PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~(unaudited)~~

Note 1—Organization and Basis of Consolidation and Presentation

Organization

Plains GP Holdings, L.P. (“PAGP”) is a Delaware limited partnership formed in ~~July~~ 2013 that has elected to be taxed as a corporation for United States federal income tax purposes. PAGP does not directly own any operating assets; as of ~~September 30, 2017,~~March 31, 2020, its principal sources of cash flow are derived from an indirect investment in Plains All American Pipeline, L.P. (“PAA”), a publicly traded Delaware limited partnership. As used in this Form 10-Q and unless the context indicates otherwise (taking into account the fact that PAGP has no operating activities apart from those conducted by PAA and its subsidiaries), the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAGP and its subsidiaries.

As of ~~September 30, 2017,~~March 31, 2020, PAGP owned (i) a 100% managing member interest in Plains All American GP LLC (“GP LLC”), an entity that has also elected to be taxed as a corporation for United States federal income tax purposes and (ii) an approximate ~~54%~~75% limited partner interest in Plains AAP, L.P. (“AAP”) through our direct ownership of approximately ~~153.5~~183.2 million Class A units of AAP (“AAP units”) and indirect ownership of approximately 1.0 million AAP units through GP LLC. GP LLC is a Delaware limited liability company that also holds the non-economic general partner interest in AAP. AAP is a Delaware limited partnership that, as of ~~September 30, 2017,~~March 31, 2020, directly owned ~~an approximate 36%~~a limited partner interest in PAA ~~represented by~~through its ownership of approximately ~~286.8~~248.4 million PAA common ~~units.~~units (approximately 31% of PAA’s total outstanding common units and Series A preferred units combined). AAP is the sole member of PAA GP LLC (“PAA GP”), a Delaware limited liability company that directly holds the non-economic general partner interest in PAA.

PAA is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services primarily for crude oil, natural gas liquids (“NGL”), and natural ~~gas and refined products.~~gas. PAA owns an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. Our business activities are conducted through ~~three~~3 operating segments: Transportation, Facilities and Supply and Logistics. See Note 13 for further discussion of our operating segments.

PAA GP Holdings LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities and is responsible for exercising on our behalf any rights we have as the sole and managing member of GP LLC, including responsibility for conducting the business and managing the operations of AAP and PAA. GP LLC employs our domestic officers and personnel involved in the operation and management of AAP and PAA. PAA’s Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ~~ULC (“PMC”).~~ULC.

References to the “Plains Entities” include us, our general partner, GP LLC, AAP, PAA GP and PAA and its subsidiaries.

~~Simplification Transactions~~

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

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

the permanent elimination of PAA’s incentive distribution rights (“IDRs”) and the economic rights associated with its 2% general partner interest in exchange for the issuance by PAA to AAP of 245.5 million PAA common units (including approximately 0.8 million units to be issued in the future) and the assumption by PAA of all of AAP’s outstanding debt ($642 million);

the implementation of a unified governance structure pursuant to which the board of directors of GP LLC was eliminated and an expanded board of directors of our general partner assumed oversight responsibility over both us and PAA;

the provision for annual shareholder meetings beginning in 2018 for the purpose of electing certain directors with expiring terms in 2018, and the participation of PAA’s common unitholders and Series A preferred unitholders in such elections through PAA’s ownership of our newly issued Class C shares, which provide PAA, as the sole holder of such

~~Class C shares, the right to vote in elections of eligible directors together with the holders of our Class A and Class B shares;~~

the execution by AAP of a reverse split to adjust the number of 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 PAA common units received by AAP at the closing of the Simplification Transactions. Simultaneously, we executed a reverse split to adjust the number of Class A and Class B shares outstanding to equal the number of AAP units we own following AAP’s reverse unit split. These reverse splits, along with the Omnibus Agreement, resulted in economic alignment between our Class A shareholders and PAA’s common unitholders, such that the number of outstanding Class A shares equals the number of AAP units owned by us, which in turn equals the number of PAA common units held by AAP that are attributable to our 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 PAA common units held by AAP. Holders of AAP units other than us and GP LLC continue to have the right to exchange their AAP units (together with the corresponding Class B shares and, if applicable, units of our general partner) for our Class A shares on a one-for-one basis.

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. In addition, the Simplification Transactions did not result in a change in ownership interest of PAGP in PAA as described in Accounting Standards Codification (“ASC”) 810-10-45-22, but instead were designed to be an exchange of equal economic ownership interests.

As part of the Simplification Transactions, as discussed above, we effected a reverse split of our Class A and Class B shares, in each case, at a ratio of approximately 1-for-2.663. The effect of the reverse split has been retroactively applied to all share and per-share amounts presented in this Form 10-Q.

Definitions

Additional defined terms are used in this Form 10-Q and shall have the meanings indicated below:



AOCI			=	Accumulated other comprehensive income/(loss)
ASC			=	Accounting Standards Codification
ASU			=	Accounting Standards Update
Bcf			=	Billion cubic feet
Btu			=	British thermal unit
CAD			=	Canadian dollar
CODM			=	Chief Operating Decision Maker
EBITDA			=	Earnings before interest, taxes, depreciation and amortization
EPA			=	United States Environmental Protection Agency
FASB			=	Financial Accounting Standards Board
GAAP			=	Generally accepted accounting principles in the United States
ICE			=	Intercontinental Exchange
~~LIBOR~~ISDA			=	International Swaps and Derivatives Association
LIBOR			=	London Interbank Offered Rate
LTIP			=	Long-term incentive plan
Mcf			=	Thousand cubic feet
~~NGL~~MMbls			=	Million barrels
NGL			=	Natural gas liquids, including ethane, propane and butane
NYMEX			=	New York Mercantile Exchange
~~Oxy~~SEC			=	~~Occidental Petroleum Corporation or its subsidiaries~~
~~PLA~~	=	~~Pipeline loss allowance~~
~~SEC~~	=	United States Securities and Exchange Commission
~~USD~~TWh			=	Terawatt hour
USD			=	United States dollar
WTI			=	West Texas Intermediate

Basis of Consolidation and Presentation

The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our ~~2016~~2019 Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of PAGP and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation.

The condensed consolidated balance sheet data as of December 31, ~~2016~~2019 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2020 should not be taken as indicative of results to be expected for the entire year.

Management judgment is required to evaluate whether PAGP controls an entity. Key areas of that evaluation include (i) determining whether an entity is a variable interest entity (“VIE”); (ii) determining whether PAGP is the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that PAGP and its related parties have over those activities through variable interests; and (iii) identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether PAGP is a VIE’s primary beneficiary.

~~Upon the completion~~

Table of the Simplification Transactions, our governance and corporate structure was modified, and based on the guidance contained in ASC 810-10-35-4, we reconsidered our prior determination that our subsidiaries, AAP and PAA, were VIEs. Based on the analysis performed at that time, we concluded that both entities were no longer VIEs. Therefore we concluded that AAP and PAA should be assessed using the voting interest entity model ("VOE"). Under the VOE model, weContents

PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

considered the new governance and corporate structure introduced by the Simplification Transactions and concluded that PAGP should continue to consolidate AAP and P AA. However, for the second quarter of 2017, we reassessed our consideration of whether PAA and AAP are VIEs and concluded that, contrary to our conclusion at the time of the Simplification Transactions, both PAA and AAP are more appropriately considered VIEs. This conclusion does not change our consolidation conclusion, has no impact on our financial statements and has limited impact on our related disclosures. NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

We have determined that our subsidiaries, PAA and AAP, are VIEs and should be consolidated by PAGP because:

•The limited partners of PAA and AAP lack (i) substantive “kick-out rights” (i.e., the right to remove the general partner) based on a simple majority or lower vote and (ii) substantive participation rights and thus lack the ability to block actions of the general partner that most significantly impact the economic performance of PAA and AAP, respectively.

•AAP is the primary beneficiary of PAA because it has the power to direct the activities that most significantly impact PAA’s performance and the right to receive benefits, and obligation to absorb losses, that could be significant to PAA.

•PAGP is the primary beneficiary of AAP because it has the power to direct the activities that most significantly impact AAP’s performance and the right to receive benefits, and obligation to absorb losses, that could be significant to AAP.

With the exception of a deferred tax asset of ~~$2,210 million~~$1.455 billion and ~~$1,876 million~~$1.280 billion as of ~~September 30, 2017~~March 31, 2020 and December 31, ~~2016,~~2019, respectively, substantially all assets and liabilities presented on PAGP’s ~~consolidated balance sheet~~Condensed Consolidated Balance Sheets are those of PAA. Only the assets of each respective VIE can be used to settle the obligations of that individual VIE, and the creditors of each/either of those VIEs do not have recourse against the general credit of PAGP. PAGP did not provide any financial support to PAA or AAP during the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 or the year ended December 31, ~~2016, respectively.~~2019. See Note 1517 to our Consolidated Financial Statements included in Part IV of our ~~2016~~2019 Annual Report on Form 10-K for information regarding the Omnibus Agreement entered into ~~in connection with~~by the ~~Simplification Transactions.~~Plains Entities on November 15, 2016.

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

COVID-19

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

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

Note 2—Summary of Significant Accounting Policies

Restricted Cash

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


	March 31, 2020		December 31, 2019
Cash and cash equivalents	$	40	$	47
Restricted cash	122		37
Total cash and cash equivalents and restricted cash	$	162	$	84

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Recent Accounting Pronouncements

Except as discussed below and in our ~~2016~~2019 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 that are of significance or potential significance to us.

Accounting Standards Updates Adopted During the Period

~~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 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~~ASUs listed below effective January 1, ~~2017~~2020 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 or shares 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 or cash flows (see Note 2 to our Consolidated Financial Statements included in Part IV of our 2019 Annual Report on Form 10-K for ~~the periods presented. We reclassified approximately $6 million~~additional information regarding these ASUs):

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

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

•ASU 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a consensus of 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 PAA units were withheld from employees’ awards.

~~In January 2017,~~ the FASB ~~issued~~ Emerging Issues Task Force);

•ASU ~~2017-04,~~ ~~Intangibles — Goodwill and Other~~2018-13, Fair Value Measurement (Topic ~~350)~~820): ~~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 equalDisclosure Framework—Changes to the ~~amount by which~~Disclosure Requirements for Fair Value Measurement; and

•ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (along with a ~~reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value~~series 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.related ASUs).

Accounting Standards Updates Issued During the Period

In ~~January 2017,~~March 2020, the FASB issued ~~ASU 2017-01,~~ ~~Business Combinations~~2020-04, Reference Rate Reform (Topic ~~805)~~848): ~~Clarifying~~Facilitation of the ~~Definition~~Effects of ~~a Business~~Reference Rate Reform on Financial Reporting, which ~~improves the guidance~~provides optional expedients and exceptions for ~~determining whether a transaction involves the purchase~~applying GAAP to contracts, hedging relationships and other transactions that reference LIBOR or ~~disposal~~another reference rate expected to be discontinued because of ~~a business or an asset.~~reference rate reform. This guidance is effective ~~for interim~~prospectively upon issuance through December 31, 2022 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~~may be applied from the ~~Derecognition~~beginning of ~~Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets.~~ ~~The update~~an interim period that includes the ~~following clarifications: (i) nonfinancial assets within the scope~~issuance date 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.this ASU. We ~~will adopt this guidance on January 1, 2018 and~~ are currently evaluating the ~~impact of the adoption~~effect that this guidance will have 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~~

Note 3—Revenues and Accounts Receivable

Revenue Recognition

We disaggregate our revenues by segment and type 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~~activity under ASC Topic 606, Revenues 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 (“Topic 606”). These categories depict how the nature, amount, timing and uncertainty of revenues and cash flows are affected by economic factors. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2019 Annual Report on Form 10-K for additional information regarding our types of revenues and policies for revenue recognition.

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


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

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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


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

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
















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

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

Minimum Volume Commitments. We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. At March 31, 2020 and December 31, 2019, counterparty deficiencies associated with contracts with customers and buy/sell arrangements that include minimum volume commitments totaled $22 million and $42 million, respectively, of which $18 million and $22 million, respectively, was recorded as a contract liability. The remaining balance of $4 million and $20 million at March 31, 2020 and December 31, 2019, respectively, was related to deficiencies for which the counterparties had not met their contractual minimum commitments and were not reflected in our Condensed Consolidated Financial Statements as we had not yet billed or collected such amounts.

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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 change in the contract liability balance during the three months ended March 31, 2020 (in millions):


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

Additions	36

Balance at March 31, 2020	$	148

Remaining Performance Obligations. Topic 606 requires a presentation of information about partially and wholly unsatisfied performance obligations under contracts that exist as of the end of the period. The information includes the amount of consideration allocated to those remaining performance obligations and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These arrangements include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. These contracts are all within the scope of Topic 606. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of March 31, 2020 (in millions):


	Remainder of 2020		2021		2022		2023		2024		2025 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements ⁽¹⁾	$	124	$	168	$	162	$	160	$	138	$	553
Storage, terminalling and throughput agreement revenues	307		324		254		192		147		367
Total	$	431	$	492	$	416	$	352	$	285	$	920

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

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

•Acreage dedications;

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

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

•Transportation and Facilities contracts that are short-term;

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

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

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Trade Accounts Receivable and Other Receivables, Net

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL. During the first quarter of 2020, macroeconomic and geopolitical conditions including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply has caused liquidity issues impacting many energy companies, which in turn has increased the potential credit risks associated with certain counterparties with which we do business. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions and perform credit reviews of each customer to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash ~~flows.~~payments, standby letters of credit, credit insurance or parental guarantees. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. For a majority of these net-cash arrangements, we also enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet).

Accounts receivable from the sale of crude oil are generally settled with counterparties on the industry settlement date, which is typically in the month following the month in which the title transfers. Otherwise, we generally invoice customers within 30 days of when the products or services were provided and generally require payment within 30 days of the invoice date. We ~~will adopt this guidance~~review all outstanding accounts receivable balances on ~~January 1, 2018,~~a monthly basis and ~~currently anticipate~~record our receivables net of expected credit losses. We do not write-off accounts receivable balances until we have exhausted substantially all collection efforts. At March 31, 2020 and December 31, 2019, substantially all of our trade accounts receivable were less than 30 days past their scheduled invoice date. Our expected credit losses are immaterial. Although we consider our credit procedures to be adequate to mitigate any significant credit losses, given the sharp decline in demand for crude oil and the drop in prices, the actual amount of current and future credit losses could vary significantly from estimated amounts.

