastructure projects, which impacts volumes, margins, returns and overall earnings;~~

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

~~maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties;~~

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

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

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

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

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

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

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

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

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

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

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

•the effectiveness of our risk management activities;

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

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

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

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

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

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

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

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

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

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

•the ~~successful integration~~use or availability of third-party assets upon which our operations depend and ~~future performance of acquired assets~~over which we have little or ~~businesses and the risks associated with operating in lines of business that are distinct and separate from our historical operations;~~no control;

~~the failure to consummate, or significant delay in consummating, sales of assets or interests as a part of our strategic divestiture program;~~

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

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

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

~~non-utilization~~•significant under-utilization of our assets and facilities;

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

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

~~the availability of, and our ability to consummate, acquisition or combination opportunities;~~

~~the effectiveness of our risk management activities;~~

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

~~the impact of current and future laws, rulings, governmental regulations, accounting standards and statements, and related interpretations;~~

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

•risks related to the development and operation of our ~~assets, including our ability to satisfy our contractual obligations to our customers;~~assets; and

~~factors affecting demand for natural gas and natural gas storage services and rates;~~

~~general economic, market or business conditions and the amplification of other risks caused by volatile financial markets, capital constraints and pervasive liquidity concerns; and~~

•other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, ~~and refined products,~~ as well as in ~~the storage of natural gas and~~ the processing, transportation, fractionation, storage and marketing of ~~natural gas liquids.~~NGL.

Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read “Risk Factors” discussed in Item 1A of our ~~2016~~2022 Annual Report on Form 10-K. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

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

•Crude oil

We utilize crude oil derivatives to hedge commodity price risk inherent in our ~~Supply~~pipeline, terminalling and ~~Logistics and Transportation segments.~~merchant activities. Our objectives for these derivatives include hedging anticipated purchases and sales, stored inventory and ~~storage capacity utilization.~~basis differentials. We manage these exposures with various instruments including ~~exchange-traded and over-the-counter~~ futures, forwards, swaps and options.

•Natural gas

We utilize natural gas derivatives to hedge commodity price risk inherent in our ~~Supply~~natural gas processing assets (natural gas purchase component of the frac spread). Additionally, we utilize natural gas derivatives to hedge anticipated operational fuel gas requirements related to our natural gas processing and ~~Logistics and Facilities segments. Our objectives for these derivatives include hedging anticipated purchases of natural gas.~~NGL fractionation plants. We manage these exposures with various instruments including ~~exchange-traded~~ futures, swaps and options.

•NGL and other

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

See Note 107 to our Condensed Consolidated Financial Statements for further discussion regarding our hedging strategies and objectives.

The fair value of our commodity derivatives and the change in fair value as of ~~September~~June 30, ~~2017~~2023 that would be expected from a 10% price increase or decrease is shown in the table below (in millions):


	Fair Value		Effect of 10% Price Increase		Effect of 10% Price Decrease
Crude oil	$	25	$	(14)	$	15
Natural gas	(35)		$	7	$	(7)
NGL and other	173		$	(18)	$	18
Total fair value	$	163

Fair Value Effect of 10%
Price Increase Effect of 10%
Price Decrease
Crude oil $ 3
$ 5
$ (3 )
Natural gas (22 ) $ 11
$ (11 )
NGL and other (191 ) $ (84 ) $ 84
Total fair value $ (210 )

