Plains GP (PAGP) 10-Q 8 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 31, 2018
Document and Entity Information
Entity Registrant Name	PLAINS GP HOLDINGS LP
Entity Central Index Key	1,581,990
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Emerging Growth Company	false
Small Business Entity	false
Entity Common Stock, Shares Outstanding (shares)		159,160,785
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
CURRENT ASSETS
Cash and cash equivalents	$ 33	$ 40
Trade accounts receivable and other receivables, net	2,954	3,029
Inventory	824	713
Other current assets	320	221
Total current assets	4,131	4,003
PROPERTY AND EQUIPMENT	17,751	16,901
Accumulated depreciation	(3,059)	(2,796)
Property and equipment, net	14,692	14,105
OTHER ASSETS
Goodwill	2,540	2,566
Investments in unconsolidated entities	2,539	2,756
Deferred tax asset	1,347	1,386
Linefill and base gas	914	872
Long-term inventory	179	164
Other long-term assets, net	948	901
Total assets	27,290	26,753
CURRENT LIABILITIES
Accounts payable and accrued liabilities	3,614	3,459
Short-term debt	429	737
Other current liabilities	615	337
Total current liabilities	4,658	4,533
LONG-TERM LIABILITIES
Senior notes, net	8,939	8,933
Other long-term debt, net	201	250
Other long-term liabilities and deferred credits	781	679
Total long-term liabilities	9,921	9,862
COMMITMENTS AND CONTINGENCIES (NOTE 13)
PARTNERS’ CAPITAL
Noncontrolling interests	10,964	10,663
Total partners’ capital	12,711	12,358
Total liabilities and partners’ capital	27,290	26,753
Class A Shares
PARTNERS’ CAPITAL
Class A Shareholders (159,160,785 and 156,111,139 shares outstanding, respectively)	$ 1,747	$ 1,695

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Class A Shares
Shares outstanding
Shares outstanding (shares)	159,160,785	156,111,139	154,543,193	101,206,526

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
REVENUES
Total revenues	$ 8,792	$ 5,873	$ 25,269	$ 18,618
COSTS AND EXPENSES
Purchases and related costs	7,768	5,327	22,838	16,239
Field operating costs	326	283	931	876
General and administrative expenses	75	68	235	213
Depreciation and amortization	131	152	307	403
Total costs and expenses	8,300	5,830	24,311	17,731
OPERATING INCOME	492	43	958	887
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	110	80	281	201
Gain on sale of investment in unconsolidated entities	210		210
Interest expense (net of capitalized interest of $8, $11, $21 and $26, respectively)	(110)	(134)	(327)	(390)
Other income/(expense), net	(3)	(1)	8	(6)
INCOME/(LOSS) BEFORE TAX	699	(12)	1,130	692
Current income tax (expense)/benefit	(14)	1	(34)	(9)
Deferred income tax (expense)/benefit	(9)	42	(50)	(76)
NET INCOME	676	31	1,046	607
Net income attributable to noncontrolling interests	(565)	(27)	(892)	(538)
NET INCOME ATTRIBUTABLE TO PAGP	$ 111	$ 4	$ 154	$ 69
Class A Shares
OTHER INCOME/(EXPENSE)
BASIC AND DILUTED NET INCOME PER CLASS A SHARE (in dollars per share)	$ 0.70	$ 0.03	$ 0.98	$ 0.49
BASIC AND DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING (in shares)	158	154	157	142
Supply and Logistics
REVENUES
Total revenues	$ 8,482	$ 5,573	$ 24,374	$ 17,749
Transportation
REVENUES
Total revenues	161	160	458	459
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	110	80	281	201
Facilities
REVENUES
Total revenues	$ 149	$ 140	$ 437	$ 410

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Statement [Abstract]
Interest expense, capitalized interest	$ 8	$ 11	$ 21	$ 26

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Net income	$ 676	$ 31	$ 1,046	$ 607
Other comprehensive income/(loss)	76	145	(46)	256
Comprehensive income	752	176	1,000	863
Comprehensive income attributable to noncontrolling interests	(624)	(141)	(856)	(742)
Comprehensive income attributable to PAGP	$ 128	$ 35	$ 144	$ 121

CONDENSED CONSOLIDATED STATEM_4

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Changes in Accumulated Other Comprehensive Income/(Loss)
Total period activity	$ 76	$ 145	$ (46)	$ 256
Derivative Instruments
Changes in Accumulated Other Comprehensive Income/(Loss)
Balance at beginning of period			(223)	(228)
Reclassification adjustments			6	19
Unrealized gain (loss) on hedges			60	(15)
Total period activity			66	4
Balance at end of period	(157)	(224)	(157)	(224)
Translation Adjustments
Changes in Accumulated Other Comprehensive Income/(Loss)
Balance at beginning of period			(548)	(782)
Currency translation adjustments			(112)	252
Total period activity			(112)	252
Balance at end of period	(660)	(530)	(660)	(530)
Other
Changes in Accumulated Other Comprehensive Income/(Loss)
Balance at beginning of period			1	1
Balance at end of period	1	1	1	1
Total
Changes in Accumulated Other Comprehensive Income/(Loss)
Balance at beginning of period			(770)	(1,009)
Reclassification adjustments			6	19
Unrealized gain (loss) on hedges			60	(15)
Currency translation adjustments			(112)	252
Total period activity			(46)	256
Balance at end of period	$ (816)	$ (753)	$ (816)	$ (753)

CONDENSED CONSOLIDATED STATEM_5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 1,046	$ 607
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	307	403
Equity-indexed compensation expense	59	33
Inventory valuation adjustments		35
Deferred income tax expense	50	76
(Gain)/loss on foreign currency revaluation	2	(20)
Settlement of terminated interest rate hedging instruments	14	(29)
Equity earnings in unconsolidated entities	(281)	(201)
Distributions on earnings from unconsolidated entities	324	222
Gain on sale of investment in unconsolidated entities	(210)
Other	17	19
Changes in assets and liabilities, net of acquisitions	(36)	770
Net cash provided by operating activities	1,292	1,915
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired		(1,282)
Investments in unconsolidated entities	(300)	(356)
Additions to property, equipment and other	(1,184)	(778)
Proceeds from sales of assets	1,298	407
Return of investment from unconsolidated entities	10	21
Other investing activities	(8)	25
Net cash used in investing activities	(184)	(1,963)
CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments under PAA commercial paper program (Note 9)	(63)	(115)
Net borrowings/(repayments) under PAA senior secured hedged inventory facility (Note 9)	(479)	7
Proceeds from PAA GO Zone term loans (Note 9)	200
Repayments of PAA senior notes		(400)
Net proceeds from sales of Class A shares		1,535
Net proceeds from sales of common units by a subsidiary		129
Distributions paid to Class A shareholders (Note 10)	(142)	(225)
Distributions paid to noncontrolling interests (Note 10)	(611)	(945)
Other financing activities	(17)	46
Net cash provided by/(used in) financing activities	(1,112)	32
Effect of translation adjustment on cash	(3)	2
Net decrease in cash and cash equivalents	(7)	(14)
Cash and cash equivalents, beginning of period	40	50
Cash and cash equivalents, end of period	33	36
Cash paid for:
Interest, net of amounts capitalized	281	325
Income taxes, net of amounts refunded	$ 20	$ 47

CONDENSED CONSOLIDATED STATEM_6

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions	Total	Noncontrolling Interests	Limited PartnersClass A Shares
Beginning balance at Dec. 31, 2016	$ 10,707	$ 8,970	$ 1,737
Increase (Decrease) in Partners' Capital
Net income	607	538	69
Distributions (Note 10)	(1,170)	(945)	(225)
Deferred tax asset	390		390
Sales of Class A shares	1,535	1,073	462
Sales of common units by a subsidiary	129	116	13
Issuance of common units by a subsidiary for acquisition of interest in Advantage Joint Venture	40	35	5
Other comprehensive income/(loss)	256	204	52
Equity-indexed compensation expense	18	14	4
Other	(7)	(28)	21
Ending balance at Sep. 30, 2017	12,505	9,977	2,528
Increase (Decrease) in Partners' Capital
Impact of adoption of ASU 2017-05 (Note 2) | ASU 2017-05	113	89	24
Beginning balance, adjusted balance	12,471	10,752	1,719
Beginning balance at Dec. 31, 2017	12,358	10,663	1,695
Increase (Decrease) in Partners' Capital
Net income	1,046	892	154
Distributions (Note 10)	(802)	(660)	(142)
Deferred tax asset	11		11
Other comprehensive income/(loss)	(46)	(36)	(10)
Equity-indexed compensation expense	37	31	6
Other	(6)	(15)	9
Ending balance at Sep. 30, 2018	$ 12,711	$ 10,964	$ 1,747

Organization and Basis of Conso

Organization and Basis of Consolidation and Presentation	9 Months Ended
	Sep. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Basis of Consolidation and Presentation	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, 2018 , 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, 2018 , 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 57% limited partner interest in Plains AAP, L.P. (“AAP”) through our direct ownership of approximately 158.2 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, 2018 , directly owned a limited partner interest in PAA through its ownership of approximately 281.0 million PAA common units (approximately 35% 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. 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 operating segments: Transportation, Facilities and Supply and Logistics. See Note 14 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”). Definitions Additional defined terms are used in this Form 10-Q and shall have the meanings indicated below: AOCI = Accumulated other comprehensive income/(loss) ASC = Accounting Standards Codification ASU = Accounting Standards Update Bcf = Billion cubic feet Btu = British thermal unit CAD = Canadian dollar CODM = Chief Operating Decision Maker EBITDA = Earnings before interest, taxes, depreciation and amortization EPA = United States Environmental Protection Agency FASB = Financial Accounting Standards Board GAAP = Generally accepted accounting principles in the United States ICE = Intercontinental Exchange ISDA = International Swaps and Derivatives Association LIBOR = London Interbank Offered Rate LTIP = Long-term incentive plan Mcf = Thousand cubic feet NGL = Natural gas liquids, including ethane, propane and butane NYMEX = New York Mercantile Exchange Oxy = Occidental Petroleum Corporation or its subsidiaries PLA = Pipeline loss allowance SEC = United States Securities and Exchange Commission 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 2017 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, 2017 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, 2018 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. 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 $1.347 billion and $1.386 billion as of September 30, 2018 and December 31, 2017 , respectively, substantially all assets and liabilities presented on PAGP’s consolidated balance sheet 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 months ended September 30, 2018 or the year ended December 31, 2017 . See Note 15 to our Consolidated Financial Statements included in Part IV of our 2017 Annual Report on Form 10-K for information regarding the Omnibus Agreement entered into in connection with the Simplification Transactions. Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable.

Recent Accounting Pronouncement

Recent Accounting Pronouncements	9 Months Ended
	Sep. 30, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Standards Updates Adopted During the Period	Recent Accounting Pronouncements Except as discussed below and in our 2017 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the nine months ended September 30, 2018 that are of significance or potential significance to us. Accounting Standards Updates Adopted During the Period In February 2017, the FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets . The ASU clarifies what type of transactions involving nonfinancial assets are covered by the scope of the standard and provides guidance on how to account for those transactions, including partial sales of real estate. Within this guidance, all sales and partial sales of businesses, which may have previously been accounted for using the in-substance real estate guidance, should follow the consolidation guidance. 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 (defined below). We adopted this ASU on January 1, 2018, using the modified retrospective approach. The cumulative effect of our adoption resulted in increases in both the carrying value of investments in unconsolidated entities and retained earnings of $113 million related to the retained noncontrolling interest in those entities from partial sales of businesses accounted for under in-substance real estate guidance during 2016 and 2017. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) , requiring that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents during the period. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual periods beginning after December 15, 2017. We adopted this ASU on January 1, 2018. Our adoption did not have an impact on our statement of cash flows. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, followed by a series of related accounting standard updates (collectively referred to as “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 control of those goods or services. We adopted Topic 606 on January 1, 2018, and applied the modified retrospective approach. See Note 3 for additional information.
Recent Accounting Pronouncements	Accounting Standards Updates Issued During the Period In August 2018, the FASB issued ASU 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a consensus of the FASB Emerging Issues Task Force), to address the accounting for implementation costs of a hosting arrangement that is a service contract and to align the accounting for implementation costs for hosting arrangements, regardless of whether they convey a license to the hosted software. This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. We expect to adopt this guidance on January 1, 2020, and we are currently evaluating the effect that our adoption of this guidance will have on our financial position, results of operations and cash flows. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement , modifying the disclosure requirements on fair value measurements in Topic 820. This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. We expect to adopt this guidance on January 1, 2020, and we are currently evaluating the effect that our adoption of this guidance will have on our financial position, results of operations and cash flows. In July 2018, the FASB issued ASU 2018-09, Codification Improvements , which makes updates for clarifications, technical corrections and other minor improvements to a wide variety of Topics to make the ASC easier to understand and to apply. The transition and effective date is based on the facts and circumstances of each amendment with some amendments effective upon issuance. The remaining amendments are effective for annual periods beginning after December 15, 2018. We expect to adopt the remaining applicable amendments within this guidance on January 1, 2019, and we are currently evaluating the effect that our adoption of this guidance will have on our financial position, results of operations and cash flows. In June 2018, the FASB issued ASU 2018-07, Compensation—Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting , which expands the scope of Topic 718 to include share-based payment awards to nonemployees and eliminates the classification differences for employee and nonemployee share-based payment awards. 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 we do not currently anticipate that our adoption will have a material impact on our financial position, results of operations or cash flows. Other Accounting Standards Updates In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), that revises the current accounting model for leases. The most significant changes are the clarification of the definition of a lease and required lessee recognition on the balance sheet of lease assets and liabilities with lease terms of more than 12 months (with the election of the practical expedient to exclude short-term leases on the balance sheet), including extensive quantitative and qualitative disclosures. This guidance will become effective for interim and annual periods beginning after December 15, 2018, with a modified retrospective application required. Early adoption is permitted, including adoption in an interim period. We expect to adopt this guidance on January 1, 2019. We have implemented a process to evaluate the impact of adopting this guidance on each type of lease contract we have entered into with counterparties. Our implementation team is in the process of determining appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard. Although our evaluation and implementation procedures are ongoing, we currently estimate that there will be a material impact on our financial position (both lease assets and lease liabilities), as well as an increase in disclosures related to leases. However, the determination of the ultimate impact of adopting this guidance will not be known until our implementation procedures are complete and will depend on our lease portfolio as of the adoption date.