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


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

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

Note 3—4—Net ~~Income~~Income/(Loss) Per Class A Share

Basic net ~~income~~income/(loss) per Class A share is determined by dividing net ~~income~~income/(loss) attributable to PAGP by the ~~weighted-average~~weighted average number of Class A shares outstanding during the period. Our Class B and Class C shares do not share in the earnings of the ~~Partnership. Accordingly,~~Partnership; accordingly, basic and diluted net income per Class B and Class C share has not been presented.

Diluted net ~~income~~income/(loss) per Class A share is determined by dividing net ~~income~~income/(loss) attributable to PAGP by the diluted ~~weighted-average~~weighted average number of Class A shares outstanding during the period. For purposes of calculating diluted net income per Class A share, both the net ~~income~~income/(loss) attributable to PAGP and the diluted ~~weighted-average~~weighted average number of Class A shares outstanding consider the impact of possible future exchanges of (i) AAP units and the associated Class B shares into our Class A shares and (ii) certain Class B units of AAP (referred to herein as “AAP Management Units”) into our Class A shares. In addition, the calculation of the diluted ~~weighted-average~~weighted average number of Class A shares outstanding considers the effect of potentially dilutive awards under the Plains GP Holdings, L.P. Long-Term Incentive Plan (the “PAGP LTIP”).

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

All AAP Management Units that have satisfied the applicable performance conditions are considered potentially dilutive. Exchanges of potentially dilutive AAP units and AAP Management Units are assumed to have occurred at the beginning of the period and the incremental income attributable to PAGP resulting from the assumed exchanges is representative of the incremental income that would have been attributable to PAGP if the assumed exchanges occurred on that date. See Note 912 to our Consolidated Financial Statements included in Part IV of our 2019 Annual Report on Form 10-K for information regarding exchanges of AAP units and AAP Management Units. PAGP LTIP awards that are deemed to be dilutive are reduced by a hypothetical share repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 18 to our Consolidated Financial Statements included in Part IV of our 2019 Annual Report on Form 10-K for information regarding PAGP LTIP awards.

For the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2020 and ~~the three months ended September 30, 2016,~~2019, the possible exchange of ~~any~~63 million and 120 million AAP units, respectively, and ~~certain~~1 million and 2 million AAP Management Units, respectively, would not have had a dilutive effect on basic net income per Class A share. For the nine months ended September 30, 2016, the possible exchange of any AAP units would have had a dilutive effect on basic net income per Class A share and the possible exchange of certain AAP Management Units would not have had a dilutive effect on basic net incomeincome/(loss) per Class A share. For the three ~~and nine~~ months ended ~~September 30, 2017 and 2016,~~March 31, 2020, our PAGP LTIP awards were antidilutive. For the three months ended March 31, 2019, our PAGP LTIP awards were dilutive; however, there were less than 0.1 million dilutive LTIP awards for ~~each~~the period, which did not change the presentation of weighted average Class A shares outstanding or net ~~income~~income/(loss) per Class A share.

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


	Three Months Ended March 31,
	2020		2019
Basic and Diluted Net Income/(Loss) per Class A Share
Net income/(loss) attributable to PAGP	$	(581)	$	147
Basic and diluted weighted average Class A shares outstanding	183		159

Basic and diluted net income/(loss) per Class A share	$	(3.18)	$	0.92

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Basic Net Income per Class A Share

Net income attributable to PAGP $ 4
$ 24
$ 69
$ 102
Basic weighted average Class A shares outstanding 154
101
142
99

Basic net income per Class A share $ 0.03
$ 0.24
$ 0.49
$ 1.03

Diluted Net Income per Class A Share

Net income attributable to PAGP $ 4
$ 24
$ 69
$ 102
Incremental net income attributable to PAGP resulting from assumed exchange of AAP units and AAP Management Units —
—
—
138
Net income attributable to PAGP including incremental net income from assumed exchange of AAP units and AAP Management Units $ 4
$ 24
$ 69
$ 240

Basic weighted average Class A shares outstanding 154
101
142
99
Dilutive shares resulting from assumed exchange of AAP units and AAP Management Units —
—
—
137
Diluted weighted average Class A shares outstanding 154
101
142
236

Diluted net income per Class A share $ 0.03
$ 0.24
$ 0.49
$ 1.02

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~Note 4—Accounts Receivable, Net~~

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions 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 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, 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.

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. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At September 30, 2017 and December 31, 2016, 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. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

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

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


	September 30, 2017						December 31, 2016							March 31, 2020										December 31, 2019
	Volumes	Unit of Measure	Carrying Value		Price/ Unit ⁽¹⁾		Volumes	Unit of Measure	Carrying Value		Price/ Unit ⁽¹⁾			Volumes	Unit of Measure	Carrying Value		Price/ Unit ⁽¹⁾		Volumes	Unit of Measure	Carrying Value		Price/ Unit ⁽¹⁾
Inventory													Inventory
Crude oil	10,632	barrels	$	480	$	45.15	23,589	barrels	$	1,049	$	44.47	Crude oil	7,168	barrels	$	128	$	17.86	8,613	barrels	$	450	$	52.25
NGL	16,604	barrels	390		$	23.49	13,497	barrels	242		$	17.93	NGL	3,992	barrels	42		$	10.52	7,574	barrels	142		$	18.75
Natural gas	—	Mcf	—		N/A		14,540	Mcf	32		$	2.20

Other	N/A		14		N/A		N/A		20		N/A		Other	N/A		11		N/A		N/A		12		N/A
Inventory subtotal			884						1,343				Inventory subtotal			181						604

Linefill and base gas													Linefill and base gas
Crude oil	12,477	barrels	729		$	58.43	12,273	barrels	710		$	57.85	Crude oil	14,251	barrels	804		$	56.42	14,316	barrels	826		$	57.70
NGL	1,630	barrels	47		$	28.83	1,660	barrels	45		$	27.11	NGL	1,640	barrels	41		$	25.00	1,701	barrels	47		$	27.63
Natural gas	24,976	Mcf	108		$	4.32	30,812	Mcf	141		$	4.58	Natural gas	25,576	Mcf	110		$	4.30	24,976	Mcf	108		$	4.32
Linefill and base gas subtotal			884						896				Linefill and base gas subtotal			955						981

Long-term inventory													Long-term inventory
Crude oil	1,800	barrels	86		$	47.78	3,279	barrels	163		$	49.71	Crude oil	2,789	barrels	55		$	19.72	2,598	barrels	152		$	58.51
NGL	2,120	barrels	49		$	23.11	1,418	barrels	30		$	21.16	NGL	1,579	barrels	18		$	11.40	1,707	barrels	30		$	17.57
Long-term inventory subtotal			135						193				Long-term inventory subtotal			73						182

Total			$	1,903					$	2,432			Total			$	1,209					$	1,767


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

⁽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~~$232 million during the ~~nine~~three months ended ~~September 30, 2017 primarily~~March 31, 2020 related to the ~~writedown~~write-down of our crude oil and NGL inventory, of which $40 million is associated with our long-term inventory, due to ~~a decline~~declines in ~~prices. Substantially all~~prices during the first quarter of 2020. A portion of this inventory valuation adjustment was offset by the recognition of gains on derivative instruments being utilized to hedge future sales of our crude oil and NGL inventory. Such gains were recorded to “Supply and Logistics segment revenues” in our accompanying ~~Condensed~~ Consolidated ~~Statements~~Statement of Operations. See Note 10 for discussion of our derivative and risk management activities. We

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 6—Goodwill

During the first quarter of 2020, we recorded ~~an inventory valuation adjustment of $3 million~~impairment losses related to goodwill. Our market capitalization declined significantly during the ~~nine months ended September 30, 2016.~~

~~Note 6—Acquisitions~~first quarter driven by current macroeconomic and ~~Dispositions~~

~~Acquisitions~~

~~The following acquisitions were accounted~~geopolitical conditions including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply as well as changing market conditions and expected lower crude oil production in certain regions, resulting in expected decreases in future cash flows for ~~using~~certain of our assets. In addition, the ~~acquisition method~~uncertainty related to oil demand continues to have a significant impact on the investment and operating plans of ~~accounting and~~our primary customers. Based on these events, we concluded that a triggering event occurred which required us to perform a quantitative impairment test as of March 31, 2020, utilizing a discounted cash flow approach. We applied a discount rate of approximately 14% in the determination of the fair value of ~~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~~each of our reporting units, which represents our estimate of the ~~issued and outstanding membership interests in Alpha Holding Company, LLC for cash consideration~~cost of ~~approximately $1.217 billion, subject to working~~ capital ~~and other adjustments (the “ACC Acquisition”).~~of a theoretical market participant. The ACC Acquisition was initially funded through borrowings under PAA's senior unsecured revolving credit facility. Such borrowings were subsequently repaid with proceeds from PAA's March 2017 issuance of its common units to AAP pursuant to the Omnibus Agreement and in connection with our underwritten equity offering. See ~~Note 9~~ ~~for additional information.~~

~~Upon completion~~fair values of the ~~ACC Acquisition, we became the owner of a crude oil gathering system known as the “Alpha Crude Connector” (the “ACC System”) located~~reporting units are Level 3 measurements in the ~~Northern Delaware Basin~~fair value hierarchy and were based on various inputs, as discussed below. The discounted cash flows for each reporting unit were based on six years of projected cash flows and terminal values that we believe would be applied by a theoretical market participant in ~~Southeastern New Mexico~~similar market transactions. The discounted cash flows for the respective reporting units utilized various other assumptions, including, but not limited to (i) volumes (based on historical information and ~~West Texas. The ACC System comprises approximately 515 miles~~estimates of ~~gathering~~future drilling 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~~completion activity, as well as ~~additional enhancements intended to increase~~expectations of future demand recovery), (ii) tariff and storage rates, (iii) future commodity prices (based on relevant indices and applicable quality and location differentials), and (iv) estimated fixed and variable costs. We used a range of cash flows for the ~~ACC System capacity to approximately 350,000 barrels per day, depending~~discounted cash flow calculations, based on ~~the level of volume at~~differing potential market scenarios but for 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~~reporting units, 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~~ultimate outcome of the ~~acquisition-date fair~~impairment test was unchanged by the various points within the range of cash flows. Based upon the results of the impairment test, we concluded that the carrying value of ~~the assets acquired and liabilities assumed is preliminary. We expect to finalize~~each of our reporting units exceeded their respective fair ~~value determination~~values, resulting 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 milliongoodwill impairment charge for the ~~period from February 14, 2017 through September 30, 2017, and the future amortization expense is estimated as follows~~entire goodwill balance for ~~the next five years (in millions):~~each reporting unit.

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

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

During the nine months ended September 30, 2017, we incurred approximately $6 million of acquisition-related costs associated with the ACC Acquisition. Such costs are reflected as a component of general and administrative expenses in our Condensed Consolidated Statements of Operations.

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

~~Other Acquisitions~~

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

~~Investment Acquisition~~

On April 3, 2017, we and an affiliate of Noble Midstream Partners LP (“Noble”) completed the acquisition of Advantage Pipeline, L.L.C. (“Advantage”) for a purchase price of $133 million through a newly formed 50/50 joint venture (the “Advantage Joint Venture”). For our 50% share ($66.5 million), we contributed approximately 1.3 million PAA 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, 2019	$	1,052	$	982	$	506	$	2,540
Acquisitions	2		—		—		2
Foreign currency translation adjustments	(19)		(7)		(5)		(31)


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

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

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 7—Investments in Unconsolidated Entities

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


		Ownership Interest at March 31, 2020	Investment Balance
Entity ⁽¹⁾	Type of Operation				March 31, 2020			December 31, 2019
BridgeTex Pipeline Company, LLC	Crude Oil Pipeline	20%	$	427		$	431
Cactus II Pipeline LLC	Crude Oil Pipeline	65%	767			738
Capline Pipeline Company LLC	Crude Oil Pipeline ⁽²⁾	54%	499			484
Diamond Pipeline LLC	Crude Oil Pipeline	50%	477			476
Eagle Ford Pipeline LLC	Crude Oil Pipeline	50%	391			382
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Terminals”)	Crude Oil Terminal and Dock	50%	128			126
Red Oak Pipeline LLC (“Red Oak”)	Crude Oil Pipeline ^{(3) (4)}	50%	54			20
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)	Crude Oil Pipeline	30%	181			234
STACK Pipeline LLC	Crude Oil Pipeline	50%	116			117
White Cliffs Pipeline, LLC	Crude Oil Pipeline	36%	193			196
Wink to Webster Pipeline LLC	Crude Oil Pipeline ⁽³⁾	16%	182			136
Other investments			299			343
Total investments in unconsolidated entities			$	3,714		$	3,683


⁽¹⁾	~~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.~~

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

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

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

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

Impairments

During the three months ended March 31, 2020, we recognized a loss of $43 million related to the write-down of certain of our investments included in “Other investments” in the table above due to an other-than-temporary impairment related to a decline in market conditions. This loss is reflected in “Gain on/(impairment of) investments in unconsolidated entities, net” on our Condensed Consolidated Statement of Operations.

Divestitures

Saddlehorn. In February 2020, we sold a 10% ownership interest in Saddlehorn for proceeds of approximately $78 million, including working capital adjustments, and have retained a 30% interest. We ~~completed~~recorded a gain of approximately $21 million related to this sale, which is included in “Gain on/(impairment of) investments in unconsolidated entities” on our ~~goodwill impairment test as~~Condensed Consolidated Statement of ~~June 30, 2017 using a qualitative assessment.~~Operations. We ~~determined that it was more likely than not that~~continue to account for our remaining interest under the ~~fair value~~equity method of ~~each reporting unit was greater than its respective book value; therefore, additional impairment testing was not necessary and goodwill was not considered impaired.~~accounting.

