View Filing Data

Document and Entity Information - shares	6 Months Ended
Document and Entity Information - shares	Jun. 30, 2016	Aug. 01, 2016
Document and Entity Information
Entity Registrant Name	PLAINS GP HOLDINGS LP
Entity Central Index Key	0001581990
Document Type	10-Q
Document Period End Date	Jun. 30, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		267,032,219
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 37	$ 30
Trade accounts receivable and other receivables, net	2,014	1,785
Inventory	1,085	916
Other current assets	469	241
Total current assets	3,605	2,972
PROPERTY AND EQUIPMENT	15,890	15,695
Accumulated depreciation	(2,273)	(2,202)
Property and equipment, net	13,617	13,493
OTHER ASSETS
Goodwill	2,396	2,405
Investments in unconsolidated entities	2,161	2,027
Deferred tax asset	1,893	1,835
Linefill and base gas	902	898
Long-term inventory	184	129
Other long-term assets, net	317	383
Total assets	25,075	24,142
CURRENT LIABILITIES
Accounts payable and accrued liabilities	2,334	2,040
Short-term debt	1,302	999
Other current liabilities	395	370
Total current liabilities	4,031	3,409
LONG-TERM LIABILITIES
Senior notes, net of unamortized discounts and debt issuance costs	9,128	9,698
Other long-term debt, net of unamortized debt issuance costs	949	1,234
Other long-term liabilities and deferred credits	678	567
Total long-term liabilities	10,755	11,499
COMMITMENTS AND CONTINGENCIES (NOTE 11)
PARTNERS' CAPITAL
Noncontrolling interests	8,487	7,472
Total partners' capital	10,289	9,234
Total liabilities and partners' capital	25,075	24,142
Class A Shares
PARTNERS' CAPITAL
Shareholders	$ 1,802	$ 1,762

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
Class A Shares
Shares outstanding
Shares outstanding	267,032,219	229,278,980	224,312,453	206,933,274

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
REVENUES
Supply and Logistics segment revenues	$ 4,648	$ 6,346	$ 8,467	$ 11,978
Transportation segment revenues	170	180	323	366
Facilities segment revenues	132	137	270	261
Total revenues	4,950	6,663	9,060	12,605
COSTS AND EXPENSES
Purchases and related costs	4,224	5,848	7,571	10,890
Field operating costs	303	417	603	763
General and administrative expenses	73	80	141	159
Depreciation and amortization	205	108	320	213
Total costs and expenses	4,805	6,453	8,635	12,025
OPERATING INCOME	145	210	425	580
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	40	52	87	89
Interest expense (net of capitalized interest of $12, $13, $26 and $27, respectively)	(118)	(109)	(233)	(216)
Other income/(expense), net	25	1	30	(3)
INCOME BEFORE TAX	92	154	309	450
Current income tax expense	(9)	(19)	(40)	(61)
Deferred income tax expense	(1)	(32)	(10)	(24)
NET INCOME	82	103	259	365
Net income attributable to noncontrolling interests	(40)	(73)	(181)	(304)
NET INCOME ATTRIBUTABLE TO PAGP	$ 42	$ 30	$ 78	$ 61
Class A Shares
BASIC AND DILUTED NET INCOME PER CLASS A SHARE
BASIC NET INCOME PER CLASS A SHARE (in dollars per share)	$ 0.16	$ 0.14	$ 0.30	$ 0.28
DILUTED NET INCOME PER CLASS A SHARE (in dollars per share)	$ 0.15	$ 0.14	$ 0.29	$ 0.27
BASIC WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING	267	224	260	218
DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING	624	224	652	606

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Interest expense, capitalized interest	$ 12	$ 13	$ 26	$ 27

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income	$ 82	$ 103	$ 259	$ 365
Other comprehensive income/(loss)	(73)	170	45	(206)
Comprehensive income	9	273	304	159
Comprehensive (income)/loss attributable to noncontrolling interests	32	(242)	(226)	(99)
Comprehensive income attributable to PAGP	$ 41	$ 31	$ 78	$ 60

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Balance at beginning of period			$ (1,081)	$ (467)
Reclassification adjustments			6	19
Deferred gain/(loss) on cash flow hedges			(158)	20
Currency translation adjustments			197	(245)
Total period activity	$ (73)	$ 170	45	(206)
Balance at end of period	(1,036)	(673)	(1,036)	(673)
Derivative Instruments
Balance at beginning of period			(203)	(159)
Reclassification adjustments			6	19
Deferred gain/(loss) on cash flow hedges			(158)	20
Total period activity			(152)	39
Balance at end of period	(355)	(120)	(355)	(120)
Translation Adjustments
Balance at beginning of period			(878)	(308)
Currency translation adjustments			197	(245)
Total period activity			197	(245)
Balance at end of period	$ (681)	$ (553)	$ (681)	$ (553)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 259	$ 365
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	320	213
Equity-indexed compensation expense	26	36
Inventory valuation adjustments	3	24
Deferred income tax expense	10	24
Gain on foreign currency revaluation	(2)	(26)
Settlement of terminated interest rate hedging instruments	(50)	(29)
Change in fair value of Preferred Distribution Rate Reset Option (Note 9)	(25)
Equity earnings in unconsolidated entities	(87)	(89)
Distributions from unconsolidated entities	101	102
Other	6	(6)
Changes in assets and liabilities, net of acquisitions	(182)	40
Net cash provided by operating activities	379	654
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions	(85)	(64)
Investments in unconsolidated entities	(120)	(119)
Additions to property, equipment and other	(699)	(1,031)
Cash paid for purchases of linefill and base gas	(7)	(125)
Proceeds from sales of assets	391	2
Other investing activities	(2)	(6)
Net cash used in investing activities	(522)	(1,343)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) under PAA commercial paper program (Note 7)	(844)	151
Net borrowings under PAA senior secured hedged inventory facility (Note 7)	252
Net borrowings under AAP senior secured revolving credit facility (Note 7)	34	24
Repayments of PAA senior notes		(149)
Net proceeds from the sale of Series A preferred units by a subsidiary (Note 8)	1,569
Net proceeds from the sale of common units by a subsidiary		1,099
Distributions paid to Class A shareholders (Note 8)	(117)	(92)
Distributions paid to noncontrolling interests (Note 8)	(743)	(713)
Other financing activities	(5)	(4)
Net cash provided by financing activities	146	316
Effect of translation adjustment on cash	4	(1)
Net increase/(decrease) in cash and cash equivalents	7	(374)
Cash and cash equivalents, beginning of period	30	404
Cash and cash equivalents, end of period	37	30
Cash paid for:
Interest, net of amounts capitalized	231	195
Income taxes, net of amounts refunded	$ 51	$ 30

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions	Noncontrolling Interests	Limited Partners Class A Shares	Total
Balance, beginning of period at Dec. 31, 2014	$ 7,724	$ 1,657	$ 9,381
Increase (Decrease) in Partners' Capital
Net income	304	61	365
Cash distributions to partners	(713)	(92)	(805)
Deferred tax asset		179	179
Change in ownership interest in connection with Exchange Right exercises (Note 8)	3	(3)
Sale of common units by a subsidiary	1,099		1,099
Other comprehensive income/(loss)	(205)	(1)	(206)
Other	1		1
Balance, end of period at Jun. 30, 2015	8,213	1,801	10,014
Balance, beginning of period at Dec. 31, 2015	7,472	1,762	9,234
Increase (Decrease) in Partners' Capital
Net income	181	78	259
Cash distributions to partners	(743)	(117)	(860)
Deferred tax asset		96	96
Change in ownership interest in connection with Exchange Right exercises (Note 8)	16	(16)
Sale of Series A preferred units by a subsidiary	1,509		1,509
Other comprehensive income/(loss)	45		45
Other	7	(1)	6
Balance, end of period at Jun. 30, 2016	$ 8,487	$ 1,802	$ 10,289

Organization and Basis of Consolidation and Presentation

6 Months Ended

Jun. 30, 2016

Organization and Basis of Consolidation and Presentation

Organization and Basis of Consolidation and Presentation

Note 1—Organization and Basis of Consolidation and Presentation

Organization

Plains GP Holdings, L.P. (“PAGP”) is a Delaware limited partnership formed on July 17, 2013 to own an interest in the general partner and incentive distribution rights (“IDRs”) of Plains All American Pipeline, L.P. (“PAA”), a publicly traded Delaware limited partnership. PAGP has elected to be treated as a corporation for U.S. federal income tax purposes. 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 consolidated subsidiaries.

As of June 30, 2016, our sole assets consisted of (i) a 100% managing member interest in Plains All American GP LLC (“GP LLC”) and (ii) an approximate 43% limited partner interest in Plains AAP, L.P. (“AAP”) through our ownership of 267,032,219 Class A units of AAP (“AAP units”). GP LLC is a Delaware limited liability company that holds the general partner interest in AAP. AAP is a Delaware limited partnership that directly owns all of PAA’s IDRs and indirectly owns the 2% general partner interest in PAA. AAP is the sole member of PAA GP LLC (“PAA GP”), a Delaware limited liability company that directly holds the 2% general partner interest in PAA. PAA GP Holdings LLC (“GP Holdings”), a Delaware limited liability company, is our general partner.

GP LLC manages the business and affairs of PAA and AAP. Except for certain matters relating to PAA that require the approval of the limited partners of PAA, and certain matters relating to AAP that require the approval of the limited partners of AAP or of us as the sole member of GP LLC, either pursuant to the governing documents of PAA, AAP or GP LLC, or as may be required by non-waivable provisions of applicable law, GP LLC has full and complete authority, power and discretion to manage and control the business, affairs and property of PAA and AAP, to make all decisions regarding those matters and to perform any and all other acts or activities customary or incident to the management of PAA and AAP’s business, including the execution of contracts and management of litigation. GP LLC employs all domestic officers and personnel involved in the operation and management of PAA and AAP. PAA’s Canadian officers and personnel are employed by Plains Midstream Canada ULC (“PMC”).

PAA is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services for crude oil, natural gas liquids (“NGL”), natural gas and refined products. 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 12 for further discussion of our operating segments.

Simplification Agreement

On July 11, 2016, PAGP, PAA, AAP, PAA GP, GP LLC and GP Holdings entered into a Simplification Agreement pursuant to which, upon closing, in exchange for the issuance by PAA to AAP of approximately 245.5 million common units representing limited partner interests in PAA and the assumption by PAA of AAP’s outstanding debt, AAP will contribute the IDRs to PAA and PAA GP’s 2% economic general partner interest in PAA will be converted into a non-economic general partner interest in PAA. Following the closing of the transactions contemplated by the Simplification Agreement, both PAGP and PAA will continue to be publicly traded. See Note 14 for further discussion of this transaction.

Definitions

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

AOCI	=	Accumulated other comprehensive income/(loss)
Bcf	=	Billion cubic feet
Btu	=	British thermal unit
CAD	=	Canadian dollar
DERs	=	Distribution equivalent rights
EPA	=	United States Environmental Protection Agency
FASB	=	Financial Accounting Standards Board
GAAP	=	Generally accepted accounting principles in the United States
ICE	=	Intercontinental Exchange
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
VIE	=	Variable Interest Entity
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 2015 Annual Report on Form 10-K. On January 1, 2016 we adopted FASB guidance regarding the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. Among other things, the guidance modified the evaluation of whether limited partnerships are variable interest entities (“VIE”) and eliminates the presumption that a general partner should consolidate a limited partnership. The adoption of this standard did not impact our consolidation conclusions, but did result in a change in our analysis and an increase in disclosures regarding our analysis.

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. Management judgment is required to evaluate whether PAGP controls an entity. Key areas of that evaluation include (i) determining whether an entity is a 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. An entity is referred to as a VIE pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity’s residual economics, or (v) the entity was established with non-substantive voting interests. We consolidate a VIE when we have both the power to direct the activities that most significantly impact the activities of the VIE and the right to receive benefits or the obligation to absorb losses of the entity that could be potentially significant to the VIE. We continually monitor both consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change.

We have determined that PAA and AAP are VIEs and should be consolidated by PAGP along with GP LLC. PAA is a VIE due to its allocation of income, but not losses, to the holder(s) of IDRs. AAP is a VIE because GP LLC controls AAP through its general partnership interest, but does not have an economic interest in AAP. AAP is the primary beneficiary of PAA because it has the power to direct the activities that most significantly impact PAA’s performance. PAGP is the primary beneficiary of AAP because it has the power, through its control of GP LLC, to direct the activities that most significantly impact AAP’s performance.

With the exception of a deferred tax asset of $1,893 million and $1,835 million as of June 30, 2016 and December 31, 2015, respectively, substantially all assets and liabilities presented on PAGP’s consolidated balance sheet are those of the consolidated VIEs above. 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 six months ended June 30, 2016 or during the year ended December 31, 2015. Amounts associated with the interests in these entities not owned by us are reflected in our results of operations as net income attributable to noncontrolling interests and on our balance sheet in the partners’ capital section as noncontrolling 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. Such reclassifications include $2 million and $5 million reclassified from “Depreciation and amortization” to “Interest expense, net” in our accompanying Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2015, respectively due to the retrospective application of revised debt issuance costs guidance issued by the FASB, which we adopted during the fourth quarter of 2015. These reclassifications do not affect net income attributable to PAGP. The condensed consolidated balance sheet data as of December 31, 2015 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three and six months ended June 30, 2016 should not be taken as indicative of results to be expected for the entire year.

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

Recent Accounting Pronouncements	6 Months Ended
Recent Accounting Pronouncements	Jun. 30, 2016
Recent Accounting Pronouncements
Recent Accounting Pronouncements	Note 2—Recent Accounting Pronouncements Except as discussed below and in our 2015 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the six months ended June 30, 2016 that are of significance or potential significance to us. In February 2015, the FASB issued guidance that revises the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. All legal entities are subject to reevaluation under the revised consolidation model. Among other things, this guidance (i) modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (ii) eliminates the presumption that a general partner should consolidate a limited partnership and (iii) affects the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships. This guidance became effective for interim and annual periods beginning after December 15, 2015. We adopted this guidance on January 1, 2016. See Note 1 for additional disclosure. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In February 2016, the FASB issued guidance 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, 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, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows. In March 2016, the FASB issued guidance to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification of certain related payments on the statement of cash flows. This guidance will become effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We expect to adopt this guidance on January 1, 2017, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows. In June 2016, the FASB issued new guidance for the accounting for credit losses on certain financial instruments. This guidance will become effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted by one year. We expect to adopt this guidance on January 1, 2020, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows.