Revenues

Revenues	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
Revenues	Revenues Revenue Recognition On January 1, 2018, we adopted Topic 606 using the modified retrospective method applied to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under ASC Topic 605, Revenue Recognition . There was no material impact to opening retained earnings as of January 1, 2018 due to the adoption of Topic 606. There also was no material impact to revenues, or any other financial statement line items, for the three and nine months ended September 30, 2018 as a result of applying Topic 606. Under Topic 606, we disaggregate our revenues by segment and type of activity. These categories depict how the nature, amount, timing and uncertainty of revenues and cash flows are affected by economic factors. Supply and Logistics Segment Revenues from Contracts with Customers. The following table presents our Supply and Logistics segment revenues from contracts with customers disaggregated by type of activity (in millions): Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Supply and Logistics segment revenues from contracts with customers Crude oil transactions $ 7,978 $ 22,651 NGL and other transactions 556 2,181 Total Supply and Logistics segment revenues from contracts with customers $ 8,534 $ 24,832 Revenues from sales of crude oil, NGL and natural gas are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. Sales of crude oil and NGL consist of outright sales contracts. The consideration received under these contracts is variable based on commodity prices. Inventory purchases and sales under buy/sell transactions are treated as inventory exchanges which are excluded from Supply and Logistics segment revenues in our Condensed Consolidated Statements of Operations. Revenues recognized by our Supply and Logistics segment primarily represent margin based activities. In addition, we have certain crude oil sales agreements that are entered into in conjunction with storage arrangements and future inventory exchanges. The revenues under these agreements are deferred until all performance obligations associated with the related agreements are completed. The inventory that has been sold under these crude oil sales agreements is reflected in “Other Current Assets” on our Condensed Consolidated Balance Sheet until all of our performance obligations are complete. At that time, the inventory that has been sold is removed from our Condensed Consolidated Balance Sheet and recorded as “Purchases and Related Costs” in our Condensed Consolidated Statement of Operations. At September 30, 2018 , other current assets and deferred revenue associated with these agreements was approximately $157 million and $159 million , respectively. See Contract Balances below for further discussion of contract liabilities associated with these agreements. We may also utilize derivatives in connection with the transactions described above. Derivative revenue is not included as a component of revenue from contracts with customers, but is included in other items in revenue. The change in the fair value of derivatives that are not designated or do not qualify for hedge accounting is recognized in revenues each period. Transportation Segment Revenues from Contracts with Customers. The following table presents our Transportation segment revenues from contracts with customers disaggregated by type of activity (in millions): Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Transportation segment revenues from contracts with customers Tariff activities: Crude oil pipelines $ 435 $ 1,237 NGL pipelines 25 76 Total tariff activities 460 1,313 Trucking 36 103 Total Transportation segment revenues from contracts with customers $ 496 $ 1,416 Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems and trucks. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil and NGL at a published tariff. We primarily recognize pipeline tariff and fee revenues over time as services are rendered, based on the volumes transported. As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor. We recognize the allowance volumes collected as part of the transaction price and record this non-cash consideration at fair value, measured as of the contract inception date. Facilities Segment Revenues from Contracts with Customers. The following table presents our Facilities segment revenues from contracts with customers disaggregated by type of activity (in millions): Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Facilities segment revenues from contracts with customers Crude oil, NGL and other terminalling and storage $ 174 $ 511 NGL and natural gas processing and fractionation 87 278 Rail load / unload 24 56 Total Facilities segment revenues from contracts with customers $ 285 $ 845 Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services primarily for crude oil, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. Revenues generated in this segment include (i) fees that are generated from storage capacity agreements, (ii) terminal throughput fees that are generated when we receive liquids from one connecting source and deliver the applicable product to another connecting carrier, (iii) fees from NGL fractionation and isomerization services, (iv) fees from natural gas and condensate processing services, (v) fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services (“natural gas storage related activities”) and (vi) loading and unloading fees at our rail terminals. We generate revenue through a combination of month-to-month and multi-year agreements and processing arrangements. Storage fees are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized as our performance obligation is to make available storage capacity for a period of time. Terminal fees (including throughput and rail fees) are recognized as the liquids enter or exit the terminal and are received from or delivered to the connecting carrier or third-party terminal, as applicable. Fees from NGL fractionation and isomerization services and gas processing services are recognized in the period when the services are performed. Natural gas storage related activities fees are recognized in the period the natural gas moves across our header system. We recognize rail loading and unloading fees when the volumes are delivered or received. Reconciliation to Total Revenues of Reportable Segments. Topic 606 requires us to provide information about the relationship between the disaggregated revenues presented above and segment revenues. These disclosures only include information regarding revenues associated with consolidated entities, and revenues from entities accounted for by the equity method are not included in the disclosures. The following table presents the reconciliation of our revenues from contracts with customers (as described above for each segment) to segment revenues and total revenues as disclosed in our Condensed Consolidated Statement of Operations (in millions): Three Months Ended September 30, 2018 Transportation Facilities Supply and Total Revenues from contracts with customers $ 496 $ 285 $ 8,534 $ 9,315 Other items in revenues 2 4 (51 ) (45 ) Total revenues of reportable segments $ 498 $ 289 $ 8,483 $ 9,270 Intersegment revenues (478 ) Total revenues $ 8,792 Nine Months Ended September 30, 2018 Transportation Facilities Supply and Total Revenues from contracts with customers $ 1,416 $ 845 $ 24,832 $ 27,093 Other items in revenues 11 21 (456 ) (424 ) Total revenues of reportable segments $ 1,427 $ 866 $ 24,376 $ 26,669 Intersegment revenues (1,400 ) Total revenues $ 25,269 Trade Accounts Receivable and Other Receivables. We generally invoice customers in the month following that in which products or services were provided and generally require payment within 30 days of the invoice date. 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 Sheet (in millions): September 30, December 31, 2017 Trade accounts receivable arising from revenues from contracts with customers $ 2,910 $ 2,584 Other trade accounts receivables and other receivables (1) 3,482 3,709 Impact due to contractual rights of offset with counterparties (3,438 ) (3,264 ) Trade accounts receivable and other receivables, net $ 2,954 $ 3,029 (1) The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of Topic 606. Minimum Volume Commitments. We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. These contracts are within the scope of Topic 606. In addition, we have certain buy/sell agreements that require customers to deliver a minimum volume over an agreed upon period that are within the scope of ASC Topic 845, Nonmonetary Transactions (“Topic 845”). Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right as a contract liability 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. At September 30, 2018 and December 31, 2017 , counterparty deficiencies associated with agreements (under Topic 606 and Topic 845) that include minimum volume commitments totaled $62 million and $57 million , respectively, of which $42 million and $37 million , respectively, was recorded as a contract liability, which we refer to as deferred revenue. The remaining balance of $20 million at both September 30, 2018 and December 31, 2017 was related to deficiencies for which the counterparties had not met their contractual minimum commitments and were not reflected in our Condensed Consolidated Financial Statements as we had not yet billed or collected such amounts. Contract Balances . Our contract balances consist of amounts received associated with services or sales for which we have not yet completed the related performance obligation. The following table presents the change in the contract liability balance during the nine months ended September 30, 2018 (in millions): Contract Liabilities Balance at December 31, 2017 $ 90 Amounts recognized as revenue (78 ) Additions (1) (2) 384 Other (3 ) Balance at September 30, 2018 $ 393 (1) Includes approximately $159 million associated with crude oil sales agreements that are entered into in conjunction with storage arrangements and future inventory exchanges. Such amount is expected to be recognized as revenue in the fourth quarter of 2018 . (2) Includes $100 million associated with long-term capacity agreements with Cactus II Pipeline LLC. See Note 12 for additional information. Remaining Performance Obligations . Topic 606 requires a presentation of information about partially and wholly unsatisfied performance obligations under contracts that exist as of the end of the period. The information includes the amount of consideration allocated to those remaining performance obligations and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These arrangements include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. These contracts are all within the scope of Topic 606. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of September 30, 2018 (in millions): Remainder of 2018 2019 2020 2021 2022 2023 and Thereafter Pipeline revenues supported by minimum volume commitments and long-term capacity agreements (1) $ 34 $ 158 $ 199 $ 190 $ 188 $ 831 Long-term storage, terminalling and throughput agreements revenues 118 374 296 214 162 573 Total $ 152 $ 532 $ 495 $ 404 $ 350 $ 1,404 (1) Includes revenues from certain contracts for which the amount and timing of revenue is subject to the completion of underlying construction projects. 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 related to the assets of equity method investees — Contracts include those related to the Eagle Ford, BridgeTex, STACK, Caddo, Saddlehorn, White Cliffs, Cheyenne, Diamond and Cactus II pipeline systems; • Acreage dedications — Contracts include those related to the Permian Basin, Eagle Ford, Central, Rocky Mountain and Canada regions; • Supply and Logistics contracts within the scope of Topic 845 — Contracts include buy/sell arrangements with future committed volumes on certain Permian Basin, Eagle Ford, Central and Canada region systems; • All other Supply and Logistics contracts, due to the election of practical expedients related to variable consideration and short-term contracts, as discussed below; • Transportation and Facilities contracts that are short-term, as discussed below; • Contracts within the scope of ASC Topic 840, Leases ; and • Contracts within the scope of ASC Topic 815, Derivatives and Hedging . We have elected practical expedients to exclude the presentation of remaining performance obligations for variable consideration which relates to wholly unsatisfied performance obligations. Certain contracts do not meet the requirements for presentation of remaining performance obligations under Topic 606 due to variability in amount of performance obligation remaining, variability in the timing of recognition or variability in consideration. Acreage dedications do require us to perform future services but do not contain a minimum level of services and are therefore excluded from this presentation. Long-term supply and logistics arrangements contain variable timing, volumes and/or consideration and are excluded from this presentation. The duration of these contracts varies across the periods presented above. Additionally, we have elected practical expedients to exclude contracts with terms of one year or less, and therefore exclude the presentation of remaining performance obligations for short-term transportation, storage and processing services, supply and logistics arrangements, including the non-cancelable period of evergreen arrangements, and any other types of arrangements with terms of one year or less.

Net Income Per Class A Share

Net Income Per Class A Share	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Net Income Per Class A Share	Net Income Per Class A Share Basic net income per Class A share is determined by dividing net income attributable to PAGP by the 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, basic and diluted net income per Class B and Class C share has not been presented. Diluted net income per Class A share is determined by dividing net income attributable to PAGP by the diluted 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 attributable to PAGP and the diluted 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 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”). 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 11 to our Consolidated Financial Statements included in Part IV of our 2017 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 16 to our Consolidated Financial Statements included in Part IV of our 2017 Annual Report on Form 10-K for information regarding PAGP LTIP awards. For the three and nine months ended September 30, 2018 and 2017, the possible exchange of any AAP units and certain AAP Management Units would not have had a dilutive effect on basic net income per Class A share. For the three and nine months ended September 30, 2018 and 2017 , our PAGP LTIP awards were dilutive; however, there were less than 0.1 million dilutive LTIP awards for each period, which did not change the presentation of weighted average Class A shares outstanding or net income per Class A share. The following table sets forth the computation of basic and diluted net income per Class A share (in millions, except per share data): Three Months Ended Nine Months Ended 2018 2017 2018 2017 Basic and Diluted Net Income per Class A Share Net income attributable to PAGP $ 111 $ 4 $ 154 $ 69 Basic and diluted weighted average Class A shares outstanding 158 154 157 142 Basic and diluted net income per Class A share $ 0.70 $ 0.03 $ 0.98 $ 0.49

Accounts Receivable, Net

Accounts Receivable, Net	9 Months Ended
	Sep. 30, 2018
Receivables [Abstract]
Accounts Receivable, Net	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 and perform credit reviews of each customer to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit, credit insurance or parental guarantees. As of September 30, 2018 and December 31, 2017 , we had received $136 million and $117 million , respectively, of advance cash payments from third parties to mitigate credit risk. We also received $36 million and $54 million as of September 30, 2018 and December 31, 2017 , 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 the majority of our net-cash 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, 2018 and December 31, 2017 , 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, 2018 and December 31, 2017 . Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

Inventory, Linefill and Base Ga

Inventory, Linefill and Base Gas and Long-term Inventory	9 Months Ended
	Sep. 30, 2018
Inventory, Linefill and Base Gas and Long-term Inventory
Inventory, Linefill and Base Gas and Long-term Inventory	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, 2018 December 31, 2017 Volumes Unit of Carrying Price/ (1) Volumes Unit of Carrying Price/ (1) Inventory Crude oil 7,020 barrels $ 389 $ 55.41 7,800 barrels $ 402 $ 51.54 NGL 15,122 barrels 422 $ 27.91 10,774 barrels 294 $ 27.29 Other N/A 13 N/A N/A 17 N/A Inventory subtotal 824 713 Linefill and base gas Crude oil 13,033 barrels 756 $ 58.01 12,340 barrels 719 $ 58.27 NGL 1,764 barrels 50 $ 28.34 1,597 barrels 45 $ 28.18 Natural gas 24,976 Mcf 108 $ 4.32 24,976 Mcf 108 $ 4.32 Linefill and base gas subtotal 914 872 Long-term inventory Crude oil 1,882 barrels 112 $ 59.51 1,870 barrels 105 $ 56.15 NGL 2,351 barrels 67 $ 28.50 2,167 barrels 59 $ 27.23 Long-term inventory subtotal 179 164 Total $ 1,917 $ 1,749 (1) Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products. At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Condensed Consolidated Statements of Operations. We recorded a charge of $35 million during the nine months ended September 30, 2017 primarily related to the writedown of our crude oil inventory due to a decline in prices. Substantially all of this inventory valuation adjustment was offset by the recognition of gains on derivative instruments being utilized to hedge future sales of our crude oil inventory. Such gains were recorded to “Supply and Logistics segment revenues” on our accompanying Condensed Consolidated Statements of Operations. See Note 11 for discussion of our derivative and risk management activities. We did not record such charges during 2018.

Divestitures

Divestitures	9 Months Ended
	Sep. 30, 2018
Discontinued Operations and Disposal Groups [Abstract]
Divestitures	Divestitures During the nine months ended September 30, 2018 , we received proceeds from asset sales of $1.298 billion . BridgeTex . During the third quarter of 2018, we sold a 30% interest in BridgeTex Pipeline Company, LLC (“BridgeTex”) for proceeds of $868 million , including working capital adjustments, and have retained a 20% interest. We recorded a gain of $210 million related to this sale, which is included in “Gain on sale of investment in unconsolidated entities” on our Condensed Consolidated Statement of Operations. We continue to account for our remaining interest under the equity method of accounting. Other . The other assets sold during the nine months ended September 30, 2018 primarily included non-core property and equipment or are associated with the formation of strategic joint ventures and were previously reported in our Facilities and Transportation segments. We recognized losses related to these asset sales of $2 million for the three months ended September 30, 2018 . For the nine months ended September 30, 2018 , we recognized a net gain of $79 million , which is comprised of gains of $105 million and losses of $26 million . Such amounts are included in “Depreciation and amortization” on our Condensed Consolidated Statements of Operations.

Goodwill

Goodwill	9 Months Ended
	Sep. 30, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	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, 2017 $ 1,070 $ 988 $ 508 $ 2,566 Foreign currency translation adjustments (8 ) (3 ) (2 ) (13 ) Dispositions (10 ) (3 ) — (13 ) Balance at September 30, 2018 $ 1,052 $ 982 $ 506 $ 2,540 We completed our goodwill impairment test as of June 30, 2018 and determined that there was no impairment of goodwill.

Debt

Debt	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Debt	Debt Debt consisted of the following (in millions): September 30, December 31, SHORT-TERM DEBT PAA commercial paper notes, bearing a weighted-average interest rate of 3.3% (1) $ 60 $ — PAA senior secured hedged inventory facility, bearing a weighted-average interest rate of 3.2% and 2.6%, respectively (1) 300 664 Other 69 73 Total short-term debt (2) 429 737 LONG-TERM DEBT PAA senior notes, net of unamortized discounts and debt issuance costs of $61 and $67, respectively 8,939 8,933 PAA commercial paper notes and senior secured hedged inventory facility borrowings (3) — 247 PAA GO Zone term loans, net of debt issuance costs of $2, bearing a weighted-average interest rate of 2.9% 198 — Other 3 3 Total long-term debt 9,140 9,183 Total debt (4) $ 9,569 $ 9,920 (1) We classified these PAA commercial paper notes and credit facility borrowings as short-term as of September 30, 2018 and December 31, 2017 , 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, 2018 and December 31, 2017 , balance includes borrowings for cash margin deposits with NYMEX and ICE, which are associated with financial derivatives used for hedging purposes. (3) As of December 31, 2017 , we classified a portion of PAA’s commercial paper notes and PAA's credit facility borrowings as long-term based on PAA’s ability and intent to refinance such amounts on a long-term basis. (4) PAA’s fixed-rate senior notes had a face value of approximately $9.0 billion at both September 30, 2018 and December 31, 2017 . We estimated the aggregate fair value of these notes as of September 30, 2018 and December 31, 2017 to be approximately $8.8 billion and $9.1 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 Agreements PAA Go Zone term loans . In August 2018, PAA entered into an agreement for two $100 million term loans (the “GO Zone term loans”) from the remarketing of our $100,000,000 Mississippi Business Finance Corporation Gulf Opportunity Zone Industrial Development Revenue Bonds (SG Resources Mississippi, LLC Project), Series 2009 and our $100,000,000 Mississippi Business Finance Corporation Gulf Opportunity Zone Industrial Development Revenue Bonds (SG Resources Mississippi, LLC Project), Series 2010 (collectively, the “GO Bonds”). The GO Zone term loans accrue interest in accordance with the interest payable on the related GO Bonds as provided in the GO Bonds Indenture pursuant to which such GO Bonds are issued and governed. The purchasers of the two GO Zone term loans have the right to put, at par, the GO Zone term loans in July 2023. The GO Bonds mature by their terms in May 2032 and August 2035, respectively. Credit Facilities. In August 2018, PAA extended the maturity dates of its senior unsecured revolving credit facility and senior secured hedged inventory facility by one year to August 2023 and August 2021, respectively, for each extending lender. The PAA 364-day senior unsecured revolving credit facility, which had a borrowing capacity of $1.0 billion , matured in August 2018. Borrowings and Repayments Total borrowings under the PAA credit facilities and commercial paper program for the nine months ended September 30, 2018 and 2017 were approximately $38.6 billion and $52.6 billion , respectively. Total repayments under the PAA credit facilities and commercial paper program were approximately $39.2 billion and $52.7 billion for the nine months ended September 30, 2018 and 2017 , respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities. Letters of Credit In connection with our supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs, derivative transactions including hedging related margin obligations and construction activities. At September 30, 2018 and December 31, 2017 , we had outstanding letters of credit of $181 million and $166 million , respectively.