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 8—Debt

Debt consisted of the following (in millions):

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

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

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

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


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




Other	126		86
Total short-term debt	363		504

LONG-TERM DEBT
PAA senior notes, net of unamortized discounts and debt issuance costs of $59 and $61, respectively ⁽²⁾	8,941		8,939
PAA senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.8% ⁽²⁾	177		—

PAA GO Zone term loans, net of debt issuance costs of $1 and $1, respectively, bearing a weighted-average interest rate of 2.5% and 2.6%, respectively	199		199
Other	101		49
Total long-term debt	9,418		9,187
Total debt ⁽³⁾	$	9,781	$	9,691


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


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


⁽³⁾	As of September 30, 2017, we have classified PAA's $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 PAA's commercial paper notes as long-term based on our ability and intent to refinance such amounts on a long-term basis.

⁽⁴⁾

PAA’s 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. PAA’s fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under the credit facilities and the PAA commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for the PAA senior notes, the credit facilities and the PAA 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, PAA extended the maturity dates of its senior unsecured revolving~~ credit facility borrowings as short-term as of March 31, 2020 and December 31, 2019, as these notes and borrowings were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.

⁽²⁾As of March 31, 2020, we classified PAA’s $600 million, 5.00% senior notes due February 2021 and a portion of PAA’s senior secured hedged inventory facility borrowings as long-term based on PAA’s ability and intent to refinance such amounts on a long-term basis.

⁽³⁾PAA’s fixed-rate senior ~~unsecured 364-day revolving credit facility to August 2022, August~~notes had a face value of approximately $9.0 billion at both March 31, 2020 and ~~August 2018, respectively, for each extending lender. Additionally,~~December 31, 2019. We estimated the aggregate fair value of these notes as of March 31, 2020 and December 31, 2019 to be approximately $7.2 billion and $9.3 billion, respectively. PAA’s fixed-rate senior notes are traded among institutions, and these trades are routinely published by a ~~provision was added to~~reporting service. Our determination of fair value is based on reported trading activity near the ~~364-day revolving credit facility agreement whereby PAA may elect to have the entire principal balance of any loans outstanding on the maturity date~~end of the ~~364-day revolving~~reporting period. We estimate that the carrying value of outstanding borrowings under PAA’s credit ~~facility converted into a non-revolving~~facilities, commercial paper program and GO Zone term ~~loan with a maturity date~~loans approximates fair value as interest rates reflect current market rates. The fair value estimates for PAA’s senior notes, credit facilities, commercial paper program and GO Zone term loans are based upon observable market data and are classified in Level 2 of ~~August 2019.~~the fair value hierarchy.

Borrowings and Repayments

Total borrowings under the PAA credit facilities and ~~the PAA~~ commercial paper program for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016~~2019 were approximately ~~$52.6~~$9.6 billion and ~~$41.4~~$0.5 billion, respectively. Total repayments under the PAA credit facilities and ~~the PAA~~ commercial paper program were approximately ~~$52.7~~$9.6 billion and ~~$41.6~~$0.5 billion for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016,~~2019, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Letters of Credit

In connection with our supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At ~~September 30, 2017~~March 31, 2020 and December 31, ~~2016,~~2019, we had outstanding letters of credit of ~~$95~~$106 million and ~~$73~~$157 million, respectively.

~~Senior Notes Repayments~~

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

Note 9—Partners’ Capital and Distributions

Shares Outstanding

The following tables present the activity for our Class A shares, Class B shares and Class C shares:

Class A Shares Class B Shares Class C Shares
Outstanding at December 31, 2016 101,206,526
138,043,486
491,910,863
Conversion of AAP Management Units ⁽¹⁾
—
1,557,860
—
Exchange Right exercises ⁽¹⁾
3,231,281
(3,231,281 ) —
Redemption Right exercises ⁽¹⁾
—
(4,959,861 ) 4,959,861
Sales of Class A shares 50,086,326
—
—
Sales of common units by a subsidiary —
—
4,033,567
Issuance of common units by a subsidiary in connection with acquisition of interest in Advantage Joint Venture (Note 6) —
—
1,252,269
Issuances of Series A preferred units by a subsidiary —
—
3,941,096
Other 19,060
—
603,497
Outstanding at September 30, 2017 154,543,193
131,410,204
506,701,153


	Class A Shares	Class B Shares	Class C Shares
Outstanding at December 31, 2019	182,138,592	65,785,702	549,538,139

Conversion of AAP Management Units⁽¹⁾	—	559,768	—
Exchange Right exercises ⁽¹⁾	2,101,487	(2,101,487)	—
Redemption Right exercises ⁽¹⁾	—	(1,206,599)	1,206,599
Other	—	—	24,431
Outstanding at March 31, 2020	184,240,079	63,037,384	550,769,169


	Class A Shares	Class B Shares	Class C Shares
Outstanding at December 31, 2018	159,485,588	119,604,338	516,938,280


Redemption Right exercises ⁽¹⁾		(91,672)	91,672

Other	—	—	226,814
Outstanding at March 31, 2019	159,485,588	119,512,666	517,256,766

Class A Shares Class B Shares
Outstanding at December 31, 2015 86,099,037
141,485,588
Conversion of AAP Management Units ⁽¹⁾
—
13,567,916
Exchange Right exercises ⁽¹⁾
14,665,076
(14,665,076 )
Issuance of Class A shares under LTIP 7,811
—
Outstanding at September 30, 2016 100,771,924
140,388,428

~~___________________________________________~~


⁽¹⁾			See Note 11 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for information regarding conversions of AAP Management Units, Exchange Rights and Redemption Rights.

⁽¹⁾See Note 12 to our Consolidated Financial Statements included in Part IV of our 2019 Annual Report on Form 10-K for information regarding conversions of AAP Management Units, Exchange Rights and Redemption Rights.

Distributions

~~On August 25, 2017, PAA announced its intention to reset its annualized distribution to $1.20 per common unit, beginning with the third-quarter distribution payable November 14, 2017.~~ The ~~amount of cash available to distribute~~following table details distributions to our Class A shareholders is completely dependent upon the amount of cash distributed by PAA to AAP in respect of its common units; therefore, any change in the distribution level on PAA's common units has a corresponding impact on the distribution level on our Class A shares. See “—Subsidiary Distributions” below for additional information.

~~The following table details the distributions~~ paid ~~to our Class A shareholders~~ during or pertaining to the first ~~nine~~three months of ~~2017~~2020 (in millions, except per share data):

Distribution Payment Date
Distributions to
Class A Shareholders

Distributions per
Class A Share
November 14, 2017 ⁽¹⁾
$ 46
$ 0.30
August 14, 2017 $ 84
$ 0.55
May 15, 2017 $ 84
$ 0.55
February 14, 2017 $ 57
$ 0.55


Distribution Payment Date	Distributions to Class A Shareholders		Distributions per Class A Share


May 15, 2020 ⁽¹⁾	$	33	$	0.18
February 14, 2020	$	66	$	0.36


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

~~Sales of Class A Shares~~

~~The following table summarizes our sales of Class A shares 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 Class A Shares Issued
Net Proceeds ⁽¹⁾

Continuous Offering Program 1,786,326
$ 61
⁽²⁾
Underwritten Offering 48,300,000
1,474

50,086,326
$ 1,535


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


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

⁽¹⁾Payable to shareholders of record at the close of business on May 1, 2020 for the period from January 1, 2020 through March 31, 2020.

~~Pursuant to the Omnibus Agreement entered into by the Plains Entities in connection with the Simplification Transactions, we used the net proceeds from the sale~~

Table of our 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. Also pursuant to the Omnibus Agreement, immediately following such purchase and sale, AAP used the net proceeds it received from such sale of AAP units to us to purchase from PAA an equivalent number of common units of PAA. See “—Subsidiary Sales of Units” below.Contents

PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

The cash purchase by PAGP of additional units issued by AAP and corresponding cash purchase by AAP of additional common units issued by PAA results in the allocation of the fair value of the proceeds between controlling and noncontrolling interests in AAP and PAA based on their respective ownership percentages. Additionally, in accordance with ASC 810, an adjustment in partners' capital based on historical carrying value is recognized by PAGP’s Class A shareholders on their increase in ownership of subsidiary entities and a corresponding adjustment is recognized in partners' capital by PAGP’s noncontrolling interests due to the dilution of their ownership interest. The allocation to noncontrolling interests results from the difference between the fair value per unit of the additional units issued and the historical carrying value per unit. Such amounts are reflected in “Sales of Class A shares” on our Condensed Consolidated Statements of Changes in Partners' Capital.NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Subsidiaries

Noncontrolling Interests in Subsidiaries

As of ~~September 30, 2017,~~March 31, 2020, noncontrolling interests in our subsidiaries consisted of (i) ~~a 64%~~ limited partner interests in PAA including a 69% interest in ~~PAA,~~PAA’s common units and PAA’s Series A preferred units combined and 100% of PAA’s Series B preferred units, (ii) an approximate ~~46%~~25% limited partner interest in AAP and (iii) a ~~25%~~33% interest in ~~SLC~~Red River Pipeline ~~LLC.~~Company LLC (“Red River LLC”).

During the three months ended March 31, 2020, we received $8 million of contributions from noncontrolling interests in Red River LLC related to the Red River pipeline capacity expansion.

Subsidiary Distributions

~~Subsidiary Sales~~PAA Series A Preferred Unit Distributions. The following table details distributions to PAA’s Series A preferred unitholders paid during or pertaining to the first three months of ~~Units~~2020 (in millions, except per unit data):

~~Issuance~~


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


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

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

PAASeries B Preferred ~~Units~~

On October 10, 2017, PAA issued 800,000 Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in PAA (the “Series B preferred units”) at a price to the public of $1,000 per unit. PAA 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 its credit facilities and commercial paper program and for general partnership purposes.

The Series B preferred units represent perpetual equity interests in PAA, 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 PAA's partnership agreement that would have a material adverse effectUnit Distributions. Distributions 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~~PAA’s Series B preferred units are in arrears, (iii) the creation or issuance of any senior securities and (iv) the payment of distributions to PAA's 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 PAA's outstanding Series A preferred units.~~

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


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

May 15, 2020 ⁽¹⁾	$	24.5	$	30.625

⁽¹⁾Payable to $61.25 per unit per year). On and after November 15, 2022, distributions on the Series B preferred units will accumulate for each distribution period at a percentage of the liquidation preference equal to the then-current three-month LIBOR plus a spread of 4.11%. PAA will pay a pro-rated initial distribution on the Series B preferred units on November 15, 2017 to holdersunitholders of record at the close of business on May 1, 2020 for the period from November ~~1, 2017 in an amount equal~~15, 2019 through May 14, 2020.

At March 31, 2020, approximately $18 million of accrued distributions payable to ~~approximately $5.9549 per unit (a total distribution of approximately $5 million).~~

~~Upon the occurrence of certain rating agency events, PAA may redeem the~~PAA’s Series B preferred ~~units,~~unitholders was included in whole but not in part, at a price of $1,020 (102% of the liquidation preference) per Series B preferred unit plus an amount equal to all accumulated and unpaid distributions thereon to, but not including, the date of redemption, whether or not declared. In addition, at any time on or after November 15, 2022, PAA may redeem the Series B preferred units, at its 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.

~~Issuance of Common Units~~

~~Continuous Offering Program.~~ During the nine months ended September 30, 2017, PAA issued an aggregate of approximately 4.0 million common units under its continuous offering program, generating proceeds of $129 million, net of $1 million of commissions paid to its sales agents.

The proceeds from the issuance of PAA common units were allocated among all of PAA’s common unitholders, including AAP, based on their percentage ownership of common units. Additionally, PAA’s capital attributable to AAP was adjusted based on historical carrying value, in accordance with ASC 810, to reflect the dilution of its interest in PAA as a result of the issuance of additional common units to the public unitholders. These adjustments were recognized by PAGP in proportion to PAGP’s ownership interest in AAP, which resulted in a net increase in partners’ capital attributable to PAGP resulting from the difference between the fair value per unit of the additional units issued and the historical carrying value per unit. Such amounts are reflected in “Sales of common units by a subsidiary”“Other current liabilities” on our Condensed Consolidated ~~Statements of Changes in Partners' Capital.~~Balance Sheet.

~~Omnibus Agreement.~~ During the nine months ended September 30, 2017, pursuant to the Omnibus Agreement discussed above, PAA sold (i) approximately 1.8 million common units to AAP in connection with our issuance of Class A shares under our Continuous Offering Program and (ii) 48.3 million common units to AAP in connection with our March 2017 underwritten offering.

~~Deferred Tax Asset Impact from the Sale of Subsidiary Units~~

In connection with the sales of AAP units and PAA common units referenced above, a deferred asset was created. The tax basis of PAGP’s purchase of the additional units was accounted for at fair market value for U.S. federal income tax purposes, but the GAAP basis was impacted by the adjustments that are based on historical carrying value. The resulting basis difference resulted in a deferred tax asset that was recorded as a component of partner’s capital as it results from transactions with shareholders.

~~Subsidiary Distributions~~

PAA Common Unit Distributions. ~~During the third quarter of 2017, PAA’s management engaged in discussions with our Board of Directors regarding a reassessment of PAA’s approach~~ The following table details distributions to ~~distributions, with a focus on resetting~~ PAA’s common unitholders paid during or pertaining to the first three months of 2020 (in millions, except per unit ~~distribution~~data):


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


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

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

⁽¹⁾Payable to a level supported by the distributable cash flow from its fee-based Transportation and Facilities segments. On August 25, 2017, PAA announced its intention to reset its annualized distribution to $1.20 per common unit, beginning with the third-quarter distribution payable November 14, 2017. On October 10, 2017, the PAGP GP Board declared a distribution of $1.20 (annualized) per common unit payable on November 14, 2017 to common unitholders of record asat the close of ~~October~~business on May 1, 2020 for the period from January 1, 2020 through March 31, ~~2017.~~2020.

AAP Distributions.The following table details the distributions to ~~PAA’s common unitholders~~AAP’s partners paid ~~in cash~~ during or pertaining to the first ~~nine~~three months of ~~2017 (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


⁽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.~~

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

On November 14, 2017, PAA will issue 1,366,593 Series A preferred units in lieu of a cash distribution of $36 million on PAA's Series A preferred units outstanding as of October 31, 2017, the record date for such distribution.