- Definition

The entire disclosure of changes in accounting principles, including adoption of new accounting pronouncements, that describes the new methods, amount and effects on financial statement line items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6507316

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Direct Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=66092750

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=64853466&loc=d3e22583-107794

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Indirect Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6515603

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=64853466&loc=d3e22580-107794

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.10-01.(b)(6))
-URI http://asc.fasb.org/extlink&oid=27015980&loc=d3e46468-122699

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Accounting Change
-URI http://asc.fasb.org/extlink&oid=6503790

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=64853466&loc=d3e22499-107794

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Retrospective Application
-URI http://asc.fasb.org/extlink&oid=6523989

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 13
-URI http://asc.fasb.org/extlink&oid=68064558&loc=d3e765-108305

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=68064558&loc=d3e725-108305

+ Details

Net Income Per Class A Share

6 Months Ended

Jun. 30, 2016

Net Income Per Class A Share

Net Income Per Class A Share

Note 3—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. Class B shares do not share in the earnings of the Partnership. Accordingly, basic and diluted net income per Class B 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 8 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.

For the three months ended June 30, 2016 and the three and six months ended June 30, 2015, the possible exchange of certain AAP Management Units would not have had a dilutive effect on basic net income per Class A share. For the three months ended June 30, 2015, the possible exchange of any AAP units would not have had a dilutive effect on basic net income per Class A share. The following table illustrates the calculation of basic and diluted net income per Class A share (in millions, except per share data):

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Basic Net Income per Class A Share
Net income attributable to PAGP	$	42	$	30	$	78	$	61
Basic weighted average Class A shares outstanding	267		224		260		218

Basic net income per Class A share	$	0.16	$	0.14	$	0.30	$	0.28


Diluted Net Income per Class A Share
Net income attributable to PAGP	$	42	$	30	$	78	$	61
Incremental net income attributable to PAGP resulting from assumed exchange of AAP units and AAP Management Units	52		—		111		105

Net income attributable to PAGP including incremental net income from assumed exchange of AAP units and AAP Management Units	$	94	$	30	$	189	$	166


Basic weighted average Class A shares outstanding	267		224		260		218
Dilutive shares resulting from assumed exchange of AAP units and AAP Management Units	357		—		392		388

Diluted weighted average Class A shares outstanding	624		224		652		606


Diluted net income per Class A share	$	0.15	$	0.14	$	0.29	$	0.27

Accounts Receivable, Net	6 Months Ended
Accounts Receivable, Net	Jun. 30, 2016
Accounts Receivable, Net
Accounts Receivable, Net	Note 4—Accounts Receivable, Net Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit or parental guarantees. As of June 30, 2016 and December 31, 2015, we had received $93 million and $88 million, respectively, of advance cash payments from third parties to mitigate credit risk. We also received $73 million and $36 million as of June 30, 2016 and December 31, 2015, respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Furthermore, we also enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet) for a majority of such 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 June 30, 2016 and December 31, 2015, 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 $4 million at both June 30, 2016 and December 31, 2015. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

- Definition

The entire disclosure for claims held for amounts due a entity, excluding financing receivables. Examples include, but are not limited to, trade accounts receivables, notes receivables, loans receivables. Includes disclosure for allowance for credit losses.

+ References + Details

Inventory, Linefill and Base Gas and Long-term Inventory

6 Months Ended

Jun. 30, 2016

Inventory, Linefill and Base Gas and Long-term Inventory

Inventory, Linefill and Base Gas and Long-term Inventory

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

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

	June 30, 2016						December 31, 2015
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	20,013	barrels	$	819	$	40.92	16,345	barrels	$	608	$	37.20
NGL	12,813	barrels	209		$	16.31	13,907	barrels	218		$	15.68
Natural gas	15,055	Mcf	31		$	2.06	22,080	Mcf	53		$	2.40
Other	N/A		26		N/A		N/A		37		N/A

Inventory subtotal			1,085						916


Linefill and base gas
Crude oil	12,227	barrels	716		$	58.56	12,298	barrels	713		$	57.98
NGL	1,355	barrels	45		$	33.21	1,348	barrels	44		$	32.64
Natural gas	30,812	Mcf	141		$	4.58	30,812	Mcf	141		$	4.58

Linefill and base gas subtotal			902						898


Long-term inventory
Crude oil	3,396	barrels	162		$	47.70	3,417	barrels	106		$	31.02
NGL	1,418	barrels	22		$	15.51	1,652	barrels	23		$	13.92

Long-term inventory subtotal			184						129


Total			$	2,171					$	1,943

(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

6 Months Ended

Jun. 30, 2016

Goodwill

Goodwill

Note 6—Goodwill

Goodwill by segment and changes in goodwill is reflected in the following table (in millions):

	Transportation			Facilities			Supply and Logistics		Total
Balance at December 31, 2015	$	815		$	1,087		$	503	$	2,405

Foreign currency translation adjustments	14			6			2		22
Dispositions	(15		)	(16		)	—		(31		)

Balance at June 30, 2016	$	814		$	1,077		$	505	$	2,396

We completed our annual goodwill impairment test as of June 30, 2016 and determined that there was no impairment of goodwill.

Debt

6 Months Ended

Jun. 30, 2016

Debt

Debt

Note 7—Debt

Debt consisted of the following (in millions):

	June 30,			December 31,
	2016			2015
SHORT-TERM DEBT
PAA commercial paper notes, bearing a weighted-average interest rate of 1.3% and 1.1%, respectively (1)	$	172		$	696
PAA senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.4% and 1.4%, respectively (1)	552			300
PAA senior notes:
5.88% senior notes due August 2016	175			—
6.13% senior notes due January 2017	400			—
Other	3			3

Total short-term debt	1,302			999

LONG-TERM DEBT
PAA senior notes, net of unamortized discounts and debt issuance costs of $72 and $77, respectively	9,128			9,698
Other long-term debt:
PAA commercial paper notes, bearing a weighted-average interest rate of 1.3% and 1.1%, respectively	354			672
AAP term loan, bearing a weighted-average interest rate of 2.1% and 2.0%, respectively	550			550
AAP senior secured revolving credit facility, bearing a weighted-average interest rate of 2.0% and 2.0%, respectively	43			9
Unamortized debt issuance costs	(2		)	(2		)
Other	4			5

Total long-term debt	10,077			10,932

Total debt (2)	$	11,379		$	11,931

(1)

We classified these PAA commercial paper notes and credit facility borrowings as short-term as of June 30, 2016 and December 31, 2015, 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)

PAA’s fixed-rate senior notes (including current maturities) had a face value of approximately $9.8 billion as of both June 30, 2016 and December 31, 2015. We estimated the aggregate fair value of these notes as of June 30, 2016 and December 31, 2015 to be approximately $9.6 billion and $8.6 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 agreements 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 agreements and the PAA commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

Borrowings and Repayments

Total borrowings under the credit agreements and the PAA commercial paper program for the six months ended June 30, 2016 and 2015 were approximately $23.0 billion and $17.9 billion, respectively. Total repayments under the credit agreements and the PAA commercial paper program were approximately $23.6 billion and $17.7 billion for the six months ended June 30, 2016 and 2015, 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 of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs, derivative transactions and construction activities. At June 30, 2016 and December 31, 2015, we had outstanding letters of credit of $48 million and $46 million, respectively.

Partners' Capital and Distributions

6 Months Ended

Jun. 30, 2016

Partners' Capital and Distributions

Partners' Capital and Distributions

Note 8—Partners’ Capital and Distributions

Exchange Rights

Holders of AAP units and their permitted transferees each have the right to exchange all or a portion of their AAP units for Class A shares at an exchange ratio of one Class A share for each AAP unit exchanged (referred to herein as the “Exchange Right”). This Exchange Right may be exercised only if, simultaneously therewith, an equal number of Class B shares and general partner units are transferred by the exercising party to us. Additionally, a holder of vested AAP Management Units is entitled to convert his or her AAP Management Units into AAP units and a like number of our Class B shares based on a conversion ratio calculated in accordance with the AAP limited partnership agreement (which conversion ratio will not be more than one-to-one and was approximately 0.941 AAP units for each AAP Management Unit as of June 30, 2016). Following any such conversion, the holder will have the Exchange Right for our Class A shares. Holders of AAP Management Units who convert such units into AAP units and our Class B shares will not receive general partner units and thus will not need to include any general partner units in a transfer or the exercise of their Exchange Right. See Note 15 to our Consolidated Financial Statements included in Part IV of our 2015 Annual Report on Form 10-K for more information regarding AAP Management Units.

During the six months ended June 30, 2016, certain holders of AAP units and their permitted transferees exercised their Exchange Right, which resulted in the exchange of AAP units, general partner units and our Class B shares for our Class A shares. Additionally, during the six months ended June 30, 2016, certain holders of AAP Management Units converted an aggregate of 19,137,234 AAP Management Units into AAP units and our Class B shares based on the conversion ratio in effect at the time of each conversion. Certain of those unitholders subsequently exercised their Exchange Right for our Class A shares. The impact on our Class A shares and Class B shares outstanding of the AAP Management Unit conversions and Exchange Right exercises that occurred during the six months ended June 30, 2016 is reflected in the table below.

Shares Outstanding

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

	Class B Shares		Class A Shares
Outstanding at December 31, 2015	376,771,593		229,278,980

Shares issued in connection with conversion of AAP Management Units	17,954,751		—
Shares (exchanged)/issued in connection with Exchange Right exercises	(37,732,439	)	37,732,439
Shares issued in connection with PAGP LTIP award vestings	—		20,800

Outstanding at June 30, 2016	356,993,905		267,032,219

	Class B Shares		Class A Shares
Outstanding at December 31, 2014	399,096,499		206,933,274
Shares (exchanged)/issued in connection with Exchange Right exercises	(17,358,379	)	17,358,379
Shares issued in connection with PAGP LTIP award vestings	—		20,800
Outstanding at June 30, 2015	381,738,120		224,312,453

Distributions

The following table details the distributions paid to our Class A shareholders during or pertaining to the first six months of 2016 (in millions, except per share data):

		Distributions to		Distributions per
Date Declared	Distribution Date	Class A Shareholders		Class A Share
July 11, 2016	August 12, 2016 (1)	$	62	$	0.231
April 7, 2016	May 13, 2016	$	62	$	0.231
January 12, 2016	February 12, 2016	$	55	$	0.231

(1)

Payable to shareholders of record at the close of business on July 29, 2016 for the period April 1, 2016 through June 30, 2016.

Consolidated Subsidiaries

Noncontrolling Interests in Subsidiaries

As of June 30, 2016, noncontrolling interests in our subsidiaries consisted of (i) a 98% limited partner interest in PAA, (ii) an approximate 57% limited partner interest in AAP that consists of Class A units and AAP Management Units (a profits interest) and (iii) a 25% interest in SLC Pipeline LLC.

Subsidiary Equity Offerings

PAA Preferred Unit Offering. In January 2016, PAA completed the private placement of approximately 61.0 million Series A preferred units representing limited partner interests in PAA, for a cash purchase price of $26.25 per unit.

The PAA Series A preferred units are a new class of equity security in PAA that ranks senior to all classes or series of equity securities in PAA with respect to distribution rights and rights upon liquidation. The holders of the PAA Series A preferred units will receive cumulative quarterly distributions, subject to customary antidilution adjustments, equal to $0.525 per unit ($2.10 per unit annualized). With respect to any quarter ending on or prior to December 31, 2017 (the “Initial Distribution Period”), PAA may elect to pay distributions on the PAA Series A preferred units in additional preferred units, in cash or a combination of both. With respect to any quarter ending after the Initial Distribution Period, PAA must pay distributions on the PAA Series A preferred units in cash. AAP will be entitled to participate in cash distributions on the PAA Series A preferred units equal to its 2% general partner interest in PAA.

After two years, the preferred units are convertible at the purchasers’ option into common units on a one-for-one basis, subject to certain conditions, and are convertible at PAA’s option in certain circumstances after three years.

For a period of 30 days following (a) the fifth anniversary of the issuance date of the PAA Series A preferred units and (b) each subsequent anniversary of the issuance date, the holders of the PAA Series A preferred units, acting by majority vote, may make a one-time election to reset the distribution rate to equal the then applicable rate of the ten-year U.S. Treasury plus 5.85% (the “Preferred Distribution Rate Reset Option”). The Preferred Distribution Rate Reset Option is accounted for as an embedded derivative. See Note 9 for additional information.

Subsidiary Distributions

PAA Cash Distributions. The following table details the distributions to PAA’s partners paid in cash during or pertaining to the first six months of 2016, net of reductions in AAP’s incentive distributions (in millions, except per unit data):

		Distributions						Distributions per
Date Declared	Distribution Date	Common Unitholders		AAP		Total		common unit
July 11, 2016	August 12, 2016 (1)	$	278	$	155	$	433	$	0.70
April 7, 2016	May 13, 2016	$	278	$	155	$	433	$	0.70
January 12, 2016	February 12, 2016	$	278	$	155	$	433	$	0.70

(1)

Payable to unitholders of record at the close of business on July 29, 2016 for the period April 1, 2016 through June 30, 2016.

PAA In-Kind Distributions. On May 13, 2016, PAA issued 858,439 additional Series A preferred units in lieu of a cash distribution of $23 million. Such distribution was issued to PAA’s Series A preferred unitholders of record as of April 29, 2016 and was prorated for the period beginning on January 28, 2016, the issuance date of the PAA Series A preferred units, through March 31, 2016. On August 12, 2016, PAA will issue 1,237,765 additional Series A preferred units in lieu of a cash distribution of $33 million.

AAP Distributions. The following table details the distributions paid to AAP’s partners during or pertaining to the first six months of 2016 from distributions received from PAA (in millions):

						Distributions to AAP’s Partners
	Distributions Received		Cash					Noncontrolling
Distribution Date	by AAP from PAA		Reserves			Total		Interests		PAGP
August 12, 2016 (1)	$	155	$	(4	)	$	151	$	89	$	62
May 13, 2016	$	155	$	(5	)	$	150	$	89	$	61
February 12, 2016	$	155	$	(4	)	$	151	$	96	$	55

(1)

Payable to unitholders of record at the close of business on July 29, 2016 for the period April 1, 2016 through June 30, 2016.

Other Distributions. During the six months ended June 30, 2016, distributions of $2 million were paid to noncontrolling interests in SLC Pipeline LLC.

Derivatives and Risk Management Activities

6 Months Ended

Jun. 30, 2016

Derivatives and Risk Management Activities

Derivatives and Risk Management Activities

Note 9—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 (i) manage our exposure to commodity price risk, as well as to optimize our profits, (ii) manage our exposure to interest rate risk and (iii) manage our exposure to currency exchange rate risk. Our commodity 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 June 30, 2016, net derivative positions related to these activities included:

A net long position of 2.1 million barrels associated with our crude oil purchases, which was unwound ratably during July 2016 to match monthly average pricing.

A net short time spread position of 3.9 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through August 2017.

A crude oil grade spread position of 7.0 million barrels through December 2018. These derivatives allow us to lock in grade basis differentials.

A net short position of 13.0 Bcf through July 2017 related to anticipated sales of natural gas inventory.

A net short position of 25.8 million barrels through December 2019 related to anticipated net sales of our crude oil and NGL inventory.

Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We utilize derivative instruments to hedge a portion of the anticipated sales of the loss allowance oil that is to be collected under our tariffs. As of June 30, 2016, our PLA hedges included a long call option position of 1.2 million barrels through December 2018.

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 June 30, 2016, we had a long natural gas position of 22.0 Bcf through December 2017, a short propane position of 4.2 million barrels through December 2017, a short butane position of 1.3 million barrels through December 2017 and a short WTI position of 0.5 million barrels through December 2017. In addition, we had a long power position of 0.3 million megawatt hours, which hedges a portion of our power supply requirements at our Canadian natural gas processing and fractionation plants through December 2018.

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 interest rate risk associated with anticipated and outstanding 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. As of June 30, 2016, AOCI includes deferred losses of $334 million that relate to open and terminated interest rate derivatives that were designated as cash flow hedges. The majority of the terminated interest rate derivatives were cash-settled in connection with the issuance or refinancing of debt agreements. The deferred loss related to these instruments is being amortized to interest expense over the terms of the hedged debt instruments.

We have entered into forward starting interest rate swaps to hedge the underlying benchmark interest rate related to forecasted interest payments through 2049. The following table summarizes the terms of our forward starting interest rate swaps as of June 30, 2016 (notional amounts in millions):

Hedged Transaction	Number and Types of Derivatives Employed	Notional Amount		Expected Termination Date	Average Rate Locked		Accounting Treatment
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	4/13/2017	2.02	%	Cash flow hedge
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	6/15/2017	3.14	%	Cash flow hedge
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	6/15/2018	3.20	%	Cash flow hedge
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	6/14/2019	2.83	%	Cash flow hedge

During June 2016, we made a cash payment of approximately $52 million in connection with the termination of eight forward starting interest rate swaps that had an aggregate notional amount of $200 million and an average fixed rate of 3.06%. In conjunction with this termination, a loss of approximately $50 million was deferred to AOCI, and a loss of approximately $2 million was immediately recognized in interest expense attributable to the determination that a previously forecasted interest payment is now considered probable of not occurring.

Currency Exchange Rate Risk Hedging

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

As of June 30, 2016, our outstanding foreign currency derivatives include derivatives we use to hedge currency exchange risk (i) associated with USD-denominated commodity purchases and sales in Canada and (ii) created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales.

The following table summarizes our open forward exchange contracts as of June 30, 2016 (in millions):

		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2016	$	19	$	25	$1.00 - $1.29

Forward exchange contracts that exchange USD for CAD:
	2016	$	186	$	241	$1.00 - $1.29
	2017	$	20	$	26	$1.00 - $1.29

Preferred Distribution Rate Reset Option

A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. The Preferred Distribution Rate Reset Option of the PAA Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, the PAA partnership agreement, and recorded at fair value on our Condensed Consolidated Balance Sheets. Corresponding changes in fair value are recognized in “Other income/(expense), net” in our Condensed Consolidated Statement of Operations. At June 30, 2016, the fair value of this embedded derivative was a liability of approximately $35 million. We recognized a gain of approximately $25 million during the three and six months ended June 30, 2016 due to changes in fair value during the period. See Note 8 for additional information regarding the PAA Series A preferred units and the Preferred Distribution Rate Reset Option.

Summary of Financial Impact

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

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

	Three Months Ended June 30, 2016									Three Months Ended June 30, 2015
Location of Gain/(Loss)	Derivatives in Hedging Relationships (1)			Derivatives Not Designated as a Hedge			Total			Derivatives in Hedging Relationships			Derivatives Not Designated as a Hedge		Total
Commodity Derivatives

Supply and Logistics segment revenues	$	(1	)	$	(159	)	$	(160	)	$	(19	)	$	44	$	25

Transportation segment revenues	—			1			1			—			2		2

Field operating costs	—			2			2			—			2		2

Interest Rate Derivatives

Interest expense, net	(4		)	—			(4		)	(4		)	—		(4		)

Foreign Currency Derivatives

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

Preferred Distribution Rate Reset Option

Other income/(expense), net	—			25			25			—			—		—


Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(5	)	$	(132	)	$	(137	)	$	(23	)	$	48	$	25

	Six Months Ended June 30, 2016									Six Months Ended June 30, 2015
Location of Gain/(Loss)	Derivatives in Hedging Relationships (1)			Derivatives Not Designated as a Hedge			Total			Derivatives in Hedging Relationships			Derivatives Not Designated as a Hedge			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	—		$	(128	)	$	(128	)	$	(12	)	$	10		$	(2	)

Transportation segment revenues	—			3			3			—			4			4

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

Interest Rate Derivatives

Interest expense, net	(6		)	—			(6		)	(5		)	—			(5		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			5			5			—			(17		)	(17		)

Preferred Distribution Rate Reset Option

Other income/(expense), net	—			25			25			—			—			—


Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(6	)	$	(95	)	$	(101	)	$	(17	)	$	(5	)	$	(22	)

(1)

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

The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of June 30, 2016 (in millions):

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	2

Interest rate derivatives				Other current liabilities	$	(64	)
				Other long-term liabilities and deferred credits	(91		)

Total derivatives designated as hedging instruments		$	2		$	(155	)


Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	45	Other current assets	$	(182	)
	Other long-term liabilities and deferred credits	6		Other current liabilities	(6		)
				Other long-term liabilities and deferred credits	(17		)

Foreign currency derivatives				Other current liabilities	(1		)

Preferred Distribution Rate Reset Option				Other long-term liabilities and deferred credits	(35		)

Total derivatives not designated as hedging instruments		$	51		$	(241	)


Total derivatives		$	53		$	(396	)

The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of December 31, 2015 (in millions):

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	4	Other current assets	$	(2	)

Interest rate derivatives	Other long-term assets, net	1		Other current liabilities	(17		)
				Other long-term liabilities and deferred credits	(33		)

Total derivatives designated as hedging instruments		$	5		$	(52	)


Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	265	Other current assets	$	(35	)
	Other long-term assets, net	10		Other long-term assets, net	(1		)
				Other current liabilities	(13		)
				Other long-term liabilities and deferred credits	(1		)

Foreign currency derivatives				Other current liabilities	(8		)

Total derivatives not designated as hedging instruments		$	275		$	(58	)


Total derivatives		$	280		$	(110	)

Our derivative transactions are governed through ISDA (International Swaps and Derivatives Association) master agreements and clearing brokerage agreements. These agreements include stipulations regarding the right of set off in the event that we or our counterparty default on performance obligations. If a default were to occur, both parties have the right to net amounts payable and receivable into a single net settlement between parties.

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through clearing brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of June 30, 2016, we had a net broker receivable of $274 million (consisting of initial margin of $84 million increased by $190 million of variation margin that had been posted by us). As of December 31, 2015, we had a net broker payable of $156 million (consisting of initial margin of $91 million reduced by $247 million of variation margin that had been returned to us).

The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions):

	June 30, 2016						December 31, 2015
	Derivative			Derivative			Derivative			Derivative
	Asset Positions			Liability Positions			Asset Positions			Liability Positions
Netting Adjustments:
Gross position - asset/(liability)	$	53		$	(396	)	$	280		$	(110	)
Netting adjustment	(188		)	188			(38		)	38
Cash collateral paid/(received)	274			—			(156		)	—

Net position - asset/(liability)	$	139		$	(208	)	$	86		$	(72	)


Balance Sheet Location After Netting Adjustments:
Other current assets	$	139		$	—		$	76		$	—
Other long-term assets, net	—			—			10			—
Other current liabilities	—			(71		)	—			(38		)
Other long-term liabilities and deferred credits	—			(137		)	—			(34		)

	$	139		$	(208	)	$	86		$	(72	)

As of June 30, 2016, there was a net loss of $355 million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the earnings recognition of the underlying hedged commodity transaction or (ii) interest expense accruals associated with underlying debt instruments. Of the total net loss deferred in AOCI at June 30, 2016, we expect to reclassify a net loss of $5 million to earnings in the next twelve months. The remaining deferred loss of $350 million is expected to be reclassified to earnings through 2049. A portion of these amounts is based on market prices as of June 30, 2016; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Commodity derivatives, net	$	—		$	(28	)	$	—		$	(25	)
Interest rate derivatives, net	(68		)	120			(158		)	45

Total	$	(68	)	$	92		$	(158	)	$	20

At June 30, 2016 and December 31, 2015, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our 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 June 30, 2016												Fair Value as of December 31, 2015
Recurring Fair Value Measures (1)	Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total
Commodity derivatives	$	(133	)	$	(19	)	$	—		$	(152	)	$	126	$	90		$	11	$	227
Interest rate derivatives	—			(155		)	—			(155		)	—		(49		)	—		(49		)
Foreign currency derivatives	—			(1		)	—			(1		)	—		(8		)	—		(8		)
Preferred Distribution Rate Reset Option	—			—			(35		)	(35		)	—		—			—		—

Total net derivative asset/(liability)	$	(133	)	$	(175	)	$	(35	)	$	(343	)	$	126	$	33		$	11	$	170

(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 such as futures and options. The fair value of exchange-traded commodity derivatives is based on unadjusted quoted prices in active markets.

Level 2

Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives and over-the-counter commodity, interest rate and foreign currency derivatives that are traded in 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 and the Preferred Distribution Rate Reset Option contained in PAA’s Series A preferred unit offering classified as an embedded derivative.

The fair value of our Level 3 physical commodity contracts is based on a valuation model utilizing broker-quoted forward commodity prices, and timing estimates, which involve management judgment. The significant unobservable inputs used in the fair value measurement of our Level 3 derivatives are forward prices obtained from brokers. A significant increase or decrease in these forward prices could result in a material change in fair value to our physical commodity contracts. We report unrealized gains and losses associated with these physical commodity contracts in our Condensed Consolidated Statements of Operations as Supply and Logistics segment revenues.

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

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

Rollforward of Level 3 Net Asset/(Liability)

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Beginning Balance	$	(59	)	$	5		$	11		$	15
Gains for the period included in earnings	23			1			23			1
Settlements	—			(1		)	(9		)	(13		)
Derivatives entered into during the period	1			4			(60		)	6

Ending Balance	$	(35	)	$	9		$	(35	)	$	9


Change in unrealized gains included in earnings relating to Level 3 derivatives still held at the end of the period	$	24		$	5		$	24		$	6

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6441202&loc=d3e80720-113993

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624171-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41620-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624163-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5579240-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4D
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624177-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35736893&loc=d3e80784-113994

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41641-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5579245-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4H
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624258-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35736893&loc=d3e80748-113994

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4K
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5708775-113959

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4J
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5708773-113959

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5618551-113959

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5580258-113959

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4E
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624181-113959

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41638-113959

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Related Party Transactions

6 Months Ended

Jun. 30, 2016

Related Party Transactions

Related Party Transactions

Note 10—Related Party Transactions

See Note 14 to our Consolidated Financial Statements included in Part IV of our 2015 Annual Report on Form 10-K for a complete discussion of our related party transactions.

Transactions with Oxy

As of June 30, 2016, Oxy owned approximately 13% of the limited partner interests in AAP and had a representative on the board of directors of GP LLC and our general partner. During the three and six months ended June 30, 2016 and 2015, 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					Six Months Ended
	June 30,					June 30,
	2016			2015		2016			2015
Revenues	$	142		$	382	$	254		$	558

Purchases and related costs (1)	$	(4	)	$	41	$	(50	)	$	146

(1)

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

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

	June 30,		December 31,
	2016		2015
Trade accounts receivable and other receivables	$	495	$	405