Partners' Capital and Distribut

Partners' Capital and Distributions	9 Months Ended
	Sep. 30, 2018
Partners' Capital Notes [Abstract]
Partners' Capital and Distributions	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, 2017 156,111,139 126,984,572 510,925,432 Exchange Right exercises (1) 3,038,396 (3,038,396 ) — Redemption Right exercises (1) — (3,306,476 ) 3,306,476 Issuance of Series A preferred units by a subsidiary — — 1,393,926 Other 11,250 — 512,166 Outstanding at September 30, 2018 159,160,785 120,639,700 516,138,000 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 for acquisition of interest in Advantage Joint Venture — — 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 ___________________________________________ (1) See Note 11 to our Consolidated Financial Statements included in Part IV of our 2017 Annual Report on Form 10-K for information regarding conversions of AAP Management Units, Exchange Rights and Redemption Rights. Distributions The following table details distributions to our Class A shareholders paid during or pertaining to the first nine months of 2018 (in millions, except per share data): Distribution Payment Date Distributions to Class A Shareholders Distributions per Class A Share November 14, 2018 (1) $ 48 $ 0.30 August 14, 2018 $ 48 $ 0.30 May 15, 2018 $ 47 $ 0.30 February 14, 2018 $ 47 $ 0.30 ___________________________________________ (1) Payable to shareholders of record at the close of business on October 31, 2018 for the period from July 1, 2018 through September 30, 2018 . Consolidated Subsidiaries Noncontrolling Interests in Subsidiaries As of September 30, 2018 , noncontrolling interests in our subsidiaries consisted of (i) limited partner interests in PAA including a 65% interest in PAA’s common units and PAA’s Series A preferred units combined and 100% of PAA’s Series B preferred units and (ii) an approximate 43% limited partner interest in AAP. Subsidiary Distributions 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 nine months of 2018 (in millions, except unit and per unit data): Series A Preferred Unitholders Distribution (2) Distribution per Unit Distribution Payment Date Cash Units November 14, 2018 (1) $ 37 — $ 0.525 August 14, 2018 $ 37 — $ 0.525 May 15, 2018 $ 37 — $ 0.525 February 14, 2018 $ — 1,393,926 $ 0.525 (1) Payable to unitholders of record at the close of business on October 31, 2018 for the period from July 1, 2018 through September 30, 2018 . At September 30, 2018 , such amount was accrued to distributions payable in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet. (2) On February 14, 2018, PAA issued additional Series A preferred units in lieu of a cash distribution of $37 million . With respect to quarters ending on or prior to December 31, 2017 (the “Initial Distribution Period”), PAA elected to pay distributions on its Series A preferred units in additional Series A preferred units. The Initial Distribution Period ended with the February 2018 distribution; as such, with respect to quarters ending after the Initial Distribution Period, distributions on PAA’s Series A preferred units are paid in cash. PAA Series B Preferred Unit Distributions . Distributions on PAA’s Series B preferred units are payable semiannually in arrears on the 15th day of May and November. The following table details distributions paid or to be paid to PAA’s Series B preferred unitholders (in millions, except per unit data): Series B Preferred Unitholders Distribution Payment Date Cash Distribution Distribution per Unit November 15, 2018 (1) $ 24.5 $ 30.625 May 15, 2018 $ 24.5 $ 30.625 (1) Payable to unitholders of record at the close of business on November 1, 2018 for the period from May 15, 2018 through November 14, 2018. As of September 30, 2018 , we had accrued approximately $18 million of distributions payable to PAA's Series B preferred unitholders in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet. PAA Common Unit Distributions. The following table details distributions paid to PAA’s common unitholders during or pertaining to the first nine months of 2018 (in millions, except per unit data): Distributions Cash Distribution per Common Unit Common Unitholders Total Cash Distribution Distribution Payment Date Public AAP November 14, 2018 (1) $ 134 $ 84 $ 218 $ 0.30 August 14, 2018 $ 133 $ 85 $ 218 $ 0.30 May 15, 2018 $ 133 $ 85 $ 218 $ 0.30 February 14, 2018 $ 133 $ 85 $ 218 $ 0.30 (1) Payable to unitholders of record at the close of business on October 31, 2018 for the period from July 1, 2018 through September 30, 2018 . AAP Distributions. The following table details the distributions paid to AAP’s partners during or pertaining to the first nine months of 2018 from distributions received from PAA (in millions): Distribution to AAP's Partners Distribution Payment Date Noncontrolling Interests PAGP Total Cash Distributions November 14, 2018 (1) $ 36 $ 48 $ 84 August 14, 2018 $ 37 $ 48 $ 85 May 15, 2018 $ 38 $ 47 $ 85 February 14, 2018 $ 38 $ 47 $ 85 ___________________________________________ (1) Payable to unitholders of record at the close of business on October 31, 2018 for the period from July 1, 2018 through September 30, 2018 .

Derivatives and Risk Management

Derivatives and Risk Management Activities	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives and Risk Management Activities	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 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. 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 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, 2018 , net derivative positions related to these activities included: • A net long position of 5.8 million barrels associated with our crude oil purchases, which was unwound ratably during October 2018 to match monthly average pricing. • A net short time spread position of 15.4 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through December 2019 . • A crude oil grade basis position of 68.6 million barrels through December 2020 . These derivatives allow us to lock in grade basis differentials. • A net short position of 16.5 million barrels through February 2020 related to anticipated net sales of our crude oil and NGL inventory. Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor. We utilize derivative instruments to hedge a portion of the anticipated sales of the loss allowance oil that is to be collected under our tariffs. As of September 30, 2018 , our PLA hedges included a short position consisting of crude oil futures of 1.5 million barrels through December 2019 and a long call option position of 1.6 million barrels through December 2020 . 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, 2018 , we had a long natural gas position of 64.9 Bcf which hedges a portion of our natural gas processing and operational needs through December 2020 . We also had a short propane position of 11.3 million barrels through December 2020 , a short butane position of 3.1 million barrels through December 2020 and a short WTI position of 1.3 million barrels through December 2020 . In addition, we had a long power position of 0.4 million megawatt hours, which hedges a portion of our power supply requirements at our Canadian natural gas processing and fractionation plants through December 2020 . Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchases and normal sales scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings. We have determined that substantially all of our physical commodity contracts qualify for the normal purchases and normal sales scope exception. Interest Rate Risk Hedging We use interest rate derivatives to hedge the benchmark interest rate associated with interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist of forward starting interest rate swaps and treasury locks. These derivatives are designated as cash flow hedges. As such, changes in fair value are deferred in AOCI and are reclassified to interest expense as we incur the interest expense associated with the underlying debt. The following table summarizes the terms of our outstanding interest rate derivatives as of September 30, 2018 (notional amounts in millions): Hedged Transaction Number and Types of Notional Expected Average Rate Accounting Anticipated interest payments 8 forward starting swaps (30-year) $ 200 6/14/2019 2.83 % Cash flow hedge Anticipated interest payments 8 forward starting swaps $ 200 6/15/2020 3.06 % Cash flow hedge Currency Exchange Rate Risk Hedging Because a significant portion of our Canadian business is conducted in CAD we use foreign currency derivatives to minimize the risk of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts, forwards and options. As of September 30, 2018 , our outstanding foreign currency derivatives include (i) derivatives we use to hedge currency exchange risk created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales and (ii) foreign currency exchange contracts we use to manage our Canadian business cash requirements. The following table summarizes our open forward exchange contracts as of September 30, 2018 (in millions): USD CAD Average Exchange Rate Forward exchange contracts that exchange CAD for USD: 2018 $ 174 $ 227 $1.00 - $1.30 Forward exchange contracts that exchange USD for CAD: 2018 $ 418 $ 543 $1.00 - $1.30 2019 $ 120 $ 155 $1.00 - $1.30 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. See Note 11 to our Consolidated Financial Statements included in Part IV of our 2017 Annual Report on Form 10-K for additional information regarding the Series A preferred units and Preferred Distribution Rate Reset Option. Summary of Financial Impact We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify as cash flow hedges, changes in fair value of the effective portion of the hedges are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions are recognized in earnings. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of the hedged items are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Condensed Consolidated Statements of Cash Flows. A summary of the impact of our derivatives recognized in earnings is as follows (in millions): Three Months Ended September 30, 2018 Three Months Ended September 30, 2017 Location of Gain/(Loss) Derivatives in Derivatives Total Derivatives in Derivatives Total Commodity Derivatives Supply and Logistics segment revenues $ — $ (59 ) $ (59 ) $ — $ (226 ) $ (226 ) Field operating costs — (1 ) (1 ) — (4 ) (4 ) Interest Rate Derivatives Interest expense, net (2 ) — (2 ) (10 ) — (10 ) Foreign Currency Derivatives Supply and Logistics segment revenues — 5 5 — 3 3 Preferred Distribution Rate Reset Option Other income/(expense), net — (2 ) (2 ) — 2 2 Total Gain/(Loss) on Derivatives Recognized in Net Income $ (2 ) $ (57 ) $ (59 ) $ (10 ) $ (225 ) $ (235 ) Nine Months Ended September 30, 2018 Nine Months Ended September 30, 2017 Location of Gain/(Loss) Derivatives in Derivatives Total Derivatives in Derivatives Total Commodity Derivatives Supply and Logistics segment revenues $ — $ (443 ) $ (443 ) $ — $ (31 ) $ (31 ) Field operating costs — — — — (8 ) (8 ) Depreciation and amortization — — — (3 ) — (3 ) Interest Rate Derivatives Interest expense, net (3 ) — (3 ) (16 ) — (16 ) Foreign Currency Derivatives Supply and Logistics segment revenues — (7 ) (7 ) — 5 5 Preferred Distribution Rate Reset Option Other income/(expense), net — 3 3 — — — Total Gain/(Loss) on Derivatives Recognized in Net Income $ (3 ) $ (447 ) $ (450 ) $ (19 ) $ (34 ) $ (53 ) The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of September 30, 2018 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Fair Balance Sheet Fair Derivatives designated as hedging instruments: Interest rate derivatives Other current assets $ 12 Other long-term assets, net 3 Total derivatives designated as hedging instruments $ 15 $ — Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ 146 Other current assets $ (358 ) Other long-term assets, net 54 Other long-term assets, net (2 ) Other current liabilities 60 Other current liabilities (211 ) Other long-term liabilities and deferred credits 9 Other long-term liabilities and deferred credits (39 ) Foreign currency derivatives Other current assets 4 Other current assets (1 ) Other current liabilities (1 ) Preferred Distribution Rate Reset Option Other long-term liabilities and deferred credits (19 ) Total derivatives not designated as hedging instruments $ 273 $ (631 ) Total derivatives $ 288 $ (631 ) The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of December 31, 2017 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Fair Balance Sheet Fair Derivatives designated as hedging instruments: Interest rate derivatives Other current liabilities $ 2 Other current liabilities $ (27 ) Other long-term liabilities and deferred credits (11 ) Total derivatives designated as hedging instruments $ 2 $ (38 ) Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ 73 Other current assets $ (227 ) Other long-term assets, net 1 Other current liabilities (131 ) Other current liabilities 5 Other long-term liabilities and deferred credits (5 ) Other long-term liabilities and deferred credits 3 Foreign currency derivatives Other current assets 6 Other current assets (2 ) Preferred Distribution Rate Reset Option Other long-term liabilities and deferred credits (22 ) Total derivatives not designated as hedging instruments $ 88 $ (387 ) Total derivatives $ 90 $ (425 ) Our derivative transactions (other than the Preferred Distribution Rate Reset Option) 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. 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: September 30, December 31, Initial margin $ 139 $ 48 Variation margin posted 222 164 Letters of credit (102 ) — Net broker receivable $ 259 $ 212 The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions): September 30, 2018 December 31, 2017 Derivative Derivative Derivative Derivative Netting Adjustments: Gross position - asset/(liability) $ 288 $ (631 ) $ 90 $ (425 ) Netting adjustment (430 ) 430 (239 ) 239 Cash collateral paid 259 — 212 — Net position - asset/(liability) $ 117 $ (201 ) $ 63 $ (186 ) Balance Sheet Location After Netting Adjustments: Other current assets $ 62 $ — $ 62 $ — Other long-term assets, net 55 — 1 — Other current liabilities — (152 ) — (151 ) Other long-term liabilities and deferred credits — (49 ) — (35 ) $ 117 $ (201 ) $ 63 $ (186 ) As of September 30, 2018 , there was a net loss of $157 million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the earnings recognition of the underlying hedged commodity transactions or (ii) interest expense accruals associated with underlying debt instruments. Of the total net loss deferred in AOCI at September 30, 2018 , we expect to reclassify a net loss of $7 million to earnings in the next twelve months. We estimate that substantially all of the remaining deferred loss will be reclassified to earnings through 2050 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of September 30, 2018 ; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions. The following table summarizes the net unrealized gain/(loss) recognized in AOCI for derivatives (in millions): Three Months Ended Nine Months Ended 2018 2017 2018 2017 Interest rate derivatives, net $ 15 $ (3 ) $ 60 $ (15 ) At September 30, 2018 and December 31, 2017 , 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 PAA’s credit ratings. Although we may be required to post margin on our cleared derivatives as described above, we do not require our non-cleared derivative counterparties to post collateral with us. 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, 2018 Fair Value as of December 31, 2017 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ (11 ) $ (326 ) $ (4 ) $ (341 ) $ 5 $ (278 ) $ (8 ) $ (281 ) Interest rate derivatives — 15 — 15 — (36 ) — (36 ) Foreign currency derivatives — 2 — 2 — 4 — 4 Preferred Distribution Rate Reset Option — — (19 ) (19 ) — — (22 ) (22 ) Total net derivative asset/(liability) $ (11 ) $ (309 ) $ (23 ) $ (343 ) $ 5 $ (310 ) $ (30 ) $ (335 ) (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. The fair value of exchange-traded commodity derivatives and over-the-counter commodity contracts are 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 of these derivatives is based on broker price quotations which are corroborated with market observable inputs. Level 3 Level 3 of the fair value hierarchy includes certain physical commodity contracts, over-the-counter financial commodity contracts, and the Preferred Distribution Rate Reset Option contained in PAA’s partnership agreement which is classified as an embedded derivative. The fair value of our Level 3 physical commodity contracts and over-the-counter financial commodity contracts are based on valuation models utilizing significant unobservable pricing inputs and timing estimates, which involve management judgment. Significant deviations from these inputs and estimates could result in a material change in fair value to our physical commodity contracts and over-the-counter financial commodity contracts. We report unrealized gains and losses associated with these physical commodity contracts in our Condensed Consolidated Statements of Operations as Supply and Logistics segment revenues. Unrealized gains and losses associated with the over-the counter financial commodity contracts are reported in our Condensed Consolidated Statements of Operations as Field operating costs. 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 change in these inputs could result in a material change in fair value to this embedded derivative feature. We report unrealized gains and losses associated with this embedded derivative in our Condensed Consolidated Statements of Operations in “Other income/(expense), net.” 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 Nine Months Ended 2018 2017 2018 2017 Beginning Balance $ (18 ) $ (30 ) $ (30 ) $ (36 ) Net gains/(losses) for the period included in earnings (5 ) (8 ) 2 (1 ) Settlements — (1 ) 7 4 Derivatives entered into during the period — (2 ) (2 ) (8 ) Ending Balance $ (23 ) $ (41 ) $ (23 ) $ (41 ) Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ (5 ) $ (10 ) $ — $ (8 )