~~PAA Series B Preferred Unit Distributions.~~ For its Series B preferred units issued on October 10, 2017, PAA will pay a pro-rated initial distribution on November 15, 2017. See “—Subsidiary Sales of Units” above for additional information.

~~AAP Distributions.~~ ~~The following table details the distributions paid to AAP’s partners during or pertaining to the first nine months of 2017~~2020 from distributions received from PAA (in millions):

Distribution to AAP's Partners
Distribution Payment Date Noncontrolling Interests PAGP Total Cash Distributions
November 14, 2017⁽¹⁾
$ 40
$ 46
$ 86
August 14, 2017 $ 75
$ 84
$ 159
May 15, 2017 $ 75
$ 84
$ 159
February 14, 2017 $ 77
$ 57
$ 134


	Distribution to AAP’s Partners
Distribution Payment Date	Noncontrolling Interests		PAGP		Total Cash Distributions


May 15, 2020 ⁽¹⁾	$	12	$	33	$	45
February 14, 2020	$	24	$	66	$	90


⁽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.~~

~~Other Distributions.~~ ~~During~~⁽¹⁾Payable to unitholders of record at the ~~nine months ended September 30, 2017, distributions~~close of ~~$2 million were paid to noncontrolling interests in SLC Pipeline LLC.~~business on May 1, 2020 for the period from January 1, 2020 through March 31, 2020.

Note 10—Derivatives and Risk Management Activities

We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on hydrocarbon commodity (referred to herein as “commodity”) price changes. We use various derivative instruments to manage our exposure to (i) commodity price risk, as well as to optimize our profits, (ii) interest rate risk and (iii) currency exchange rate risk. Our commodity price risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. ~~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 as a hedging instrument and derivatives that do not qualify for hedge accounting are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Condensed Consolidated Statements of Cash Flows.

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

At March 31, 2020 and December 31, 2019, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our exchange-traded derivatives transacted through a clearing brokerage account, as described below, we do not require our non-cleared derivative counterparties to post collateral with us.

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Commodity Price Risk Hedging

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

Commodity Purchases and Sales — In the normal course of our operations, we purchase and sell commodities. We use derivatives to manage the associated risks and to optimize profits. As of ~~September 30, 2017,~~March 31, 2020, net derivative positions related to these activities included:

•A net long position of ~~6.9~~9.9 million barrels associated with our crude oil purchases, which was unwound ratably during ~~October 2017~~April 2020 to match monthly average pricing.

•A net short time spread position of ~~3.5~~6.0 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through ~~December 2018.~~May 2021.

•A net crude oil ~~grade~~ basis spread position of ~~25.2~~6.3 million barrels at multiple locations through December ~~2019.~~2021. These derivatives allow us to lock in grade basis differentials.

•A net short position of ~~14.4~~15.7 million barrels through December ~~2020~~2022 related to anticipated net sales of ~~our~~ crude oil and NGL inventory.

~~Pipeline Loss Allowance Oil~~Storage Capacity Utilization — For capacity allocated to our supply and logistics operations, we have utilization risk in a backwardated market structure. As ~~is common in~~of March 31, 2020, we used derivatives to manage the ~~pipeline transportation industry, our tariffs incorporate a loss allowance factor~~risk that ~~is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We utilize derivative instruments to hedge~~ a portion of ~~the anticipated sales~~our storage capacity will not be utilized (an average 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~~approximately 2.0 million barrels per month of storage capacity through December ~~2019.~~2021). These positions involve no outright price exposure.

Natural Gas Processing/NGL Fractionation — We purchase natural gas for processing and operational needs. Additionally, we purchase NGL mix for fractionation and sell the resulting individual specification products (including ethane, propane, butane and condensate). In conjunction with these activities, we hedge the price risk associated with the purchase of the natural gas and the subsequent sale of the individual specification products. ~~As of September 30, 2017, we had a long natural gas position of 63.9 Bcf which hedges~~The following table summarizes our open derivative positions utilized to hedge the price risk associated with anticipated purchases and sales related to our natural gas processing and ~~operational needs through December 2020. We also had a short propane~~NGL fractionation activities as of March 31, 2020:

Notional Volume

(Short)/Long

Remaining Tenor

Natural gas purchases

41.8 Bcf

December 2022

Propane sales

(3.0) MMbls

December 2020

Butane sales

(1.8) MMbls

December 2020

Condensate sales (WTI position)

(0.9) MMbls

December 2020

Power supply requirements ⁽¹⁾

0.9 TWh

December 2022

⁽¹⁾Power position 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 hedgesto hedge a portion of our power supply 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~~

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

~~We use interest rate~~NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Our commodity derivatives ~~to hedge the benchmark interest rate risk associated with interest payments occurring~~are not designated 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~~hedging relationship, 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 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 (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

~~Preferred Distribution Rate Reset Option~~

A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. The Preferred Distribution Rate Reset Option of the PAA Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, the PAA partnership agreement, and recorded at fair value on our Condensed Consolidated Balance Sheets. 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 recognizedreported 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~~commodity derivatives 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.


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

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through clearing brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. The following table provides the components of our net broker ~~receivable:~~receivable/(payable) (in millions):

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


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

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


	March 31, 2020															December 31, 2019
					Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet						Effect of Collateral Netting			Net Carrying Value Presented on the Balance Sheet
	Commodity Derivatives														Commodity Derivatives
	Assets		Liabilities								Assets				Liabilities
Derivative Assets
Other current assets	$	446	$	(256)	$	(125)	$	65	$	179	$	(37)	$	(45)		$	97
Other long-term assets, net	99		(15)		—		84		24		—		—			24
Derivative Liabilities
Other current liabilities	161		(171)		—		(10)		32		(56)		—			(24)
Other long-term liabilities and deferred credits	—		(12)		—		(12)		—		(12)		—			(12)
Total	$	706	$	(454)	$	(125)	$	127	$	235	$	(105)	$	(45)		$	85

Interest Rate Risk Hedging

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.

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the terms of our outstanding interest rate derivatives as of March 31, 2020 (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	6/15/2020	3.06	%	Cash flow hedge
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	6/15/2023	1.38	%	Cash flow hedge
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	6/14/2024	0.73	%	Cash flow hedge

As of ~~September 30, 2017,~~March 31, 2020, there was a net loss of ~~$224~~$336 million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the earnings recognition of the underlying hedged commodity ~~transaction~~transactions or (ii) interest expense accruals associated with underlying debt instruments. We reclassified a net loss of $2 million and $2 million during the three months ended March 31, 2020 and 2019, respectively. Of the total net loss deferred in AOCI at ~~September 30, 2017,~~March 31, 2020, we expect to reclassify a net loss of $8$12 million to earnings in the next twelve months. ~~The~~We estimate that substantially all of the remaining deferred loss ~~of $216 million is expected to~~will be reclassified to earnings through ~~2049.~~2054 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of ~~September 30, 2017;~~March 31, 2020; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

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

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


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

At March 31, 2020, the net fair value of our interest rate hedges, which were included in “Other current liabilities” and “Other long-term liabilities and deferred credits” on our Condensed Consolidated Balance Sheet, totaled $115 million and $9 million, respectively. At December 31, 2019, the fair value of these hedges was $44 million and included in “Other current liabilities.”

Currency Exchange Rate Risk Hedging

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

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

The following table summarizes our open forward exchange contracts as of March 31, 2020 (in millions):


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

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

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

These derivatives are not designated as a hedging relationship. As such, changes in fair value are recognized in earnings as a component of Supply and Logistics segment revenues. For the three months ended March 31, 2020 and 2019, the amounts recognized in earnings for our currency exchange rate hedges were a loss of $6 million and a gain of $5 million, respectively.

At ~~September 30, 2017~~March 31, 2020, the net fair value of these currency exchange rate hedges, which was included in “Other current assets” and “Other current liabilities” on our Condensed Consolidated Balance Sheet, totaled $1 million and $6 million, respectively. At December 31, 2019, the net fair value of these currency exchange rate hedges, which was included in “Other current assets” and “Other current liabilities” on our Condensed Consolidated Balance Sheet, totaled $2 million and $1 million, respectively.

Preferred Distribution Rate Reset Option

A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. The Preferred Distribution Rate Reset Option of the PAA Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, the PAA partnership agreement, and recorded at fair value on our Condensed Consolidated Balance Sheets. This embedded derivative is not designated as a hedging relationship and corresponding changes in fair value are recognized in “Other income/(expense), net” in our Condensed Consolidated Statement of Operations. For the three months ended March 31, 2020 and 2019, we recognized gains of $26 million and $23 million, respectively. The fair value of the Preferred Distribution Rate Reset Option, which was included in “Other long-term liabilities and deferred credits” on our Condensed Consolidated Balance Sheets, totaled $8 million and $34 million at March 31, 2020 and December 31, ~~2016, none~~2019, respectively. See Note 13 to our Consolidated Financial Statements included in Part IV of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in PAA's credit ratings. Although we may be required to post margin2019 Annual Report on ~~our cleared derivatives as described above, we do not require our non-cleared derivative counterparties to post collateral with us.~~Form 10-K for additional information regarding the Series A preferred units and 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													Fair Value as of March 31, 2020														Fair Value as of December 31, 2019
Recurring Fair Value Measures ⁽¹⁾	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total			Recurring Fair Value Measures ⁽¹⁾	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivatives	$	(4	)	$	(198	)	$	(8	)	$	(210	)	$	(113	)	$	(171	)	$	(4	)	$	(288	)	Commodity derivatives	$	177	$	128	$	(53)	$	252	$	42	$	105	$	(17)	$	130
Interest rate derivatives	—			(34		)	—			(34		)	—			(50		)	—			(50		)	Interest rate derivatives	—		(124)		—		(124)		—		(44)		—		(44)
Foreign currency derivatives	—			2			—			2			—			(3		)	—			(3		)	Foreign currency derivatives	—		(5)		—		(5)		—		1		—		1
Preferred Distribution Rate Reset Option	—			—			(33		)	(33		)	—			—			(32		)	(32		)	Preferred Distribution Rate Reset Option	—		—		(8)		(8)		—		—		(34)		(34)
Total net derivative liability	$	(4	)	$	(230	)	$	(41	)	$	(275	)	$	(113	)	$	(224	)	$	(36	)	$	(373	)
Total net derivative asset/(liability)																									Total net derivative asset/(liability)	$	177	$	(1)	$	(61)	$	115	$	42	$	62	$	(51)	$	53


⁽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, 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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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Level 3

Level 3 of the fair value hierarchy includes certain physical commodity and other contracts, over-the-counter options and the Preferred Distribution Rate Reset Option contained in PAA’s partnership agreement which is classified as an embedded derivative.

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

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

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

Rollforward of Level 3 Net Asset/(Liability)

The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 (in millions):


	Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended March 31,
	2017			2016			2017			2016				2020		2019
Beginning Balance	$	(30	)	$	(35	)	$	(36	)	$	11		Beginning Balance	$	(51)	$	(24)
Net gains/(losses) for the period included in earnings	(8		)	17			(1		)	41			Net gains/(losses) for the period included in earnings	(10)		23
Settlements	(1		)	—			4			(10		)	Settlements	—		(10)
Derivatives entered into during the period	(2		)	1			(8		)	(59		)	Derivatives entered into during the period	—		1
Ending Balance	$	(41	)	$	(17	)	$	(41	)	$	(17	)	Ending Balance	$	(61)	$	(10)

Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period	$	(10	)	$	18		$	(8	)	$	43		Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period	$	(10)	$	24

Note 11—Related Party Transactions

See Note 1517 to our Consolidated Financial Statements included in Part IV of our ~~2016~~2019 Annual Report on Form 10-K for a complete discussion of our related party transactions.

PAA’s Ownership of our Class C Shares

As of March 31, 2020 and December 31, 2019, PAA owned 550,769,169 and 549,538,139, respectively, Class C shares. The Class C shares represent a non-economic limited partner interest in us that provides PAA, as the sole holder, a “pass-through” voting right through which PAA’s common unitholders and Series A preferred unitholders have the effective right to vote, pro rata with the holders of our Class A and Class B shares, for the election of eligible directors.

Transactions with~~Oxy~~Other Related Parties

AsOur other related parties include (i) principal owners and their affiliated entities and (ii) entities in which we hold investments and account for under the equity method of ~~September 30, 2017, Oxy had~~accounting (see Note 7 for information regarding such entities). We recognize as our principal owners entities that have a designated representative on the board of directors of our general partner ~~and owned approximately~~and/or own greater than 10% of the limited partner interests in AAP. Such limited partner interests in AAP translates into a significantly smaller indirect ownership interest in PAA. We also consider subsidiaries or funds identified as affiliated with principal owners to be related parties. As of March 31, 2020, Kayne Anderson Capital Advisors, L.P. was a principal owner.

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

During the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2020 and ~~2016,~~2019, we recognized sales and transportation revenues, ~~and~~ purchased petroleum products and utilized transportation services from ~~Oxy.~~our principal owners and their affiliated entities and our equity method investees. These transactions were conducted at posted tariff rates or prices that we believe approximate market. Included in these transactions was a crude oil buy/sell agreement that includes a multi-year minimum volume commitment. The impact to our Condensed Consolidated Statements of Operations from ~~those~~these transactions is included below (in millions):

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

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


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

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


⁽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.~~

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

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

⁽³⁾Revenues and purchases and related costs from related parties for 2019 include transactions with The Energy & Minerals Group (“EMG”) and its subsidiaries through May 2019 and Occidental Petroleum Corporation (“Oxy”) and its subsidiaries through September 2019. Following transactions reducing EMG and Oxy’s ownership interest in AAP in May and September 2019, respectively, EMG and Oxy are no longer recognized as principal owners. See Note 17 to our 2019 Annual Report on Form 10-K for additional information.

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

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

Accounts payable $ 833
$ 836


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

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

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

⁽²⁾We have agreements to store and transport crude oil at posted tariff rates on pipelines or at facilities that are owned by equity method investees, in which we own a 50% interest. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities.