Accounts payable	$	460	$	363

Commitments and Contingencies	6 Months Ended
Commitments and Contingencies	Jun. 30, 2016
Commitments and Contingencies
Commitments and Contingencies	Note 11—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 June 30, 2016, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled $160 million, of which $59 million was classified as short-term and $101 million was classified as long-term. At December 31, 2015, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident) totaled $185 million, of which $81 million was classified as short-term and $104 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 June 30, 2016, we had recorded receivables totaling $68 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which $46 million was reflected in “Trade accounts receivable and other receivables, net” and $22 million was reflected in “Other long-term assets, net” on our Condensed Consolidated Balance Sheets. At December 31, 2015, we had recorded $161 million of such receivables, of which $138 million was reflected in “Trade accounts receivable and other receivables, net” and $23 million was reflected in “Other long-term assets, net” on our Condensed Consolidated Balance Sheets. In some cases, the actual cash expenditures associated with these liabilities may not occur for three years or longer. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing or future legal claims giving rise to additional liabilities. Therefore, although we believe that the reserve is adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of the reserve and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Specific Legal, Environmental or Regulatory Matters Line 901 Incident. In May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. A portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert. Following the release, we shut down the pipeline and initiated our emergency response plan. A Unified Command, which includes 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, subject to continued shoreline monitoring. Our current “worst case” estimate of the amount of oil spilled, representing the maximum volume of oil that we believed could have been spilled based on relevant facts, data and information, is approximately 2,935 barrels. As a result of the Line 901 incident, several governmental agencies and regulators have 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. On June 3, 2015, the corrective action order was amended to require us to take additional corrective actions with respect to both Lines 901 and 903. On November 13, 2015, the corrective action order was further amended to require the purge and shutdown of Line 903 between Gaviota and Pentland. On June 16, 2016, the corrective action order was further amended to require additional corrective actions and documentation with respect to both Line 901and Line 903 (as amended, the “CAO”). Among other requirements, the CAO also obligates 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 imposes a pressure restriction on Line 903 and requires 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. 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 pursued any such civil or criminal charges with respect to the Line 901 release, their investigation is still open and we may have fines or penalties imposed upon us, or civil or criminal charges brought against us, in the future. On September 11, 2015, we received a Notice of Probable Violation and Proposed Compliance Order from PHMSA arising out of its inspection of Lines 901 and 903 in August, September and October of 2013 (the “2013 Audit NOPV”). The 2013 Audit NOPV alleges that the Partnership committed probable violations of various federal pipeline safety regulations by failing to document, or inadequately documenting, certain activities. On October 12, 2015, the Partnership filed a response to the 2013 Audit NOPV. To date, PHMSA has not issued a final order with respect to the 2013 Audit NOPV, nor has it assessed any fines or penalties with respect thereto; however, we cannot provide any assurances that any such fines or penalties will not be assessed against us. 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 indictment included a total 46 counts, 36 of which were misdemeanor charges relating to wildlife allegedly taken as a result of the accidental release. The remaining 10 counts (four felony and six misdemeanor charges) relate to the release of crude oil or reporting of the release. PAA believes that the criminal charges are unwarranted and that neither PAA nor any of its employees engaged in any criminal behavior at any time in connection with this accident. PAA intends to vigorously defend itself against the charges. On July 28, 2016, at an arraignment hearing held in California Superior Court in Santa Barbara County, PAA pled not guilty to all counts. Also in late May of 2015, the United States Attorney for the Department of Justice, Central District of California, Environmental Crimes Section (“DOJ”) began an investigation into whether there were any violations of federal criminal statutes in connection with the Line 901 incident, including potential violations of the federal Clean Water Act. We are cooperating with the DOJ’s investigation by responding to their requests for documents and access to our employees. The DOJ has already spoken to several of our employees and has expressed an interest in talking to other employees; consistent with the terms of our governing organizational documents, we are funding our employees’ defense costs, including the costs of separate counsel engaged to represent such individuals. On August 26, 2015, we received a Request for Information from the EPA relating to Line 901. We have provided various responsive materials to date and we will continue to do so in the future in cooperation with the EPA. While to date no civil or criminal charges with respect to the Line 901 release, other than those brought pursuant to the May 2016 Indictment, have been brought against PAA or any of its affiliates, officers or employees by PHMSA, DOJ, EPA, the California Attorney General, the Santa Barbara District Attorney or the California Department of Fish and Wildlife, and no fines or penalties have been imposed by such governmental agencies, the investigations being conducted by such agencies are still open and we may have fines or penalties imposed upon us, our officers or our employees, or civil or criminal charges brought against us, our officers or our employees in the future, whether by those or other governmental agencies. Shortly following the Line 901 incident, we established a claims line and encouraged any parties that were damaged by the release to contact us to discuss their damage claims. We have received a number of claims through the claims line and we are processing those claims for payment as we receive them. In addition, we have also had nine class action lawsuits filed against us, seven of which have been administratively consolidated into a single proceeding in the United States District Court for the Central District of California. In general, the plaintiffs are seeking to establish different classes of claimants that have allegedly been damaged by the release, including potential classes such as persons that derive a significant portion of their income through commercial fishing and harvesting activities in the waters adjacent to Santa Barbara County or from businesses that are dependent on marine resources from Santa Barbara County, retail businesses located in historic downtown Santa Barbara, certain owners of oceanfront and/or beachfront property on the Pacific Coast of California, and other classes of individuals and businesses that were allegedly impacted by the release. 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, deny the allegations in these lawsuits and intend to respond 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 these lawsuits; we are also indemnifying and funding the defense costs of our underwriters pursuant to the terms of the underwriting agreements we previously entered into with such underwriters. In addition, three unitholder derivative lawsuits have been filed by certain purported investors in PAA against PAA, certain of its affiliates and certain officers and directors. Two of these lawsuits which were filed in the United States District Court for the Southern District of Texas have been administratively consolidated into one action and the other was filed in State District Court in Harris County, Texas. In general, these lawsuits allege that the various defendants breached their fiduciary duties, engaged in gross mismanagement and made false and misleading statements, among other similar allegations, in connection with their management and oversight of PAA during the period of time leading up to and following the Line 901 release. The plaintiffs claim that PAA suffered unspecified damages as a result of the actions of the various defendants and seek to hold the defendants liable for such damages, in addition to other remedies. The defendants deny the allegations in these lawsuits and intend to respond 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 these lawsuits. We have also had two lawsuits filed against us wherein the respective plaintiffs seek to compel the production of certain books and records that purportedly relate to the Line 901 incident, our alleged failure to comply with certain regulations and other matters. These lawsuits have been consolidated into a single proceeding in the Chancery Court for the State of Delaware. 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 June 30, 2016, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $269 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. 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 expected number of days that monitoring services will be required, (ii) the duration of the natural resource damage assessment and the ultimate amount of damages determined, (iii) 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, (iv) the determination and calculation of fines and penalties, but excluding fines and penalties that are not probable and reasonably estimable and (v) 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 June 30, 2016, we had a remaining undiscounted gross liability of $91 million related to this event, of which approximately $51 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 June 30, 2016, we had collected, subject to customary reservations, $124 million out of the approximate $186 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of June 30, 2016, we have recognized a receivable of approximately $62 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 $42 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 substantially completed the clean-up and remediation efforts, excluding long-term site monitoring activities; however, we expect to make payments for additional costs associated with restoration and monitoring of the area, as well as natural resource damage assessment, legal, professional and regulatory costs, in addition to fines and penalties, during future periods. MP29 Release. On July 10, 2015, we experienced a crude oil release of approximately 100 barrels at our Pocahontas Pump Station near the border of Bond and Madison Counties in Illinois, approximately 40 miles from St. Louis, Missouri. The Pocahontas Station is part of the Capwood pipeline that runs from our Patoka Station to Wood River, Illinois. A portion of the released crude oil was contained within our Pocahontas facility, but some of the released crude oil entered a nearby waterway where it was contained with booms. On July 14, 2015, PHMSA issued a corrective action order requiring us to take various actions in response to the release, including remediation, reporting and other actions. As of December 18, 2015, we had submitted all requested information and reports required by the corrective action order and are currently awaiting PHMSA’s comment or approval. On August 10, 2015, we received a Notice of Violation from the Illinois Environmental Protection Agency (the “Agency”) alleging violations relating to the release and outlining the activities recommended by the Agency to resolve the alleged violations, including the completion of an investigation and various remediation activities. The Agency approved a work plan describing remediation activities proposed for remaining hydrocarbons at Pocahontas Station and affected waterways. Remediation activities under this work plan have effectively been completed, and on December 17, 2015, we entered into a Compliance Commitment Agreement with the Agency, which provides the framework for final completion and documentation of the remediation effort. On April 15, 2016, the Agency confirmed that all of the activities required by the Compliance Commitment Agreement had been completed and that the violations associated with the incident had been resolved. To date, no fines or penalties have been assessed in this matter; however, it remains possible that fines and penalties could be assessed in the future. In connection with this incident, we have also had one class action lawsuit filed against us in the United States District Court for the Southern District of Illinois, which was subsequently voluntarily dismissed by the plaintiff. We estimate that the aggregate total costs we have incurred or will incur with respect to this release will be less than $10 million. In the Matter of Bakersfield Crude Terminal LLC et al. On April 30, 2015, the EPA issued a Finding and Notice of Violation (“NOV”) to Bakersfield Crude Terminal LLC, our subsidiary, for alleged violations of the Clean Air Act, as amended. The NOV, which cites 10 separate rule violations, questions the validity of construction and operating permits issued to our Bakersfield rail unloading facility in 2012 and 2014 by the San Joaquin Valley Air Pollution Control District (the “SJV District”). We believe we fully complied with all applicable regulatory requirements and that the permits issued to us by the SJV District are valid. To date, no fines or penalties have been assessed in this matter; however, it is possible that fines and penalties could be assessed in the future. Mesa to Basin Pipeline. On January 6, 2016, PHMSA issued a Notice of Probable Violation and Proposed Civil Penalty relating to an approximate 500 barrel release of crude oil that took place on January 1, 2015 on our Mesa to Basin 12” pipeline in Midland, Texas. PHMSA conducted an accident investigation and reviewed documentation related to the incident, and concluded that we had committed probable violations of certain pipeline safety regulations. In the Notice, PHMSA maintains that we failed to carry out our written damage prevention program and to follow our pipeline excavation/ditching and backfill procedures on four separate occasions, and that such failures resulted in outside force damage that led to the January 1, 2015 release. PHMSA’s compliance officer has recommended that we be assessed a civil penalty of $190,000. We have formally responded to PHMSA regarding this matter, but at this point we can provide no assurance regarding the final disposition of this matter or the final amount of any civil penalties.

Operating Segments

6 Months Ended

Jun. 30, 2016

Operating Segments

Operating Segments

Note 12—Operating Segments

We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates segment performance based on measures including segment profit and maintenance capital investment. We define segment profit 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. Each of the items above excludes depreciation and amortization. Maintenance capital consists of capital expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets.

The following table reflects certain financial data for each segment (in millions):

Three Months Ended June 30, 2016	Transportation		Facilities		Supply and Logistics			Total
Revenues:
External customers	$	170	$	132	$	4,648		$	4,950
Intersegment (1)	233		138		4			375

Total revenues of reportable segments	$	403	$	270	$	4,652		$	5,325

Equity earnings in unconsolidated entities	$	40	$	—	$	—		$	40

Segment profit/(loss) (2) (3)	$	252	$	156	$	(18	)	$	390

Maintenance capital	$	23	$	9	$	3		$	35

Three Months Ended June 30, 2015	Transportation		Facilities		Supply and Logistics		Total
Revenues:
External customers	$	180	$	137	$	6,346	$	6,663
Intersegment (1)	222		132		5		359

Total revenues of reportable segments	$	402	$	269	$	6,351	$	7,022

Equity earnings in unconsolidated entities	$	52	$	—	$	—	$	52

Segment profit (2) (3)	$	186	$	144	$	41	$	371

Maintenance capital	$	33	$	17	$	2	$	52

Six Months Ended June 30, 2016	Transportation		Facilities		Supply and Logistics		Total
Revenues:
External customers	$	323	$	270	$	8,467	$	9,060
Intersegment (1)	464		265		6		735

Total revenues of reportable segments	$	787	$	535	$	8,473	$	9,795

Equity earnings in unconsolidated entities	$	87	$	—	$	—	$	87

Segment profit (2) (3)	$	499	$	315	$	19	$	833

Maintenance capital	$	57	$	18	$	6	$	81

Six Months Ended June 30, 2015	Transportation		Facilities		Supply and Logistics		Total
Revenues:
External customers	$	366	$	261	$	11,978	$	12,605
Intersegment (1)	437		264		6		707

Total revenues of reportable segments	$	803	$	525	$	11,984	$	13,312

Equity earnings in unconsolidated entities	$	89	$	—	$	—	$	89

Segment profit (2) (3)	$	428	$	285	$	171	$	884

Maintenance capital	$	66	$	32	$	4	$	102

(1)

Segment revenues include intersegment amounts that are eliminated in “Purchases and related costs” and “Field operating costs” in our Condensed Consolidated Statements of Operations. Intersegment sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated. For further discussion, see “Analysis of Operating Segments” under Item 7 of our 2015 Annual Report on Form 10-K.

(2)

Supply and Logistics segment profit includes interest expense (related to hedged inventory purchases) of $3 million and $2 million for the three months ended June 30, 2016 and 2015, respectively, and $6 million and $3 million for the six months ended June 30, 2016 and 2015, respectively.

(3)

The following table reconciles segment profit to net income attributable to PAGP (in millions):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Segment profit	$	390		$	371		$	833		$	884
Unallocated general and administrative expenses	—			(1		)	(1		)	(2		)
Depreciation and amortization	(205		)	(108		)	(320		)	(213		)
Interest expense, net	(118		)	(109		)	(233		)	(216		)
Other income/(expense), net	25			1			30			(3		)

Income before tax	92			154			309			450
Income tax expense	(10		)	(51		)	(50		)	(85		)

Net income	82			103			259			365
Net income attributable to noncontrolling interests	(40		)	(73		)	(181		)	(304		)

Net income attributable to PAGP	$	42		$	30		$	78		$	61

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e9038-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 33
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8971-108599

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8595-108599

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8380-108599

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8844-108599

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 35
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8984-108599

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 40
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e9031-108599

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e9054-108599

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8538-108599

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 29
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8864-108599

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8924-108599

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8906-108599

+ Details

Acquisitions, Dispositions and Impairments	6 Months Ended
Acquisitions, Dispositions and Impairments	Jun. 30, 2016
Acquisitions, Dispositions and Impairments
Acquisitions, Dispositions and Impairments	Note 13—Acquisitions, Dispositions and Impairments Acquisitions. During the first six months of 2016, we completed one acquisition for cash consideration of $85 million. We did not recognize any goodwill related to this acquisition. In addition, in August 2016, we completed the acquisition of an integrated system of NGL assets in Western Canada from Westcoast Energy Inc., a unit of Spectra Energy, for cash consideration of approximately $204 million, including $51 million for inventory and working capital. Dispositions and Divestitures. During the six months ended June 30, 2016, we sold several non-core assets, including certain of our Gulf of Mexico pipelines and East Coast refined products terminals. In addition, in June 2016 we sold 50% of our investment in Cheyenne Pipeline LLC. We recognized gains of approximately $71 million and losses of $55 million related to these sales, including $15 million of impairment of goodwill that was included in a disposal group classified as held for sale as of March 31, 2016. These gains and losses are included in “Depreciation and amortization” on our Condensed Consolidated Statement of Operations. As of June 30, 2016, we classified approximately $152 million of assets as held for sale on our Condensed Consolidated Balance Sheet (in “Other current assets”) related to definitive agreements to sell additional non-core assets, a majority of which are included in our Transportation segment. A portion of these transactions closed in July 2016, and we expect the sale of the remaining assets to be consummated later in the third quarter of 2016, subject to customary closing conditions, as applicable. Impairments. During the second quarter of 2016, we recognized approximately $80 million of non-cash impairment losses on certain of our long-lived rail and other terminal assets included in our Facilities segment. Such impairment losses are reflected in “Depreciation and amortization” on our Condensed Consolidated Statement of Operations. The decline in demand for movements of crude oil by rail in the United States due to sustained unfavorable market conditions resulted in expected decreases in future cash flows for certain of our rail terminal assets, which was a triggering event that required us to assess the recoverability of our carrying value of such long-lived assets. As a result of this impairment review, we wrote off the portion of the carrying amount of these long-lived assets that exceeded their fair value. Our estimated fair values were based upon recent sales prices of comparable facilities, as well as management’s expectation of the market values for such assets based on their industry experience. We consider such inputs to be a Level 3 input in the fair value hierarchy. In addition, during the second quarter of 2016, we recognized a charge of approximately $18 million to “Depreciation and amortization” related to the write-off of the remaining book value of assets taken out of service.

Simplification Transactions

6 Months Ended

Jun. 30, 2016

Simplification Transactions

Simplification Transactions

Note 14—Simplification Transactions

On July 11, 2016, PAGP, PAA, AAP, PAA GP, GP LLC and GP Holdings entered into a Simplification Agreement pursuant to which, upon closing, in exchange for the issuance by PAA to AAP of approximately 245.5 million common units representing limited partner interests in PAA (“PAA Common Units”) and the assumption by PAA of AAP’s outstanding debt (as of June 30, 2016, approximately $593 million), AAP will contribute the IDRs to PAA and PAA GP’s 2% economic general partner interest in PAA will be converted into a non-economic general partner interest in PAA. Following the closing of the transactions contemplated by the Simplification Agreement (the “Simplification Transactions”), both PAGP and PAA will continue to be publicly traded.

Among other approvals, the terms of the Simplification Agreement and the Simplification Transactions were unanimously approved by a conflicts committee comprised of independent directors of the Board of Directors of GP LLC on behalf of PAA, and unanimously approved by the Board of Directors of our general partner on behalf of PAGP.

In addition to the terms described above, the Simplification Agreement also provides for the following:

Under a unified governance structure, the Board of Directors of our general partner will have oversight responsibility over both PAGP and PAA. In addition, starting in 2018, our Class A and Class B shareholders and PAA’s common and preferred unitholders will have the right to participate in the election of directors of the board of our general partner whose terms expire. Under the current structure, PAA common unitholders are not eligible to participate in the election of directors of our general partner and our Class A and Class B shareholders only participate in such elections following a reduction in ownership of the private AAP owner group to below 40%.