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2018
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions See Note 15 to our Consolidated Financial Statements included in Part IV of our 2017 Annual Report on Form 10-K for a complete discussion of our related party transactions. Ownership of PAGP Class C Shares As of September 30, 2018 and December 31, 2017, PAA owned 516,138,000 and 510,925,432 , 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 As of September 30, 2018 , Oxy had a representative on the board of directors of our general partner and owned approximately 11% of the limited partner interests in AAP (which represents an approximate 4% indirect ownership interest in PAA). During the three and nine months ended September 30, 2018 and 2017 , we recognized sales and transportation revenues and purchased petroleum products from Oxy. 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 transactions is included below (in millions): Three Months Ended Nine Months Ended 2018 2017 2018 2017 Revenues $ 260 $ 204 $ 818 $ 657 Purchases and related costs (1) $ (22 ) $ (68 ) $ (184 ) $ (169 ) (1) Crude oil purchases that are part of inventory exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Condensed Consolidated Statements of Operations. We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with Oxy were as follows (in millions): September 30, December 31, Trade accounts receivable and other receivables $ 1,039 $ 1,075 Accounts payable $ 976 $ 990 Transactions with Equity Method Investees We also have transactions with companies in which we hold an investment accounted for under the equity method of accounting. We recorded revenues of $3 million and $1 million during the three months ended September 30, 2018 and 2017 , respectively, and $9 million and $3 million during the nine months ended September 30, 2018 and 2017 , respectively, primarily related to transportation services. In addition, we utilized transportation services and purchased petroleum products provided by these companies. Costs related to these services and product purchases totaled $146 million and $124 million for the three months ended September 30, 2018 and 2017 , respectively, and $411 million and $318 million for the nine months ended September 30, 2018 and 2017 , respectively. These costs include amounts associated with a joint tariff administered by an equity method investee, of which $74 million and $57 million for the three months ended September 30, 2018 and 2017, respectively, and $213 million and $150 million for the nine months ended September 30, 2018 and 2017 , respectively, were associated with a PAA wholly-owned pipeline. These transactions were conducted at posted tariff rates or contracted rates or prices that we believe approximate market. Receivables from our equity method investees totaled $41 million and $26 million at September 30, 2018 and December 31, 2017, respectively, and primarily included amounts related to transportation services and amounts owed to us related to expansion projects where we serve as construction manager. Accounts payable to our equity method investees were $112 million and $41 million at September 30, 2018 and December 31, 2017, respectively, and primarily included amounts related to transportation services utilized and amounts advanced to us related to expansion projects where we serve as construction manager. In addition, we have an agreement to transport crude oil at posted tariff rates on a pipeline that is owned by an equity method investee, in which we own a 50% interest. Our commitment to transport is supported by crude oil buy/sell agreements with third parties (including Oxy) with commensurate quantities. During the nine months ended September 30, 2018 , we made net investments in our equity method investees of $300 million (including amounts contributed to and received from Cactus II Pipeline LLC subsequent to its formation, as discussed further below). Such net investments are primarily related to funding our portion of the development, construction or capital expansion projects of such entities and are reflected in “Investments in unconsolidated entities” on our Condensed Consolidated Statement of Cash Flows. Cactus II JV Formation. In the second quarter of 2018, a subsidiary of Oxy and another third party each exercised their purchase options for a 20% interest and a 15% interest, respectively, in Cactus II Pipeline LLC (“Cactus II”), which owns the Cactus II pipeline system that is currently under construction. Although we own a majority of Cactus II’s equity, we do not have a controlling financial interest in Cactus II because the other members have substantive participating rights. Therefore, we account for our ownership interest in Cactus II as an equity method investment. Following the exercise of the purchase options, we deconsolidated Cactus II resulting in a reduction of property and equipment of $74 million (which was representative of the costs incurred to date to construct the pipeline and equivalent to fair value), and we received $26 million of cash from Cactus II, which represented the other members’ portion of the property and equipment. In addition, during the second quarter of 2018, we received a $100 million advance cash payment from Cactus II associated with pipeline capacity agreements, which is recorded as long-term deferred revenue within “Other long-term liabilities and deferred credits” on our Condensed Consolidated Balance Sheet. Such amount will be recognized in revenue ratably over the life of the contracts beginning once the Cactus II pipeline system has been placed into service.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Loss Contingencies — General To the extent we are able to assess the likelihood of a negative outcome for a contingency, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Legal Proceedings — General In the ordinary course of business, we are involved in various legal proceedings, including those arising from regulatory and environmental matters. 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 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 believe that the outcome of the legal proceedings in which we are currently involved (including those described below) will, 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 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, 2018 , our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled $126 million , of which $46 million was classified as short-term and $80 million was classified as long-term. At December 31, 2017 , our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident) totaled $162 million , of which $72 million was classified as short-term and $90 million was classified as long-term. The short- and long-term environmental liabilities referenced above are reflected in “Accounts payable and accrued liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Condensed Consolidated Balance Sheets. At September 30, 2018 , we had recorded receivables totaling $49 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which $23 million was reflected in “Trade accounts receivable and other receivables, net” and $26 million was reflected in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet. At December 31, 2017 , we had recorded $55 million of such receivables, of which $29 million was reflected in “Trade accounts receivable and other receivables, net” and $26 million was reflected in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet. 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 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, 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, 2015; and June 16, 2016 to require us to take additional corrective actions with respect to both Lines 901 and 903 (as amended, the “CAO”). Among other requirements, the CAO obligated us to conduct a root cause failure analysis with respect to Line 901 and present remedial work plans and restart plans to PHMSA prior to returning Line 901 and 903 to service; the CAO also imposed a pressure restriction on the section of Line 903 between Pentland Pump Station and Emidio Pump Station and required us to take other specified actions with respect to both Lines 901 and 903. We intend to continue to comply with the CAO and to cooperate with any other governmental investigations relating to or arising 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. No timeline has been established for the restart of Line 901 or Line 903. On February 17, 2016, PHMSA issued a Preliminary Factual Report of the Line 901 failure, which contains PHMSA’s preliminary findings regarding factual information about the events leading up to the accident and the technical analysis that has been conducted to date. On May 19, 2016, PHMSA issued its final Failure Investigation Report regarding the Line 901 incident. PHMSA’s findings indicate that the direct cause of the Line 901 incident was external corrosion that thinned the pipe wall to a level where it ruptured suddenly and released crude oil. PHMSA also concluded that there were numerous contributory causes of the Line 901 incident, including ineffective protection against external corrosion, failure to detect and mitigate the corrosion and a lack of timely detection and response to the rupture. The report also included copies of various engineering and technical reports regarding the incident. By virtue of its statutory authority, PHMSA has the power and authority to impose fines and penalties on us and cause civil or criminal charges to be brought against us. While to date PHMSA has not imposed any such fines or penalties or brought any such civil or criminal charges with respect to the Line 901 release, their investigation is still open and we are likely to have fines or penalties imposed upon us, and we may have civil or criminal charges brought against us, in the future. In late May of 2015, the California Attorney General’s Office and the District Attorney’s office for the County of Santa Barbara began investigating the Line 901 incident to determine whether any applicable state or local laws had been violated. On May 16, 2016, PAA and one of its employees were charged by a California state grand jury, pursuant to an indictment filed in California Superior Court, Santa Barbara County (the “May 2016 Indictment”), with alleged violations of California law in connection with the Line 901 incident. The May 2016 Indictment included a total of 46 counts against PAA. On July 28, 2016, at an arraignment hearing held in California Superior Court in Santa Barbara County, PAA pled not guilty to all counts. Between May of 2016 and May of 2018, 31 of the criminal charges against PAA (including one felony charge) and all of the criminal charges against our employee, were dismissed. The remaining 15 charges were the subject of a jury trial in California Superior Court in Santa Barbara County that began in May of 2018. The jury returned a verdict on September 7, 2018, pursuant to which we were (i) found guilty on one felony discharge count and eight misdemeanor counts (which included one reporting count, one strict liability discharge count and six strict liability animal takings counts) and (ii) found not guilty on one strict liability animal takings count. The jury deadlocked on three counts (including two felony discharge counts and one strict liability animal takings count), and two misdemeanor discharge counts were dropped. We are in the process of pursuing and evaluating our post-trial options, which include the possibility of an appeal. We do not anticipate that the fines or penalties imposed as a result of the jury’s decision will have a material adverse impact on the financial position or operations of the Partnership. Also in late May of 2015, the United States Attorney for the Department of Justice, Central District of California, Environmental Crimes Section (“DOJ”) began an investigation into whether there were any violations of federal criminal statutes in connection with the Line 901 incident, including potential violations of the federal Clean Water Act. We have cooperated with the DOJ’s investigation by responding to their requests for documents and access to our employees. Consistent with the terms of our governing organizational documents, we are funding our employees’ defense costs, including the costs of separate counsel engaged to represent such individuals. On August 26, 2015, we received a Request for Information from the EPA relating to Line 901. We have provided various responsive materials to date and we will continue to do so in the future in cooperation with the EPA. While to date no civil actions or criminal charges with respect to the Line 901 release, other than those brought pursuant to the May 2016 Indictment and a separate civil claim brought by the California Attorney General on behalf of the California State Lands Commission, 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 actions or criminal charges brought against us, our officers or our employees in the future, whether by those or other governmental agencies. Shortly following the Line 901 incident, we established a claims line and encouraged any parties that were damaged by the release to contact us to discuss their damage claims. We have received a number of claims through the claims line and we have been processing those claims and making payments as appropriate. In addition, we have also had nine class action lawsuits filed against us, six of which have been administratively consolidated into a single proceeding in the United States District Court for the Central District of California. In general, the plaintiffs are seeking to establish different classes of claimants that have allegedly been damaged by the release. To date, the court has certified three sub-classes of claimants and denied certification of the other proposed sub-class. The sub-classes that have been certified include (i) commercial fishermen who landed fish in certain specified fishing blocks in the waters adjacent to Santa Barbara County or persons or businesses who resold commercial seafood landed in such areas; (ii) individuals or businesses who were employed by or had contracts with certain designated oil platforms and related onshore processing facilities in the vicinity of the release as of the date of the release and (iii) beachfront property and easement owners whose properties were oiled. The Ninth Circuit Court of Appeals has granted our petition for leave to appeal the oil industry class certification. 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 refiled their complaint. On April 2, 2018, the Court dismissed all of the refiled claims against all defendants with prejudice. Plaintiffs have appealed the dismissal. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we have indemnified and funded the defense costs of our officers and directors in connection with this lawsuit; we have also indemnified and funded the defense costs of our underwriters pursuant to the terms of the underwriting agreements we previously entered into with such underwriters. In addition, four unitholder derivative lawsuits have been filed by certain purported investors in PAA against PAA, certain of its affiliates and certain officers and directors. One lawsuit was filed in State District Court in Harris County, Texas and subsequently dismissed by the Court. Two of these lawsuits were filed in the United States District Court for the Southern District of Texas and were administratively consolidated into one action and later dismissed on the basis that Plains Partnership agreements require that derivative suits be filed in Delaware Chancery Court. Following the order dismissing the Texas Federal Court suits, a new derivative suit brought by different plaintiffs was filed in Delaware Chancery Court. In general, these derivative lawsuits allege that the various defendants breached their fiduciary duties, engaged in gross mismanagement and made false and misleading statements, among other similar allegations, in connection with their management and oversight of PAA during the period of time leading up to and following the Line 901 release. The plaintiffs in the remaining lawsuit 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 this lawsuit and have responded accordingly. 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 this lawsuit. 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, and we also have exposure to the payment of additional fines, penalties and costs under other applicable federal, state and local laws, statutes and regulations. To the extent any such costs are reasonably estimable, we have included an estimate of such costs in the loss accrual described below. Taking the foregoing into account, as of September 30, 2018 , we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $335 million , which estimate includes actual and projected emergency response and clean-up costs, natural resource damage assessments and certain third party claims settlements, as well as estimates for fines, penalties and certain legal fees. We accrue such estimates of aggregate total costs to “Field operating costs” in our Condensed Consolidated Statement of Operations. This estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the duration of the natural resource damage assessment process and the ultimate amount of damages determined, (ii) the resolution of certain third party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and excluding future claims and lawsuits, (iii) the determination and calculation of fines and penalties, but excluding fines and penalties that are not probable and reasonably estimable and (iv) 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. As of September 30, 2018 , we had a remaining undiscounted gross liability of $65 million related to this event, of which approximately $37 million is presented as a 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”. 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, 2018 , we had collected, subject to customary reservations, $180 million out of the approximate $220 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of September 30, 2018 , we have recognized a receivable of approximately $40 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 $16 million is recognized as a current asset in “Trade accounts receivable and other receivables, net” on our Condensed Consolidated Balance Sheet, with the remainder in “Other long-term assets, net”. We have completed the required clean-up and remediation work as determined by the Unified Command and the Unified Command has been dissolved; however, we expect to make payments for additional costs associated with restoration of the impacted areas, as well as natural resource damage assessment and compensation, legal, professional and regulatory costs, in addition to fines and penalties, during future periods.

Operating Segments

Operating Segments	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Operating Segments	Operating Segments We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. See Note 3 for a summary of the types of products and services from which each segment derives its revenues. Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below) and maintenance capital investment. We define Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus our proportionate share of the depreciation and amortization expense and gains or losses on significant asset sales of unconsolidated entities, and further adjusted for certain selected items including (i) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance. Segment Adjusted EBITDA excludes depreciation and amortization. Maintenance capital consists of capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. The following tables reflect certain financial data for each segment (in millions): Three Months Ended September 30, 2018 Transportation Facilities Supply and Intersegment Adjustment Total Revenues: External customers (1) $ 292 $ 149 $ 8,482 $ (131 ) $ 8,792 Intersegment (2) 206 140 1 131 478 Total revenues of reportable segments $ 498 $ 289 $ 8,483 $ — $ 9,270 Equity earnings in unconsolidated entities $ 110 $ — $ — $ 110 Segment Adjusted EBITDA $ 388 $ 173 $ 75 $ 636 Maintenance capital $ 41 $ 33 $ 4 $ 78 Three Months Ended September 30, 2017 Transportation Facilities Supply and Intersegment Adjustment Total Revenues: External customers (1) $ 274 $ 140 $ 5,573 $ (114 ) $ 5,873 Intersegment (2) 172 151 1 114 438 Total revenues of reportable segments $ 446 $ 291 $ 5,574 $ — $ 6,311 Equity earnings in unconsolidated entities $ 80 $ — $ — $ 80 Segment Adjusted EBITDA $ 363 $ 182 $ (56 ) $ 489 Maintenance capital $ 32 $ 28 $ 3 $ 63 Nine Months Ended September 30, 2018 Transportation Facilities Supply and Intersegment Adjustment Total Revenues: External customers (1) $ 808 $ 437 $ 24,374 $ (350 ) $ 25,269 Intersegment (2) 619 429 2 350 1,400 Total revenues of reportable segments $ 1,427 $ 866 $ 24,376 $ — $ 26,669 Equity earnings in unconsolidated entities $ 281 $ — $ — $ 281 Segment Adjusted EBITDA $ 1,083 $ 530 $ 120 $ 1,733 Maintenance capital $ 102 $ 74 $ 10 $ 186 Nine Months Ended September 30, 2017 Transportation Facilities Supply and Intersegment Adjustment 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 (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 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 from external customers 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 activities are conducted at posted tariff rates where applicable, or otherwise at rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated. Segment Adjusted EBITDA Reconciliation The following table reconciles Segment Adjusted EBITDA to net income attributable to PAGP (in millions): Three Months Ended Nine Months Ended 2018 2017 2018 2017 Segment Adjusted EBITDA $ 636 $ 489 $ 1,733 $ 1,451 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (15 ) (13 ) (44 ) (31 ) Gains/(losses) from derivative activities net of inventory valuation adjustments (3) 110 (216 ) (107 ) 86 Long-term inventory costing adjustments (4) 10 16 18 2 Deficiencies under minimum volume commitments, net (5) 4 (8 ) (9 ) (5 ) Equity-indexed compensation expense (6) (14 ) (7 ) (37 ) (18 ) Net gain/(loss) on foreign currency revaluation (7) 3 14 (5 ) 27 Line 901 incident (8) — — — (12 ) Significant acquisition-related expenses (9) — — — (6 ) Unallocated general and administrative expenses (1 ) — (3 ) (3 ) Depreciation and amortization (131 ) (152 ) (307 ) (403 ) Gain on sale of investment in unconsolidated entities 210 — 210 — Interest expense, net (110 ) (134 ) (327 ) (390 ) Other income/(expense), net (3 ) (1 ) 8 (6 ) Income/(loss) before tax 699 (12 ) 1,130 692 Income tax (expense)/benefit (23 ) 43 (84 ) (85 ) Net income 676 31 1,046 607 Net income attributable to noncontrolling interests (565 ) (27 ) (892 ) (538 ) Net income attributable to PAGP $ 111 $ 4 $ 154 $ 69 (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 and losses on significant asset sales of equity method investments. (3) We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining Segment Adjusted EBITDA. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. (4) We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We exclude the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and writedowns of such inventory that result from price declines from Segment Adjusted EBITDA. (5) We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to Segment Adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results. (6) Includes equity-indexed compensation expense associated with awards that will or may be settled in 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 13 for additional information regarding the Line 901 incident. (9) Includes acquisition-related expenses associated with the acquisition of the Alpha Crude Connector Gathering System (the “ACC Acquisition”). See Note 6 to our Consolidated Financial Statements included in Part IV of our 2017 Annual Report on Form 10-K for additional discussion.