Note 12—Commitments and Contingencies

Loss Contingencies — General

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

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

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

At ~~September 30, 2017,~~March 31, 2020, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled ~~$134~~$142 million, of which ~~$47~~$89 million was classified as short-term and ~~$87~~$53 million was classified as long-term. At December 31, ~~2016,~~2019, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident) totaled ~~$147~~$140 million, of which ~~$61~~$60 million was classified as short-term and ~~$86~~$80 million was classified as long-term. ~~The~~Such short- and long-term environmental liabilities ~~referenced above~~ are reflected in ~~“Accounts payable and accrued~~“Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Condensed Consolidated Balance Sheets. At ~~September 30, 2017,~~March 31, 2020, we had recorded receivables totaling ~~$47~~$81 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which ~~$26~~$69 million was classified as short-term and $12 million was classified as long-term. At December 31, 2019, we had recorded $72 million of such receivables, of which $35 million was classified as short-term and $37 million was classified as long-term. Such short- and long-term receivables are reflected in “Trade accounts receivable and other receivables, net” and ~~$21 million was reflected in~~ “Other long-term assets, ~~net”~~net,” respectively, on our Condensed Consolidated Balance ~~Sheet. At December 31, 2016, we had recorded $56 million~~Sheets.

Table 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.Contents

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

Specific Legal, Environmental or Regulatory Matters

Line 901 Incident. In May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. A portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert. Following the release, we shut down the pipeline and initiated our emergency response plan. A Unified Command, which included the United States Coast Guard, the EPA, the State of California Department of Fish and Wildlife (“CDFW”), the California Office of Spill Prevention and Response and the Santa Barbara Office of Emergency Management, was established for the response effort. Clean-up and

remediation operations with respect to impacted shoreline and other areas has been determined by the Unified Command to be complete, and the Unified Command has been dissolved. Our estimate of the amount of oil spilled, based on relevant facts, data and information and as set forth in the Consent Decree described below, is approximately 2,934 barrels; of this amount, we estimate that 598 barrels reached the Pacific Ocean.

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

On May 21, 2015, we received a corrective action order from the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”), the governmental agency with jurisdiction over the operation of Line 901 as well as over a second stretch of pipeline extending from Gaviota Pump Station in Santa Barbara County to Emidio Pump Station in Kern County, California (Line 903), requiring us to shut down, purge, review, remediate and test Line 901. The corrective action order was subsequently amended on June 3, 2015; November ~~13,~~12, 2015; and June 16, 2016 to require us to take additional corrective actions with respect to both Lines 901 and 903 (as amended, the “CAO”). Among other requirements, the CAO obligated us to conduct a root cause failure analysis with respect to Line 901 and present remedial work plans and restart plans to PHMSA prior to returning Line 901 and 903 to service; the CAO also imposed a pressure restriction on the section of Line 903 between Pentland Pump Station and Emidio Pump Station, which was subsequently lifted, and required us to take other specified actions with respect to both Lines 901 and 903. We intend to continue to comply with the CAO and to cooperate with any other governmental investigations relating to or arising out of the release. Excavation and removal of the affected section of the pipeline was completed on May 28, 2015. Line 901 and Line 903 have been purged and are not currently operational, with the exception of the Pentland to Emidio segment of Line 903, which remains in ~~service under a pressure restriction.~~service. No timeline has been established for the restart of Line 901 or Line 903. The remaining uncompleted portions of the CAO, which primarily relate to returning Lines 901 and 903 to service, have been incorporated into the Consent Decree (defined and discussed below). Upon entry of the Consent Decree by the Court, we expect that the CAO will be closed out by PHMSA.

On February 17, 2016, PHMSA issued a Preliminary Factual Report of the Line 901 failure, which contains PHMSA’s preliminary findings regarding factual information about the events leading up to the accident and the technical analysis that has been conducted to date. On May 19, 2016, PHMSA issued its final Failure Investigation Report regarding the Line 901 incident. PHMSA’s findings indicate that the direct cause of the Line 901 incident was external corrosion that thinned the pipe wall to a level where it ruptured suddenly and released crude oil. PHMSA also concluded that there were numerous contributory causes of the Line 901 incident, including ineffective protection against external corrosion, failure to detect and mitigate the corrosion and a lack of timely detection and response to the rupture. The report also included copies of various engineering and technical reports regarding the incident. ~~By virtue~~All potential claims by PHMSA against PAA arising out of its statutory authority, PHMSA has the power and authority to impose fines and penalties on us and cause civil or criminal charges to be brought against us. While to date PHMSA has not imposed any such fines or penalties or 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 responsefailure would be settled pursuant 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.Consent Decree discussed below.

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In late May of 2015, the California Attorney General’s Office and the District Attorney’s office for the County of Santa Barbara (collectively, the “Prosecutors”) began investigating the Line 901 incident to determine whether any applicable state or local laws had been violated. On May 16, 2016, PAA and one of its employees were charged by a California state grand jury, pursuant to an indictment filed in California Superior Court, Santa Barbara County (the “May 2016 Indictment”), with alleged violations of California law in connection with the Line 901 incident. The May 2016 Indictment included a total of 46 counts 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.~~PAA. On July 28, 2016, at an arraignment hearing held in California Superior Court in Santa Barbara County, PAA pled not guilty to all counts. Between May of 2016 and May of 2018, 31 of the criminal charges against PAA (including 1 felony charge) and all of the criminal charges against our employee, were dismissed. The remaining 15 charges were the subject of a jury trial in California Superior Court in Santa Barbara County that began in May of 2018. The jury returned a verdict on September 7, 2018, pursuant to which we were (i) found guilty on 1 felony discharge count and 8 misdemeanor counts (which included 1 reporting count, 1 strict liability discharge count and 6 strict liability animal takings counts) and (ii) found not guilty on 1 strict liability animal takings count. The jury deadlocked on 3 counts (including 2 felony discharge counts and 1 strict liability animal takings count), and 2 misdemeanor discharge counts were dropped. On April 25, 2019, PAA was sentenced to pay fines and penalties in the aggregate amount of just under $3.35 million for the convictions covered by the September 2018 jury verdict (the “2019 Sentence”). The fines and penalties imposed in connection with the 2019 Sentence have been paid. The Superior Court also indicated that it would conduct further hearings on the issue of whether there were any “direct victims” of the spill that are entitled to restitution under applicable law. In April of 2019, the Prosecutors announced their intent to re-try the two felony discharge counts for which no jury verdict was returned. The strict liability animal taking count for which no jury verdict was returned has been dismissed. On October 7, 2019, upon motion from Plains, the court dismissed the 2 remaining felony counts and vacated a second trial on these counts.

Also in late May of 2015, the United States Attorney for the Department of Justice, Central District of California, Environmental Crimes Section (“DOJ”) began an investigation into whether there were any violations of federal criminal statutes in connection with the Line 901 incident, including potential violations of the federal Clean Water Act. We ~~are~~

~~cooperating~~have cooperated 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~~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~~Except in connection with the ~~EPA relating to Line 901. We have provided various responsive materials~~May 2016 Indictment and the 2019 Sentence, 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 to the Line 901 release ~~other than those brought pursuant to the May 2016 Indictment,~~ 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.employees.

Shortly following the Line 901 incident, we established a claims line and encouraged any parties that were damaged by the release to contact us to discuss their damage claims. We have received a number of claims through the claims line and we ~~are~~have been processing those claims ~~for payment~~and making payments as ~~we receive them.~~appropriate. In addition, we have also had ~~nine~~9 class action lawsuits filed against us, ~~six~~6 of which have been administratively consolidated into a single proceeding in the United States District Court for the Central District of California. In general, the plaintiffs are seeking to establish different classes of claimants that have allegedly been damaged by the ~~release, including potential classes such as~~release. The court originally certified three sub-classes of claimants and denied certification of the other proposed sub-class. On appeal, the Ninth Circuit Court of Appeals overturned the certification of one of the three sub-classes, the oil-industry sub-class, and the District Court subsequently dismissed the oil-industry sub-class representatives’ claims. The two remaining sub-classes include (i) commercial fishermen who landed fish in certain specified fishing blocks in the waters adjacent to Santa Barbara County or ~~from~~ persons or businesses who resold commercial seafood landed in such ~~areas, certain owners~~areas; and (ii) residential beachfront properties on a beach and residential properties with a private easement to a beach where oil from the spill washed up. The court has tentatively set a trial date of oceanfront and/or beachfront property on the Pacific Coast of California, and other classes of individuals and businesses that were allegedly impacted by the release. To date, only the commercial fisherman and seafood reseller class has been certified by the court.September 1, 2020 for those two sub-classes. We are also defending a separate class action lawsuit proceeding in the United States District Court for the Central District of California brought on behalf of the Line 901 and Line 903 easement holders seeking injunctive relief as well as compensatory damages.

There have also been two securities law class action lawsuits filed on behalf of certain purported investors in PAA and/or PAGP against PAA, PAGP and/or certain of their respective officers, directors and underwriters. Both of these lawsuits have been consolidated into a single proceeding in the United States District Court for the Southern District of Texas. In general, these lawsuits allege that the various defendants violated securities laws by misleading investors regarding the integrity of PAA’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 PAA and PAGP, which they attribute to the alleged wrongful acts of the defendants. PAA and PAGP, and the other defendants, denied the allegations in, and moved to dismiss these lawsuits. On March 29, 2017, the Court ruled in our favor dismissing all claims against all defendants. Plaintiffs have refiled their complaint and we are opposing their claims. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we are indemnifying and funding the defense costs of our officers and directors in connection with these lawsuits; we are also indemnifying and funding the defense costs of our underwriters pursuant to the terms of the underwriting agreements we previously entered into with such underwriters.

In addition, ~~four~~4 unitholder derivative lawsuits have been filed by certain purported investors in PAA against ~~PAA,~~PAGP and certain of ~~its~~PAA’s affiliates, ~~and certain~~ officers and directors. ~~Two~~NaN lawsuit was filed in State District Court in Harris County, Texas and subsequently dismissed by the Court. NaN of these lawsuits were filed in the United States District Court for the Southern District of Texas and were administratively consolidated into one action and later dismissed on the basis that Plains Partnership agreements require that derivative suits be filed in Delaware Chancery Court.

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Following 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~~and subsequently dismissed without prejudice. Plaintiffs amended and refiled their complaint on June 3, 2019. All claims against the ~~various defendants breached their fiduciary duties, engaged in gross mismanagement~~officers and ~~made false and misleading statements, among other similar allegations, in connection with their management and oversight~~directors of PAA ~~during the period~~and all affiliates of ~~time leading up to and following the Line 901 release. The plaintiffs~~PAA, except PAGP, were dismissed with prejudice in the two remaining lawsuits claim that PAA suffered unspecified damages as a result of the actions of the various defendants and seek to hold the defendants liable for such damages, in addition to other remedies. The defendants deny the allegations in these lawsuits and have responded accordingly.January 2020. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we ~~are indemnifying~~have indemnified and ~~funding~~funded the defense costs of our officers and directors in connection with these lawsuits. We will vigorously defend the remaining derivative claim against PAGP.

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

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,~~Act. In this regard, following the Line 901 incident, we entered into a cooperative Natural Resource Damage Assessment (“NRDA”) process with the following federal and ~~we also have exposure~~state agencies designated or authorized by law to act as trustees for the natural resources of the United States and the State of California (collectively, the “Trustees”): the United States Department of Interior, the National Oceanic and Atmospheric Administration, CDFW, the California Department of Parks and Recreation, the California State Lands Commission, and the Regents of the University of California. As part of the NRDA process, PAA and the Trustees jointly and independently planned and conducted a number of natural resource assessment activities related to the ~~payment~~Line 901 incident. On March 13, 2020, the United States and the People of ~~additional fines,~~the State of California filed a civil complaint against Plains All American Pipeline, L.P. and Plains Pipeline L.P. along with a pre-negotiated settlement agreement in the form of a Consent Decree (the “Consent Decree”). The Consent Decree, which was pre-negotiated and signed by DOJ, PHMSA, EPA, CDFW, California Department of Parks and Recreation, California State Lands Commission, Office of the State Fire Marshal, Central Coast Regional Water Quality Control Board, and Regents of the University of California, will, if entered by the court, settle all of the claims asserted in the lawsuit. The Consent Decree would require Plains to pay $24 million in civil penalties and ~~costs under other applicable federal, state~~implement certain agreed-upon injunctive relief, and ~~local laws, statutes~~pay $22.325 million as compensation for injuries to, destruction of, loss of, or loss of use of natural resources resulting from the Line 901 incident. The Consent Decree is subject to a public notice and ~~regulations. To~~comment period that is set to expire on May 20, 2020, and review and approval by the ~~extent any such costs are reasonably estimable, we~~Federal District Court for the Central District of California. We have included ~~an estimate of such~~the costs associated with the Consent Decree settlement in the loss accrual described below.

Taking the foregoing into account, as of ~~September 30, 2017,~~March 31, 2020, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately ~~$300~~$400 million, which estimate includes actual and projected emergency response and clean-up costs, natural resource damage assessments and certain third party claims settlements, as well as estimates for fines, penalties and certain legal fees. We ~~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~~or reasonably estimable and (iv) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. Our estimate does not include any lost revenue associated with the shutdown of Line 901 or 903 and does not include any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, the amount of time it takes for us to resolve all of the current and future lawsuits, claims and investigations that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated. In addition, with respect to fines and penalties, the ultimate amount of any fines and penalties assessed against us depends on a wide variety of factors, many of which are not estimable at this time. Where fines and penalties are probable and estimable, we have included them in our estimate, although such estimates could turn out to be wrong. Accordingly, our assumptions and estimates may turn out to be inaccurate and our total costs could turn out to be materially higher; therefore, we can provide no assurance that we will not have to accrue significant additional costs in the future with respect to the Line 901 incident.

