View Filing Data

Print Document View Excel Document

Document and Entity Information - shares	9 Months Ended
Document and Entity Information - shares	Sep. 30, 2016	Nov. 01, 2016
Document and Entity Information
Entity Registrant Name	PLAINS ALL AMERICAN PIPELINE LP
Entity Central Index Key	0001070423
Document Type	10-Q
Document Period End Date	Sep. 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 (shares)		412,962,773
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 31	$ 27
Trade accounts receivable and other receivables, net	1,946	1,785
Inventory	1,258	916
Other current assets	538	241
Total current assets	3,773	2,969
PROPERTY AND EQUIPMENT	16,103	15,654
Accumulated depreciation	(2,292)	(2,180)
Property and equipment, net	13,811	13,474
OTHER ASSETS
Goodwill	2,353	2,405
Investments in unconsolidated entities	2,216	2,027
Linefill and base gas	899	898
Long-term inventory	146	129
Other long-term assets, net	309	386
Total assets	23,507	22,288
CURRENT LIABILITIES
Accounts payable and accrued liabilities	2,280	2,038
Short-term debt	1,384	999
Other current liabilities	413	370
Total current liabilities	4,077	3,407
LONG-TERM LIABILITIES
Senior notes, net of unamortized discounts and debt issuance costs	9,130	9,698
Other long-term debt	504	677
Other long-term liabilities and deferred credits	722	567
Total long-term liabilities	10,356	10,942
COMMITMENTS AND CONTINGENCIES (NOTE 12)
PARTNERS’ CAPITAL
General partner	268	301
Total partners’ capital excluding noncontrolling interests	9,016	7,881
Noncontrolling interests	58	58
Total partners’ capital	9,074	7,939
Total liabilities and partners’ capital	23,507	22,288
Series A Preferred Units
PARTNERS’ CAPITAL
Unitholders	1,508
Common Units
PARTNERS’ CAPITAL
Unitholders	$ 7,240	$ 7,580

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Sep. 30, 2016	Dec. 31, 2015
Series A Preferred Units
Units outstanding (units)	63,126,331
Common Units
Units outstanding (units)	408,107,646	397,727,624

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
REVENUES
Supply and Logistics segment revenues	$ 4,876	$ 5,247	$ 13,344	$ 17,225
Transportation segment revenues	159	172	482	538
Facilities segment revenues	135	132	405	393
Total revenues	5,170	5,551	14,231	18,156
COSTS AND EXPENSES
Purchases and related costs	4,429	4,701	12,000	15,591
Field operating costs	289	348	893	1,111
General and administrative expenses	70	60	210	217
Depreciation and amortization	33	107	351	319
Total costs and expenses	4,821	5,216	13,454	17,238
OPERATING INCOME	349	335	777	918
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	46	45	133	134
Interest expense (net of capitalized interest of $11, $14, $37 and $42, respectively)	(113)	(109)	(339)	(320)
Other income/(expense), net	17	(4)	46	(7)
INCOME BEFORE TAX	299	267	617	725
Current income tax expense	(4)	(11)	(45)	(72)
Deferred income tax benefit/(expense)	3	(6)	30	6
NET INCOME	298	250	602	659
Net income attributable to noncontrolling interests	(1)	(1)	(3)	(2)
NET INCOME ATTRIBUTABLE TO PAA	297	249	599	657
BASIC NET INCOME PER COMMON UNIT (NOTE 3):
Net income allocated to common unitholders - Basic	162	98	110	211
Net income allocated to common unitholders - Diluted	$ 162	$ 98	$ 110	$ 211
Common Units
BASIC NET INCOME PER COMMON UNIT (NOTE 3):
Basic weighted average common units outstanding (units)	401	398	399	393
Basic net income per common unit (usd per unit)	$ 0.40	$ 0.25	$ 0.27	$ 0.54
Diluted weighted average common units outstanding (units)	402	399	400	395
Diluted net income per common unit (usd per unit)	$ 0.40	$ 0.24	$ 0.27	$ 0.53

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Statement [Abstract]
Interest expense, capitalized interest	$ 11	$ 14	$ 37	$ 42

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
Net income	$ 298	$ 250	$ 602	$ 659
Other comprehensive loss	(45)	(311)	0	(518)
Comprehensive income/(loss)	253	(61)	602	141
Comprehensive income attributable to noncontrolling interests	(1)	(1)	(3)	(2)
Comprehensive income/(loss) attributable to PAA	$ 252	$ (62)	$ 599	$ 139