In addition, similar to the current structure, for so long as each of EMG Investment, LLC (an affiliate of The Energy & Minerals Group), KAFU Holdings, L.P. (an affiliate of Kayne Anderson Investment Management Inc.) and Oxy Holding Company (Pipeline), Inc. (a subsidiary of Occidental Petroleum Corporation), together with their respective affiliates (together, the “Original Designating Parties”), own at least a 10% interest in the outstanding AAP units, such party will continue to be entitled to designate one director to the Board of Directors of our general partner. The calculation of such qualifying interest will include, in addition to any of our Class A shares owned by an Original Designating Party or its affiliates, any PAA common units received by such Original Designating Party of its affiliates in connection with their exercise of the Redemption Right (defined below).

AAP will execute a reverse split to adjust the number of AAP units such that the number of outstanding AAP units (assuming the conversion of AAP Management Units into AAP units) equals the number of PAA Common Units received by AAP at the closing of the Simplification Transactions. Simultaneously, we will execute a reverse split to adjust the number of our Class A and Class B shares outstanding to equal the number of AAP units we own following AAP’s reverse unit split. As a result of these reverse splits, each Class A share will correspond, on a one-to-one basis, to an underlying PAA Common Unit held by AAP which is attributable to our ownership in AAP.

Holders of AAP units other than us and GP LLC will continue to have the right to exchange their AAP units (together with the corresponding Class B shares and, if applicable, units of our general partner) for our Class A shares on a one-for-one basis or, alternatively, to redeem such ownership and related rights for their proportionate share of PAA Common Units held by AAP, subject to certain limitations (the “Redemption Right”). Upon any such redemption, the holders of AAP units receiving PAA Common Units will have registration rights with respect to such PAA Common Units.

It is anticipated that the Simplification Transactions will be consummated during the fourth quarter of 2016. Pursuant to the terms of the Simplification Agreement, AAP has agreed that if such closing does not occur prior to the record date for PAA’s distribution of available cash in respect of the third quarter of 2016 and the amount of such distribution is below the current quarterly level of $0.70 per common unit, AAP will borrow funds under its existing credit agreement as necessary to make a special “true-up” distribution to AAP’s unitholders that, when added to the distributions to be paid to AAP in respect of its indirect 2% general partner interest and IDRs, equals the total distribution such unitholders would have received had the closing of the Simplification Transactions occurred prior to such third quarter record date. Based on the previously announced intent of PAA to reduce its quarterly distribution to $0.55 per common unit commencing with its third quarter distribution, it is estimated that the potential incremental borrowings that would be made by AAP if the closing of the Simplification Transactions does not take place by the record date for PAA’s third quarter distribution will be approximately $41 million.

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

The consummation of the matters contemplated by the Simplification Agreement is subject to customary closing conditions and may be terminated under certain conditions.

Net Income Per Class A Share (Tables)

6 Months Ended

Jun. 30, 2016

Net Income Per Class A Share

Calculation of basic and diluted net income per Class A share

The following table illustrates the calculation of basic and diluted net income per Class A share (in millions, except per share data):

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Basic Net Income per Class A Share
Net income attributable to PAGP	$	42	$	30	$	78	$	61
Basic weighted average Class A shares outstanding	267		224		260		218

Basic net income per Class A share	$	0.16	$	0.14	$	0.30	$	0.28


Diluted Net Income per Class A Share
Net income attributable to PAGP	$	42	$	30	$	78	$	61
Incremental net income attributable to PAGP resulting from assumed exchange of AAP units and AAP Management Units	52		—		111		105

Net income attributable to PAGP including incremental net income from assumed exchange of AAP units and AAP Management Units	$	94	$	30	$	189	$	166


Basic weighted average Class A shares outstanding	267		224		260		218
Dilutive shares resulting from assumed exchange of AAP units and AAP Management Units	357		—		392		388

Diluted weighted average Class A shares outstanding	624		224		652		606


Diluted net income per Class A share	$	0.15	$	0.14	$	0.29	$	0.27

Inventory, Linefill and Base Gas and Long-term Inventory (Tables)

6 Months Ended

Jun. 30, 2016

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):

	June 30, 2016						December 31, 2015
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	20,013	barrels	$	819	$	40.92	16,345	barrels	$	608	$	37.20
NGL	12,813	barrels	209		$	16.31	13,907	barrels	218		$	15.68
Natural gas	15,055	Mcf	31		$	2.06	22,080	Mcf	53		$	2.40
Other	N/A		26		N/A		N/A		37		N/A

Inventory subtotal			1,085						916


Linefill and base gas
Crude oil	12,227	barrels	716		$	58.56	12,298	barrels	713		$	57.98
NGL	1,355	barrels	45		$	33.21	1,348	barrels	44		$	32.64
Natural gas	30,812	Mcf	141		$	4.58	30,812	Mcf	141		$	4.58

Linefill and base gas subtotal			902						898


Long-term inventory
Crude oil	3,396	barrels	162		$	47.70	3,417	barrels	106		$	31.02
NGL	1,418	barrels	22		$	15.51	1,652	barrels	23		$	13.92

Long-term inventory subtotal			184						129


Total			$	2,171					$	1,943

(1)

Goodwill (Tables)

6 Months Ended

Jun. 30, 2016

Goodwill

Schedule of goodwill by segment and changes during the period

Goodwill by segment and changes in goodwill is reflected in the following table (in millions):

	Transportation			Facilities			Supply and Logistics		Total
Balance at December 31, 2015	$	815		$	1,087		$	503	$	2,405

Foreign currency translation adjustments	14			6			2		22
Dispositions	(15		)	(16		)	—		(31		)

Balance at June 30, 2016	$	814		$	1,077		$	505	$	2,396

Debt (Tables)

6 Months Ended

Jun. 30, 2016

Debt

Schedule of debt

Debt consisted of the following (in millions):

	June 30,			December 31,
	2016			2015
SHORT-TERM DEBT
PAA commercial paper notes, bearing a weighted-average interest rate of 1.3% and 1.1%, respectively (1)	$	172		$	696
PAA senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.4% and 1.4%, respectively (1)	552			300
PAA senior notes:
5.88% senior notes due August 2016	175			—
6.13% senior notes due January 2017	400			—
Other	3			3

Total short-term debt	1,302			999

LONG-TERM DEBT
PAA senior notes, net of unamortized discounts and debt issuance costs of $72 and $77, respectively	9,128			9,698
Other long-term debt:
PAA commercial paper notes, bearing a weighted-average interest rate of 1.3% and 1.1%, respectively	354			672
AAP term loan, bearing a weighted-average interest rate of 2.1% and 2.0%, respectively	550			550
AAP senior secured revolving credit facility, bearing a weighted-average interest rate of 2.0% and 2.0%, respectively	43			9
Unamortized debt issuance costs	(2		)	(2		)
Other	4			5

Total long-term debt	10,077			10,932

Total debt (2)	$	11,379		$	11,931

(1)

(2)

Partners' Capital and Distributions (Tables)

6 Months Ended

Jun. 30, 2016

Partners Capital and Distributions

Schedule of activity for Class A and Class B shares

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

	Class B Shares		Class A Shares
Outstanding at December 31, 2015	376,771,593		229,278,980

Shares issued in connection with conversion of AAP Management Units	17,954,751		—
Shares (exchanged)/issued in connection with Exchange Right exercises	(37,732,439	)	37,732,439
Shares issued in connection with PAGP LTIP award vestings	—		20,800

Outstanding at June 30, 2016	356,993,905		267,032,219

	Class B Shares		Class A Shares
Outstanding at December 31, 2014	399,096,499		206,933,274
Shares (exchanged)/issued in connection with Exchange Right exercises	(17,358,379	)	17,358,379
Shares issued in connection with PAGP LTIP award vestings	—		20,800
Outstanding at June 30, 2015	381,738,120		224,312,453

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 six months of 2016 from distributions received from PAA (in millions):

						Distributions to AAP’s Partners
	Distributions Received		Cash					Noncontrolling
Distribution Date	by AAP from PAA		Reserves			Total		Interests		PAGP
August 12, 2016 (1)	$	155	$	(4	)	$	151	$	89	$	62
May 13, 2016	$	155	$	(5	)	$	150	$	89	$	61
February 12, 2016	$	155	$	(4	)	$	151	$	96	$	55

(1)

Payable to unitholders of record at the close of business on July 29, 2016 for the period April 1, 2016 through June 30, 2016.

Class A Shares

Partners Capital and Distributions

Schedule of distributions

The following table details the distributions paid to our Class A shareholders during or pertaining to the first six months of 2016 (in millions, except per share data):

		Distributions to		Distributions per
Date Declared	Distribution Date	Class A Shareholders		Class A Share
July 11, 2016	August 12, 2016 (1)	$	62	$	0.231
April 7, 2016	May 13, 2016	$	62	$	0.231
January 12, 2016	February 12, 2016	$	55	$	0.231

(1)

Payable to shareholders of record at the close of business on July 29, 2016 for the period April 1, 2016 through June 30, 2016.

PAA

Partners Capital and Distributions

Schedule of distributions

The following table details the distributions to PAA’s partners paid in cash during or pertaining to the first six months of 2016, net of reductions in AAP’s incentive distributions (in millions, except per unit data):

		Distributions						Distributions per
Date Declared	Distribution Date	Common Unitholders		AAP		Total		common unit
July 11, 2016	August 12, 2016 (1)	$	278	$	155	$	433	$	0.70
April 7, 2016	May 13, 2016	$	278	$	155	$	433	$	0.70
January 12, 2016	February 12, 2016	$	278	$	155	$	433	$	0.70

(1)

Payable to unitholders of record at the close of business on July 29, 2016 for the period April 1, 2016 through June 30, 2016.

Derivatives and Risk Management Activities (Tables)

6 Months Ended

Jun. 30, 2016

Derivatives and Risk Management Activities

Impact of derivative activities recognized in earnings

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

	Three Months Ended June 30, 2016									Three Months Ended June 30, 2015
Location of Gain/(Loss)	Derivatives in Hedging Relationships (1)			Derivatives Not Designated as a Hedge			Total			Derivatives in Hedging Relationships			Derivatives Not Designated as a Hedge		Total
Commodity Derivatives

Supply and Logistics segment revenues	$	(1	)	$	(159	)	$	(160	)	$	(19	)	$	44	$	25

Transportation segment revenues	—			1			1			—			2		2

Field operating costs	—			2			2			—			2		2

Interest Rate Derivatives

Interest expense, net	(4		)	—			(4		)	(4		)	—		(4		)

Foreign Currency Derivatives

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

Preferred Distribution Rate Reset Option

Other income/(expense), net	—			25			25			—			—		—


Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(5	)	$	(132	)	$	(137	)	$	(23	)	$	48	$	25

	Six Months Ended June 30, 2016									Six Months Ended June 30, 2015
Location of Gain/(Loss)	Derivatives in Hedging Relationships (1)			Derivatives Not Designated as a Hedge			Total			Derivatives in Hedging Relationships			Derivatives Not Designated as a Hedge			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	—		$	(128	)	$	(128	)	$	(12	)	$	10		$	(2	)

Transportation segment revenues	—			3			3			—			4			4

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

Interest Rate Derivatives

Interest expense, net	(6		)	—			(6		)	(5		)	—			(5		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			5			5			—			(17		)	(17		)

Preferred Distribution Rate Reset Option

Other income/(expense), net	—			25			25			—			—			—


Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(6	)	$	(95	)	$	(101	)	$	(17	)	$	(5	)	$	(22	)

(1)

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 June 30, 2016 (in millions):

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	2

Interest rate derivatives				Other current liabilities	$	(64	)
				Other long-term liabilities and deferred credits	(91		)

Total derivatives designated as hedging instruments		$	2		$	(155	)


Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	45	Other current assets	$	(182	)
	Other long-term liabilities and deferred credits	6		Other current liabilities	(6		)
				Other long-term liabilities and deferred credits	(17		)

Foreign currency derivatives				Other current liabilities	(1		)

Preferred Distribution Rate Reset Option				Other long-term liabilities and deferred credits	(35		)

Total derivatives not designated as hedging instruments		$	51		$	(241	)


Total derivatives		$	53		$	(396	)

The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of December 31, 2015 (in millions):

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	4	Other current assets	$	(2	)

Interest rate derivatives	Other long-term assets, net	1		Other current liabilities	(17		)
				Other long-term liabilities and deferred credits	(33		)

Total derivatives designated as hedging instruments		$	5		$	(52	)


Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	265	Other current assets	$	(35	)
	Other long-term assets, net	10		Other long-term assets, net	(1		)
				Other current liabilities	(13		)
				Other long-term liabilities and deferred credits	(1		)

Foreign currency derivatives				Other current liabilities	(8		)

Total derivatives not designated as hedging instruments		$	275		$	(58	)


Total derivatives		$	280		$	(110	)

Schedule of derivative financial assets and 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):

	June 30, 2016						December 31, 2015
	Derivative			Derivative			Derivative			Derivative
	Asset Positions			Liability Positions			Asset Positions			Liability Positions
Netting Adjustments:
Gross position - asset/(liability)	$	53		$	(396	)	$	280		$	(110	)
Netting adjustment	(188		)	188			(38		)	38
Cash collateral paid/(received)	274			—			(156		)	—

Net position - asset/(liability)	$	139		$	(208	)	$	86		$	(72	)


Balance Sheet Location After Netting Adjustments:
Other current assets	$	139		$	—		$	76		$	—
Other long-term assets, net	—			—			10			—
Other current liabilities	—			(71		)	—			(38		)
Other long-term liabilities and deferred credits	—			(137		)	—			(34		)

	$	139		$	(208	)	$	86		$	(72	)

Net deferred gain/(loss) recognized in AOCI for derivatives

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Commodity derivatives, net	$	—		$	(28	)	$	—		$	(25	)
Interest rate derivatives, net	(68		)	120			(158		)	45

Total	$	(68	)	$	92		$	(158	)	$	20

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 June 30, 2016												Fair Value as of December 31, 2015
Recurring Fair Value Measures (1)	Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total
Commodity derivatives	$	(133	)	$	(19	)	$	—		$	(152	)	$	126	$	90		$	11	$	227
Interest rate derivatives	—			(155		)	—			(155		)	—		(49		)	—		(49		)
Foreign currency derivatives	—			(1		)	—			(1		)	—		(8		)	—		(8		)
Preferred Distribution Rate Reset Option	—			—			(35		)	(35		)	—		—			—		—

Total net derivative asset/(liability)	$	(133	)	$	(175	)	$	(35	)	$	(343	)	$	126	$	33		$	11	$	170

(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						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Beginning Balance	$	(59	)	$	5		$	11		$	15
Gains for the period included in earnings	23			1			23			1
Settlements	—			(1		)	(9		)	(13		)
Derivatives entered into during the period	1			4			(60		)	6