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

Interest Rate Risk

Our use of variable rate debt and any forecasted issuances of fixed rate debt expose us to interest rate risk. Therefore, from time to time, we use interest rate derivatives to hedge interest rate risk associated with anticipated interest payments and, in certain cases, outstanding debt instruments. All of our senior notes are fixed rate notes and thus are not subject to interest rate risk. ~~Our~~We did not have any variable rate debt outstanding at ~~September~~June 30, ~~2017, approximately $1.5 billion, was subject to interest rate re-sets that range from less than one week to approximately three months.~~2023. The average interest rate on variable rate debt that was outstanding during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 was ~~2.0%~~5.1%, based upon rates in effect during such period. The fair value of our interest rate derivatives was a ~~liability~~net asset of ~~$34~~$42 million as of ~~September~~June 30, ~~2017.~~2023. A 10% increase in the forward ~~LIBOR~~SOFR curve as of ~~September~~June 30, ~~2017~~2023 would have resulted in an increase of ~~$33~~$16 million to the fair value of our interest rate derivatives. A 10% decrease in the forward ~~LIBOR~~SOFR curve as of ~~September~~June 30, ~~2017~~2023 would have resulted in a decrease of ~~$33~~$16 million to the fair value of our interest rate derivatives. See Note 107 to our Condensed Consolidated Financial Statements for a discussion of our interest rate risk hedging activities.

~~Currency Exchange Rate Risk~~

We use foreign currency derivatives to hedge foreign currency exchange rate risk associated with our exposure to fluctuations in the USD-to-CAD exchange rate. Because a significant portion of our Canadian business is conducted in CAD and, at times, a portion of our debt is denominated in CAD, we use certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts, forwards and options. The fair value of our foreign currency derivatives was an asset of $2 million as of September 30, 2017. A 10% increase in the exchange rate (USD-to-CAD) would have resulted in a decrease of $24 million to the fair value of our foreign currency derivatives. A 10% decrease in the exchange rate (USD-to-CAD) would have resulted in an increase of $24 million to the fair value of our foreign currency derivatives. See ~~Note 10~~ ~~to our Condensed Consolidated Financial Statements for a discussion of our currency exchange rate risk hedging.~~

~~Preferred Distribution Rate Reset Option~~

The Preferred Distribution Rate Reset Option of our Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, our partnership agreement, and recorded at fair value in our Condensed Consolidated Balance Sheets. The valuation model utilized for this embedded derivative contains inputs including our common unit price, ten-year U.S. treasury rates and default probabilities to ultimately calculate the fair value of our Series A preferred units with and without the Preferred Distribution Rate Reset Option. The fair value of this embedded derivative was a liability of $33 million as of September 30, 2017. A 10% increase in the fair value would have an impact of $3 million. A 10% decrease in the fair value would also have an impact of $3 million. See ~~Note 10~~ ~~to our Condensed Consolidated Financial Statements for a discussion of embedded derivatives.~~

Item 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Applicable SEC rules require an evaluation of the effectiveness of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our DCP as of ~~September~~June 30, ~~2017,~~2023, the end of the period covered by this report, and, based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our DCP is effective.

Changes in Internal Control over Financial Reporting

In addition to the information concerning our DCP, we are required to disclose certain changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting during the ~~third~~second quarter of ~~2017~~2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Certifications

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

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PART II. OTHER INFORMATION

Item 1.LEGAL PROCEEDINGS

The information required by this item is included in Note 129 to our Condensed Consolidated Financial Statements, and is incorporated herein by reference thereto.

Item 1A. RISK FACTORS

For a discussion ~~regarding~~of our risk factors, see Item 1A. of our ~~2016~~2022 Annual Report on Form 10-K. Those risks and uncertainties are not the only ones facing us and there may be additional matters of which we are unaware or that we currently consider immaterial. All of those risks and uncertainties could adversely affect our business, financial condition and/or results of operations.

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

~~Common Units. The Omnibus Agreement, entered into as part~~Sales of ~~the Simplification Transactions, provides for the mechanics by which (i) the total number~~Unregistered Securities

None.