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Changes in Accumulated Other Comprehensive Income/(Loss)
Balance at beginning of period			$ (1,081)	$ (467)
Reclassification adjustments			7	(21)
Deferred loss on cash flow hedges			(178)	(28)
Currency translation adjustments			171	(469)
Total period activity	$ (45)	$ (311)	0	(518)
Balance at end of period	(1,081)	(985)	(1,081)	(985)
Derivative Instruments
Changes in Accumulated Other Comprehensive Income/(Loss)
Balance at beginning of period			(203)	(159)
Reclassification adjustments			7	(21)
Deferred loss on cash flow hedges			(178)	(28)
Total period activity			(171)	(49)
Balance at end of period	(374)	(208)	(374)	(208)
Translation Adjustments
Changes in Accumulated Other Comprehensive Income/(Loss)
Balance at beginning of period			(878)	(308)
Currency translation adjustments			171	(469)
Total period activity			171	(469)
Balance at end of period	$ (707)	$ (777)	$ (707)	$ (777)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 602	$ 659
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	351	319
Equity-indexed compensation expense	40	27
Inventory valuation adjustments	3	25
Deferred income tax benefit	(30)	(6)
(Gain)/loss on foreign currency revaluation	1	(20)
Settlement of terminated interest rate hedging instruments	(50)	(48)
Change in fair value of Preferred Distribution Rate Reset Option (Note 9)	(42)
Equity earnings in unconsolidated entities	(133)	(134)
Distributions from unconsolidated entities	151	159
Other	13	(5)
Changes in assets and liabilities, net of acquisitions	(264)	246
Net cash provided by operating activities	642	1,222
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	(282)	(104)
Investments in unconsolidated entities	(171)	(213)
Additions to property, equipment and other	(1,030)	(1,617)
Cash paid for purchases of linefill and base gas	(7)	(131)
Proceeds from sales of assets	638	4
Other investing activities	(2)	(8)
Net cash used in investing activities	(854)	(2,069)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) under commercial paper program (Note 7)	(617)	151
Net borrowings under senior secured hedged inventory facility (Note 7)	424
Proceeds from the issuance of senior notes		998
Repayments of senior notes (Note 7)	(175)	(549)
Net proceeds from the sale of Series A preferred units (Note 8)	1,569
Net proceeds from the sale of common units (Note 8)	283	1,099
Contributions from general partner	39	23
Distributions paid to common unitholders (Note 8)	(835)	(802)
Distributions paid to general partner (Note 8)	(464)	(436)
Other financing activities	(12)	(15)
Net cash provided by financing activities	212	469
Effect of translation adjustment on cash	4	(3)
Net increase/(decrease) in cash and cash equivalents	4	(381)
Cash and cash equivalents, beginning of period	27	403
Cash and cash equivalents, end of period	31	22
Cash paid for:
Interest, net of amounts capitalized	313	287
Income taxes, net of amounts refunded	$ 78	$ 43

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions	Total	Partners’ Capital Excluding Noncontrolling Interests	Noncontrolling Interests	Limited Partners Series A Preferred Units Partners’ Capital Excluding Noncontrolling Interests	Limited Partners Common Units Partners’ Capital Excluding Noncontrolling Interests	General Partner Partners’ Capital Excluding Noncontrolling Interests
Balance, beginning of period at Dec. 31, 2014	$ 8,191	$ 8,133	$ 58		$ 7,793	$ 340
Increase (Decrease) in Partners' Capital
Net income	659	657	2		215	442
Cash distributions to partners	(1,240)	(1,238)	(2)		(802)	(436)
Sale of common units	1,121	1,121			1,099	22
Other comprehensive loss	(518)	(518)			(507)	(11)
Other	3	3			1	2
Balance, end of period at Sep. 30, 2015	8,216	8,158	58		7,799	359
Balance, beginning of period at Dec. 31, 2015	7,939	7,881	58		7,580	301
Increase (Decrease) in Partners' Capital
Net income	602	599	3		209	390
Cash distributions to partners	(1,302)	(1,299)	(3)		(835)	(464)
Sale of Series A preferred units	1,542	1,542		$ 1,509		33
Sale of common units	289	289			283	6
Other comprehensive loss	0
Other	4	4		(1)	3	2
Balance, end of period at Sep. 30, 2016	$ 9,074	$ 9,016	$ 58	$ 1,508	$ 7,240	$ 268

Organization and Basis of Consolidation and Presentation

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Basis of Consolidation and Presentation

Organization

Plains All American Pipeline, L.P. (“PAA”) is a Delaware limited partnership formed in 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in this Form 10-Q and unless the context indicates otherwise, the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAA and its subsidiaries.

We own and operate midstream energy infrastructure and provide logistics services for crude oil, natural gas liquids (“NGL”), natural gas and refined products. We own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. Our business activities are conducted through three operating segments: Transportation, Facilities and Supply and Logistics. See Note 13 for further discussion of our operating segments.

Our 2% general partner interest is held by PAA GP LLC (“PAA GP”), a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP, AAP also owns all of our incentive distribution rights (“IDRs”). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole member of GP LLC, and at September 30, 2016, owned an approximate 42% limited partner interest in AAP. PAA GP Holdings LLC (“GP Holdings”) is PAGP’s general partner.

GP LLC manages our operations and activities and employs our domestic officers and personnel. Our Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC (“PMC”). References to our “general partner,” as the context requires, include any or all of PAA GP, AAP and GP LLC.

Simplification Agreement

On July 11, 2016, PAA, PAGP, 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, which is expected to occur on November 15, 2016, both PAA and PAGP will continue to be publicly traded. See Note 15 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
MLP	=	Master limited partnership
NGL	=	Natural gas liquids, including ethane, propane and butane
NYMEX	=	New York Mercantile Exchange
Oxy	=	Occidental Petroleum Corporation or its subsidiaries
PLA	=	Pipeline loss allowance
SEC	=	United States Securities and Exchange Commission
USD	=	United States dollar
WTI	=	West Texas Intermediate

Basis of Consolidation and Presentation

The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our 2015 Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of PAA and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. 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 $7 million reclassified from “Depreciation and amortization” to “Interest expense, net” in our accompanying Condensed Consolidated Statements of Operations for the three and nine months ended September 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 PAA. 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 nine months ended September 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.