Revenues (Tables)

Revenues (Tables)	9 Months Ended
	Sep. 30, 2018
Disaggregation of Revenue [Line Items]
Disaggregation of Revenue	The following table presents the reconciliation of our revenues from contracts with customers (as described above for each segment) to segment revenues and total revenues as disclosed in our Condensed Consolidated Statement of Operations (in millions): Three Months Ended September 30, 2018 Transportation Facilities Supply and Total Revenues from contracts with customers $ 496 $ 285 $ 8,534 $ 9,315 Other items in revenues 2 4 (51 ) (45 ) Total revenues of reportable segments $ 498 $ 289 $ 8,483 $ 9,270 Intersegment revenues (478 ) Total revenues $ 8,792 Nine Months Ended September 30, 2018 Transportation Facilities Supply and Total Revenues from contracts with customers $ 1,416 $ 845 $ 24,832 $ 27,093 Other items in revenues 11 21 (456 ) (424 ) Total revenues of reportable segments $ 1,427 $ 866 $ 24,376 $ 26,669 Intersegment revenues (1,400 ) Total revenues $ 25,269
Contracts with Customers, Assets and Liabilities	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 Sheet (in millions): September 30, December 31, 2017 Trade accounts receivable arising from revenues from contracts with customers $ 2,910 $ 2,584 Other trade accounts receivables and other receivables (1) 3,482 3,709 Impact due to contractual rights of offset with counterparties (3,438 ) (3,264 ) Trade accounts receivable and other receivables, net $ 2,954 $ 3,029 (1) The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of Topic 606. The following table presents the change in the contract liability balance during the nine months ended September 30, 2018 (in millions): Contract Liabilities Balance at December 31, 2017 $ 90 Amounts recognized as revenue (78 ) Additions (1) (2) 384 Other (3 ) Balance at September 30, 2018 $ 393 (1) Includes approximately $159 million associated with crude oil sales agreements that are entered into in conjunction with storage arrangements and future inventory exchanges. Such amount is expected to be recognized as revenue in the fourth quarter of 2018 . (2) Includes $100 million associated with long-term capacity agreements with Cactus II Pipeline LLC. See Note 12 for additional information.
Remaining Performance Obligations	The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of September 30, 2018 (in millions): Remainder of 2018 2019 2020 2021 2022 2023 and Thereafter Pipeline revenues supported by minimum volume commitments and long-term capacity agreements (1) $ 34 $ 158 $ 199 $ 190 $ 188 $ 831 Long-term storage, terminalling and throughput agreements revenues 118 374 296 214 162 573 Total $ 152 $ 532 $ 495 $ 404 $ 350 $ 1,404 (1) Includes revenues from certain contracts for which the amount and timing of revenue is subject to the completion of underlying construction projects.
Supply and Logistics
Disaggregation of Revenue [Line Items]
Disaggregation of Revenue	The following table presents our Supply and Logistics segment revenues from contracts with customers disaggregated by type of activity (in millions): Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Supply and Logistics segment revenues from contracts with customers Crude oil transactions $ 7,978 $ 22,651 NGL and other transactions 556 2,181 Total Supply and Logistics segment revenues from contracts with customers $ 8,534 $ 24,832
Transportation
Disaggregation of Revenue [Line Items]
Disaggregation of Revenue	The following table presents our Transportation segment revenues from contracts with customers disaggregated by type of activity (in millions): Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Transportation segment revenues from contracts with customers Tariff activities: Crude oil pipelines $ 435 $ 1,237 NGL pipelines 25 76 Total tariff activities 460 1,313 Trucking 36 103 Total Transportation segment revenues from contracts with customers $ 496 $ 1,416
Facilities
Disaggregation of Revenue [Line Items]
Disaggregation of Revenue	The following table presents our Facilities segment revenues from contracts with customers disaggregated by type of activity (in millions): Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Facilities segment revenues from contracts with customers Crude oil, NGL and other terminalling and storage $ 174 $ 511 NGL and natural gas processing and fractionation 87 278 Rail load / unload 24 56 Total Facilities segment revenues from contracts with customers $ 285 $ 845

Net Income Per Class A Share (T

Net Income Per Class A Share (Tables)	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Calculation of basic and diluted net income per Class A share	The following table sets forth the computation of basic and diluted net income per Class A share (in millions, except per share data): Three Months Ended Nine Months Ended 2018 2017 2018 2017 Basic and Diluted Net Income per Class A Share Net income attributable to PAGP $ 111 $ 4 $ 154 $ 69 Basic and diluted weighted average Class A shares outstanding 158 154 157 142 Basic and diluted net income per Class A share $ 0.70 $ 0.03 $ 0.98 $ 0.49

Inventory, Linefill and Base _2

Inventory, Linefill and Base Gas and Long-term Inventory (Tables)	9 Months Ended
	Sep. 30, 2018
Inventory, Linefill and Base Gas and Long-term Inventory
Schedule of 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, 2018 December 31, 2017 Volumes Unit of Carrying Price/ (1) Volumes Unit of Carrying Price/ (1) Inventory Crude oil 7,020 barrels $ 389 $ 55.41 7,800 barrels $ 402 $ 51.54 NGL 15,122 barrels 422 $ 27.91 10,774 barrels 294 $ 27.29 Other N/A 13 N/A N/A 17 N/A Inventory subtotal 824 713 Linefill and base gas Crude oil 13,033 barrels 756 $ 58.01 12,340 barrels 719 $ 58.27 NGL 1,764 barrels 50 $ 28.34 1,597 barrels 45 $ 28.18 Natural gas 24,976 Mcf 108 $ 4.32 24,976 Mcf 108 $ 4.32 Linefill and base gas subtotal 914 872 Long-term inventory Crude oil 1,882 barrels 112 $ 59.51 1,870 barrels 105 $ 56.15 NGL 2,351 barrels 67 $ 28.50 2,167 barrels 59 $ 27.23 Long-term inventory subtotal 179 164 Total $ 1,917 $ 1,749 (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.

Goodwill (Tables)

Goodwill (Tables)	9 Months Ended
	Sep. 30, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of goodwill by segment and changes during the period	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, 2017 $ 1,070 $ 988 $ 508 $ 2,566 Foreign currency translation adjustments (8 ) (3 ) (2 ) (13 ) Dispositions (10 ) (3 ) — (13 ) Balance at September 30, 2018 $ 1,052 $ 982 $ 506 $ 2,540

Debt (Tables)

Debt (Tables)	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Schedule of debt	Debt consisted of the following (in millions): September 30, December 31, SHORT-TERM DEBT PAA commercial paper notes, bearing a weighted-average interest rate of 3.3% (1) $ 60 $ — PAA senior secured hedged inventory facility, bearing a weighted-average interest rate of 3.2% and 2.6%, respectively (1) 300 664 Other 69 73 Total short-term debt (2) 429 737 LONG-TERM DEBT PAA senior notes, net of unamortized discounts and debt issuance costs of $61 and $67, respectively 8,939 8,933 PAA commercial paper notes and senior secured hedged inventory facility borrowings (3) — 247 PAA GO Zone term loans, net of debt issuance costs of $2, bearing a weighted-average interest rate of 2.9% 198 — Other 3 3 Total long-term debt 9,140 9,183 Total debt (4) $ 9,569 $ 9,920 (1) We classified these PAA commercial paper notes and credit facility borrowings as short-term as of September 30, 2018 and December 31, 2017 , 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, 2018 and December 31, 2017 , balance includes borrowings for cash margin deposits with NYMEX and ICE, which are associated with financial derivatives used for hedging purposes. (3) As of December 31, 2017 , we classified a portion of PAA’s commercial paper notes and PAA's credit facility borrowings as long-term based on PAA’s ability and intent to refinance such amounts on a long-term basis. (4) PAA’s fixed-rate senior notes had a face value of approximately $9.0 billion at both September 30, 2018 and December 31, 2017 . We estimated the aggregate fair value of these notes as of September 30, 2018 and December 31, 2017 to be approximately $8.8 billion and $9.1 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.

Partners' Capital and Distrib_2

Partners' Capital and Distributions (Tables)	9 Months Ended
	Sep. 30, 2018
Partners' Capital and Distributions
Schedule of activity for Class A shares, Class B shares and Class C shares	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, 2017 156,111,139 126,984,572 510,925,432 Exchange Right exercises (1) 3,038,396 (3,038,396 ) — Redemption Right exercises (1) — (3,306,476 ) 3,306,476 Issuance of Series A preferred units by a subsidiary — — 1,393,926 Other 11,250 — 512,166 Outstanding at September 30, 2018 159,160,785 120,639,700 516,138,000 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 for acquisition of interest in Advantage Joint Venture — — 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 ___________________________________________ (1) See Note 11 to our Consolidated Financial Statements included in Part IV of our 2017 Annual Report on Form 10-K for information regarding conversions of AAP Management Units, Exchange Rights and Redemption Rights.
AAP
Partners' Capital and Distributions
Schedule of distributions	The following table details the distributions paid to AAP’s partners during or pertaining to the first nine months of 2018 from distributions received from PAA (in millions): Distribution to AAP's Partners Distribution Payment Date Noncontrolling Interests PAGP Total Cash Distributions November 14, 2018 (1) $ 36 $ 48 $ 84 August 14, 2018 $ 37 $ 48 $ 85 May 15, 2018 $ 38 $ 47 $ 85 February 14, 2018 $ 38 $ 47 $ 85 ___________________________________________ (1) Payable to unitholders of record at the close of business on October 31, 2018 for the period from July 1, 2018 through September 30, 2018 .
Class A Shares
Partners' Capital and Distributions
Schedule of distributions	The following table details distributions to our Class A shareholders paid during or pertaining to the first nine months of 2018 (in millions, except per share data): Distribution Payment Date Distributions to Class A Shareholders Distributions per Class A Share November 14, 2018 (1) $ 48 $ 0.30 August 14, 2018 $ 48 $ 0.30 May 15, 2018 $ 47 $ 0.30 February 14, 2018 $ 47 $ 0.30 ___________________________________________ (1) Payable to shareholders of record at the close of business on October 31, 2018 for the period from July 1, 2018 through September 30, 2018 .
Series A Preferred Units | PAA
Partners' Capital and Distributions
Schedule of distributions	The following table details distributions to PAA’s Series A preferred unitholders paid during or pertaining to the first nine months of 2018 (in millions, except unit and per unit data): Series A Preferred Unitholders Distribution (2) Distribution per Unit Distribution Payment Date Cash Units November 14, 2018 (1) $ 37 — $ 0.525 August 14, 2018 $ 37 — $ 0.525 May 15, 2018 $ 37 — $ 0.525 February 14, 2018 $ — 1,393,926 $ 0.525 (1) Payable to unitholders of record at the close of business on October 31, 2018 for the period from July 1, 2018 through September 30, 2018 . At September 30, 2018 , such amount was accrued to distributions payable in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet. (2) On February 14, 2018, PAA issued additional Series A preferred units in lieu of a cash distribution of $37 million . With respect to quarters ending on or prior to December 31, 2017 (the “Initial Distribution Period”), PAA elected to pay distributions on its Series A preferred units in additional Series A preferred units. The Initial Distribution Period ended with the February 2018 distribution; as such, with respect to quarters ending after the Initial Distribution Period, distributions on PAA’s Series A preferred units are paid in cash.
Series B Preferred Units | PAA
Partners' Capital and Distributions
Schedule of distributions	The following table details distributions paid or to be paid to PAA’s Series B preferred unitholders (in millions, except per unit data): Series B Preferred Unitholders Distribution Payment Date Cash Distribution Distribution per Unit November 15, 2018 (1) $ 24.5 $ 30.625 May 15, 2018 $ 24.5 $ 30.625 (1) Payable to unitholders of record at the close of business on November 1, 2018 for the period from May 15, 2018 through November 14, 2018.
Common Units | PAA
Partners' Capital and Distributions
Schedule of distributions	The following table details distributions paid to PAA’s common unitholders during or pertaining to the first nine months of 2018 (in millions, except per unit data): Distributions Cash Distribution per Common Unit Common Unitholders Total Cash Distribution Distribution Payment Date Public AAP November 14, 2018 (1) $ 134 $ 84 $ 218 $ 0.30 August 14, 2018 $ 133 $ 85 $ 218 $ 0.30 May 15, 2018 $ 133 $ 85 $ 218 $ 0.30 February 14, 2018 $ 133 $ 85 $ 218 $ 0.30 (1) Payable to unitholders of record at the close of business on October 31, 2018 for the period from July 1, 2018 through September 30, 2018 .