Issuer Purchases of PAGP’s outstanding Class A shares will equal the number of AAP units held by PAGP, and (ii) the total number of our common units held by AAP will equal the sum of the number of outstanding AAP units and the number of AAP units that are issuable to the holders of vested and earned AAP Management Units. As such, we are obligated to issue common units to AAP in connection with PAGP’s issuance of Class A shares upon PAGP LTIP award vestings. During the three months ended September 30, 2017, we issued 11,250 common units to AAP in connection with PAGP LTIP award vestings. The issuance of all such common units to AAP was exempt from the registration requirements of theEquity Securities ~~Act of 1933, as amended, pursuant to Section 4(a)(2) thereof.~~

~~Series A Preferred Units~~. With respect to any quarter ending on or prior to December 31, 2017, we may elect to pay distributions on our Series A preferred units in additional preferred units, in cash or a combination of both. During the three months ended September 30, 2017 we issued 1,339,796 additional Series A preferred units in lieu of a cash distribution of $35 million. The issuance of the Series A preferred units, in connection with the quarterly distribution for the Series A preferred units, was exempt from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section

4(a)(2) thereof. Our Series A preferred units are convertible into common units, generally on a one-for-one basis and subject to customary antidiultion adjustments and certain minimum conversion amounts, at any time after January 28, 2018. 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 our Series A preferred units.None.

Item 3.DEFAULTS UPON SENIOR SECURITIES

None.

Item 4.MINE SAFETY DISCLOSURES

~~None.~~Not applicable.

Item 5.OTHER INFORMATION

~~None.~~ During the quarter ended June 30, 2023, none of our directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted or terminated a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K).

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Item 6.EXHIBITS

~~The exhibits listed on the accompanying Exhibit Index are filed or incorporated by reference as part of this report, and such Exhibit Index is incorporated herein by reference.~~

~~SIGNATURES~~

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


Exhibit No.				Description

3.1			~~PLAINS ALL AMERICAN PIPELINE, L.P.~~

	~~By:~~	~~PAA GP LLC,~~
		~~its general partner~~

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

	~~By:~~	~~PLAINS ALL AMERICAN GP LLC,~~
		~~its general partner~~

	~~By:~~	~~/s/ Greg L. Armstrong~~
		~~Greg L. Armstrong,~~
		~~Chief Executive Officer of Plains All American GP LLC~~
		~~(Principal Executive Officer)~~

~~November 8, 2017~~

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

~~November 8, 2017~~

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

~~November 8, 2017~~

~~EXHIBIT INDEX~~



2.1 *	—	Securities Purchase Agreement dated as of January 19, 2017 by and between COG Operating LLC, as seller, and Plains Pipeline, L.P., as purchaser (the schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (incorporated by reference to Exhibit 2.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).

2.2 *	—	Securities Purchase Agreement dated as of January 19, 2017 by and between Frontier Midstream Solutions, LLC, as seller, and Plains Pipeline, L.P., as purchaser (the schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (incorporated by reference to Exhibit 2.2 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).

~~3.1~~	—	Seventh Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P., dated as of October 10, 2017 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 12, 2017).

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

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

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

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

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

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

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

~~3.8~~3.9			—	Amendment No. 1 dated January 1, 2013 to the Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. (incorporated by reference to Exhibit 3.10 to our Annual Report on Form 10-K for the year ended December 31, 2013).

~~3.9~~3.10			—	Seventh Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated November 15, 2016 (incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K filed November 21, 2016).

~~3.10~~3.11			—	Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. dated November 15, 2016 (incorporated by reference to Exhibit 3.4 to our Current Report on Form 8-K filed November 21, 2016).

~~3.11~~3.12			—	Amendment No. 1 dated September 26, 2018 to the Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 2, 2018).

3.13			—	Amendment No. 2 dated May 23, 2019 to the Eighth Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed May 30, 2019).

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

~~3.12~~3.15			—	Bylaws of PAA Finance Corp. (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.11 to our Annual Report on Form 10-K for the year ended December 31, 2006).

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~~3.13~~3.16	—	Limited Liability Company Agreement of PAA GP LLC dated December 28, 2007 (incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K filed January 4, 2008).

~~3.14~~3.17	—	Certificate of Limited Partnership of Plains GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to PAGP’s Registration Statement on Form S-1 (333-190227) filed July 29, 2013).