Income Allocation

Net income for partners’ capital presentation purposes is allocated in accordance with our partnership agreement. Our general partner and common unitholders are allocated income based on their respective partnership percentages, after giving effect to income allocations for (i) incentive distributions, if any, to our general partner (the holder of the IDRs pursuant to our partnership agreement) for distributions declared and paid following the close of each quarter and (ii) cash distributions to our preferred unitholders. In accordance with our partnership agreement, our preferred unitholders are not allocated income for paid-in-kind distributions.

For purposes of determining basic and diluted net income per common unit, income is allocated as prescribed in FASB guidance for calculating earnings per unit including application of the two-class method for MLPs. See Note 3 for additional information.

Recent Accounting Pronouncements	9 Months Ended
Recent Accounting Pronouncements	Sep. 30, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Recent Accounting Pronouncements	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 nine months ended September 30, 2016 that are of significance or potential significance to us. 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. We are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows. Although our evaluation is ongoing, we do expect that the adoption will impact our financial statements as the standard requires the recognition on the balance sheet of a right of use asset and corresponding lease liability. We are currently analyzing our contracts to determine whether they contain a lease under the revised guidance and have not quantified the amount of the asset and liability that will be recognized on our consolidated balance sheet. 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 do not anticipate that our adoption will have a material impact on our financial position, results of operations or 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. In August 2016, the FASB issued guidance relating to the classification and presentation of eight specific cash flow issues. This guidance will become effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. We plan to early adopt this guidance during the fourth quarter of 2016, and we do not currently expect that our adoption will impact our statement of cash flows.

Net Income Per Common Unit

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Net Income Per Common Unit

Basic and diluted net income per common unit is determined pursuant to the two-class method for MLPs as prescribed in FASB guidance. The two-class method is an earnings allocation formula that is used to determine earnings to our general partner, limited partners and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings. Under this method, all earnings are allocated to our preferred unitholders, general partner, common unitholders and participating securities based on their respective rights to receive distributions, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective.

We calculate basic and diluted net income per common unit by dividing net income attributable to PAA (after deducting the amount allocated to the preferred unitholders, the general partner’s interest, IDRs and participating securities) by the basic and diluted weighted-average number of common units outstanding during the period. Participating securities include LTIP awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units.

Diluted net income per common unit is computed based on the weighted-average number of common units plus the effect of potentially dilutive securities outstanding during the period. When applying the if-converted method prescribed by FASB guidance, the possible conversion of our Series A preferred units was excluded from the calculation of diluted net income per common unit for the three and nine months ended September 30, 2016 as the effect was antidilutive. See Note 8 to our Condensed Consolidated Financial Statements for additional information regarding our Series A preferred units. Our LTIP awards that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 15 to our Consolidated Financial Statements included in Part IV of our 2015 Annual Report on Form 10-K for a complete discussion of our LTIP awards including specific discussion regarding DERs.

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Basic Net Income per Common Unit
Net income attributable to PAA	$	297		$	249		$	599		$	657
Distributions to Series A preferred units ⁽¹⁾	(33		)	—			(88		)	—
Distributions to general partner ⁽¹⁾	(102		)	(154		)	(412		)	(454		)
Distributions to participating securities⁽¹⁾	(1		)	(1		)	(3		)	(4		)
Undistributed loss allocated to general partner⁽¹⁾	1			4			14			12
Net income allocated to common unitholders in accordance with application of the two-class method for MLPs	$	162		$	98		$	110		$	211

Basic weighted average common units outstanding	401			398			399			393

Basic net income per common unit	$	0.40		$	0.25		$	0.27		$	0.54

Diluted Net Income per Common Unit
Net income attributable to PAA	$	297		$	249		$	599		$	657
Distributions to Series A preferred units ⁽¹⁾	(33		)	—			(88		)	—
Distributions to general partner ⁽¹⁾	(102		)	(154		)	(412		)	(454		)
Distributions to participating securities⁽¹⁾	(1		)	(1		)	(3		)	(4		)
Undistributed loss allocated to general partner⁽¹⁾	1			4			14			12
Net income allocated to common unitholders in accordance with application of the two-class method for MLPs	$	162		$	98		$	110		$	211

Basic weighted average common units outstanding	401			398			399			393
Effect of dilutive securities: Weighted average LTIP units	1			1			1			2
Diluted weighted average common units outstanding	402			399			400			395

Diluted net income per common unit	$	0.40		$	0.24		$	0.27		$	0.53

___________________________________________

⁽¹⁾

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

Pursuant to the terms of our partnership agreement, the general partner’s incentive distribution is limited to a percentage of available cash, which, as defined in our partnership agreement, is net of reserves deemed appropriate. As such, IDRs are not allocated undistributed earnings or distributions in excess of earnings in the calculation of net income per common unit. If, however, undistributed earnings were allocated to our IDRs beyond amounts distributed to them under the terms of our partnership agreement, basic and diluted net income per common unit as reflected in the table above would not have been impacted, as we did not have undistributed earnings for any of the periods presented.