Ending Balance	$	(35	)	$	9		$	(35	)	$	9


Change in unrealized gains included in earnings relating to Level 3 derivatives still held at the end of the period	$	24		$	5		$	24		$	6

Interest Rate Swaps

Derivatives and Risk Management Activities

Schedule of terms of forward starting interest rate swaps

The following table summarizes the terms of our forward starting interest rate swaps as of June 30, 2016 (notional amounts in millions):

Hedged Transaction	Number and Types of Derivatives Employed	Notional Amount		Expected Termination Date	Average Rate Locked		Accounting Treatment
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	4/13/2017	2.02	%	Cash flow hedge
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	6/15/2017	3.14	%	Cash flow hedge
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	6/15/2018	3.20	%	Cash flow hedge
Anticipated interest payments	8 forward starting swaps (30-year)	$	200	6/14/2019	2.83	%	Cash flow hedge

Foreign Currency Derivatives

Derivatives and Risk Management Activities

Open forward exchange contracts

The following table summarizes our open forward exchange contracts as of June 30, 2016 (in millions):

		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2016	$	19	$	25	$1.00 - $1.29

Forward exchange contracts that exchange USD for CAD:
	2016	$	186	$	241	$1.00 - $1.29
	2017	$	20	$	26	$1.00 - $1.29

Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2016

Oxy

Related Party Transactions

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					Six Months Ended
	June 30,					June 30,
	2016			2015		2016			2015
Revenues	$	142		$	382	$	254		$	558

Purchases and related costs (1)	$	(4	)	$	41	$	(50	)	$	146

(1)

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

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

	June 30,		December 31,
	2016		2015
Trade accounts receivable and other receivables	$	495	$	405

Accounts payable	$	460	$	363

Operating Segments (Tables)

6 Months Ended

Jun. 30, 2016

Operating Segments

Segment financial data

The following table reflects certain financial data for each segment (in millions):

Three Months Ended June 30, 2016	Transportation		Facilities		Supply and Logistics			Total
Revenues:
External customers	$	170	$	132	$	4,648		$	4,950
Intersegment (1)	233		138		4			375

Total revenues of reportable segments	$	403	$	270	$	4,652		$	5,325

Equity earnings in unconsolidated entities	$	40	$	—	$	—		$	40

Segment profit/(loss) (2) (3)	$	252	$	156	$	(18	)	$	390

Maintenance capital	$	23	$	9	$	3		$	35

Three Months Ended June 30, 2015	Transportation		Facilities		Supply and Logistics		Total
Revenues:
External customers	$	180	$	137	$	6,346	$	6,663
Intersegment (1)	222		132		5		359

Total revenues of reportable segments	$	402	$	269	$	6,351	$	7,022

Equity earnings in unconsolidated entities	$	52	$	—	$	—	$	52

Segment profit (2) (3)	$	186	$	144	$	41	$	371

Maintenance capital	$	33	$	17	$	2	$	52

Six Months Ended June 30, 2016	Transportation		Facilities		Supply and Logistics		Total
Revenues:
External customers	$	323	$	270	$	8,467	$	9,060
Intersegment (1)	464		265		6		735

Total revenues of reportable segments	$	787	$	535	$	8,473	$	9,795

Equity earnings in unconsolidated entities	$	87	$	—	$	—	$	87

Segment profit (2) (3)	$	499	$	315	$	19	$	833

Maintenance capital	$	57	$	18	$	6	$	81

Six Months Ended June 30, 2015	Transportation		Facilities		Supply and Logistics		Total
Revenues:
External customers	$	366	$	261	$	11,978	$	12,605
Intersegment (1)	437		264		6		707

Total revenues of reportable segments	$	803	$	525	$	11,984	$	13,312

Equity earnings in unconsolidated entities	$	89	$	—	$	—	$	89

Segment profit (2) (3)	$	428	$	285	$	171	$	884

Maintenance capital	$	66	$	32	$	4	$	102

(1)

(2)

(3)

The following table reconciles segment profit to net income attributable to PAGP (in millions):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Segment profit	$	390		$	371		$	833		$	884
Unallocated general and administrative expenses	—			(1		)	(1		)	(2		)
Depreciation and amortization	(205		)	(108		)	(320		)	(213		)
Interest expense, net	(118		)	(109		)	(233		)	(216		)
Other income/(expense), net	25			1			30			(3		)

Income before tax	92			154			309			450
Income tax expense	(10		)	(51		)	(50		)	(85		)

Net income	82			103			259			365
Net income attributable to noncontrolling interests	(40		)	(73		)	(181		)	(304		)

Net income attributable to PAGP	$	42		$	30		$	78		$	61

Reconciliation of segment profit to net income attributable to PAGP

The following table reconciles segment profit to net income attributable to PAGP (in millions):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Segment profit	$	390		$	371		$	833		$	884
Unallocated general and administrative expenses	—			(1		)	(1		)	(2		)
Depreciation and amortization	(205		)	(108		)	(320		)	(213		)
Interest expense, net	(118		)	(109		)	(233		)	(216		)
Other income/(expense), net	25			1			30			(3		)

Income before tax	92			154			309			450
Income tax expense	(10		)	(51		)	(50		)	(85		)

Net income	82			103			259			365
Net income attributable to noncontrolling interests	(40		)	(73		)	(181		)	(304		)

Net income attributable to PAGP	$	42		$	30		$	78		$	61

Organization and Basis of Consolidaton and Presentation (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($) segment shares	Dec. 31, 2015 USD ($)
Organization and basis of presentation
Operating segments number \| segment	3
Deferred tax asset	$ 1,893	$ 1,835
Consolidated Entity Excluding VIEs
Organization and basis of presentation
Deferred tax asset	$ 1,893	$ 1,835
AAP \| PAA \| Indirect Ownership
Organization and basis of presentation
General partner ownership interest (as a percent)	2.00%
PAA GP \| PAA
Organization and basis of presentation
General partner ownership interest (as a percent)	2.00%
GP LLC
Organization and basis of presentation
Consolidated subsidiary, ownership interest held by the parent (as a percent)	100.00%
AAP
Organization and basis of presentation
Consolidated subsidiary, ownership interest held by the parent (as a percent)	43.00%
Consolidated subsidiary, ownership interest held by the parent (in units) \| shares	267,032,219

Organization and Basis of Consolidaton and Presentation - Simplification Agreement (Details) - Simplification Agreement - PAA - Forecast shares in Millions	3 Months Ended
	Dec. 31, 2016 shares
AAP
Simplification Transactions
Issuance of common units (in units)	245.5
PAA GP
Simplification Transactions
Economic general partner interest converted into non-economic interest (as a percent)	2.00%

Organization and Basis of Consolidaton and Presentation - Debt Issuance Costs (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Recent Accounting Pronouncements
Depreciation and amortization	$ 205	$ 108	$ 320	$ 213
Interest expense, net	$ 118	109	$ 233	216
ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs \| Reclassification due to retrospective application of revised guidance
Recent Accounting Pronouncements
Depreciation and amortization		(2)		(5)
Interest expense, net		$ 2		$ 5

Net Income Per Class A Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Basic Net Income per Class A Share
Net income attributable to PAGP	$ 42	$ 30	$ 78	$ 61
Diluted Net Income per Class A Share
Net income attributable to PAGP	42	30	78	61
Incremental net income attributable to PAGP resulting from assumed exchange of AAP units and AAP Management Units	52		111	105
Net income attributable to PAGP including incremental net income from assumed exchange of AAP units and AAP Management Units	$ 94	$ 30	$ 189	$ 166
Class A Shares
Basic Net Income per Class A Share
Basic weighted average Class A shares outstanding	267	224	260	218
Basic net income per Class A share (in dollars per share)	$ 0.16	$ 0.14	$ 0.30	$ 0.28
Diluted Net Income per Class A Share
Basic weighted average Class A shares outstanding	267	224	260	218
Dilutive shares resulting from assumed exchange of AAP units and AAP Management Units	357		392	388
Diluted weighted average Class A shares outstanding	624	224	652	606
Diluted net income per Class A share (in dollars per share)	$ 0.15	$ 0.14	$ 0.29	$ 0.27

Accounts Receivable, Net (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
Accounts Receivable, Net (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Accounts Receivable, Net
Advance cash payments received from third parties to mitigate credit risk	$ 93	$ 88
Standby letters of credit	$ 73	$ 36
Substantially all trade accounts receivable, net, maximum age of balances past their scheduled invoice date	30 days	30 days
Allowance for doubtful accounts receivable	$ 4	$ 4

Inventory, Linefill and Base Gas and Long-term Inventory (Details) bbl in Thousands, Mcf in Thousands, $ in Millions	Jun. 30, 2016 USD ($) $ / bbl $ / Mcf Mcf bbl	Dec. 31, 2015 USD ($) $ / bbl $ / Mcf Mcf bbl
Inventory by category
Inventory	$ 1,085	$ 916
Linefill and base gas	902	898
Long-term inventory	184	129
Total	2,171	1,943
Crude oil
Inventory by category
Inventory	819	608
Linefill and base gas	716	713
Long-term inventory	$ 162	$ 106
Inventory, Volumes (in barrels or in Mcf) \| bbl	20,013	16,345
Linefill and base gas, Volumes (in barrels or in Mcf) \| bbl	12,227	12,298
Long-term inventory, Volumes (in barrels or in Mcf) \| bbl	3,396	3,417
Inventory, Price/Unit of measure (in dollars per unit) \| $ / bbl	40.92	37.20
Linefill and base gas, Price/Unit of measure (in dollars per unit) \| $ / bbl	58.56	57.98
Long-term inventory, Price/Unit of measure (in dollars per unit) \| $ / bbl	47.70	31.02
NGL
Inventory by category
Inventory	$ 209	$ 218
Linefill and base gas	45	44
Long-term inventory	$ 22	$ 23
Inventory, Volumes (in barrels or in Mcf) \| bbl	12,813	13,907
Linefill and base gas, Volumes (in barrels or in Mcf) \| bbl	1,355	1,348
Long-term inventory, Volumes (in barrels or in Mcf) \| bbl	1,418	1,652
Inventory, Price/Unit of measure (in dollars per unit) \| $ / bbl	16.31	15.68
Linefill and base gas, Price/Unit of measure (in dollars per unit) \| $ / bbl	33.21	32.64
Long-term inventory, Price/Unit of measure (in dollars per unit) \| $ / bbl	15.51	13.92
Natural gas
Inventory by category
Inventory	$ 31	$ 53
Linefill and base gas	$ 141	$ 141
Inventory, Volumes (in barrels or in Mcf) \| Mcf	15,055	22,080
Linefill and base gas, Volumes (in barrels or in Mcf) \| Mcf	30,812	30,812
Inventory, Price/Unit of measure (in dollars per unit) \| $ / Mcf	2.06	2.40
Linefill and base gas, Price/Unit of measure (in dollars per unit) \| $ / Mcf	4.58	4.58
Other
Inventory by category
Inventory	$ 26	$ 37

Goodwill (Details) $ in Millions	6 Months Ended
Goodwill (Details) $ in Millions	Jun. 30, 2016 USD ($)
Changes in goodwill
Balance at beginning of period	$ 2,405
Foreign currency translation adjustments	22
Dispositions	(31)
Balance at end of period	2,396
Impairment of goodwill	0
Transportation
Changes in goodwill
Balance at beginning of period	815
Foreign currency translation adjustments	14
Dispositions	(15)
Balance at end of period	814
Facilities
Changes in goodwill
Balance at beginning of period	1,087
Foreign currency translation adjustments	6
Dispositions	(16)
Balance at end of period	1,077
Supply and Logistics
Changes in goodwill
Balance at beginning of period	503
Foreign currency translation adjustments	2
Balance at end of period	$ 505

Debt - Components (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Short-term debt:
Total short-term debt	$ 1,302	$ 999
Long-term debt:
PAA senior notes, net of unamortized discounts and debt issuance costs of $72 and $77, respectively	9,128	9,698
Noncurrent portion of other long-term debt	949	1,234
Total long-term debt	10,077	10,932
Total debt	11,379	11,931
PAA senior notes
Long-term debt:
Unamortized discounts and debt issuance costs	(72)	(77)
PAA senior notes, net of unamortized discounts and debt issuance costs of $72 and $77, respectively	$ 9,128	9,698
5.88% senior notes due August 2016
Debt
Debt instrument, interest rate (as a percent)	5.88%
Short-term debt:
Current portion of long-term notes and other debt	$ 175
6.13% senior notes due January 2017
Debt
Debt instrument, interest rate (as a percent)	6.13%
Short-term debt:
Current portion of long-term notes and other debt	$ 400
Other
Short-term debt:
Current portion of long-term notes and other debt	3	3
Long-term debt:
Noncurrent portion of other long-term debt	4	5
PAA commercial paper notes
Short-term debt:
Short-term notes and borrowings	$ 172	$ 696
Weighted average interest rate, short-term (as a percent)	1.30%	1.10%
Long-term debt:
Noncurrent portion of other long-term debt	$ 354	$ 672
Weighted average interest rate, long-term (as a percent)	1.30%	1.10%
PAA senior secured hedged inventory facility
Short-term debt:
Short-term notes and borrowings	$ 552	$ 300
Weighted average interest rate, short-term (as a percent)	1.40%	1.40%
AAP senior secured credit agreement
Long-term debt:
Unamortized debt issuance costs	$ (2)	$ (2)
AAP term loan
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 550	$ 550
Weighted average interest rate, long-term (as a percent)	2.10%	2.00%
AAP senior secured revolving credit facility
Long-term debt:
Long-term debt, before deducting unamortized discounts and debt issuance costs	$ 43	$ 9
Weighted average interest rate, long-term (as a percent)	2.00%	2.00%

Debt - Fair Value, Activity, Letters of Credit (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Letters of credit
Debt
Outstanding letters of credit	$ 48		$ 46
Credit agreements and PAA commercial paper program
Debt
Total borrowings	23,000	$ 17,900
Total repayments	23,600	$ 17,700
PAA senior notes
Debt
Debt instrument face value	9,800		9,800
PAA senior notes \| Level 2
Debt
Debt instrument fair value	$ 9,600		$ 8,600