~~3.15~~3.18	—	Second Amended and Restated Agreement of Limited Partnership of Plains GP Holdings, L.P. dated November 15, 2016 (incorporated by reference to Exhibit 3.2 to PAGP’s Current Report on Form 8-K filed November 21, 2016).



~~3.16~~3.19			—	Amendment No. 1 dated April 6, 2020 to the Second Amended and Restated Agreement of Limited Partnership of Plains GP Holdings, L.P. (incorporated by reference to Exhibit 3.1 to PAGP’s Current Report on Form 8-K filed April 9, 2020).

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

~~3.17~~3.21			—	~~Third~~Fourth Amended and Restated Limited Liability Company Agreement of PAA GP Holdings LLC dated effective as of ~~February 16, 2017~~August 19, 2021 (incorporated by reference to Exhibit ~~3.1~~3.21 to our ~~Current~~Annual Report on Form ~~8-K filed February 21, 2017)~~10-K for the year ended December 31, 2021).

4.1			—	Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).

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

4.3			—	Tenth Supplemental Indenture (Series A and Series B 6.650% Senior Notes due 2037) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed October 30, 2006).

4.4			—	Thirteenth Supplemental Indenture (Series A and Series B 6.50% Senior Notes due 2018) dated April 23, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed April 23, 2008).

~~4.5~~	—	Fifteenth Supplemental Indenture (8.75% Senior Notes due 2019) dated April 20, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed April 20, 2009).

~~4.6~~	—	Seventeenth Supplemental Indenture (5.75% Senior Notes due 2020) dated September 4, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed September 4, 2009).

~~4.7~~	—	Nineteenth Supplemental Indenture (5.00% Senior Notes due 2021) dated January 14, 2011 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed January 11, 2011).

~~4.8~~	—	Twentieth Supplemental Indenture (3.65% Senior Notes due 2022) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed March 26, 2012).

~~4.9~~	—	Twenty-First Supplemental Indenture (5.15% Senior Notes due 2042) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed March 26, 2012).

~~4.10~~4.5			—	Twenty-Second Supplemental Indenture (2.85% Senior Notes due 2023) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed December 12, 2012).

~~4.11~~	—	Twenty-Third Supplemental Indenture (4.30% Senior Notes due 2043) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 12, 2012).

~~4.12~~4.6			—	Twenty-Fourth Supplemental Indenture (3.85% Senior Notes due 2023) dated August 15, 2013, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed August 15, 2013).

~~4.13~~4.7			—	Twenty-Fifth Supplemental Indenture (4.70% Senior Notes due 2044) dated April 23, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed April 29, 2014).



~~4.14~~4.8			—	Twenty-Sixth Supplemental Indenture (3.60% Senior Notes due 2024) dated September 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed September 11, 2014).

~~4.15~~4.9			—	Twenty-Seventh Supplemental Indenture (2.60% Senior Notes due 2019) dated December 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed December 11, 2014).

~~4.16~~	—	Twenty-Eighth Supplemental Indenture (4.90% Senior Notes due 2045) dated December 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 11, 2014).

Table of Contents


~~4.17~~4.1			—	Twenty-Ninth Supplemental Indenture (4.65% Senior Notes due 2025) dated August 24, 2015, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed August 26, 2015).

~~4.18~~4.11			—	Thirtieth Supplemental Indenture (4.50% Senior Notes due 2026) dated November 22, 2016, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed November 29, 2016).

~~4.19~~4.12			—	Thirty-First Supplemental Indenture (3.55% Senior Notes due 2029) dated September 16, 2019, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed September 17, 2019).

4.13			—	Thirty-Second Supplemental Indenture (3.80% Senior Notes due 2030) dated June 11, 2020, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed June 11, 2020).

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

~~4.20~~4.15			—	Registration Rights Agreement dated as of January 28, 2016 among Plains All American Pipeline, L.P. and the Purchasers named therein (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed February 2, 2016).