Accounts Receivable, Net	9 Months Ended
Accounts Receivable, Net	Sep. 30, 2016
Receivables [Abstract]
Accounts Receivable, Net	Accounts Receivable, Net Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit or parental guarantees. As of September 30, 2016 and December 31, 2015, we had received $62 million and $88 million, respectively, of advance cash payments from third parties to mitigate credit risk. We also received $103 million and $36 million as of September 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 September 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 $3 million and $4 million at September 30, 2016 and December 31, 2015, respectively. 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

9 Months Ended

Sep. 30, 2016

Inventory, Linefill and Base Gas and Long-term Inventory

Inventory, Linefill and Base Gas and Long-term Inventory

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



	September 30, 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	20,494	barrels	$	879	$	42.89	16,345	barrels	$	608	$	37.20
NGL	21,087	barrels	321		$	15.22	13,907	barrels	218		$	15.68
Natural gas	15,116	Mcf	32		$	2.12	22,080	Mcf	53		$	2.40
Other	N/A		26		N/A		N/A		37		N/A
Inventory subtotal			1,258						916

Linefill and base gas
Crude oil	12,215	barrels	712		$	58.29	12,298	barrels	713		$	57.98
NGL	1,490	barrels	46		$	30.87	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			899						898

Long-term inventory
Crude oil	3,428	barrels	124		$	36.17	3,417	barrels	106		$	31.02
NGL	1,418	barrels	22		$	15.51	1,652	barrels	23		$	13.92
Long-term inventory subtotal			146						129

Total			$	2,303					$	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

9 Months Ended

Sep. 30, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

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	12			5			2		19
Dispositions and reclassifications to assets held for sale	(15		)	(56		)	—		(71		)
Balance at September 30, 2016	$	812		$	1,036		$	505	$	2,353

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

Debt

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Debt

Debt consisted of the following (in millions):



	September 30, 2016		December 31, 2015
SHORT-TERM DEBT
Commercial paper notes, bearing a weighted-average interest rate of 1.3% and 1.1%, respectively⁽¹⁾	$	256	$	696
Senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.5% and 1.4%, respectively⁽¹⁾	725		300
Senior notes:
6.13% senior notes due January 2017	400		—
Other	3		3
Total short-term debt	1,384		999

LONG-TERM DEBT
Senior notes, net of unamortized discounts and debt issuance costs of $70 and $77, respectively	9,130		9,698
Commercial paper notes, bearing a weighted-average interest rate of 1.3% and 1.1%, respectively ⁽²⁾	500		672
Other	4		5
Total long-term debt	9,634		10,375
Total debt ⁽³⁾	$	11,018	$	11,374

___________________________________________


⁽¹⁾	We classified these commercial paper notes and credit facility borrowings as short-term as of September 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⁾	As of September 30, 2016 and December 31, 2015, we classified a portion of our commercial paper notes as long-term based on our ability and intent to refinance such amounts on a long-term basis under our credit facilities.

⁽³⁾

Our fixed-rate senior notes (including current maturities) had a face value of approximately $9.6 billion and $9.8 billion as of September 30, 2016 and December 31, 2015, respectively. We estimated the aggregate fair value of these notes as of September 30, 2016 and December 31, 2015 to be approximately $9.7 billion and $8.6 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under our credit facilities and commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, credit facilities and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

Credit Facilities

In August 2016, we extended the maturity dates of our senior unsecured revolving credit facility, senior secured hedged inventory facility and 364-day credit facility to August 2021, August 2019 and August 2017, respectively.

Borrowings and Repayments

Total borrowings under our credit facilities and commercial paper program for the nine months ended September 30, 2016 and 2015 were approximately $41.4 billion and $37.1 billion, respectively. Total repayments under our credit facilities and commercial paper program were approximately $41.6 billion and $36.9 billion for the nine months ended September 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 September 30, 2016 and December 31, 2015, we had outstanding letters of credit of $47 million and $46 million, respectively.

Senior Notes Repayments

Our $175 million, 5.88% senior notes were repaid in August 2016. We utilized cash on hand and available capacity under our commercial paper program and credit facilities to repay these notes.

Partners' Capital and Distributions

9 Months Ended

Sep. 30, 2016

Partners' Capital Notes [Abstract]

Partners' Capital and Distributions

Partners’ Capital and Distributions

Units Outstanding

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



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



	Limited Partners
	Common Units
Outstanding at December 31, 2014	375,107,793
Sale of common units	22,133,904
Issuance of common units under LTIP	485,927
Outstanding at September 30, 2015	397,727,624

Equity Offerings

Series A Preferred Unit Offering. On January 28, 2016 (the "Issuance Date"), we completed the private placement of approximately 61.0 million Series A preferred units representing limited partner interests in us for a cash purchase price of $26.25 per unit (the “Issue Price”).

The Series A preferred units are a new class of equity security that ranks senior to all classes or series of our equity securities with respect to distribution rights and rights upon liquidation. The holders of the Series A preferred units 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”), we may elect to pay distributions on the Series A preferred units in additional preferred units, in cash or a combination of both. With respect to any quarter ending after the Initial Distribution Period, we must pay distributions on the Series A preferred units in cash.