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As of ~~September 30, 2017,~~March 31, 2020, we had a remaining undiscounted gross liability of ~~$64~~$90 million related to this event, of which approximately ~~$36~~$80 million is presented ~~as a~~in “Other current ~~liability in “Accounts payable and accrued~~ liabilities” on our Condensed Consolidated Balance Sheet, with the remainder presented in “Other long-term liabilities and deferred ~~credits”.~~credits.” We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such environmental liabilities. Subject to such exclusions and deductibles, we believe that our coverage is adequate to cover the current estimated total emergency response and clean-up costs, claims settlement costs and remediation costs and we believe that this coverage is also adequate to cover any potential increase in the estimates for these costs that exceed the amounts currently identified. Through ~~September 30, 2017,~~March 31, 2020, we had collected, subject to customary reservations, ~~$166~~$203 million out of the approximate ~~$205~~$275 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of ~~September 30, 2017,~~March 31, 2020, we have recognized a receivable of approximately ~~$39~~$72 million for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected. Of this amount, approximately ~~$18~~$63 million is recognized as a current asset in “Trade accounts receivable and other receivables, ~~net��~~net” on our Condensed Consolidated Balance Sheet, with the remainder in “Other long-term assets, ~~net”.~~net.” We have completed the required clean-up and remediation work as determined by the Unified Command and the Unified Command has been dissolved; however, we expect to make payments for additional costs associated with restoration of the impacted areas, as well as natural resource damage assessment and compensation, legal, professional and regulatory costs, in addition to fines and penalties, during future periods.

Note 13—Operating Segments

We manage our operations through ~~three~~3 operating segments: Transportation, Facilities and Supply and Logistics. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2019 Annual Report on Form 10-K for a summary of the types of products and services from which each segment derives its revenues. Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including ~~segment adjusted~~Segment Adjusted EBITDA (as defined below) and maintenance capital investment.

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 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) 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 related to

investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance.

Segment ~~adjusted~~Adjusted EBITDA excludes depreciation and amortization.

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

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


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

														Transportation		Facilities		Supply and Logistics		Intersegment Adjustment		Total
Three Months Ended March 31, 2020													Three Months Ended March 31, 2020
Revenues:													Revenues:
External customers ⁽¹⁾	$	274	$	140	$	5,573		$	(114	)	$	5,873	External customers ⁽¹⁾	$	297	$	175	$	7,907	$	(110)	$	8,269
Intersegment ⁽²⁾	172		151		1			114			438		Intersegment ⁽²⁾	282		138		1		110		531
Total revenues of reportable segments	$	446	$	291	$	5,574		$	—		$	6,311	Total revenues of reportable segments	$	579	$	313	$	7,908	$	—	$	8,800
Equity earnings in unconsolidated entities	$	80	$	—	$	—					$	80	Equity earnings in unconsolidated entities	$	108	$	2	$	—			$	110
Segment adjusted EBITDA	$	363	$	182	$	(56	)				$	489
Segment Adjusted EBITDA													Segment Adjusted EBITDA	$	442	$	210	$	141			$	793
Maintenance capital	$	32	$	28	$	3					$	63	Maintenance capital	$	34	$	14	$	3			$	51

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

As of March 31, 2020													As of March 31, 2020
Total assets													Total assets	$	14,461	$	6,416	$	4,289			$	25,166
As of December 31, 2019													As of December 31, 2019
Total assets													Total assets	$	15,549	$	7,593	$	6,827			$	29,969

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

⁽¹⁾

⁽¹⁾Transportation revenues from External customers include certain inventory exchanges with our customers where our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2019 Annual Report on Form 10-K for a discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenues from External customers presented above and adjusted those revenues out such that Total revenues from External customers reconciles to our Condensed Consolidated Statements of Operations. This presentation is consistent with the information provided to our CODM.

⁽²⁾Segment revenues include intersegment amounts that are eliminated in Purchases and related costs and Field operating costs in our Condensed Consolidated Statements of Operations. Intersegment activities are conducted at posted tariff rates where applicable, or otherwise at rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated.

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PLAINS GP HOLDINGS, L.P. AND SUBSIDIARIES

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 income~~Net income/(loss) attributable to PAGP (in millions):


														Three Months Ended March 31,
	Three Months Ended September 30,						Nine Months Ended September 30,							2020		2019
	2017			2016			2017			2016
Segment adjusted EBITDA	$	489		$	462		$	1,451		$	1,568
Segment Adjusted EBITDA													Segment Adjusted EBITDA	$	793	$	861
Adjustments ⁽¹⁾:													Adjustments ⁽¹⁾:
Depreciation and amortization of unconsolidated entities ⁽²⁾	(13		)	(13		)	(31		)	(38		)	Depreciation and amortization of unconsolidated entities ⁽²⁾	(17)		(12)
Gains/(losses) from derivative activities net of inventory valuation adjustments ⁽³⁾	(216		)	52			86			(189		)
Gains/(losses) from derivative activities, net of inventory valuation adjustments ⁽³⁾													Gains/(losses) from derivative activities, net of inventory valuation adjustments ⁽³⁾	(30)		74
Long-term inventory costing adjustments ⁽⁴⁾	16			(38		)	2			6			Long-term inventory costing adjustments ⁽⁴⁾	(115)		21
Deficiencies under minimum volume commitments, net ⁽⁵⁾	(8		)	(25		)	(5		)	(59		)	Deficiencies under minimum volume commitments, net ⁽⁵⁾	2		7
Equity-indexed compensation expense ⁽⁶⁾	(7		)	(8		)	(18		)	(23		)	Equity-indexed compensation expense ⁽⁶⁾	(4)		(3)
Net gain/(loss) on foreign currency revaluation ⁽⁷⁾	14			(2		)	27			(4		)	Net gain/(loss) on foreign currency revaluation ⁽⁷⁾	13		(5)
Line 901 incident ⁽⁸⁾	—			—			(12		)	—
Significant acquisition-related expenses ⁽⁹⁾	—			—			(6		)	—

Significant acquisition-related expenses ⁽⁸⁾													Significant acquisition-related expenses ⁽⁸⁾	(3)		—
Unallocated general and administrative expenses	—			(1		)	(3		)	(2		)	Unallocated general and administrative expenses	(1)		(1)
Depreciation and amortization	(152		)	(33		)	(403		)	(352		)	Depreciation and amortization	(169)		(136)
Gains/(losses) on asset sales and asset impairments, net													Gains/(losses) on asset sales and asset impairments, net	(619)		(4)
Goodwill impairment losses													Goodwill impairment losses	(2,515)		—
Gain on/(impairment of) investments in unconsolidated entities, net													Gain on/(impairment of) investments in unconsolidated entities, net	(22)		267
Interest expense, net	(134		)	(116		)	(390		)	(349		)	Interest expense, net	(108)		(101)
Other income/(expense), net	(1		)	17			(6		)	46			Other income/(expense), net	(31)		25
Income/(loss) before tax	(12		)	295			692			604			Income/(loss) before tax	(2,826)		993
Income tax benefit/(expense)	43			(16		)	(85		)	(66		)
Net income	31			279			607			538
Net income attributable to noncontrolling interests	(27		)	(255		)	(538		)	(436		)
Net income attributable to PAGP	$	4		$	24		$	69		$	102
Income tax (expense)/benefit													Income tax (expense)/benefit	134		(79)
Net income/(loss)													Net income/(loss)	(2,692)		914
Net (income)/loss attributable to noncontrolling interests													Net (income)/loss attributable to noncontrolling interests	2,111		(767)
Net income/(loss) attributable to PAGP													Net income/(loss) attributable to PAGP	$	(581)	$	147

Table of the income tax provision for the period in which the law is enacted to change current or future tax rates. A reduction in the corporate federal income tax rate to 20%, as currently proposed, would result in a write-off of a portion of the deferred tax asset through income tax expense in the period the legislation is enacted.Contents

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

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 activity 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 in the fourth quarter of this year and during 2018. The increased production levels should continue 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 levels 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 compression as well, substantially driven by increased competition 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 PAA’s Business” discussed in Item 1A of our 2016 Annual Report on Form 10‑K.

Outlook for Certain ~~Idled and Underutilized Assets~~Investments in Unconsolidated Entities

~~During 2015,~~As of March 31, 2020, we ~~shut down Line 901 and~~owned 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%~~50% undivided joint interest in Red Oak Pipeline LLC (“Red Oak”), which was in the ~~Capline Pipeline (“Capline”) system, which originates in St. James, Louisiana and terminates in Patoka, Illinois. We anticipate the construction~~process of developing a new pipeline that would provide crude oil ~~pipeline infrastructure~~transportation service from Cushing, Oklahoma, and the ~~ongoing changing crude oil flows~~Permian Basin in West Texas to multiple destinations along the ~~United States may result in a decline in volumes~~Texas Gulf Coast, including Corpus Christi, Ingleside, Houston and Beaumont, Texas. In March 2020, the partners announced they were deferring the Red Oak pipeline project and suspending actions that would require additional capital spending on the ~~Capline system in future years to levels~~project, and that ~~cannot sustain operations. The owners of the Capline system are considering various alternatives~~they would re-evaluate demand for the ~~use~~project in light of recent market developments. If the partners decide not to move forward with the pipeline system, including an assessment 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 orproject, we may recognize an impairment of the carrying value of our interest in ~~the Capline system,~~Red Oak, which was ~~$196~~$54 million as of ~~September 30, 2017.~~March 31, 2020 ($122 million including our estimate of committed costs incurred in the second quarter).

Liquidity and Capital Resources

General

On a consolidated basis, our primary sources of liquidity are (i) cash flow from operating activities, (ii) borrowings under ~~PAA's~~PAA’s credit facilities or the PAA commercial paper program and (iii) funds received from sales of equity and debt securities. In addition, we may supplement these sources of liquidity with proceeds from our ~~non-core asset sales~~divestiture program, as further discussed below in the section entitled “—Acquisitions ~~Investments, Expansion~~and Capital ~~Expenditures and Divestitures.~~Expenditures.” Our primary cash requirements include, but are not limited to, (i) ordinary course of business uses, such as the payment of amounts related to the purchase of crude oil, NGL and other products, ~~and~~ other expenses and interest payments on outstanding debt, (ii) expansion and maintenance activities, (iii) acquisitions of assets or businesses, (iv) repayment of principal on long-term debt and (v) distributions to our Class A shareholders and noncontrolling interests. We generally expect to fund our short-term cash requirements through cash flow generated from operating activities and/or borrowings under the PAA

commercial paper program or ~~PAA's~~PAA’s credit facilities. In addition, we generally expect to fund our long-term needs, such as those resulting from expansion activities or acquisitions and refinancing long-term debt, through a variety of sources (either separately or in combination), which may include the sources mentioned above as funding for short-term needs and/or the issuance of additional equity or debt securities and the sale of ~~non-core~~ assets.

As of ~~September 30, 2017,~~March 31, 2020, although we had a working capital deficit of ~~less than $1~~$286 million, ~~and~~we had approximately $2.5 billion of liquidity available to meet our ongoing operating, investing and financing needs, subject to continued covenant compliance, as noted below (in millions):

As of
September 30, 2017
Availability under PAA senior unsecured revolving credit facility ^(1) (2)
$ 1,584
Availability under PAA senior secured hedged inventory facility ^(1) (2)
568
Availability under PAA senior unsecured 364-day revolving credit facility 1,000
Amounts outstanding under PAA commercial paper program (698 )
Subtotal 2,454
Cash and cash equivalents 36
Total $ 2,490


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

	As of March 31, 2020
⁽²⁾		~~Available capacity was reduced by outstanding letters of credit of $95 million, comprised of $16 million~~Availability under ~~the~~ PAA senior unsecured revolving credit facility ~~and $79 million~~^(1) (2)	$	1,583
Availability under ~~the~~ PAA senior secured hedged inventory ~~facility.~~facility ^(1) (2)		897

Subtotal		2,480
Cash and cash equivalents		40
Total		$	2,520

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

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

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Current macroeconomic and geopolitical conditions including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply has caused liquidity issues impacting many energy companies; however, we believe that we have, and will continue to have, the ability to access the PAA 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; however, extended disruptions in the financial markets and/or energy price volatility that adversely affect our business may have a materially adverse effect on our financial condition, results of operations or cash flows. ~~Also, see Item 1A. “Risk Factors” of our 2016 Annual Report on Form 10-K for further discussion regarding such risks that may impact our liquidity and capital resources. Usage~~In addition, usage of the PAA credit facilities, which provide the financial backstop for the PAA commercial paper program, is subject to ongoing compliance with covenants. As of ~~September 30, 2017,~~March 31, 2020, PAA was in compliance with all such covenants. Also, see Item 1A. “Risk Factors” included in our 2019 Annual Report on Form 10-K and Item 1A. “Risk Factors” below in Part II of this Form 10-Q for further discussion regarding such risks that may impact our liquidity and capital resources.

Cash Flow from Operating Activities

For a comprehensive discussion of the primary drivers of cash flow from operating activities, including the impact of varying market conditions and the timing of settlement of our derivatives, see Item 7. “Liquidity and Capital Resources—Cash Flow from Operating Activities” included in our ~~2016~~2019 Annual Report on Form 10-K.

Net cash provided by operating activities for the first ~~nine~~three months of ~~2017~~2020 and ~~2016~~2019 was ~~$1.915 billion~~$889 million and ~~$636~~$1,032 million, respectively, and primarily resulted from earnings from our operations.

~~Net cash provided by operating activities for the 2017 period was positively impacted by decreases~~ Additionally, as discussed further below, changes during these periods in ~~(i) the volume of crude oil~~our inventory ~~that we held~~levels and ~~(ii) the~~associated margin balances required as part of our hedging activities ~~both of which had been funded by short-term debt. This was consistent with~~impacted our ~~plan to reduce our hedged inventory volumes,~~cash flow from operating activities.

During the three months ended March 31, 2020 and ~~the cash inflows associated with these items resulted in a favorable impact on~~2019, our cash provided by operating ~~activities. However,~~activities was positively impacted by decreases in the volume of inventory that we held, primarily due to the sale of NGL and crude oil inventory. The favorable effects from the liquidation of such ~~activities~~inventory were partially offset by ~~higher weighted average prices and volumes for NGL inventory that was purchased and stored at~~ the ~~end~~timing of ~~the 2017 period in anticipation of the 2017-2018 heating season.~~

During the nine months ended September 30, 2016, we increased our inventory levels and margin balances required as part of our hedging activities that were funded by short-term debt, resulting in an unfavorable impact on our cash provided by operating activities.