Derivatives and Risk Manageme_2

Derivatives and Risk Management Activities (Tables)	9 Months Ended
	Sep. 30, 2018
Derivatives and Risk Management Activities
Impact of derivatives recognized in earnings	A summary of the impact of our derivatives recognized in earnings is as follows (in millions): Three Months Ended September 30, 2018 Three Months Ended September 30, 2017 Location of Gain/(Loss) Derivatives in Derivatives Total Derivatives in Derivatives Total Commodity Derivatives Supply and Logistics segment revenues $ — $ (59 ) $ (59 ) $ — $ (226 ) $ (226 ) Field operating costs — (1 ) (1 ) — (4 ) (4 ) Interest Rate Derivatives Interest expense, net (2 ) — (2 ) (10 ) — (10 ) Foreign Currency Derivatives Supply and Logistics segment revenues — 5 5 — 3 3 Preferred Distribution Rate Reset Option Other income/(expense), net — (2 ) (2 ) — 2 2 Total Gain/(Loss) on Derivatives Recognized in Net Income $ (2 ) $ (57 ) $ (59 ) $ (10 ) $ (225 ) $ (235 ) Nine Months Ended September 30, 2018 Nine Months Ended September 30, 2017 Location of Gain/(Loss) Derivatives in Derivatives Total Derivatives in Derivatives Total Commodity Derivatives Supply and Logistics segment revenues $ — $ (443 ) $ (443 ) $ — $ (31 ) $ (31 ) Field operating costs — — — — (8 ) (8 ) Depreciation and amortization — — — (3 ) — (3 ) Interest Rate Derivatives Interest expense, net (3 ) — (3 ) (16 ) — (16 ) Foreign Currency Derivatives Supply and Logistics segment revenues — (7 ) (7 ) — 5 5 Preferred Distribution Rate Reset Option Other income/(expense), net — 3 3 — — — Total Gain/(Loss) on Derivatives Recognized in Net Income $ (3 ) $ (447 ) $ (450 ) $ (19 ) $ (34 ) $ (53 )
Summary of derivative assets and liabilities on Condensed Consolidated Balance Sheets on a gross basis	The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of September 30, 2018 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Fair Balance Sheet Fair Derivatives designated as hedging instruments: Interest rate derivatives Other current assets $ 12 Other long-term assets, net 3 Total derivatives designated as hedging instruments $ 15 $ — Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ 146 Other current assets $ (358 ) Other long-term assets, net 54 Other long-term assets, net (2 ) Other current liabilities 60 Other current liabilities (211 ) Other long-term liabilities and deferred credits 9 Other long-term liabilities and deferred credits (39 ) Foreign currency derivatives Other current assets 4 Other current assets (1 ) Other current liabilities (1 ) Preferred Distribution Rate Reset Option Other long-term liabilities and deferred credits (19 ) Total derivatives not designated as hedging instruments $ 273 $ (631 ) Total derivatives $ 288 $ (631 ) The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of December 31, 2017 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Fair Balance Sheet Fair Derivatives designated as hedging instruments: Interest rate derivatives Other current liabilities $ 2 Other current liabilities $ (27 ) Other long-term liabilities and deferred credits (11 ) Total derivatives designated as hedging instruments $ 2 $ (38 ) Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ 73 Other current assets $ (227 ) Other long-term assets, net 1 Other current liabilities (131 ) Other current liabilities 5 Other long-term liabilities and deferred credits (5 ) Other long-term liabilities and deferred credits 3 Foreign currency derivatives Other current assets 6 Other current assets (2 ) Preferred Distribution Rate Reset Option Other long-term liabilities and deferred credits (22 ) Total derivatives not designated as hedging instruments $ 88 $ (387 ) Total derivatives $ 90 $ (425 )
Schedule of net broker receivables	The following table provides the components of our net broker receivable: September 30, December 31, Initial margin $ 139 $ 48 Variation margin posted 222 164 Letters of credit (102 ) — Net broker receivable $ 259 $ 212
Schedule of derivative financial assets that are subject to offsetting, including enforceable master netting arrangements	The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions): September 30, 2018 December 31, 2017 Derivative Derivative Derivative Derivative Netting Adjustments: Gross position - asset/(liability) $ 288 $ (631 ) $ 90 $ (425 ) Netting adjustment (430 ) 430 (239 ) 239 Cash collateral paid 259 — 212 — Net position - asset/(liability) $ 117 $ (201 ) $ 63 $ (186 ) Balance Sheet Location After Netting Adjustments: Other current assets $ 62 $ — $ 62 $ — Other long-term assets, net 55 — 1 — Other current liabilities — (152 ) — (151 ) Other long-term liabilities and deferred credits — (49 ) — (35 ) $ 117 $ (201 ) $ 63 $ (186 )
Schedule of derivative financial liabilities that are subject to offsetting, including enforceable master netting arrangements	The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions): September 30, 2018 December 31, 2017 Derivative Derivative Derivative Derivative Netting Adjustments: Gross position - asset/(liability) $ 288 $ (631 ) $ 90 $ (425 ) Netting adjustment (430 ) 430 (239 ) 239 Cash collateral paid 259 — 212 — Net position - asset/(liability) $ 117 $ (201 ) $ 63 $ (186 ) Balance Sheet Location After Netting Adjustments: Other current assets $ 62 $ — $ 62 $ — Other long-term assets, net 55 — 1 — Other current liabilities — (152 ) — (151 ) Other long-term liabilities and deferred credits — (49 ) — (35 ) $ 117 $ (201 ) $ 63 $ (186 )
Net deferred gain recognized in AOCI for derivatives	The following table summarizes the net unrealized gain/(loss) recognized in AOCI for derivatives (in millions): Three Months Ended Nine Months Ended 2018 2017 2018 2017 Interest rate derivatives, net $ 15 $ (3 ) $ 60 $ (15 )
Schedule of derivative financial assets and liabilities accounted for at fair value on a recurring basis, by level within the fair value hierarchy	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, 2018 Fair Value as of December 31, 2017 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ (11 ) $ (326 ) $ (4 ) $ (341 ) $ 5 $ (278 ) $ (8 ) $ (281 ) Interest rate derivatives — 15 — 15 — (36 ) — (36 ) Foreign currency derivatives — 2 — 2 — 4 — 4 Preferred Distribution Rate Reset Option — — (19 ) (19 ) — — (22 ) (22 ) Total net derivative asset/(liability) $ (11 ) $ (309 ) $ (23 ) $ (343 ) $ 5 $ (310 ) $ (30 ) $ (335 ) (1) Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.
Reconciliation of changes in fair value of derivatives classified as Level 3	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 Nine Months Ended 2018 2017 2018 2017 Beginning Balance $ (18 ) $ (30 ) $ (30 ) $ (36 ) Net gains/(losses) for the period included in earnings (5 ) (8 ) 2 (1 ) Settlements — (1 ) 7 4 Derivatives entered into during the period — (2 ) (2 ) (8 ) Ending Balance $ (23 ) $ (41 ) $ (23 ) $ (41 ) Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ (5 ) $ (10 ) $ — $ (8 )
Interest Rate Derivatives
Derivatives and Risk Management Activities
Schedule of terms of outstanding interest rate derivatives	The following table summarizes the terms of our outstanding interest rate derivatives as of September 30, 2018 (notional amounts in millions): Hedged Transaction Number and Types of Notional Expected Average Rate Accounting Anticipated interest payments 8 forward starting swaps (30-year) $ 200 6/14/2019 2.83 % Cash flow hedge Anticipated interest payments 8 forward starting swaps $ 200 6/15/2020 3.06 % Cash flow hedge
Foreign Currency Derivatives
Derivatives and Risk Management Activities
Summary of open forward exchange contracts	The following table summarizes our open forward exchange contracts as of September 30, 2018 (in millions): USD CAD Average Exchange Rate Forward exchange contracts that exchange CAD for USD: 2018 $ 174 $ 227 $1.00 - $1.30 Forward exchange contracts that exchange USD for CAD: 2018 $ 418 $ 543 $1.00 - $1.30 2019 $ 120 $ 155 $1.00 - $1.30

Related Party Transactions (Tab

Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2018
Oxy
Related Party Transaction [Line Items]
Schedule of related party transactions	The impact to our Condensed Consolidated Statements of Operations from those transactions is included below (in millions): Three Months Ended Nine Months Ended 2018 2017 2018 2017 Revenues $ 260 $ 204 $ 818 $ 657 Purchases and related costs (1) $ (22 ) $ (68 ) $ (184 ) $ (169 ) (1) Crude oil purchases that are part of inventory exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Condensed Consolidated Statements of Operations. We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with Oxy were as follows (in millions): September 30, December 31, Trade accounts receivable and other receivables $ 1,039 $ 1,075 Accounts payable $ 976 $ 990

Operating Segments (Tables)

Operating Segments (Tables)	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Segment financial data	The following tables reflect certain financial data for each segment (in millions): Three Months Ended September 30, 2018 Transportation Facilities Supply and Intersegment Adjustment Total Revenues: External customers (1) $ 292 $ 149 $ 8,482 $ (131 ) $ 8,792 Intersegment (2) 206 140 1 131 478 Total revenues of reportable segments $ 498 $ 289 $ 8,483 $ — $ 9,270 Equity earnings in unconsolidated entities $ 110 $ — $ — $ 110 Segment Adjusted EBITDA $ 388 $ 173 $ 75 $ 636 Maintenance capital $ 41 $ 33 $ 4 $ 78 Three Months Ended September 30, 2017 Transportation Facilities Supply and Intersegment Adjustment Total Revenues: External customers (1) $ 274 $ 140 $ 5,573 $ (114 ) $ 5,873 Intersegment (2) 172 151 1 114 438 Total revenues of reportable segments $ 446 $ 291 $ 5,574 $ — $ 6,311 Equity earnings in unconsolidated entities $ 80 $ — $ — $ 80 Segment Adjusted EBITDA $ 363 $ 182 $ (56 ) $ 489 Maintenance capital $ 32 $ 28 $ 3 $ 63 Nine Months Ended September 30, 2018 Transportation Facilities Supply and Intersegment Adjustment Total Revenues: External customers (1) $ 808 $ 437 $ 24,374 $ (350 ) $ 25,269 Intersegment (2) 619 429 2 350 1,400 Total revenues of reportable segments $ 1,427 $ 866 $ 24,376 $ — $ 26,669 Equity earnings in unconsolidated entities $ 281 $ — $ — $ 281 Segment Adjusted EBITDA $ 1,083 $ 530 $ 120 $ 1,733 Maintenance capital $ 102 $ 74 $ 10 $ 186 Nine Months Ended September 30, 2017 Transportation Facilities Supply and Intersegment Adjustment 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 (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 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 from external customers 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 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.
Reconciliation of segment adjusted EBITDA to net income attributable to PAGP	The following table reconciles Segment Adjusted EBITDA to net income attributable to PAGP (in millions): Three Months Ended Nine Months Ended 2018 2017 2018 2017 Segment Adjusted EBITDA $ 636 $ 489 $ 1,733 $ 1,451 Adjustments (1) : Depreciation and amortization of unconsolidated entities (2) (15 ) (13 ) (44 ) (31 ) Gains/(losses) from derivative activities net of inventory valuation adjustments (3) 110 (216 ) (107 ) 86 Long-term inventory costing adjustments (4) 10 16 18 2 Deficiencies under minimum volume commitments, net (5) 4 (8 ) (9 ) (5 ) Equity-indexed compensation expense (6) (14 ) (7 ) (37 ) (18 ) Net gain/(loss) on foreign currency revaluation (7) 3 14 (5 ) 27 Line 901 incident (8) — — — (12 ) Significant acquisition-related expenses (9) — — — (6 ) Unallocated general and administrative expenses (1 ) — (3 ) (3 ) Depreciation and amortization (131 ) (152 ) (307 ) (403 ) Gain on sale of investment in unconsolidated entities 210 — 210 — Interest expense, net (110 ) (134 ) (327 ) (390 ) Other income/(expense), net (3 ) (1 ) 8 (6 ) Income/(loss) before tax 699 (12 ) 1,130 692 Income tax (expense)/benefit (23 ) 43 (84 ) (85 ) Net income 676 31 1,046 607 Net income attributable to noncontrolling interests (565 ) (27 ) (892 ) (538 ) Net income attributable to PAGP $ 111 $ 4 $ 154 $ 69 (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 and losses on significant asset sales of equity method investments. (3) We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining Segment Adjusted EBITDA. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. (4) We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We exclude the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and writedowns of such inventory that result from price declines from Segment Adjusted EBITDA. (5) We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to Segment Adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results. (6) Includes equity-indexed compensation expense associated with awards that will or may be settled in 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 13 for additional information regarding the Line 901 incident. (9) Includes acquisition-related expenses associated with the acquisition of the Alpha Crude Connector Gathering System (the “ACC Acquisition”). See Note 6 to our Consolidated Financial Statements included in Part IV of our 2017 Annual Report on Form 10-K for additional discussion.

Organization and Basis of Con_2

Organization and Basis of Consolidation and Presentation - Additional Information (Details) shares in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)segmentshares	Dec. 31, 2017USD ($)
Organization and basis of presentation
Operating segments number | segment	3
Deferred tax asset | $	$ 1,347	$ 1,386
PAA | AAP
Organization and basis of presentation
Ownership interest in the subsidiary	35.00%
Ownership interest in the subsidiary (units)	281
GP LLC
Organization and basis of presentation
Ownership interest in the subsidiary	100.00%
AAP
Organization and basis of presentation
Ownership interest in the subsidiary	57.00%
Ownership interest in the subsidiary (units)	158.2
AAP | GP LLC
Organization and basis of presentation
Ownership interest in the subsidiary (units)	1
Consolidated Entity Excluding VIE
Organization and basis of presentation
Deferred tax asset | $	$ 1,347	$ 1,386

Recent Accounting Pronounceme_2

Recent Accounting Pronouncements - Additional Information (Details) - USD ($) $ in Millions	Sep. 30, 2018	Jan. 01, 2018	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impact on Investments in unconsolidated entities	$ 2,539		$ 2,756
ASU 2017-05
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impact on Investments in unconsolidated entities		$ 113
Impact on retained earnings		$ 113	$ 113

Revenues - Disaggregation of Re

Revenues - Disaggregation of Revenue (Details) - Operating Segments - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 9,315	$ 27,093
Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	8,534	24,832
Supply and Logistics | Crude oil transactions
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	7,978	22,651
Supply and Logistics | NGL and other transactions
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	556	2,181
Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	496	1,416
Transportation | Total tariff activities
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	460	1,313
Transportation | Crude oil pipelines
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	435	1,237
Transportation | NGL pipelines
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	25	76
Transportation | Trucking
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	36	103
Facilities
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	285	845
Facilities | Crude oil, NGL and other terminalling and storage
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	174	511
Facilities | NGL and natural gas processing and fractionation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	87	278
Facilities | Rail load / unload
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 24	$ 56

Revenues - Segment Revenue (Det

Revenues - Segment Revenue (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Disaggregation of Revenue [Line Items]
Total revenues	$ 8,792	$ 5,873	$ 25,269	$ 18,618
Transportation
Disaggregation of Revenue [Line Items]
Total revenues	161	160	458	459
Facilities
Disaggregation of Revenue [Line Items]
Total revenues	149	140	437	410
Supply and Logistics
Disaggregation of Revenue [Line Items]
Total revenues	8,482	5,573	24,374	17,749
Operating Segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	9,315		27,093
Total revenues	9,270	6,311	26,669	19,890
Operating Segments | Transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	496		1,416
Total revenues	498	446	1,427	1,260
Operating Segments | Facilities
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	285		845
Total revenues	289	291	866	873
Operating Segments | Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	8,534		24,832
Total revenues	8,483	5,574	24,376	17,757
Intersegment
Disaggregation of Revenue [Line Items]
Total revenues	(478)	(438)	(1,400)	(1,272)
Intersegment | Transportation
Disaggregation of Revenue [Line Items]
Total revenues	(206)	(172)	(619)	(503)
Intersegment | Facilities
Disaggregation of Revenue [Line Items]
Total revenues	(140)	(151)	(429)	(463)
Intersegment | Supply and Logistics
Disaggregation of Revenue [Line Items]
Total revenues	(1)	$ (1)	(2)	$ (8)
Other | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenues	(45)		(424)
Other | Operating Segments | Transportation
Disaggregation of Revenue [Line Items]
Total revenues	2		11
Other | Operating Segments | Facilities
Disaggregation of Revenue [Line Items]
Total revenues	4		21
Other | Operating Segments | Supply and Logistics
Disaggregation of Revenue [Line Items]
Total revenues	$ (51)		$ (456)

Revenues - Contract Assets and

Revenues - Contract Assets and Liabilities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Contract With Customer, Asset And Liability [Line Items]
Revenue recognized	$ 78
Other current assets	320	$ 221
Contract liability, deferred revenue	$ 393	90
General payment terms	P30D
Trade accounts receivable arising from revenues from contracts with customers	$ 2,910	2,584
Other trade accounts receivables and other receivables	3,482	3,709
Impact due to contractual rights of offset with counterparties	(3,438)	(3,264)
Trade accounts receivable and other receivables, net	2,954	3,029
Minimum Volume Commitments
Contract With Customer, Asset And Liability [Line Items]
Contract liability, deferred revenue	42	37
Counterparty deficiencies	62	57
Counterparty deficiencies unbilled and uncollected	20	$ 20
Crude Oil Sales Agreements Entered Into In Conjunction WIth Storage Arrangements And Future Inventory Exchanges
Contract With Customer, Asset And Liability [Line Items]
Other current assets	157
Contract liability, deferred revenue	$ 159