~~4.21~~4.16			—	Registration Rights Agreement by and among Plains All American Pipeline, L.P. and the Holders defined therein, dated November 15, 2016 (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed November 21, 2016).

10.1 **4.17			—	~~Form~~Description of ~~Director LTIP Grant Letter (February 2017) - Director Grant - Designated Directors and Audit Committee Members (PAA Plan)~~Our Securities (incorporated by reference to Exhibit ~~10.1~~4.18 to our ~~Quarterly~~Annual Report on Form ~~10-Q~~10-K for the ~~quarter~~year ended ~~March~~December 31, ~~2017)~~2022).

10.2 **31.1 †			—	Form of Director LTIP Grant Letter (February 2017) - Audit Committee Supplement (PAA Plan) (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).

10.3 **	—	Form of Director LTIP Grant Letter (February 2017) - Independent Director Grant (PAA Plan) (incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).

10.4 **	—	~~Form of LTIP Grant Letter for Officers (July 2017) (incorporated by reference to Exhibit 10.4 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).~~

~~10.5 †~~	—	Third Amendment to 364-Day Credit Agreement dated as of August 10, 2017 among Plains All American Pipeline, L.P., as Borrower; Bank of America, N.A., as Administrative Agent; Citibank, N.A., JPMorgan Chase Bank N.A. and Wells Fargo Bank, National Association, as Co-Syndication Agents; DNB Bank ASA, New York Branch and Mizuho Bank, Ltd., as Co-Documentation Agents; the other Lenders party thereto; and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., DNB Markets, Inc., J.P. Morgan Securities LLC, Mizuho Bank, Ltd. and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Bookrunners.

~~10.6 †~~	—	Fourth Amendment to Third Amended and Restated Credit Agreement dated as of August 16, 2017 among Plains Marketing, L.P. and Plains Midstream Canada ULC, as Borrowers; Plains All American Pipeline, L.P., as Guarantor; Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer; Wells Fargo Bank, National Association, as an L/C Issuer; and the other Lenders party thereto.

~~12.1 †~~	—	~~Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Unit Distributions.~~

~~31.1 †~~	—	Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

31.2 †			—	Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).



32.1 ††	—	Certification of Principal Executive Officer pursuant to 18 U.S.C. 1350.

32.2 ††	—	Certification of Principal Financial Officer pursuant to 18 U.S.C. 1350.

101.INS†	—	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH†	—	Inline XBRL Taxonomy Extension Schema Document

101.CAL†	—	Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF†	—	Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB†	—	Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE†	—	Inline XBRL Taxonomy Extension Presentation Linkbase Document

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

†Filed herewith.

††Furnished herewith.

Table of Contents

SIGNATURES

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


†			~~Filed herewith.~~

	PLAINS ALL AMERICAN PIPELINE, L.P.
††			~~Furnished herewith.~~


*			~~Certain schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule will be furnished supplementally to the SEC upon request.~~

By:	PAA GP LLC,
**		~~Management compensatory plan or arrangement.~~	its general partner

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

		By:	Plains All American GP LLC,
			its general partner

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

August 8, 2023

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

August 8, 2023

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

August 8, 2023



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



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~~June 30 ~~2017~~, 2023 and December 31, ~~2016~~2022		3
Condensed Consolidated Statements of Operations: For the three and ~~nine~~ six months ended ~~September~~June 30 ~~2017~~, 2023 and ~~2016~~2022		4
Condensed Consolidated Statements of Comprehensive ~~Income:~~Income/(Loss): For the three and ~~nine~~ six months ended ~~September~~June 30 ~~2017~~, 2023 and ~~2016~~2022		5
Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss): For the ~~nine~~ three and six months ended ~~September~~June 30 ~~2017~~, 2023 and ~~2016~~2022		5
Condensed Consolidated Statements of Cash Flows: For the ~~nine~~six months ended ~~September 30, 2017~~June 3 0 , 2023 and ~~2016~~2022		6
Condensed Consolidated Statements of Changes in Partners’ Capital: For the ~~nine~~ three and six months ended ~~September 30, 2017~~June 3 0 , 2023 and ~~2016~~2022		7
Notes to the Condensed Consolidated Financial Statements:
1. Organization and Basis of Consolidation and Presentation		89