~~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 inrevenue recognized during 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~~cash was received in ~~our Condensed Consolidated Financial Statements as we had not yet billed or collected such amounts.~~prior periods.

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

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

~~Acquisitions. During the nine months ended September 30, 2017~~Acquisitions. In February 2020, we acquired a crude oil gathering system and 2016, we paid cash 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 locatedrelated assets in the ~~Northern~~ Delaware Basin ~~in Southeastern New Mexico and West Texas.~~for approximately $300 million. See Note 614 to our Condensed Consolidated Financial Statements for additional information regarding the ACC Acquisition. The ACC Acquisition was initially funded through borrowings under PAA's senior unsecured revolving credit facility. Such borrowings were subsequently repaid with proceeds from PAA's March 2017 issuance of its common units to AAP pursuant to the Omnibus Agreement and in connection with our 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 PAA common units and approximately $26 million in cash.information.

CapitalProjects. We invested ~~approximately $893~~$352 million in midstream infrastructure during the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2020, and we expect to invest approximately ~~$1.050~~$1.1 billion during the full year ~~ended~~ending December 31, ~~2017.~~2020. Our expected capital investment for 2020 reflects a reduction from our expected capital investment at year-end 2019 due to the current dynamic and uncertain market conditions. See “—Acquisitions and Capital ~~Projects~~”Projects” for ~~detail of our projected capital expenditures for the year ending December 31, 2017. Our preliminary forecast for our 2018 expansion capital program is $700 million.~~

additional information. We ~~funded a majority of our 2017 capital program with proceeds from equity issuances during the first quarter of 2017, and we~~ expect to fund our ~~remaining 2017~~2020 capital program ~~and our 2018 program~~ with ~~proceeds from PAA's October 2017 Series B preferred unit offering,~~ retained cash flow, ~~and the sale~~proceeds from assets sold as part of ~~various non-core assets.~~

~~Divestitures. Our~~our divestiture program ~~includes~~or debt.

Divestitures. In January 2020, we entered into a definitive agreement to sell certain of our Los Angeles Basin crude oil terminals for $195 million, subject to certain adjustments and expect the ~~evaluation~~transaction to close in the second half of potential sales of non-core assets and/or sales of partial interests in assets to strategic joint venture partners to optimize our asset portfolio and strengthen our balance sheet and leverage metrics. 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 2017,2020. In April 2020, we sold ~~our interests in~~ certain ~~non-core pipelines in the Rocky Mountain, Bakken and Mid-Continent regions~~NGL terminals for ~~aggregate proceeds of approximately $385 million.~~$163 million, subject to certain adjustments. See Note 614 to our Condensed Consolidated Financial Statements for additional ~~information regarding these~~information. Additionally, we sold a 10% ownership interest in Saddlehorn Pipeline Company, LLC for proceeds of approximately $78 million. See Note 7 to our Condensed Consolidated Financial Statements for additional information.

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Ongoing Acquisition, Divestiture and Investment Activities. We intend to continue to focus on activities to enhance investment returns and reinforce capital discipline through asset ~~sales~~optimization, joint ventures, potential divestitures and ~~divestitures.~~

~~During the third quarter of 2017,~~similar arrangements. We typically do not announce a transaction until after we have executed a definitive agreement. However, in certain 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 may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future acquisition or investment efforts will be successful, or that our strategic asset divestitures will be completed. Although we expect the acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized. Also, see Item 1A. “Risk Factors—Risks Related to PAA’s Business” of our 2019 Annual Report on Form 10-K for ~~the potential sale of terminal assets located in Northern California was jointly terminated by us~~further discussion regarding risks related to our acquisitions 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.~~divestitures.

Equity and Debt Financing Activities

On a consolidated basis, our financing activities primarily relate to funding expansion capital projects, acquisitions and refinancing of 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, PAA senior notes offerings and borrowings and repayments under the credit facilities or the PAA commercial paper program and other debt agreements, as well as payment of distributions to our Class A shareholders and noncontrolling interests.

PAGP Registration Statements. We have filed with the SEC a ~~universal~~ shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to an aggregate of $1.0 billion of equity securities (the ~~“Traditional~~“PAGP 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,~~March 31, 2020, we had approximately $939 million of unsold securities available under the PAGP Traditional Shelf. ~~Additionally, in February 2017, we filed~~We also have access to a ~~universal~~ shelf registration statement (the ~~“WKSI~~“PAGP WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of equity securities, subject to market conditions and capital needs. ~~Our Underwritten Offering, discussed further below, was conducted~~We did not conduct any offerings under ~~our~~the PAGP Traditional Shelf or the PAGP WKSI ~~Shelf.~~

~~Sales of Class A Shares. The following table summarizes our sales of Class A shares~~Shelf during the ~~nine~~three months ended ~~September 30, 2017, all of which occurred in the first four months of the year (net proceeds in millions):~~March 31, 2020.

Type of Offering Class A Shares Issued
Net Proceeds ⁽¹⁾

Continuous Offering Program 1,786,326
$ 61
^{(2) (3)}
Underwritten Offering 48,300,000
1,474
⁽³⁾
50,086,326
$ 1,535


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


⁽²⁾	We pay commissions to our sales agents in connection with issuances of Class A shares 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 in conjunction with the Simplification Transactions, we used the net proceeds from the sale of our 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. Also pursuant to the Omnibus Agreement, immediately following such purchase and sale, AAP used the net proceeds it received from such sale of AAP units to us to purchase from PAA an equivalent number of common units of PAA. See “—Subsidiary Sales of Common Units” below.

PAA Registration Statements. PAA periodically accesses the capital markets for both equity and debt financing. PAA has filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows PAA to issue up to an aggregate of ~~$2.0~~$1.1 billion of debt or equity securities (the “PAA Traditional Shelf”). ~~All issuances of PAA equity securities associated with PAA's Continuous Offering Program have been issued pursuant to the PAA Traditional Shelf.~~ At ~~September 30, 2017,~~March 31, 2020, PAA had approximately $1.1 billion of unsold securities available under the PAA Traditional Shelf. PAA also has access to a universal shelf registration statement (the “PAA WKSI Shelf”), which provides it with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and capital needs. PAA did not conduct any offerings under the PAA Traditional Shelf or the PAA WKSI Shelf during the ~~nine~~three months ended ~~September 30, 2017; however, PAA's October 2017 Series B preferred unit offering was conducted under the PAA WKSI Shelf. See~~ ~~Note 9~~ ~~to our Condensed Consolidated Financial Statements for further discussion of PAA's Series B preferred unit offering.~~March 31, 2020.

~~PAA Continuous Offering Program.~~ During the nine months ended September 30, 2017, PAA issued an aggregate of approximately 4.0 million common units under its continuous offering program, generating proceeds of $129 million, net of $1 million of commissions paid to its sales agents.

~~PAA Unit Issuances Under Omnibus Agreement.~~ During the nine months ended September 30, 2017, pursuant to the Omnibus Agreement discussed above, PAA sold (i) approximately 1.8 million common units to AAP in connection with our issuance of Class A shares under our Continuous Offering Program and (ii) 48.3 million common units to AAP in connection with our underwritten offering.

~~Issuance of Series B Preferred Units.~~ On October 10, 2017, PAA issued 800,000 Series B preferred units at a price to the public of $1,000 per unit. PAA 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 its 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 PAA's Series B preferred unit offering.

Credit Agreements, Commercial Paper Program and Indentures. The ~~PAA~~ credit agreements for the PAA revolving credit facilities (which impact ~~the~~PAA’s ability to access the PAA commercial paper program because they provide the financial backstop that supports PAA’s short-term credit ratings) and its GO Zone term loans and the indentures governing ~~PAA’s~~its senior notes contain cross-default provisions. A default under ~~the~~PAA’s credit agreements or indentures would permit the lenders to accelerate the maturity of the outstanding debt. As long as PAA is in compliance with the provisions in ~~the~~its credit agreements, its ability to make distributions of available cash is not restricted. As of ~~September 30, 2017,~~March 31, 2020, PAA was in compliance with the covenants contained in ~~the~~its credit agreements and indentures.

PAA’s fixed-rate senior notes had a face value of approximately $9.0 billion at both March 31, 2020 and December 31, 2019. We estimated the aggregate fair value of these notes as of March 31, 2020 and December 31, 2019 to be approximately $7.2 billion and $9.3 billion, respectively. PAA’s fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. The decrease in the fair value of PAA’s fixed-rate senior notes is attributable to widening credit spreads in the secondary market for the debt of oil and gas industry participants in general, and the debt of PAA and many of its peers in the United States midstream sector specifically. This widening has occurred due to a number of external forces, such as the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply.

~~On a consolidated basis, during~~During the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2020, we had net repayments ~~under PAA's~~on PAA’s credit ~~facilities~~agreements and ~~PAA~~ commercial paper program of ~~$108~~$4 million. The net repayments resulted primarily from cash flow from operating activities and ~~cash received~~proceeds from ~~equity activities,~~

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asset sales, which offset borrowings during the period related to funding needs for ~~(i) acquisition and~~ capital investments, ~~(ii) repayment of PAA's $400 million, 6.13% senior notes in January 2017~~inventory purchases and ~~(iii)~~ other general partnership purposes.

~~During~~As of March 31, 2019 and December 31, 2018, we had no outstanding borrowings under PAA’s credit agreements or commercial paper program. However, during the ~~nine~~three months ended ~~September 30, 2016,~~March 31, 2019, we ~~had net repayments~~borrowed and repaid $0.5 billion under ~~the credit facilities and the PAA~~PAA’s commercial paper ~~program of $149 million.~~program. 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 PAA's $175 million senior notes in August 2016 and (iv) other general partnership purposes.activities.

In August 2017, PAA extended the maturity dates of its 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 PAA 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 PAA's action plan announced on August 25, 2017, PAA intends to reduce its 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, PAA intends to redeem a total of $950 million of senior notes before year end 2017, which are its two nearest maturities and among the most expensive of its senior note issues and are comprised of (i) PAA's $600 million of 6.50% senior notes maturing in May 2018 and (ii) PAA's $350 million of 8.75% senior notes maturing in May 2019.

Distributions to Our Class A Shareholders ~~and Noncontrolling Interests~~

Distributions to our Class A shareholders. We distribute all of our available cash within 55 days following the end of each quarter to Class A shareholders of record. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. Our levels of financial reserves are established by our general partner and include reserves for the proper conduct of our business (including future capital expenditures and anticipated credit needs), compliance with law or contractual obligations and funding of future distributions to our shareholders. On ~~November 14, 2017,~~May 15, 2020, we will pay a quarterly distribution of ~~$0.30~~$0.18 per Class A share ($~~1.20~~0.72 per Class A share on an annualized basis), which equates to a reduction of ~~approximately 45%~~50% compared to the quarterly distribution of ~~$0.55~~$0.36 per Class A share ($~~2.20~~1.44 per Class A share on an annualized basis) paid in August 2017. The amount of cash available to distribute to our Class A shareholders is completely dependent upon the amount of cash distributed by PAA to AAP in respect of its common units; therefore, any change in the distribution level on PAA's common units will have a corresponding impact on the distribution level on our Class A shares.February 2020. This reduction ~~is part of PAA's plan~~was made in response to ~~adopt~~the current dynamic and uncertain market conditions to further reinforce our commitment to maintaining a ~~distribution approach underpinned by fee-based business activities, to reduce its leverage thereby improving its credit metrics~~solid capital structure and ~~to position itself for future distribution growth. Cash retained will be used to reduce indebtedness.~~strong liquidity. See “—Executive ~~Summary—Overview of Operating Results, Capital Investments and Other Significant Activities”~~Summary—Recent Events & Outlook” for further discussion. See Note 9 to our Condensed Consolidated Financial Statements for details of distributions paid during or pertaining to the first ~~nine~~three months of ~~2017.~~2020. Also, see Item 5. “Market for Registrant’s Shares, Related Shareholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy” included in our ~~2016~~2019 Annual Report on Form 10-K for additional discussion regarding distributions.

Distributions to ~~noncontrolling interests.~~Noncontrolling Interests

Distributions to noncontrolling interests represent amounts paid on interests in consolidated entities that are not owned by us. ~~During~~As of March 31, 2020, noncontrolling interests in our subsidiaries consisted of (i) limited partner interests in PAA including a 69% interest in PAA’s common units and PAA’s Series A preferred units combined and 100% of PAA’s Series B preferred units, (ii) an approximate 25% limited partner interest in AAP and (iii) a 33% interest in Red River LLC. See Note 9 to our Condensed Consolidated Financial Statements for additional information.

Distributions to PAA’s Series A preferred unitholders. On May 15, 2020, PAA will pay a cash distribution of $37 million ($0.525 per unit) on its Series A preferred units outstanding as of May 1, 2020, the ~~nine~~record date for such distribution for the period from January 1, 2020 through March 31, 2020. See Note 9 to our Condensed Consolidated Financial Statements for details of distributions made during or pertaining to the first three months ~~ended September 30, 2017~~of 2020.

Distributions to PAA’s Series B preferred unitholders. Distributions on PAA’s Series B preferred units are payable in cash semi-annually in arrears on the 15th day of May and ~~2016, we~~November. On May 15, 2020, PAA will pay the semi-annual cash distribution of $24.5 million on the Series B preferred units to holders of record at the close of business on May 1, 2020 for the period from November 15, 2019 to May 14, 2020. See Note 9 to our Condensed Consolidated Financial Statements for additional information.

Distributions to PAA’s common unitholders. On May 15, 2020, PAA will pay a quarterly distribution of $0.18 per common unit ($0.72 per common unit on an annualized basis) on its common units outstanding as of May 1, 2020, the record date for such distribution for the period from January 1, 2020 through March 31, 2020. See Note 9 to our Condensed Consolidated Financial Statements for details of distributions paid ~~distributions~~during or pertaining to the first three months of ~~approximately $945 million and $1.112 billion, respectively, to noncontrolling interests.~~2020.