Revenues - Contract Balances (D

Revenues - Contract Balances (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)
Change in Contract Liabilities [Roll Forward]
Beginning balance	$ 90
Amounts recognized as revenue	(78)
Additions	384
Other	(3)
Ending balance	393
Crude Oil Sales Agreements Entered Into In Conjunction WIth Storage Arrangements And Future Inventory Exchanges
Change in Contract Liabilities [Roll Forward]
Additions	159
Ending balance	159
Long-term capacity agreement | Cactus II Pipeline LLC
Change in Contract Liabilities [Roll Forward]
Additions	$ 100

Revenues - Performance Obligati

Revenues - Performance Obligations (Details) $ in Millions	Sep. 30, 2018USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2018-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 152
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	532
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	495
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	404
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	350
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	1,404
Pipeline revenues supported by minimum volume commitments and long-term capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2018-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	34
Pipeline revenues supported by minimum volume commitments and long-term capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	158
Pipeline revenues supported by minimum volume commitments and long-term capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	199
Pipeline revenues supported by minimum volume commitments and long-term capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	190
Pipeline revenues supported by minimum volume commitments and long-term capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	188
Pipeline revenues supported by minimum volume commitments and long-term capacity agreements | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	831
Long-term storage, terminalling and throughput agreements revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2018-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	118
Long-term storage, terminalling and throughput agreements revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	374
Long-term storage, terminalling and throughput agreements revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	296
Long-term storage, terminalling and throughput agreements revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	214
Long-term storage, terminalling and throughput agreements revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	162
Long-term storage, terminalling and throughput agreements revenues | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 573

Net Income Per Class A Share (D

Net Income Per Class A Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Basic and Diluted Net Income per Class A Share
Net income attributable to PAGP	$ 111	$ 4	$ 154	$ 69
Class A Shares
Basic and Diluted Net Income per Class A Share
Basic and diluted weighted average Class A shares outstanding (in shares)	158	154	157	142
Basic and diluted net income per Class A share (in dollars per share)	$ 0.70	$ 0.03	$ 0.98	$ 0.49
Maximum
Net Income Per Class A Share
Dilutive LTIP awards (shares), less than	0.1	0.1	0.1	0.1

Accounts Receivable, Net (Detai

Accounts Receivable, Net (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Accounts Receivable, Net
Advance cash payments received from third parties to mitigate credit risk	$ 136	$ 117
Standby letters of credit	$ 36	$ 54
Substantially all trade accounts receivable, net, maximum age of balances past their scheduled invoice date	30 days	30 days
Allowance for doubtful accounts receivable	$ 3	$ 3

Inventory, Linefill and Base _3

Inventory, Linefill and Base Gas and Long-term Inventory (Details) bbl in Thousands, Mcf in Thousands, $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)$ / Mcf$ / bblMcfbbl	Dec. 31, 2017USD ($)$ / Mcf$ / bblMcfbbl
Inventory by category
Inventory		$ 824	$ 713
Linefill and base gas		914	872
Long-term inventory		179	164
Total		1,917	1,749
Charge related to the writedown of inventory	$ 35
Crude oil
Inventory by category
Inventory		389	402
Linefill and base gas		756	719
Long-term inventory		$ 112	$ 105
Inventory, Volumes (in barrels or in Mcf) | bbl		7,020	7,800
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl		13,033	12,340
Long-term inventory, Volumes (in barrels or in Mcf) | bbl		1,882	1,870
Inventory (Price/Unit of measure) | $ / bbl		55.41	51.54
Linefill and base gas (Price/Unit of measure) | $ / bbl		58.01	58.27
Long-term inventory (Price/Unit of measure) | $ / bbl		59.51	56.15
NGL
Inventory by category
Inventory		$ 422	$ 294
Linefill and base gas		50	45
Long-term inventory		$ 67	$ 59
Inventory, Volumes (in barrels or in Mcf) | bbl		15,122	10,774
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl		1,764	1,597
Long-term inventory, Volumes (in barrels or in Mcf) | bbl		2,351	2,167
Inventory (Price/Unit of measure) | $ / bbl		27.91	27.29
Linefill and base gas (Price/Unit of measure) | $ / bbl		28.34	28.18
Long-term inventory (Price/Unit of measure) | $ / bbl		28.50	27.23
Natural gas
Inventory by category
Linefill and base gas		$ 108	$ 108
Linefill and base gas, Volumes (in barrels or in Mcf) | Mcf		24,976	24,976
Linefill and base gas (Price/Unit of measure) | $ / Mcf		4.32	4.32
Other
Inventory by category
Inventory		$ 13	$ 17

Divestitures - Dispositions an

Divestitures - Dispositions and Divestitures (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018	Sep. 30, 2017
Dispositions
Proceeds from sales of assets		$ 1,298	$ 407
Gain on sale of investment in unconsolidated entities	$ 210	210
Depreciation and amortization
Dispositions
Recognized gains/(losses related to sale of assets, net	$ 2	79
Recognized gains related to sale of assets		105
Recognized losses related to sale of assets		$ 26
BridgeTex Pipeline Company, LLC
Dispositions
Ownership percentage sold	30.00%	30.00%
Proceeds from sale of equity method investments	$ 868
Ownership percentage	20.00%	20.00%
Gain on sale of investment in unconsolidated entities	$ 210

Goodwill (Details)

Goodwill (Details)	9 Months Ended
	Sep. 30, 2018USD ($)
Changes in goodwill
Beginning Balance	$ 2,566,000,000
Foreign currency translation adjustments	(13,000,000)
Dispositions	(13,000,000)
Ending Balance	2,540,000,000
Goodwill impairment	0
Operating Segments | Transportation
Changes in goodwill
Beginning Balance	1,070,000,000
Foreign currency translation adjustments	(8,000,000)
Dispositions	(10,000,000)
Ending Balance	1,052,000,000
Operating Segments | Facilities
Changes in goodwill
Beginning Balance	988,000,000
Foreign currency translation adjustments	(3,000,000)
Dispositions	(3,000,000)
Ending Balance	982,000,000
Operating Segments | Supply and Logistics
Changes in goodwill
Beginning Balance	508,000,000
Foreign currency translation adjustments	(2,000,000)
Ending Balance	$ 506,000,000

Debt - Components (Details)

Debt - Components (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Short-term debt:
Total short-term debt	$ 429	$ 737
Long-term debt:
PAA senior notes, net of unamortized discounts and debt issuance costs of $61 and $67, respectively	8,939	8,933
Other long-term debt	201	250
Total long-term debt	9,140	9,183
Total debt	9,569	9,920
Senior notes
Long-term debt:
PAA senior notes, net of unamortized discounts and debt issuance costs of $61 and $67, respectively	8,939	8,933
Unamortized discounts and debt issuance costs	61	67
Debt instrument face value	9,000	9,000
Other
Long-term debt:
Other long-term debt	3	3
Level 2 | Senior notes
Long-term debt:
Debt instrument fair value	8,800	9,100
Commercial paper notes
Short-term debt:
Short-term notes and borrowings	$ 60
Weighted average interest rate, short-term	3.30%
Other
Short-term debt:
Total short-term debt	$ 69	73
Senior secured hedged inventory facility | Commercial paper notes
Long-term debt:
Other long-term debt		247
Senior secured hedged inventory facility | Credit facility
Short-term debt:
Short-term notes and borrowings	$ 300	$ 664
Weighted average interest rate, short-term	3.20%	2.60%
GO Zone term loans | Term loan
Long-term debt:
Other long-term debt	$ 198
Weighted average interest rate, long-term	2.90%
Debt issuance costs	$ 2

Debt - Letters of Credit, Borr

Debt - Letters of Credit, Borrowings and Repayments (Details)	1 Months Ended	9 Months Ended
	Aug. 31, 2018USD ($)debt_instrument	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)
Debt
Outstanding letters of credit		$ 181,000,000		$ 166,000,000
Credit agreements and PAA commercial paper program
Debt
Total borrowings		38,600,000,000	$ 52,600,000,000
Total repayments		$ 39,200,000,000	$ 52,700,000,000
Term loan | GO Zone term loans
Debt
Number of debt instruments | debt_instrument	2
Term loan | GO Zone term loan 1
Debt
Debt instrument face value	$ 100,000,000
Term loan | GO Zone term loan 2
Debt
Debt instrument face value	$ 100,000,000
Credit facility | Senior unsecured revolving credit facility
Debt
Maturity extension	1 year
Expired borrowing capacity	$ 1,000,000,000

Partners' Capital and Distrib_3

Partners' Capital and Distributions - Exchange Rights and Shares Activity (Details) - shares	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Class A Shares
Activity for Class A shares and Class B shares
Balance, beginning of period (shares)	156,111,139	101,206,526
Exchange Right exercises (shares)	3,038,396	3,231,281
Sales of Class A shares (shares)		50,086,326
Other (shares)	11,250	19,060
Balance, end of period (shares)	159,160,785	154,543,193
Class B Shares
Activity for Class A shares and Class B shares
Balance, beginning of period (shares)	126,984,572	138,043,486
Conversion of AAP Management Units (shares)		1,557,860
Exchange Right exercises (shares)	(3,038,396)	(3,231,281)
Redemption Right exercises (shares)	(3,306,476)	(4,959,861)
Balance, end of period (shares)	120,639,700	131,410,204
Class C Shares
Activity for Class A shares and Class B shares
Balance, beginning of period (shares)	510,925,432	491,910,863
Redemption Right exercises (shares)	3,306,476	4,959,861
Sales of common units by a subsidiary (shares)		4,033,567
Issuance of common units by a subsidiary for acquisition of interest in Advantage Joint Venture (shares)		1,252,269
Issuance of Series A preferred units by a subsidiary (shares)	1,393,926	3,941,096
Other (shares)	512,166	603,497
Balance, end of period (shares)	516,138,000	506,701,153

Partners' Capital and Distrib_4

Partners' Capital and Distributions - Distributions, Class A (Details) - Class A Shares - USD ($) $ / shares in Units, $ in Millions	Nov. 14, 2018	Aug. 14, 2018	May 15, 2018	Feb. 14, 2018
Partners' Capital and Distributions
Distributions to Class A shareholders		$ 48	$ 47	$ 47
Distribution per Class A share, paid (usd per share)		$ 0.30	$ 0.30	$ 0.30
Forecast
Partners' Capital and Distributions
Distributions to Class A shareholders	$ 48
Distribution per Class A share, paid (usd per share)	$ 0.30

Partners' Capital and Distrib_5

Partners' Capital and Distributions - Noncontrolling Interests in Subsidiaries (Details)	Sep. 30, 2018
AAP
Partners' Capital and Distributions
Noncontrolling interests in subsidiaries (percent)	43.00%
Common Units and Series A Preferred Units | PAA
Partners' Capital and Distributions
Noncontrolling interests in subsidiaries (percent)	65.00%
Series B Preferred Units | PAA
Partners' Capital and Distributions
Noncontrolling interests in subsidiaries (percent)	100.00%

Partners' Capital and Distrib_6

Partners' Capital and Distributions - Subsidiary Distributions (Details) - USD ($) $ / shares in Units, $ in Millions	Nov. 15, 2018	Nov. 14, 2018	Aug. 14, 2018	May 15, 2018	Feb. 14, 2018	Sep. 30, 2018	Sep. 30, 2017
Partners' Capital and Distributions
Total distributions paid						$ 802	$ 1,170
PAA | Common Units | Cash Distributions
Partners' Capital and Distributions
Total distributions paid			$ 218	$ 218	$ 218
Distributions per common unit, paid (usd per unit)			$ 0.3	$ 0.3	$ 0.3
PAA | Series A Preferred Units | Cash Distributions
Partners' Capital and Distributions
Preferred unit distribution amount			$ 37	$ 37
Preferred Stock, Dividends, Per Share, Cash Paid			$ 0.525	$ 0.525
PAA | Series A Preferred Units | In-Kind Distributions
Partners' Capital and Distributions
Distribution of units in lieu of cash (units)					1,393,926
Preferred unit distribution amount					$ 37
Preferred Stock, Dividends, Per Share, Cash Paid					$ 0.525
PAA | Series B Preferred Units
Partners' Capital and Distributions
Amount accrued to distributions payable						$ 18
PAA | Series B Preferred Units | Cash Distributions
Partners' Capital and Distributions
Preferred unit distribution amount				$ 24.5
Preferred Stock, Dividends, Per Share, Cash Paid				$ 30.625
AAP
Partners' Capital and Distributions
Total distributions paid			$ 85	$ 85	$ 85
Distributions to noncontrolling interests			37	38	38
Distributions to PAGP			48	47	47
Forecast | PAA | Common Units | Cash Distributions
Partners' Capital and Distributions
Total distributions paid		$ 218
Distributions per common unit, paid (usd per unit)		$ 0.30
Forecast | PAA | Series A Preferred Units | Cash Distributions
Partners' Capital and Distributions
Preferred unit distribution amount		$ 37
Preferred Stock, Dividends, Per Share, Cash Paid		$ 0.525
Forecast | PAA | Series B Preferred Units | Cash Distributions
Partners' Capital and Distributions
Preferred unit distribution amount	$ 24.5
Preferred Stock, Dividends, Per Share, Cash Paid	$ 30.625
Forecast | AAP
Partners' Capital and Distributions
Total distributions paid		$ 84
Distributions to noncontrolling interests		36
Distributions to PAGP		48
Public | PAA | Common Units | Cash Distributions
Partners' Capital and Distributions
Distributions to common unitholders			133	133	133
Public | Forecast | PAA | Common Units | Cash Distributions
Partners' Capital and Distributions
Distributions to common unitholders		134
AAP | PAA | Common Units | Cash Distributions
Partners' Capital and Distributions
Distributions to common unitholders			$ 85	$ 85	$ 85
AAP | Forecast | PAA | Common Units | Cash Distributions
Partners' Capital and Distributions
Distributions to common unitholders		$ 84

Derivatives and Risk Manageme_3

Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions, Mcf in Millions, MWh in Millions	9 Months Ended
	Sep. 30, 2018MWhMcfbbl
Net long position associated with crude oil purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	5.8
Net short time spread position hedging anticipated crude oil lease gathering purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	15.4
Crude oil grade basis position
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	68.6
Net short position related to anticipated net sales of crude oil and NGL inventory
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	16.5
PLA short position consisting of crude oil futures
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	1.5
PLA long call option position
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	1.6
Long natural gas position for natural gas purchases and operational needs
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf) | Mcf	64.9
Short propane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	11.3
Short butane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	3.1
Short WTI position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	1.3
Long power position for power supply requirements
Commodity Price Risk Hedging:
Derivative position notional amount (in megawatt hours) | MWh	0.4

Derivatives and Risk Manageme_4

Derivatives and Risk Management Activities - Interest Rate Risk Hedging (Details) - Cash flow hedge	9 Months Ended
	Sep. 30, 2018USD ($)contract
8 forward starting interest rate swaps (30-year), 2.83%
Interest Rate Risk Hedging
Number of interest rate derivatives | contract	8
Term of derivative contract	30 years
Notional amount of derivatives | $	$ 200,000,000
Average rate locked (percent)	2.83%
8 forward starting interest rate swaps (30-year), 3.06%
Interest Rate Risk Hedging
Number of interest rate derivatives | contract	8
Term of derivative contract	30 years
Notional amount of derivatives | $	$ 200,000,000
Average rate locked (percent)	3.06%

Derivatives and Risk Manageme_5

Derivatives and Risk Management Activities - Currency Exchange Rate Risk Hedging (Details) $ in Millions, $ in Millions	Sep. 30, 2018USD ($)$ / $	Sep. 30, 2018CAD ($)$ / $
Forward exchange contracts that exchange CAD For USD maturing in 2018
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 174	$ 227
Average exchange rate (cad per usd)	1.30	1.30
Forward exchange contracts that exchange USD for CAD maturing in 2018
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 418	$ 543
Average exchange rate (cad per usd)	1.30	1.30
Forward exchange contracts that exchange USD for CAD maturing in 2019
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 120	$ 155
Average exchange rate (cad per usd)	1.30	1.30