The purchasers may convert their Series A preferred units into common units, generally on a one-for-one basis and subject to customary antidilution adjustments, at any time after the second anniversary of the Issuance Date (or prior to a liquidation), in whole or in part, subject to certain minimum conversion amounts. We may convert the Series A preferred units into common units at any time (but not more often than once per quarter) after the third anniversary of the Issuance Date, in whole or in part, subject to certain minimum conversion amounts, if the closing price of our common units is greater than 150% of the Issue Price for the preceding 20 trading days. The Series A preferred units will vote on an as-converted basis with our common units and will have certain other class voting rights with respect to any amendment to our partnership agreement that would adversely affect any rights, preferences or privileges of the Series A preferred units. In addition, upon certain events involving a change of control, the holders of the Series A preferred units may elect, among other potential elections, to convert the Series A preferred units to common units at the then applicable conversion rate.

For a period of 30 days following (a) the fifth anniversary of the Issuance Date of the Series A preferred units and (b) each subsequent anniversary of the Issuance Date, the holders of the 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. If the holders of the Series A preferred units have exercised the Preferred Distribution Rate Reset Option, then, at any time following 30 days after the sixth anniversary of the Issuance Date, we may redeem all or any portion of the outstanding Series A preferred units in exchange for cash, common units (valued at 95% of the volume-weighted average price of the common units for a trading day period specified in our partnership agreement) or a combination of cash and common units at a redemption price equal to 110% of the Issue Price, plus any accrued and unpaid distributions.

Continuous Offering Program. During the nine months ended September 30, 2016, we issued an aggregate of approximately 9.9 million common units under our continuous offering program, generating proceeds of $289 million, including our general partner's proportionate capital contribution of $6 million, net of $2 million of commissions paid to our sales agents.

Distributions

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



	Distributions						Distributions per common unit
Distribution Date	Common Unitholders		General Partner		Total		Distributions per common unit
November 14, 2016 ⁽¹⁾	$	227	$	101	$	328	$	0.55
August 12, 2016	$	278	$	155	$	433	$	0.70
May 13, 2016	$	278	$	155	$	433	$	0.70
February 12, 2016	$	278	$	155	$	433	$	0.70

___________________________________________


⁽¹⁾	Payable to unitholders of record at the close of business on October 31, 2016 for the period July 1, 2016 through September 30, 2016.

In-Kind Distributions. On May 13, 2016, we issued 858,439 additional Series A preferred units in lieu of a cash distribution of $23 million. Such distribution was issued to 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 Series A preferred units, through March 31, 2016. On August 12, 2016, we issued 1,237,765 additional Series A preferred units in lieu of a cash distribution of $33 million.

On November 14, 2016, we will issue 1,262,522 additional Series A preferred units in lieu of a cash distribution of $33 million. Since the November 14, 2016 Series A preferred unit distribution was declared as payment-in-kind, this distribution payable was accrued to partners’ capital as of September 30, 2016 and thus had no net impact on the Series A preferred unitholders’ capital account.

Noncontrolling Interests in Subsidiaries

As of September 30, 2016, noncontrolling interests in our subsidiaries consisted of a 25% interest in SLC Pipeline LLC.

Derivatives and Risk Management Activities

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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 September 30, 2016, net derivative positions related to these activities included:


•	A net long position of 4.4 million barrels associated with our crude oil purchases, which was unwound ratably during October 2016 to match monthly average pricing.


•	A net short time spread position of 3.1 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through December 2017.


•	A crude oil grade spread position of 16.0 million barrels through December 2019. These derivatives allow us to lock in grade basis differentials.


•	A net short position of 12.9 Bcf through July 2017 related to anticipated sales of natural gas inventory.


•	A net short position of 34.7 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 September 30, 2016, our PLA hedges included a long call option position of 1.1 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 September 30, 2016, we had a long natural gas position of 31.6 Bcf of which 27.7 Bcf hedges our natural gas processing needs through December 2017. The remaining 3.9 Bcf of our natural gas position hedges natural gas required for operational needs through December 2018. We also had a short propane position of 5.1 million barrels through December 2017, a short butane position of 1.6 million barrels through December 2017 and a short WTI position of 0.7 million barrels through December 2017. In addition, we had a long power position of 0.4 million megawatt hours, which hedges a portion of our power supply requirements at our Canadian natural gas processing and fractionation plants through December 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 September 30, 2016, AOCI includes deferred losses of $353 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 September 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 September 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 September 30, 2016 (in millions):



		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2016	$	222	$	291	$1.00 - $1.31
	2017	$	51	$	67	$1.00 - $1.31

Forward exchange contracts that exchange USD for CAD:
	2016	$	273	$	355	$1.00 - $1.30
	2017	$	126	$	164	$1.00 - $1.30

Preferred Distribution Rate Reset Option

A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. The Preferred Distribution Rate Reset Option of our Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, our partnership agreement, and recorded at fair value on our Condensed Consolidated Balance Sheets. Corresponding changes in fair value are recognized in “Other income/(expense), net” in our Condensed Consolidated Statement of Operations. At September 30, 2016, the fair value of this embedded derivative was a liability of approximately $18 million. We recognized gains of approximately $17 million and $42 million during the three and nine months ended September 30, 2016, respectively, due to changes in fair value during the periods. See Note 8 for additional information regarding our 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 September 30, 2016									Three Months Ended September 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		$	10		$	11		$	42		$	14		$	56