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

Contingencies

For a discussion of contingencies that may impact us, see Note 12 to our Condensed Consolidated Financial Statements.

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Commitments

Contractual Obligations. In the ordinary course of doing business, we purchase crude oil and NGL from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years, with a limited number of contracts with remaining terms extending up to ~~approximately ten~~13 years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. The table below includes purchase obligations related to these activities. Where applicable, the amounts presented represent the net obligations associated with our counterparties (including giving effect to netting buy/sell contracts and those subject to a net settlement arrangement). We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy or who have provided credit support we consider adequate.

The following table includes our best estimate of the amount and timing of these payments as well as ~~others~~other amounts due under the specified contractual obligations as of ~~September 30, 2017~~March 31, 2020 (in millions):


																Remainder of 2020		2021		2022		2023		2024		2025 and Thereafter		Total
	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
Long-term debt and related interest payments ⁽¹⁾															Long-term debt and related interest payments ⁽¹⁾	$	311	$	1,026	$	1,312	$	1,636	$	1,055	$	8,753	$	14,093
Leases ⁽²⁾															Leases ⁽²⁾	97		99		93		70		58		305		722
Other obligations ⁽³⁾	105		230		168		136		132		564		1,335		Other obligations ⁽³⁾	619		477		301		304		279		1,189		3,169
Subtotal	878		1,457		1,582		1,126		1,175		12,053		18,271		Subtotal	1,027		1,602		1,706		2,010		1,392		10,247		17,984
Crude oil, NGL and other purchases ⁽⁴⁾	2,688		4,682		3,950		3,236		2,968		9,224		26,748		Crude oil, NGL and other purchases ⁽⁴⁾	5,830		6,440		6,182		5,849		5,454		14,024		43,779
Total	$	3,566	$	6,139	$	5,532	$	4,362	$	4,143	$	21,277	$	45,019	Total	$	6,857	$	8,042	$	7,888	$	7,859	$	6,846	$	24,271	$	61,763



Delaware		90-1005472
(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
Class A Shares	PAGP	New York Stock Exchange



		Page
PART I. FINANCIAL INFORMATION
Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
Condensed Consolidated Balance Sheets: As of ~~September 30, 2017~~March 31 , 20 20 and December 31, ~~2016~~201 9		3
Condensed Consolidated Statements of Operations: For the three m onths ended March 31 , 20 20 and ~~nine months ended September 30, 2017 and 2016~~20 19		4
Condensed Consolidated Statements of Comprehensive ~~Income:~~Income /(Loss): For the three ~~and nine~~ months ended ~~September 30, 2017~~March 31 , 20 20 and ~~2016~~201 9		5
Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income/(Loss): For the ~~nine~~three months ended ~~September 30, 2017~~March 31 , 20 20 and ~~2016~~201 9		5
Condensed Consolidated Statements of Cash Flows: For the ~~nine~~ three months ended ~~September 30, 2017~~March 31 , 20 20 and ~~2016~~201 9		6
Condensed Consolidated Statements of Changes in Partners’ Capital: For the ~~nine~~ three months ended ~~September 30, 2017~~March 31 , 20 20 and ~~2016~~201 9		7
Notes to the Condensed Consolidated Financial Statements:
1. Organization and Basis of Consolidation and Presentation		8
2. ~~Recent~~Summary of Significant Accounting ~~Pronouncements~~Policies		1110
3. Revenues and Accounts Receivable		11
4. Net Income /(Loss) Per Class A Share		1314
~~4. Accounts Receivable, Net~~		14
5. Inventory, Linefill and Base Gas and Long-term Inventory	1416
6. ~~Acquisitions and Dispositions~~Goodwill		1517
7. ~~Goodwill~~Investments in Unconsolidated Entities		18
8. Debt		1819
9. Partners’ Capital and Distributions		20
10. Derivatives and Risk Management Activities		2422
11. Related Party Transactions		3227
12. Commitments and Contingencies		3228
13. Operating Segments		33
14. Acquisitions, Divestitures and Asset Impairments		36

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		4038
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		6561
Item 4. CONTROLS AND PROCEDURES		6763

PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS		6864
Item 1A. RISK FACTORS		6864
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		6866
Item 3. DEFAULTS UPON SENIOR SECURITIES		6866
Item 4. MINE SAFETY DISCLOSURES		6866
Item 5. OTHER INFORMATION		6866
Item 6. EXHIBITS		6867
SIGNATURES		6970


	September 30, 2017			December 31, 2016				March 31, 2020		December 31, 2019
	(unaudited)							(unaudited)
ASSETS							ASSETS

CURRENT ASSETS							CURRENT ASSETS
Cash and cash equivalents	$	36		$	50		Cash and cash equivalents	$	40	$	47
Restricted cash							Restricted cash	122		37
Trade accounts receivable and other receivables, net	2,287			2,279			Trade accounts receivable and other receivables, net	2,200		3,614
Inventory	884			1,343			Inventory	181		604
Other current assets	811			603			Other current assets	530		312
Total current assets	4,018			4,275			Total current assets	3,073		4,614

PROPERTY AND EQUIPMENT	16,906			16,261			PROPERTY AND EQUIPMENT	17,962		18,983
Accumulated depreciation	(2,621		)	(2,371		)	Accumulated depreciation	(3,549)		(3,616)
Property and equipment, net	14,285			13,890			Property and equipment, net	14,413		15,367

OTHER ASSETS							OTHER ASSETS
Investments in unconsolidated entities							Investments in unconsolidated entities	3,714		3,683
Goodwill	2,598			2,344			Goodwill	—		2,540
Investments in unconsolidated entities	2,671			2,343
Deferred tax asset	2,210			1,876			Deferred tax asset	1,455		1,280
Linefill and base gas	884			896			Linefill and base gas	955		981
Long-term operating lease right-of-use assets, net							Long-term operating lease right-of-use assets, net	430		466
Long-term inventory	135			193			Long-term inventory	73		182
Other long-term assets, net	909			286			Other long-term assets, net	1,053		856
Total assets	$	27,710		$	26,103		Total assets	$	25,166	$	29,969

LIABILITIES AND PARTNERS’ CAPITAL							LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES							CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	2,715		$	2,590
Trade accounts payable							Trade accounts payable	$	2,246	$	3,687
Short-term debt	918			1,715			Short-term debt	363		504
Other current liabilities	385			361			Other current liabilities	750		828
Total current liabilities	4,018			4,666			Total current liabilities	3,359		5,019

LONG-TERM LIABILITIES							LONG-TERM LIABILITIES
Senior notes, net of unamortized discounts and debt issuance costs	9,881			9,874
Other long-term debt	608			250
Senior notes, net							Senior notes, net	8,941		8,939
Other long-term debt, net							Other long-term debt, net	477		248
Long-term operating lease liabilities							Long-term operating lease liabilities	370		387
Other long-term liabilities and deferred credits	698			606			Other long-term liabilities and deferred credits	833		891
Total long-term liabilities	11,187			10,730			Total long-term liabilities	10,621		10,465

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

PARTNERS’ CAPITAL							PARTNERS’ CAPITAL
Class A Shareholders (154,543,193 and 101,206,526 shares outstanding, respectively)	2,528			1,737
Class A shareholders (184,240,079 and 182,138,592 shares outstanding, respectively)							Class A shareholders (184,240,079 and 182,138,592 shares outstanding, respectively)	1,457		2,155
Noncontrolling interests	9,977			8,970			Noncontrolling interests	9,729		12,330
Total partners’ capital	12,505			10,707			Total partners’ capital	11,186		14,485
Total liabilities and partners’ capital	$	27,710		$	26,103		Total liabilities and partners’ capital	$	25,166	$	29,969


	Derivative Instruments		Translation Adjustments		Other		Total
	(unaudited)
Balance at December 31, 2019	$	(259)	$	(674)	$	—	$	(933)

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


	Class A Shareholders		Noncontrolling Interests		Total Partners’ Capital
	(unaudited)
Balance at December 31, 2019	$	2,155	$	12,330	$	14,485
Net loss	(581)		(2,111)		(2,692)
Distributions (Note 9)	(66)		(245)		(311)
Deferred tax asset	20		—		20


Other comprehensive loss	(82)		(245)		(327)
Change in ownership interest in connection with Exchange Right exercises (Note 9)	10		(10)		—


Contributions from noncontrolling interests (Note 9)	—		8		8
Other	1		2		3
Balance at March 31, 2020	$	1,457	$	9,729	$	11,186














	Class A Shareholders		Noncontrolling Interests		Total Partners’ Capital
	(unaudited)
Balance at December 31, 2018	$	1,846	$	11,473	$	13,319


Net income	147		767		914
Distributions	(48)		(219)		(267)
Deferred tax asset	(3)		—		(3)
Other comprehensive income	13		45		58


Other	—		1		1
Balance at March 31, 2019	$	1,955	$	12,067	$	14,022



	Class A Shareholders			Noncontrolling Interests			Total Partners’ Capital
	(unaudited)
Balance at December 31, 2016	$	1,737		$	8,970		$	10,707
Net income	69			538			607
Cash distributions to partners	(225		)	(945		)	(1,170		)
Deferred tax asset (Note 9)	390			—			390
Sales of Class A shares (Note 9)	462			1,073			1,535
Sales of common units by a subsidiary (Note 9)	13			116			129
Issuance of common units by a subsidiary for acquisition of interest in Advantage Joint Venture (Note 6)	5			35			40
Other comprehensive income	52			204			256
Other	25			(14		)	11
Balance at September 30, 2017	$	2,528		$	9,977		$	12,505



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



	Class A Shares	Class B Shares
Outstanding at December 31, 2015	86,099,037	141,485,588
Conversion of AAP Management Units ⁽¹⁾	—	13,567,916
Exchange Right exercises ⁽¹⁾	14,665,076	(14,665,076	)
Issuance of Class A shares under LTIP	7,811	—
Outstanding at September 30, 2016	100,771,924	140,388,428



Type of Offering	Class A Shares Issued	Net Proceeds ⁽¹⁾
Continuous Offering Program	1,786,326	$	61	⁽²⁾
Underwritten Offering	48,300,000	1,474
	50,086,326	$	1,535



	Distribution to AAP's Partners
Distribution Payment Date	Noncontrolling Interests		PAGP		Total Cash Distributions
November 14, 2017⁽¹⁾	$	40	$	46	$	86
August 14, 2017	$	75	$	84	$	159
May 15, 2017	$	75	$	84	$	159
February 14, 2017	$	77	$	57	$	134



	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	)


⁽¹⁾	~~Represents adjustments utilized by our CODM in 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.~~


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


⁽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.



Projects				~~2017~~2020
~~Diamond~~Long-haul Pipeline ⁽¹⁾ Projects				$~~300~~	220
Permian Basin ~~Area Systems~~Takeaway Pipeline Projects				~~235~~355
~~Fort Saskatchewan Facility~~Complementary Permian Basin Projects				75225
~~STACK~~Selected Facilities/Downstream Projects⁽¹⁾				55160
~~Cushing Terminal Expansions~~Other Projects				40140
~~Corpus Christi JV Dock~~ ⁽¹⁾		30
~~St. James Terminal Projects~~	10
~~Other Projects~~	~~305~~
Total Projected ~~2017~~2020 Expansion Capital Expenditures		$~~1,050~~	1,100


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



	Three Months Ended September 30,						Variance					Nine Months Ended September 30,						Variance
	2017			2016			$			%		2017			2016			$			%
Transportation segment adjusted EBITDA ⁽¹⁾	$	363		$	308		$	55		18	%	$	933		$	863		$	70		8	%
Facilities segment adjusted EBITDA ⁽¹⁾	182			171			11			6	%	550			497			53			11	%
Supply and Logistics segment adjusted EBITDA ⁽¹⁾	(56		)	(17		)	(39		)	(229	)%	(32		)	208			(240		)	(115	)%
Adjustments:
Depreciation and amortization of unconsolidated entities	(13		)	(13		)	—			—	%	(31		)	(38		)	7			18	%
Selected items impacting comparability - segment adjusted EBITDA	(201		)	(21		)	(180		)	**		74			(269		)	343			**
Unallocated general and administrative expenses	—			(1		)	1			100	%	(3		)	(2		)	(1		)	(50	)%
Depreciation and amortization	(152		)	(33		)	(119		)	(361	)%	(403		)	(352		)	(51		)	(14	)%
Interest expense, net	(134		)	(116		)	(18		)	(16	)%	(390		)	(349		)	(41		)	(12	)%
Other income/(expense), net	(1		)	17			(18		)	(106	)%	(6		)	46			(52		)	(113	)%
Income tax benefit/(expense)	43			(16		)	59			369	%	(85		)	(66		)	(19		)	(29	)%
Net income	31			279			(248		)	(89	)%	607			538			69			13	%
Net income attributable to noncontrolling interests	(27		)	(255		)	228			89	%	(538		)	(436		)	(102		)	(23	)%
Net income attributable to PAGP	$	4		$	24		$	(20	)	(83	)%	$	69		$	102		$	(33	)	(32	)%

Basic net income per Class A share ⁽²⁾	$	0.03		$	0.24		$	(0.21	)	(88	)%	$	0.49		$	1.03		$	(0.54	)	(52	)%
Diluted net income per Class A share ⁽²⁾	$	0.03		$	0.24		$	(0.21	)	(88	)%	$	0.49		$	1.02		$	(0.53	)	(52	)%
Basic weighted average Class A shares outstanding ⁽²⁾	154			101			53			52	%	142			99			43			43	%
Diluted weighted average Class A shares outstanding ⁽²⁾	154			101			53			52	%	142			236			(94		)	(40	)%


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


⁽²⁾	~~The share and per-share amounts for the 2016 period have been retroactively adjusted to reflect the effect of the reverse split that was effected as part of the Simplification Transactions. See~~ ~~Note 1~~ ~~to our Condensed Consolidated Financial Statements for additional discussion of the Simplification Transactions.~~


⁽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 amortization expense and gains or losses on significant asset sales of such unconsolidated entities when reviewing Adjusted EBITDA, similar to our consolidated assets.


⁽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.~~



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	)%