2. Revenues and Accounts Receivable		11
~~2. Recent Accounting Pronouncements~~3. Net Income Per Common Unit		1015
~~3. Net Income/(Loss) Per Common Unit~~4. Inventory, Linefill and Long-term Inventory		1116
~~4. Accounts Receivable, Net~~5. Debt		1317
~~5. Inventory, Linefill and Base Gas and Long-term Inventory~~		13
6. ~~Acquisitions and Dispositions~~	14
~~7. Goodwill~~	16
~~8. Debt~~	17
9. Partners’ Capital and Distributions	18
~~10.~~7. Derivatives and Risk Management Activities		20
~~11.~~8. Related Party Transactions		2924
~~12.~~9. Commitments and Contingencies		2926
~~13. Operating Segments~~10. Segment Information		3431
11. Acquisitions and Divestitures		34

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		3835
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		6354
Item 4. CONTROLS AND PROCEDURES		6555

PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS		6656
Item 1A. RISK FACTORS		6656
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		6656
Item 3. DEFAULTS UPON SENIOR SECURITIES		6656
Item 4. MINE SAFETY DISCLOSURES		6656
Item 5. OTHER INFORMATION		6656
Item 6. EXHIBITS		6657
SIGNATURES		6760



	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


	Derivative Instruments		Translation Adjustments		Other		Total
	(unaudited)
Balance at December 31, 2022	$	(107)	$	(846)	$	(1)	$	(954)

Reclassification adjustments	5		—		—		5
Unrealized gain on hedges	2		—		—		2
Currency translation adjustments	—		77		—		77
Other	—		—		1		1
Total period activity	7		77		1		85
Balance at June 30, 2023	$	(100)	$	(769)	$	—	$	(869)


	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, 2022	$	1,505	$	787	$	7,765	$	10,057	$	3,268	$	13,325
Net income	85		36		594		715		109		824
Distributions (Note 6)	(85)		(36)		(374)		(495)		(151)		(646)
Other comprehensive income	—		—		85		85		—		85


Other	2		—		15		17		(3)		14
Balance at June 30, 2023	$	1,507	$	787	$	8,085	$	10,379	$	3,223	$	13,602

	Limited Partners						Partners’ Capital Excluding Noncontrolling Interests		Noncontrolling Interests		Total Partners’ Capital
	Preferred Unitholders				Common Unitholders
	Series A		Series B
	(unaudited)
Balance at March 31, 2023	$	1,506	$	787	$	7,950	$	10,243	$	3,240	$	13,483
Net income	44		18		231		293		56		349
Distributions (Note 6)	(44)		(18)		(187)		(249)		(73)		(322)
Other comprehensive income	—		—		85		85		—		85



Other	1		—		6		7		—		7
Balance at June 30, 2023	$	1,507	$	787	$	8,085	$	10,379	$	3,223	$	13,602



	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	)



	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



	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



	Remainder of 2017		2018		2019		2020		2021		2022 and Thereafter		Total
Long-term debt, including current maturities and related interest payments ⁽¹⁾	$	725	$	1,054	$	1,271	$	870	$	941	$	11,056	$	15,917
Leases and rights-of-way easements ⁽²⁾	48		173		143		120		102		433		1,019
Other obligations ⁽³⁾	105		230		168		136		132		564		1,335
Subtotal	878		1,457		1,582		1,126		1,175		12,053		18,271
Crude oil, NGL and other purchases ⁽⁴⁾	2,688		4,682		3,950		3,236		2,968		9,224		26,748
Total	$	3,566	$	6,139	$	5,532	$	4,362	$	4,143	$	21,277	$	45,019