Transportation segment revenues	—			1			1			—			2			2

Field operating costs	—			(2		)	(2		)	—			(9		)	(9		)

Interest Rate Derivatives

Interest expense, net	(2		)	—			(2		)	(4		)	—			(4		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			(1		)	(1		)	—			(9		)	(9		)

Preferred Distribution Rate Reset Option

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

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(1	)	$	25		$	24		$	38		$	(2	)	$	36



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

Supply and Logistics segment revenues	$	1		$	(118	)	$	(117	)	$	30		$	24		$	54

Transportation segment revenues	—			4			4			—			6			6

Field operating costs	—			(2		)	(2		)	—			(11		)	(11		)

Interest Rate Derivatives

Interest expense, net	(8		)	—			(8		)	(9		)	—			(9		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			4			4			—			(26		)	(26		)

Preferred Distribution Rate Reset Option

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

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(7	)	$	(70	)	$	(77	)	$	21		$	(7	)	$	14

___________________________________________

⁽¹⁾

During the nine months ended September 30, 2016 we reclassified losses of approximately $2 million and $2 million to Supply and Logistics segment revenues and Interest expense, net, respectively, due to anticipated hedged transactions being probable of not occurring. During the nine months ended September 30, 2015, we reclassified a loss of approximately $4 million from AOCI to Interest expense, net due to an anticipated hedged transaction being probable of not occurring.

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



	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	1

Interest rate derivatives				Other current liabilities	$	(72	)
				Other long-term liabilities and deferred credits	(103		)
Total derivatives designated as hedging instruments		$	1		$	(175	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	77	Other current assets	$	(119	)
	Other long-term liabilities and deferred credits	3		Other current liabilities	(10		)
				Other long-term liabilities and deferred credits	(18		)

Foreign currency derivatives	Other current liabilities	1		Other current liabilities	(4		)

Preferred Distribution Rate Reset Option				Other long-term liabilities and deferred credits	(18		)
Total derivatives not designated as hedging instruments		$	81		$	(169	)

Total derivatives		$	82		$	(344	)

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 Location	Fair Value		Balance Sheet Location	Fair 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 September 30, 2016, we had a net broker receivable of $142 million (consisting of initial margin of $96 million increased by $46 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):



	September 30, 2016						December 31, 2015
	Derivative Asset Positions			Derivative Liability Positions			Derivative Asset Positions			Derivative Liability Positions
Netting Adjustments:
Gross position - asset/(liability)	$	82		$	(344	)	$	280		$	(110	)
Netting adjustment	(123		)	123			(38		)	38
Cash collateral paid/(received)	142			—			(156		)	—
Net position - asset/(liability)	$	101		$	(221	)	$	86		$	(72	)

Balance Sheet Location After Netting Adjustments:
Other current assets	$	101		$	—		$	76		$	—
Other long-term assets, net	—			—			10			—
Other current liabilities	—			(85		)	—			(38		)
Other long-term liabilities and deferred credits	—			(136		)	—			(34		)
	$	101		$	(221	)	$	86		$	(72	)

As of September 30, 2016, there was a net loss of $374 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 September 30, 2016, we expect to reclassify a net loss of $7 million to earnings in the next twelve months. The remaining deferred loss of $367 million is expected to be reclassified to earnings through 2049. A portion of these amounts is based on market prices as of September 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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Commodity derivatives, net	$	—		$	37		$	—		$	12
Interest rate derivatives, net	(20		)	(85		)	(178		)	(40		)
Total	$	(20	)	$	(48	)	$	(178	)	$	(28	)

At September 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 September 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	$	(27	)	$	(40	)	$	1		$	(66	)	$	126	$	90		$	11	$	227
Interest rate derivatives	—			(175		)	—			(175		)	—		(49		)	—		(49		)
Foreign currency derivatives	—			(3		)	—			(3		)	—		(8		)	—		(8		)
Preferred Distribution Rate Reset Option	—			—			(18		)	(18		)	—		—			—		—
Total net derivative asset/(liability)	$	(27	)	$	(218	)	$	(17	)	$	(262	)	$	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 our partnership agreement 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 our partnership agreement is based on a valuation model that estimates the fair value of the Series A preferred units with and without the Preferred Distribution Rate Reset Option. This model contains inputs, including our common unit price, ten-year U.S. treasury rates, default probabilities and timing estimates which involve management judgment. A significant increase or decrease in the value of these inputs could result in a material change in fair value to this embedded derivative feature. We report unrealized gains and losses associated with this embedded derivative in our Condensed Consolidated Statements of Operations as “Other income/(expense), net.”