Partners' Capital and Distributions - Exchange Rights and Shares Activity (Details)	6 Months Ended
	Jun. 30, 2016 shares	Jun. 30, 2015 shares
Class B Shares
Activity for Class A shares and Class B shares
Balance, beginning of period (in shares)	376,771,593	399,096,499
Balance, end of period (in shares)	356,993,905	381,738,120
Class B Shares \| Exchange of AAP Units and Class B Shares for Class A Shares
Activity for Class A shares and Class B shares
Shares exchanged in connection with Exchange Right exercises	(37,732,439)	(17,358,379)
Class B Shares \| Conversion of AAP Management Units into AAP Units and Class B Shares
Activity for Class A shares and Class B shares
Shares issued in connection with conversion of AAP Management Units	17,954,751
Class A Shares
Activity for Class A shares and Class B shares
Balance, beginning of period (in shares)	229,278,980	206,933,274
Shares issued in connection with PAGP LTIP award vestings	20,800	20,800
Balance, end of period (in shares)	267,032,219	224,312,453
Class A Shares \| Exchange of AAP Units and Class B Shares for Class A Shares
Activity for Class A shares and Class B shares
Shares issued in connection with Exchange Right exercises	37,732,439	17,358,379
AAP \| Exchange of AAP Units and Class B Shares for Class A Shares
Partners Capital and Distributions
Ratio for conversion or exchange of units	1
AAP \| Conversion of AAP Management Units into AAP Units and Class B Shares \| AAP Management Units
Partners Capital and Distributions
Ratio for conversion or exchange of units	0.941
AAP Management Units converted	19,137,234
AAP \| Conversion of AAP Management Units into AAP Units and Class B Shares \| AAP Management Units \| Maximum
Partners Capital and Distributions
Ratio for conversion or exchange of units	1

Partners' Capital and Distributions - Distributions, Class A (Details) - USD ($) $ / shares in Units, $ in Millions					6 Months Ended
	Aug. 12, 2016	Jul. 11, 2016	May 13, 2016	Feb. 12, 2016	Jun. 30, 2016	Jun. 30, 2015
Distributions
Distributions to Class A shareholders					$ 117	$ 92
Class A Shares \| First Quarter Distribution
Distributions
Distribution declared, date			Apr. 07, 2016
Distribution payment date			May 13, 2016
Distributions to Class A shareholders			$ 62
Distribution per Class A share, paid (in dollars per share)			$ 0.231
Class A Shares \| Fourth Quarter Distribution
Distributions
Distribution declared, date				Jan. 12, 2016
Distribution payment date				Feb. 12, 2016
Distributions to Class A shareholders				$ 55
Distribution per Class A share, paid (in dollars per share)				$ 0.231
Class A Shares \| Subsequent Event \| Second Quarter Distribution
Distributions
Distribution declared, date		Jul. 11, 2016
Distributions per Class A share, declared (in dollars per share)		$ 0.231
Shareholders or unitholders of record, date		Jul. 29, 2016
Class A Shares \| Forecast \| Second Quarter Distribution
Distributions
Distribution payment date	Aug. 12, 2016
Distributions to Class A shareholders	$ 62

Partners' Capital and Distributions - Subsidiary Equity Offerings (Details) - Series A Preferred Units - PAA shares in Millions	1 Months Ended	6 Months Ended
	Jan. 31, 2016 $ / shares shares	Jun. 30, 2016 item $ / shares
Partners Capital and Distributions
Private placement of units (in units) \| shares	61.0
Cash purchase price (in dollars per unit)	$ 26.25
Quarterly distribution rate (in dollars per unit)		$ 0.525
Annualized distribution rate (in dollars per unit)		$ 2.10
Number of years following issuance after which unitholders have the option to convert units		2 years
Preferred unit conversion ratio		1
Number of years following issuance after which PAA has the option to convert units		3 years
Preferred Distribution Rate Reset Option
Partners Capital and Distributions
Period after fifth and subsequent anniversaries of issuance for distribution rate reset election option		30 days
Number of distribution rate reset elections allowed \| item		1
Basis spread on variable rate (as a percent)		5.85%
AAP
Partners Capital and Distributions
Distribution percentage for general partner interest		2.00%

Partners' Capital and Distributions - Subsidiary Distributions Paid (Details) - USD ($) $ / shares in Units, $ in Millions					6 Months Ended
	Aug. 12, 2016	Jul. 11, 2016	May 13, 2016	Feb. 12, 2016	Jun. 30, 2016	Jun. 30, 2015
Partners Capital and Distributions
Total distributions paid					$ 860	$ 805
PAA
Partners Capital and Distributions
Noncontrolling interests in subsidiaries (as a percent)					98.00%
AAP
Partners Capital and Distributions
Noncontrolling interests in subsidiaries (as a percent)					57.00%
SLC Pipeline LLC
Partners Capital and Distributions
Noncontrolling interests in subsidiaries (as a percent)					25.00%
Distributions to noncontrolling interests					$ 2
Second Quarter Distribution \| Forecast \| AAP
Partners Capital and Distributions
Distribution payment date	Aug. 12, 2016
Distributions received by AAP from PAA	$ 155
Cash Reserves	(4)
Distributions to limited partners	151
Distributions to noncontrolling interests	89
Distributions to PAGP	$ 62
Unitholders of record, date	Jul. 29, 2016
First Quarter Distribution \| AAP
Partners Capital and Distributions
Distribution payment date			May 13, 2016
Distributions received by AAP from PAA			$ 155
Cash Reserves			(5)
Distributions to limited partners			150
Distributions to noncontrolling interests			89
Distributions to PAGP			$ 61
Fourth Quarter Distribution \| AAP
Partners Capital and Distributions
Distribution payment date				Feb. 12, 2016
Distributions received by AAP from PAA				$ 155
Cash Reserves				(4)
Distributions to limited partners				151
Distributions to noncontrolling interests				96
Distributions to PAGP				$ 55
PAA \| Second Quarter Distribution \| Forecast
Partners Capital and Distributions
Distribution payment date	Aug. 12, 2016
PAA \| Second Quarter Distribution \| Cash Distributions \| Forecast
Partners Capital and Distributions
Distributions to AAP	$ 155
Total distributions paid	433
PAA \| Second Quarter Distribution \| Common Units \| Cash Distributions \| Forecast
Partners Capital and Distributions
Distributions to limited partners	278
PAA \| Second Quarter Distribution \| Series A Preferred Units \| In-Kind Distributions \| Forecast
Partners Capital and Distributions
Distributions to limited partners	$ 33
Distribution of units in lieu of cash (in units)	1,237,765
PAA \| First Quarter Distribution
Partners Capital and Distributions
Distribution declared, date			Apr. 07, 2016
Distribution payment date			May 13, 2016
PAA \| First Quarter Distribution \| Cash Distributions
Partners Capital and Distributions
Distributions to AAP			$ 155
Total distributions paid			433
PAA \| First Quarter Distribution \| Common Units \| Cash Distributions
Partners Capital and Distributions
Distributions to limited partners			$ 278
Distributions per common unit, paid (in dollars per unit)			$ 0.70
PAA \| First Quarter Distribution \| Series A Preferred Units \| In-Kind Distributions
Partners Capital and Distributions
Distributions to limited partners			$ 23
Distribution of units in lieu of cash (in units)			858,439
PAA \| Fourth Quarter Distribution
Partners Capital and Distributions
Distribution declared, date				Jan. 12, 2016
Distribution payment date				Feb. 12, 2016
PAA \| Fourth Quarter Distribution \| Cash Distributions
Partners Capital and Distributions
Distributions to AAP				$ 155
Total distributions paid				433
PAA \| Fourth Quarter Distribution \| Common Units \| Cash Distributions
Partners Capital and Distributions
Distributions to limited partners				$ 278
Distributions per common unit, paid (in dollars per unit)				$ 0.70
Subsequent Event \| PAA \| Second Quarter Distribution
Partners Capital and Distributions
Distribution declared, date		Jul. 11, 2016
Unitholders of record, date		Jul. 29, 2016
Subsequent Event \| PAA \| Second Quarter Distribution \| Common Units \| Cash Distributions
Partners Capital and Distributions
Distributions per common unit, declared (in dollars per unit)		$ 0.70

Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions, Mcf in Millions, MWh in Millions	6 Months Ended
	Jun. 30, 2016 MWh Mcf bbl
Net long position associated with crude oil purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	2.1
Net short time spread position hedging anticipated crude oil lease gathering purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	3.9
Crude oil grade spread positions
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	7.0
Net short position related to anticipated sales of natural gas inventory
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf) \| Mcf	13.0
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)	25.8
PLA crude oil long call option position
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	1.2
Long natural gas position for natural gas purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf) \| Mcf	22.0
Short propane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	4.2
Short butane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	1.3
Short WTI position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	0.5
Long power position for power supply requirements
Commodity Price Risk Hedging:
Derivative position notional amount (in megawatt hours) \| MWh	0.3

Derivatives and Risk Management Activities - Interest Rate Risk Hedging (Details) $ in Millions	1 Months Ended	6 Months Ended
	Jun. 30, 2016 USD ($) contract	Jun. 30, 2016 USD ($) contract	Jun. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Interest Rate Risk Hedging
Net deferred gains/(losses) included in AOCI	$ (1,036)	$ (1,036)	$ (673)	$ (1,081)	$ (467)
Cash paid in connection with termination of interest rate derivatives		50	$ 29
Interest Rate Derivatives
Interest Rate Risk Hedging
Net deferred gains/(losses) included in AOCI	$ (334)	$ (334)
8 forward starting interest rate swaps (30-year), 2.02% \| Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives (in contracts) \| contract	8	8
Notional amount of derivatives	$ 200	$ 200
Average rate locked (as a percent)	2.02%	2.02%
8 forward starting interest rate swaps (30-year), 3.14% \| Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives (in contracts) \| contract	8	8
Notional amount of derivatives	$ 200	$ 200
Average rate locked (as a percent)	3.14%	3.14%
8 forward starting interest rate swaps (30-year), 3.20% \| Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives (in contracts) \| contract	8	8
Notional amount of derivatives	$ 200	$ 200
Average rate locked (as a percent)	3.20%	3.20%
8 forward starting interest rate swaps (30-year), 2.83% \| Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives (in contracts) \| contract	8	8
Notional amount of derivatives	$ 200	$ 200
Average rate locked (as a percent)	2.83%	2.83%
8 forward starting interest rate swaps (30-year), 3.06%
Interest Rate Risk Hedging
Net deferred gains/(losses) included in AOCI	$ (50)	$ (50)
Cash paid in connection with termination of interest rate derivatives	$ 52
Number of interest rate derivatives terminated (in contracts) \| contract	8
Notional amount of derivatives	$ 200	$ 200
Average rate locked (as a percent)	3.06%	3.06%
8 forward starting interest rate swaps (30-year), 3.06% \| Interest expense, net
Interest Rate Risk Hedging
Loss recognized due to anticipated hedged transactions now considered probable of not occurring	$ 2

Derivatives and Risk Management Activities - Currency Exchange Rate Risk Hedging (Details) $ in Millions, $ in Millions	Jun. 30, 2016 CAD ($) $ / $	Jun. 30, 2016 USD ($) $ / $
Forward exchange contracts that exchange CAD for USD at the rate USD 1.00 to CAD 1.29 maturing in 2016
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 25	$ 19
Average exchange rate	1.29	1.29
Forward exchange contracts that exchange USD for CAD at the rate USD 1.00 to CAD 1.29 maturing in 2016
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 241	$ 186
Average exchange rate	1.29	1.29
Forward exchange contracts that exchange USD for CAD at the rate USD 1.00 to CAD 1.29 maturing in 2017
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 26	$ 20
Average exchange rate	1.29	1.29

Derivatives and Risk Management Activities - Embedded Derivatives (Details) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)
Embedded Derivatives
Gain recognized due to changes in fair value		$ 25
Preferred Distribution Rate Reset Option \| PAA \| Series A Preferred Units
Embedded Derivatives
Fair value of derivative liability	$ 35	35
Gain recognized due to changes in fair value	$ 25	$ 25

Derivatives and Risk Management Activities - Financial Impact (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Impact of derivative activities recognized in earnings
Total Gain/(Loss) on Derivatives Recognized in Net Income	$ (137)	$ 25	$ (101)	$ (22)
Commodity Derivatives \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total Gain/(Loss) on Derivatives Recognized in Net Income	(160)	25	(128)	(2)
Commodity Derivatives \| Transportation segment revenues
Impact of derivative activities recognized in earnings
Total Gain/(Loss) on Derivatives Recognized in Net Income	1	2	3	4
Commodity Derivatives \| Field operating costs
Impact of derivative activities recognized in earnings
Total Gain/(Loss) on Derivatives Recognized in Net Income	2	2		(2)
Interest Rate Derivatives \| Interest expense, net
Impact of derivative activities recognized in earnings
Total Gain/(Loss) on Derivatives Recognized in Net Income	(4)	(4)	(6)	(5)
Foreign Currency Derivatives \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total Gain/(Loss) on Derivatives Recognized in Net Income	(1)		5	(17)
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	25		25
Derivatives in Hedging Relationships
Impact of derivative activities recognized in earnings
Total Gain/(Loss) on Derivatives Recognized in Net Income	(5)	(23)	(6)	(17)
Derivatives in Hedging Relationships \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Loss recognized due to anticipated hedged transactions now considered probable of not occurring	2		2
Derivatives in Hedging Relationships \| Interest expense, net
Impact of derivative activities recognized in earnings
Loss recognized due to anticipated hedged transactions now considered probable of not occurring	2		2
Derivatives in Hedging Relationships \| Commodity Derivatives \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total Gain/(Loss) on Derivatives Recognized in Net Income	(1)	(19)		(12)
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	(4)	(4)	(6)	(5)
Derivatives Not Designated as a Hedge
Impact of derivative activities recognized in earnings
Total Gain/(Loss) on Derivatives Recognized in Net Income	(132)	48	(95)	(5)
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	(159)	44	(128)	10
Derivatives Not Designated as a Hedge \| Commodity Derivatives \| Transportation segment revenues
Impact of derivative activities recognized in earnings
Total Gain/(Loss) on Derivatives Recognized in Net Income	1	2	3	4
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	2	$ 2		(2)
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	(1)		5	$ (17)
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	$ 25		$ 25