Derivatives and Risk Manageme_6

Derivatives and Risk Management Activities - Financial Impact (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	$ (59)	$ (235)	$ (450)	$ (53)
Commodity Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	(59)	(226)	(443)	(31)
Commodity Derivatives | Field operating costs
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	(1)	(4)		(8)
Commodity Derivatives | Depreciation and amortization
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income				(3)
Interest Rate Derivatives | Interest expense, net
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	(2)	(10)	(3)	(16)
Foreign Currency Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	5	3	(7)	5
Preferred Distribution Rate Reset Option | Other income/(expense), net
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	(2)	2	3
Derivatives in Hedging Relationships
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	(2)	(10)	(3)	(19)
Derivatives in Hedging Relationships | Commodity Derivatives | Depreciation and amortization
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income				(3)
Derivatives in Hedging Relationships | Interest Rate Derivatives | Interest expense, net
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	(2)	(10)	(3)	(16)
Derivatives Not Designated as a Hedge
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	(57)	(225)	(447)	(34)
Derivatives Not Designated as a Hedge | Commodity Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	(59)	(226)	(443)	(31)
Derivatives Not Designated as a Hedge | Commodity Derivatives | Field operating costs
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	(1)	(4)		(8)
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	5	3	(7)	$ 5
Derivatives Not Designated as a Hedge | Preferred Distribution Rate Reset Option | Other income/(expense), net
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	$ (2)	$ 2	$ 3

Derivatives and Risk Manageme_7

Derivatives and Risk Management Activities - Assets and Liabilities (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Derivative assets and liabilities
Asset Derivatives Fair Value	$ 288		$ 288		$ 90
Liability Derivatives Fair Value	(631)		(631)		(425)
Net loss deferred in AOCI	157		157
Net loss expected to be reclassified to earnings in the next twelve months			7
Interest Rate Derivatives
Derivative assets and liabilities
Unrealized gain (loss) on hedges	15	$ (3)	60	$ (15)
Derivatives in Hedging Relationships
Derivative assets and liabilities
Asset Derivatives Fair Value	15		15		2
Liability Derivatives Fair Value					(38)
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other current assets
Derivative assets and liabilities
Asset Derivatives Fair Value	12		12
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other long-term assets, net
Derivative assets and liabilities
Asset Derivatives Fair Value	3		3
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other current liabilities
Derivative assets and liabilities
Asset Derivatives Fair Value					2
Liability Derivatives Fair Value					(27)
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other long-term liabilities and deferred credits
Derivative assets and liabilities
Liability Derivatives Fair Value					(11)
Derivatives Not Designated as a Hedge
Derivative assets and liabilities
Asset Derivatives Fair Value	273		273		88
Liability Derivatives Fair Value	(631)		(631)		(387)
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other current assets
Derivative assets and liabilities
Asset Derivatives Fair Value	146		146		73
Liability Derivatives Fair Value	(358)		(358)		(227)
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other long-term assets, net
Derivative assets and liabilities
Asset Derivatives Fair Value	54		54		1
Liability Derivatives Fair Value	(2)		(2)
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other current liabilities
Derivative assets and liabilities
Asset Derivatives Fair Value	60		60		5
Liability Derivatives Fair Value	(211)		(211)		(131)
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other long-term liabilities and deferred credits
Derivative assets and liabilities
Asset Derivatives Fair Value	9		9		3
Liability Derivatives Fair Value	(39)		(39)		(5)
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Other current assets
Derivative assets and liabilities
Asset Derivatives Fair Value	4		4		6
Liability Derivatives Fair Value	(1)		(1)		(2)
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Other current liabilities
Derivative assets and liabilities
Liability Derivatives Fair Value	(1)		(1)
Derivatives Not Designated as a Hedge | Preferred Distribution Rate Reset Option
Derivative assets and liabilities
Asset Derivatives Fair Value
Derivatives Not Designated as a Hedge | Preferred Distribution Rate Reset Option | Other long-term liabilities and deferred credits
Derivative assets and liabilities
Liability Derivatives Fair Value	$ (19)		$ (19)		$ (22)

Derivatives and Risk Manageme_8

Derivatives and Risk Management Activities - Broker Receivable/Payable (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Offsetting Assets, Liabilities [Line Items]
Initial margin	$ 139	$ 48
Variation margin posted	222	164
Letters of credit	(181)	(166)
Net broker receivable	259	$ 212
Exchange Traded
Offsetting Assets, Liabilities [Line Items]
Letters of credit	$ (102)

Derivatives and Risk Manageme_9

Derivatives and Risk Management Activities - Offsetting (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivative Asset Positions
Gross Position - Asset	$ 288	$ 90
Netting adjustment	(430)	(239)
Cash collateral paid	259	212
Net Position - Asset	117	63
Derivative Liability Positions
Gross Position - Liability	(631)	(425)
Netting adjustment	430	239
Net Position - Liability	(201)	(186)
Other current assets
Derivative Asset Positions
Net Position - Asset	62	62
Other long-term assets, net
Derivative Asset Positions
Net Position - Asset	55	1
Other current liabilities
Derivative Liability Positions
Net Position - Liability	(152)	(151)
Other long-term liabilities and deferred credits
Derivative Liability Positions
Net Position - Liability	$ (49)	$ (35)

Derivatives and Risk Managem_10

Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Level 3
Rollforward of Level 3 Net Asset/(Liability)
Beginning Balance	$ (18)	$ (30)	$ (30)	$ (36)
Net gains/(losses) for the period included in earnings	(5)	(8)	2	(1)
Settlements		(1)	7	4
Derivatives entered into during the period		(2)	(2)	(8)
Ending Balance	(23)	(41)	(23)	(41)
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period	(5)	$ (10)	0	$ (8)
Recurring Fair Value Measures
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(343)		(343)		$ (335)
Recurring Fair Value Measures | Commodity Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(341)		(341)		(281)
Recurring Fair Value Measures | Interest Rate Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	15		15		(36)
Recurring Fair Value Measures | Foreign Currency Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	2		2		4
Recurring Fair Value Measures | Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(19)		(19)		(22)
Recurring Fair Value Measures | Level 1
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(11)		(11)		5
Recurring Fair Value Measures | Level 1 | Commodity Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(11)		(11)		5
Recurring Fair Value Measures | Level 2
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(309)		(309)		(310)
Recurring Fair Value Measures | Level 2 | Commodity Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(326)		(326)		(278)
Recurring Fair Value Measures | Level 2 | Interest Rate Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	15		15		(36)
Recurring Fair Value Measures | Level 2 | Foreign Currency Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	2		2		4
Recurring Fair Value Measures | Level 3
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(23)		(23)		(30)
Recurring Fair Value Measures | Level 3 | Commodity Derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	(4)		(4)		(8)
Recurring Fair Value Measures | Level 3 | Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Total net derivative asset/(liability)	$ (19)		$ (19)		$ (22)

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2018	Jun. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Related Party Transaction [Line Items]
Net investments in equity method investees						$ 300	$ 356
Oxy
Related Party Transaction [Line Items]
Revenues			$ 260		$ 204	818	657
Purchases and related costs			(22)		(68)	(184)	(169)
Trade accounts receivable and other receivables	$ 1,039	$ 1,075	1,039			1,039
Accounts payable	976	990	976			976
Equity Method Investee
Related Party Transaction [Line Items]
Revenues			3		1	9	3
Costs related to services provided by related party			146		124	411	318
Trade accounts receivable and other receivables	41	26	41			41
Accounts payable	$ 112	$ 41	$ 112			$ 112
Class C Shares | PAA
Related Party Transaction [Line Items]
Shares owned	516,138,000	510,925,432
Agreement To Transport Crude Oil On Pipeline Of Equity Method Investee | Equity Method Investee
Related Party Transaction [Line Items]
Ownership percentage	50.00%		50.00%			50.00%
Cactus II Pipeline LLC
Related Party Transaction [Line Items]
Reduction in property, plant and equipment				$ 74
Proceeds from sale of equity method investments				$ 26
Cactus II Pipeline LLC | Third Party
Related Party Transaction [Line Items]
Interest acquired				15.00%
Cactus II Pipeline LLC | Oxy
Related Party Transaction [Line Items]
Interest acquired				20.00%
Cactus II Pipeline LLC | Other long-term liabilities and deferred credits
Related Party Transaction [Line Items]
Deferred revenue	$ 100		$ 100			$ 100
Joint Tariff | Equity Method Investee
Related Party Transaction [Line Items]
Costs related to services provided by related party			$ 74		$ 57	$ 213	$ 150
AAP | Oxy
Related Party Transaction [Line Items]
Limited partner interest	11.00%
PAA | Oxy
Related Party Transaction [Line Items]
Limited partner interest	4.00%

Commitments and Contingencies

Commitments and Contingencies - Legal, Environmental or Regulatory (Details)	May 16, 2016employeecount	May 31, 2015bbl	Sep. 30, 2018USD ($)count	Sep. 30, 2018USD ($)countlawsuit	Sep. 07, 2018count	Dec. 31, 2017USD ($)
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities			$ 126,000,000	$ 126,000,000		$ 162,000,000
Amounts probable of recovery under insurance and from third parties under indemnification agreements			49,000,000	49,000,000		55,000,000
Trade accounts receivable and other receivables, net
Legal, Environmental or Regulatory Matters
Amounts probable of recovery under insurance and from third parties under indemnification agreements			23,000,000	23,000,000		29,000,000
Other long-term assets, net
Legal, Environmental or Regulatory Matters
Amounts probable of recovery under insurance and from third parties under indemnification agreements			26,000,000	26,000,000		26,000,000
Accounts payable and accrued liabilities
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities, short-term			46,000,000	46,000,000		72,000,000
Other long-term liabilities and deferred credits
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities, long-term			80,000,000	80,000,000		$ 90,000,000
Line 901 Incident
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities			65,000,000	65,000,000
Amounts probable of recovery under insurance and from third parties under indemnification agreements			40,000,000	40,000,000
Estimated size of release (in bbl) | bbl		2,934
Estimated size of release to reach Pacific Ocean (in bbl) | bbl		598
Fines or penalties assessed			0	0
Aggregate total estimated costs			335,000,000	335,000,000
Recoveries from insurance carriers				180,000,000
Total release costs probable of recovery			220,000,000	220,000,000
Line 901 Incident | Trade accounts receivable and other receivables, net
Legal, Environmental or Regulatory Matters
Amounts probable of recovery under insurance and from third parties under indemnification agreements			16,000,000	16,000,000
Line 901 Incident | Accounts payable and accrued liabilities
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities, short-term			$ 37,000,000	$ 37,000,000
Line 901 Incident | May 2016 Indictment
Legal, Environmental or Regulatory Matters
Number of employees charged | employee	1
Total counts included in the indictment | count	46		15	15
Number of counts dismissed | count			31
Number of felony charges dismissed | count			1
Number of felony charges found guilty | count					1
Number of misdemeanor charges found guilty | count					8
Number of misdemeanor charges found guilty, reporting | count					1
Number of misdemeanor charges found guilty, strict liability discharge | count					1
Number of misdemeanor charges found guilty, strict liability animal takings | count					6
Number of misdemeanor charges not guilty, strict liability animal takings | count					1
Number of charges jury deadlocked | count					3
Number of charges jury deadlocked, felony discharges | count					2
Number of charges jury deadlocked, strict liability animal takings | count					1
Number of misdemeanor charges dropped | count					2
Line 901 Incident | Class Action Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed during the period | lawsuit				9
Number of cases consolidated into a single proceeding | lawsuit				6
Line 901 Incident | Securities Law Class Action Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed during the period | lawsuit				2
Line 901 Incident | Unitholder Derivative Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed during the period | lawsuit				4
UNITED STATES | Line 901 Incident | Unitholder Derivative Lawsuits
Legal, Environmental or Regulatory Matters
Number of lawsuits dismissed | lawsuit				2
TEXAS | Line 901 Incident | Unitholder Derivative Lawsuits
Legal, Environmental or Regulatory Matters
Number of lawsuits dismissed | lawsuit				1

Operating Segments - Segment F

Operating Segments - Segment Financial Data (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)segment	Sep. 30, 2017USD ($)
Segment Reporting Information [Line Items]
Operating segments number | segment			3
Revenues:
Revenues	$ 8,792	$ 5,873	$ 25,269	$ 18,618
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	110	80	281	201
Segment Adjusted EBITDA	636	489	1,733	1,451
Maintenance capital	78	63	186	194
Transportation
Revenues:
Revenues	161	160	458	459
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	110	80	281	201
Segment Adjusted EBITDA	388	363	1,083	933
Maintenance capital	41	32	102	89
Facilities
Revenues:
Revenues	149	140	437	410
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment Adjusted EBITDA	173	182	530	550
Maintenance capital	33	28	74	94
Supply and Logistics
Revenues:
Revenues	8,482	5,573	24,374	17,749
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment Adjusted EBITDA	75	(56)	120	(32)
Maintenance capital	4	3	10	11
Operating Segments, Before Intersegment Adjustment | Transportation
Revenues:
Revenues	292	274	808	757
Operating Segments, Before Intersegment Adjustment | Facilities
Revenues:
Revenues	149	140	437	410
Operating Segments, Before Intersegment Adjustment | Supply and Logistics
Revenues:
Revenues	8,482	5,573	24,374	17,749
Operating Segments
Revenues:
Revenues	9,270	6,311	26,669	19,890
Operating Segments | Transportation
Revenues:
Revenues	498	446	1,427	1,260
Operating Segments | Facilities
Revenues:
Revenues	289	291	866	873
Operating Segments | Supply and Logistics
Revenues:
Revenues	8,483	5,574	24,376	17,757
Intersegment
Revenues:
Revenues	(478)	(438)	(1,400)	(1,272)
Intersegment | Transportation
Revenues:
Revenues	(206)	(172)	(619)	(503)
Intersegment | Facilities
Revenues:
Revenues	(140)	(151)	(429)	(463)
Intersegment | Supply and Logistics
Revenues:
Revenues	(1)	(1)	(2)	(8)
Intersegment Adjustment
Revenues:
Revenues	$ (131)	$ (114)	$ (350)	$ (298)

Operating Segments - Segment A

Operating Segments - Segment Adjusted EBITDA Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Segment Reporting, Reconciling Item from Segments to Consolidated [Line Items]
Segment Adjusted EBITDA	$ 636	$ 489	$ 1,733	$ 1,451
Adjustments:
Depreciation and amortization of unconsolidated entities	(15)	(13)	(44)	(31)
Gains/(losses) from derivative activities net of inventory valuation adjustments	110	(216)	(107)	86
Long-term inventory costing adjustments	10	16	18	2
Deficiencies under minimum volume commitments, net	4	(8)	(9)	(5)
Equity-indexed compensation expense	(14)	(7)	(37)	(18)
Net gain/(loss) on foreign currency revaluation	3	14	(5)	27
Significant acquisition-related expenses				(6)
Unallocated general and administrative expenses	(75)	(68)	(235)	(213)
Depreciation and amortization	(131)	(152)	(307)	(403)
Gain on sale of investment in unconsolidated entities	210		210
Interest expense, net	(110)	(134)	(327)	(390)
Other income/(expense), net	(3)	(1)	8	(6)
INCOME/(LOSS) BEFORE TAX	699	(12)	1,130	692
Income tax (expense)/benefit	(23)	43	(84)	(85)
NET INCOME	676	31	1,046	607
Net income attributable to noncontrolling interests	(565)	(27)	(892)	(538)
NET INCOME ATTRIBUTABLE TO PAGP	111	$ 4	154	69
Unallocated
Adjustments:
Unallocated general and administrative expenses	$ (1)		$ (3)	(3)
Line 901 Incident
Adjustments:
Line 901 incident				$ (12)