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

Rollforward of Level 3 Net Asset/(Liability)

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Beginning Balance	$	(35	)	$	9		$	11		$	15
Gains for the period included in earnings	17			2			41			1
Settlements	—			(2		)	(10		)	(13		)
Derivatives entered into during the period	1			2			(59		)	8
Ending Balance	$	(17	)	$	11		$	(17	)	$	11

Change in unrealized gains included in earnings relating to Level 3 derivatives still held at the end of the period	$	18		$	4		$	43		$	9

- 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

9 Months Ended

Sep. 30, 2016

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 September 30, 2016, Oxy owned approximately 12% of the limited partner interests in our general partner and had a representative on the board of directors of GP LLC. During the three and nine months ended September 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 September 30,					Nine Months Ended September 30,
	2016		2015			2016			2015
Revenues	$	171	$	187		$	424		$	745

Purchases and related costs ⁽¹⁾	$	4	$	(34	)	$	(46	)	$	112

___________________________________________


⁽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 were as follows (in millions):



	September 30, 2016		December 31, 2015
Trade accounts receivable and other receivables	$	610	$	405

Accounts payable	$	587	$	363

Equity-Indexed Compensation Plan	9 Months Ended
Equity-Indexed Compensation Plan	Sep. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity-Indexed Compensation Plan	Equity-Indexed Compensation Plans We refer to the PAA LTIPs and AAP Management Units collectively as our “equity-indexed compensation plans.” For additional discussion of our equity-indexed compensation plans and awards, see Note 15 to our Consolidated Financial Statements included in Part IV of our 2015 Annual Report on Form 10-K. During the third quarter of 2016, modifications were made to the vesting criteria of approximately 2.2 million PAA LTIP units to eliminate distribution performance thresholds, if any, greater than $0.70 per common unit per quarter, and provide that such units will vest based solely on the passage of time during the years 2017 to 2020. In addition, approximately 1.7 million PAA LTIP units were granted with a weighted average grant date fair value of $22.85 per unit. Modifications were also made to the distribution performance thresholds of approximately 2.2 million unearned AAP Management Units such that the awards will become earned based on the attainment of PAA distribution levels between $2.20 and $2.40 per common unit, on an annualized basis, and additional performance conditions based on our distributable cash flow.

- Definition

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

+ References + Details

Commitments and Contingencies	9 Months Ended
Commitments and Contingencies	Sep. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Loss Contingencies — General To the extent we are able to assess the likelihood of a negative outcome for a contingency, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Legal Proceedings — General In the ordinary course of business, we are involved in various legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully protect us from losses arising from current or future legal proceedings. Taking into account what we believe to be all relevant known facts and circumstances, and based on what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing laws and regulations, we do not believe that the outcome of the legal proceedings in which we are currently involved (including those described below) will, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Environmental — General Although over the course of the last several years we have made significant investments in our maintenance and integrity programs, and have hired additional personnel in those areas, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail, storage and other facility operations. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows. We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. We record receivables for amounts recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery. Environmental expenditures that pertain to current operations or to future revenues are expensed or capitalized consistent with our capitalization policy for property and equipment. Expenditures that result from the remediation of an existing condition caused by past operations and that do not contribute to current or future profitability are expensed. At September 30, 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 $57 million was classified as short-term and $103 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 September 30, 2016, we had recorded receivables totaling $79 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which $57 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 initiated investigations into the Line 901 incident, various claims have been made against us and a number of lawsuits have been filed against us. We may be subject to additional claims, investigations and lawsuits, which could materially impact the liabilities and costs we currently expect to incur as a result of the Line 901 incident. Set forth below is a brief summary of actions and matters that are currently pending: On May 21, 2015, we received a corrective action order from the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”), the governmental agency with jurisdiction over the operation of Line 901 as well as over a second stretch of pipeline extending from Gaviota Pump Station in Santa Barbara County to Emidio Pump Station in Kern County, California (Line 903), requiring us to shut down, purge, review, remediate and test Line 901. The corrective action order was subsequently amended on June 3, 2015; November 13, 2015; and June 16, 2016 to require us to take additional corrective actions with respect to both Lines 901 and 903 (as amended, the “CAO”). Among other requirements, the CAO 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 of 46 counts, 36 of which were misdemeanor charges relating to wildlife allegedly taken as a result of the accidental release. The remaining 10 counts (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, six of which have been administratively consolidated into a single proceeding in the United States District Court for the Central District of California. In general, the plaintiffs are seeking to establish different classes of claimants that have allegedly been damaged by the release, 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 the Partnership and/or PAGP against the Partnership, PAGP and/or certain of their respective officers, directors and underwriters. Both of these lawsuits have been consolidated into a single proceeding in the United States District Court for the Southern District of Texas. In general, these lawsuits allege that the various defendants violated securities laws by misleading investors regarding the integrity of the Partnership’s pipelines and related facilities through false and misleading statements, omission of material facts and concealing of the true extent of the spill. The plaintiffs claim unspecified damages as a result of the reduction in value of their investments in the Partnership and PAGP, which they attribute to the alleged wrongful acts of the defendants. The Partnership and PAGP, and the other defendants, 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 the Partnership against the Partnership, certain of its affiliates and certain officers and directors. Two of these lawsuits were filed in the United States District Court for the Southern District of Texas and have been administratively consolidated into one action; the other lawsuit was filed in State District Court in Harris County, Texas. In general, these lawsuits allege that the various defendants breached their fiduciary duties, engaged in gross mismanagement and made false and misleading statements, among other similar allegations, in connection with their management and oversight of the Partnership during the period of time leading up to and following the Line 901 release. The plaintiffs claim that the Partnership 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. We have also received several other individual lawsuits and complaints from companies and individuals alleging damages arising out of the Line 901 incident. These lawsuits and claims generally seek compensatory and punitive damages, and in some cases permanent injunctive relief. In addition to the foregoing, as the “responsible party” for the Line 901 incident we are liable for various costs and for certain natural resource damages under the Oil Pollution Act, and we also have exposure to the payment of additional fines, penalties and costs under other applicable federal, state and local laws, statutes and regulations. To the extent any such costs are reasonably estimable, we have included an estimate of such costs in the loss accrual described below. Taking the foregoing into account, as of September 30, 2016, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $280 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 September 30, 2016, we had a remaining undiscounted gross liability of $87 million related to this event, of which approximately $47 million is presented as a current liability in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet, with the remainder presented in “Other long-term liabilities and deferred credits”. We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such environmental liabilities. Subject to such exclusions and deductibles, we believe that our coverage is adequate to cover the current estimated total emergency response and clean-up costs, claims settlement costs and remediation costs and we believe that this coverage is also adequate to cover any potential increase in the estimates for these costs that exceed the amounts currently identified. Through September 30, 2016, we had collected, subject to customary reservations, $129 million out of the approximate $197 million of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of September 30, 2016, we have recognized a receivable of approximately $68 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 $48 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