Derivatives and Risk Management Activities - Assets and Liabilities (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016 USD ($) contract	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($) contract	Jun. 30, 2015 USD ($)	Dec. 31, 2015 USD ($) contract
Derivative assets and liabilities
Asset Derivatives Fair Value	$ 53		$ 53		$ 280
Liability Derivatives Fair Value	(396)		(396)		(110)
Broker receivable	274		274
Broker payable					156
Initial margin	84		84		91
Variation margin posted/(returned)	190		190		$ (247)
Net loss deferred in AOCI	355		355
Net loss expected to be reclassified to earnings in the next twelve months			5
Remaining loss expected to be reclassified to earnings through 2049			350
Net deferred gain/(loss) recognized in AOCI on derivatives	$ (68)	$ 92	$ (158)	$ 20
Number of outstanding derivatives containing credit-risk related contingent features \| contract	0		0		0
Derivative credit-risk related contingent features			none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings
Commodity Derivatives
Derivative assets and liabilities
Net deferred gain/(loss) recognized in AOCI on derivatives		(28)		(25)
Interest Rate Derivatives
Derivative assets and liabilities
Net deferred gain/(loss) recognized in AOCI on derivatives	$ (68)	$ 120	$ (158)	$ 45
Derivatives in Hedging Relationships
Derivative assets and liabilities
Asset Derivatives Fair Value	2		2		$ 5
Liability Derivatives Fair Value	(155)		(155)		(52)
Derivatives in Hedging Relationships \| Commodity Derivatives \| Other current assets
Derivative assets and liabilities
Asset Derivatives Fair Value	2		2		4
Liability Derivatives Fair Value					(2)
Derivatives in Hedging Relationships \| Interest Rate Derivatives \| Other long-term assets, net
Derivative assets and liabilities
Asset Derivatives Fair Value					1
Derivatives in Hedging Relationships \| Interest Rate Derivatives \| Other current liabilities
Derivative assets and liabilities
Liability Derivatives Fair Value	(64)		(64)		(17)
Derivatives in Hedging Relationships \| Interest Rate Derivatives \| Other long-term liabilities and deferred credits
Derivative assets and liabilities
Liability Derivatives Fair Value	(91)		(91)		(33)
Derivatives Not Designated as a Hedge
Derivative assets and liabilities
Asset Derivatives Fair Value	51		51		275
Liability Derivatives Fair Value	(241)		(241)		(58)
Derivatives Not Designated as a Hedge \| Commodity Derivatives \| Other current assets
Derivative assets and liabilities
Asset Derivatives Fair Value	45		45		265
Liability Derivatives Fair Value	(182)		(182)		(35)
Derivatives Not Designated as a Hedge \| Commodity Derivatives \| Other long-term assets, net
Derivative assets and liabilities
Asset Derivatives Fair Value					10
Liability Derivatives Fair Value					(1)
Derivatives Not Designated as a Hedge \| Commodity Derivatives \| Other current liabilities
Derivative assets and liabilities
Liability Derivatives Fair Value	(6)		(6)		(13)
Derivatives Not Designated as a Hedge \| Commodity Derivatives \| Other long-term liabilities and deferred credits
Derivative assets and liabilities
Asset Derivatives Fair Value	6		6
Liability Derivatives Fair Value	(17)		(17)		(1)
Derivatives Not Designated as a Hedge \| Foreign Currency Derivatives \| Other current liabilities
Derivative assets and liabilities
Liability Derivatives Fair Value	(1)		(1)		$ (8)
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	$ (35)		$ (35)

Derivatives and Risk Management Activities - Offsetting (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Derivative Asset Positions
Gross Position - Asset	$ 53	$ 280
Netting Adjustment	(188)	(38)
Cash collateral paid	274
Cash collateral received		(156)
Net Position - Asset	139	86
Derivative Liability Positions
Gross Position - Liability	(396)	(110)
Netting Adjustment	188	38
Net Position - Liability	(208)	(72)
Other current assets
Derivative Asset Positions
Net Position - Asset	139	76
Other long-term assets, net
Derivative Asset Positions
Net Position - Asset		10
Other current liabilities
Derivative Liability Positions
Net Position - Liability	(71)	(38)
Other long-term liabilities and deferred credits
Derivative Liability Positions
Net Position - Liability	$ (137)	$ (34)

Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Level 3
Rollforward of Level 3 Net Asset/(Liability)
Beginning Balance	$ (59)	$ 5	$ 11	$ 15
Gains for the period included in earnings	23	1	23	1
Settlements		(1)	(9)	(13)
Derivatives entered into during the period	1	4	(60)	6
Ending Balance	(35)	9	(35)	9
Change in unrealized gains included in earnings relating to Level 3 derivatives still held at the end of the period	24	$ 5	24	$ 6
Recurring Fair Value Measures
Recurring Fair Value Measurements
Net derivative asset/(liability)	(343)		(343)		$ 170
Recurring Fair Value Measures \| Commodity Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(152)		(152)		227
Recurring Fair Value Measures \| Interest Rate Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(155)		(155)		(49)
Recurring Fair Value Measures \| Foreign Currency Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(1)		(1)		(8)
Recurring Fair Value Measures \| Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Net derivative asset/(liability)	(35)		(35)
Recurring Fair Value Measures \| Level 1
Recurring Fair Value Measurements
Net derivative asset/(liability)	(133)		(133)		126
Recurring Fair Value Measures \| Level 1 \| Commodity Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(133)		(133)		126
Recurring Fair Value Measures \| Level 2
Recurring Fair Value Measurements
Net derivative asset/(liability)	(175)		(175)		33
Recurring Fair Value Measures \| Level 2 \| Commodity Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(19)		(19)		90
Recurring Fair Value Measures \| Level 2 \| Interest Rate Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(155)		(155)		(49)
Recurring Fair Value Measures \| Level 2 \| Foreign Currency Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(1)		(1)		(8)
Recurring Fair Value Measures \| Level 3
Recurring Fair Value Measurements
Net derivative asset/(liability)	(35)		(35)		11
Recurring Fair Value Measures \| Level 3 \| Commodity Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)					$ 11
Recurring Fair Value Measures \| Level 3 \| Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Net derivative asset/(liability)	$ (35)		$ (35)

Related Party Transactions (Details) - Oxy - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Related Party Transactions
Revenues	$ 142	$ 382	$ 254	$ 558
Purchases and related costs		$ 41		$ 146
Purchases and related costs net credit	(4)		(50)
Trade accounts receivable and other receivables	495		495		$ 405
Accounts payable	$ 460		$ 460		$ 363
AAP
Related Party Transactions
Ownership interest held (as a percent)			13.00%

Commitments and Contingencies - Legal, Environmental or Regulatory (Details)					1 Months Ended	12 Months Ended	14 Months Ended
	May 16, 2016 employee item	Jan. 06, 2016 USD ($) item	Jul. 10, 2015 bbl	Jan. 01, 2015 bbl	May 31, 2015 bbl	Jun. 30, 2016 USD ($) lawsuit	Jun. 30, 2016 USD ($) lawsuit	Dec. 31, 2015 USD ($)	Apr. 30, 2015 item
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities						$ 160,000,000	$ 160,000,000	$ 185,000,000
Estimated undiscounted reserve for environmental liabilities, short-term						59,000,000	59,000,000	81,000,000
Estimated undiscounted reserve for environmental liabilities, long-term						101,000,000	101,000,000	104,000,000
Amounts probable of recovery under insurance and from third parties under indemnification agreements						68,000,000	68,000,000	161,000,000
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						46,000,000	46,000,000	138,000,000
Other long-term assets, net
Legal, Environmental or Regulatory Matters
Amounts probable of recovery under insurance and from third parties under indemnification agreements						22,000,000	22,000,000	$ 23,000,000
Line 901 Incident
Legal, Environmental or Regulatory Matters
Aggregate total estimated costs						269,000,000	269,000,000
Estimated undiscounted reserve for environmental liabilities						91,000,000	91,000,000
Recoveries from insurance carriers							124,000,000
Total release costs probable of recovery						186,000,000	186,000,000
Amounts probable of recovery under insurance and from third parties under indemnification agreements						62,000,000	62,000,000
Fines or penalties assessed						0	0
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						42,000,000	42,000,000
Line 901 Incident \| Accounts payable and accrued liabilities
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities, short-term						51,000,000	$ 51,000,000
Line 901 Incident \| May 2016 Indictment
Legal, Environmental or Regulatory Matters
Number of employees charged \| employee	1
Total counts included in the indictment \| item	46
Number of misdemeanor charges relating to wildlife allegedly taken \| item	36
Number of counts relating to the release of crude oil or reporting of the release \| item	10
Number of felony charges \| item	4
Number of misdemeanor charges relating to the release of crude oil or reporting of the release \| item	6
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							7
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							3
Number of cases consolidated into a single proceeding \| lawsuit							2
Number of actions resulting from consolidation of separate cases \| lawsuit							1
Line 901 Incident \| Production of Books And Records Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed during the period \| lawsuit							2
Line 901 Incident \| Worst Case Estimate
Legal, Environmental or Regulatory Matters
Estimated size of release (in barrels) \| bbl					2,935
MP 29 Release
Legal, Environmental or Regulatory Matters
Estimated size of release (in barrels) \| bbl			100
Fines or penalties assessed						0	$ 0
MP 29 Release \| Maximum
Legal, Environmental or Regulatory Matters
Aggregate total estimated costs						$ 10,000,000	10,000,000
MP 29 Release \| Class Action Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed during the period \| lawsuit						1
In the Matter of Bakersfield Crude Terminal LLC et al
Legal, Environmental or Regulatory Matters
Number of alleged rule violations \| item									10
Fines or penalties assessed						$ 0	$ 0
Mesa To Basin Pipeline
Legal, Environmental or Regulatory Matters
Estimated size of release (in barrels) \| bbl				500
Mesa To Basin Pipeline \| PHMSA
Legal, Environmental or Regulatory Matters
Number of occasions of alleged failure to carry out damage prevention program and other procedures \| item		4
Fines or penalties recommended		$ 190,000

Operating Segments - Segment Financial Data (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($) segment	Jun. 30, 2015 USD ($)
Operating Segments
Operating segments number \| segment			3
Revenues:
Revenues	$ 4,950	$ 6,663	$ 9,060	$ 12,605
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	40	52	87	89
Segment profit/(loss)	390	371	833	884
Maintenance capital	35	52	81	102
Transportation
Revenues:
Revenues	170	180	323	366
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	40	52	87	89
Segment profit/(loss)	252	186	499	428
Maintenance capital	23	33	57	66
Facilities
Revenues:
Revenues	132	137	270	261
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment profit/(loss)	156	144	315	285
Maintenance capital	9	17	18	32
Supply and Logistics
Revenues:
Revenues	4,648	6,346	8,467	11,978
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment profit/(loss)	(18)	41	19	171
Interest expense related to hedged inventory purchases	3	2	6	3
Maintenance capital	3	2	6	4
Operating Segments.
Revenues:
Revenues	5,325	7,022	9,795	13,312
Operating Segments. \| Transportation
Revenues:
Revenues	403	402	787	803
Operating Segments. \| Facilities
Revenues:
Revenues	270	269	535	525
Operating Segments. \| Supply and Logistics
Revenues:
Revenues	4,652	6,351	8,473	11,984
Intersegment
Revenues:
Revenues	(375)	(359)	(735)	(707)
Intersegment \| Transportation
Revenues:
Revenues	(233)	(222)	(464)	(437)
Intersegment \| Facilities
Revenues:
Revenues	(138)	(132)	(265)	(264)
Intersegment \| Supply and Logistics
Revenues:
Revenues	$ (4)	$ (5)	$ (6)	$ (6)

Operating Segments - Reconciliation of Segment Profit (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Reconciliation of segment profit to net income attributable to PAGP
Segment profit/(loss)	$ 390	$ 371	$ 833	$ 884
General and administrative expenses	(73)	(80)	(141)	(159)
Depreciation and amortization	(205)	(108)	(320)	(213)
Interest expense, net	(118)	(109)	(233)	(216)
Other income/(expense), net	25	1	30	(3)
INCOME BEFORE TAX	92	154	309	450
Income tax expense	(10)	(51)	(50)	(85)
NET INCOME	82	103	259	365
Net income attributable to noncontrolling interests	(40)	(73)	(181)	(304)
NET INCOME ATTRIBUTABLE TO PAGP	$ 42	30	78	61
Unallocated
Reconciliation of segment profit to net income attributable to PAGP
General and administrative expenses		$ (1)	$ (1)	$ (2)

Acquisitions, Dispositions and Impairments - Acquisitions (Details) $ in Millions	1 Months Ended	6 Months Ended
	Aug. 31, 2016 USD ($)	Jun. 30, 2016 USD ($) item
Acquisitions
Number of acquisitions completed \| item		1
Cash consideration		$ 85
Integrated system of NGL assets \| Subsequent Event
Acquisitions
Cash consideration	$ 204
Inventory and working capital included in the acquisition	$ 51

Acquisitions, Dispositions and Impairments - Dispositions (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2016
Disposal Group, Not Discontinued Operations \| Cheyenne Pipeline LLC
Dispositions
Percentage of investment sold	50.00%
Held for sale \| Goodwill \| Depreciation and amortization
Dispositions
Impairment losses		$ 15
Held for sale \| Non-core assets \| Other current assets
Dispositions
Assets classified as held for sale	$ 152		$ 152
Disposed of by sale \| Depreciation and amortization
Dispositions
Recognized gains related to sale of assets			71
Recognized losses related to sales of assets			$ 55

Acquisitions, Dispositions and Impairments - Impairments (Details) - Depreciation and amortization $ in Millions	3 Months Ended
	Jun. 30, 2016 USD ($)
Impairments
Charge related to write-off of remaining book value of assets taken out of service	$ 18
Rail and other terminal assets \| Facilities
Impairments
Non-cash impairment losses on long-lived assets	$ 80

Simplification Transactions (Details) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended	6 Months Ended
	Jul. 11, 2016 director $ / shares	Dec. 31, 2016 USD ($) $ / shares shares	Jun. 30, 2016
AAP \| Forecast \| AAP senior secured revolving credit facility
Simplification Transactions
Estimated borrowings for true-up distribution if transactions not closed \| $		$ 41
Exchange of AAP Units and Class B Shares for Class A Shares \| AAP
Simplification Transactions
Ratio for conversion or exchange of units			1
PAA \| PAA GP
Simplification Transactions
General partner ownership interest (as a percent)			2.00%
PAA \| Indirect Ownership \| AAP
Simplification Transactions
General partner ownership interest (as a percent)			2.00%
PAA \| Subsequent Event \| Common Units \| Cash Distributions \| Second Quarter Distribution
Simplification Transactions
Quarterly level of distributions per common unit (in dollars per unit) \| $ / shares	$ 0.70
PAA \| Forecast \| Common Units \| Cash Distributions \| Third Quarter Distribution
Simplification Transactions
Quarterly level of distributions per common unit (in dollars per unit) \| $ / shares		$ 0.55
PAGP \| AAP
Simplification Transactions
Threshold of private AAP ownership below which shareholders are eligible to participate in general partner Board of Director elections (as a percent)			40.00%
Simplification Agreement \| Exchange of AAP Units and Class B Shares for Class A Shares \| Subsequent Event
Simplification Transactions
Ratio for conversion or exchange of units	1
Simplification Agreement \| PAA \| Forecast \| AAP
Simplification Transactions
Issuance of common units (in units) \| shares		245.5
Assumption of outstanding debt \| $		$ 593
Simplification Agreement \| PAA \| Forecast \| PAA GP
Simplification Transactions
Economic general partner interest converted into non-economic interest (as a percent)		2.00%
Simplification Agreement \| PAGP \| AAP \| Forecast \| PAA
Simplification Transactions
Ratio of PAGP Class A shares to underlying PAA Common Units held by AAP		1
Simplification Agreement \| AAP \| Subsequent Event \| GP Holdings \| Original Designating Parties
Simplification Transactions
Threshold ownership for interest holder to nominate a director to the Board of Directors of the general partner (as a percent)	10.00%
Number of directors interest holder may designate to the Board of Directors of the general partner \| director	1