9 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

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 September 30, 2016	Transportation		Facilities		Supply and Logistics			Total
Revenues:
External customers	$	159	$	135	$	4,876		$	5,170
Intersegment ⁽¹⁾	242		147		3			392
Total revenues of reportable segments	$	401	$	282	$	4,879		$	5,562
Equity earnings in unconsolidated entities	$	46	$	—	$	—		$	46
Segment profit/(loss) ^(2) (3)	$	261	$	173	$	(6	)	$	428
Maintenance capital	$	29	$	15	$	3		$	47



Three Months Ended September 30, 2015	Transportation		Facilities		Supply and Logistics		Total
Revenues:
External customers	$	172	$	132	$	5,247	$	5,551
Intersegment ⁽¹⁾	229		131		7		367
Total revenues of reportable segments	$	401	$	263	$	5,254	$	5,918
Equity earnings in unconsolidated entities	$	45	$	—	$	—	$	45
Segment profit ^(2) (3)	$	254	$	146	$	87	$	487
Maintenance capital	$	34	$	16	$	2	$	52



Nine Months Ended September 30, 2016	Transportation		Facilities		Supply and Logistics		Total
Revenues:
External customers	$	482	$	405	$	13,344	$	14,231
Intersegment ⁽¹⁾	706		412		9		1,127
Total revenues of reportable segments	$	1,188	$	817	$	13,353	$	15,358
Equity earnings in unconsolidated entities	$	133	$	—	$	—	$	133
Segment profit ^(2) (3)	$	760	$	488	$	13	$	1,261
Maintenance capital	$	86	$	32	$	10	$	128



Nine Months Ended September 30, 2015	Transportation		Facilities		Supply and Logistics		Total
Revenues:
External customers	$	538	$	393	$	17,225	$	18,156
Intersegment ⁽¹⁾	665		396		13		1,074
Total revenues of reportable segments	$	1,203	$	789	$	17,238	$	19,230
Equity earnings in unconsolidated entities	$	134	$	—	$	—	$	134
Segment profit ^(2) (3)	$	681	$	432	$	258	$	1,371
Maintenance capital	$	101	$	48	$	5	$	154

___________________________________________

⁽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 $5 million and $1 million for the three months ended September 30, 2016 and 2015, respectively, and $10 million and $4 million for the nine months ended September 30, 2016 and 2015, respectively.


⁽³⁾	The following table reconciles segment profit to net income attributable to PAA (in millions):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Segment profit	$	428		$	487		$	1,261		$	1,371
Depreciation and amortization	(33		)	(107		)	(351		)	(319		)
Interest expense, net	(113		)	(109		)	(339		)	(320		)
Other income/(expense), net	17			(4		)	46			(7		)
Income before tax	299			267			617			725
Income tax expense	(1		)	(17		)	(15		)	(66		)
Net income	298			250			602			659
Net income attributable to noncontrolling interests	(1		)	(1		)	(3		)	(2		)
Net income attributable to PAA	$	297		$	249		$	599		$	657

- 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, Investments in Unconsolidated Entities, Dispositions and Impairments	9 Months Ended
	Sep. 30, 2016
Business Combinations [Abstract]
Acquisitions, Investments in Unconsolidated Entities, Dispositions and Impairments	Acquisitions, Investments in Unconsolidated Entities, Dispositions and Impairments Acquisitions. During the first nine months of 2016, we completed two acquisitions for cash consideration of $289 million. We did not recognize any goodwill related to these acquisitions. Included in these acquisitions was 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. Investments in Unconsolidated Entities. In June 2016, we sold 50% of our investment in Cheyenne Pipeline LLC (“Cheyenne”), and in August 2016 we sold 50% of our investment in STACK Pipeline LLC (“STACK Pipeline”). As a result of these transactions, we now account for our remaining 50% equity interest in such entities under the equity method of accounting. Dispositions and Divestitures. During the nine months ended September 30, 2016, we sold several non-core assets, including certain of our Gulf Coast pipelines and East Coast refined products terminals. In addition, we sold interests in Cheyenne and STACK Pipeline, as discussed above. In the aggregate, we recognized a net gain of approximately $99 million related to these transactions, which is included in "Depreciation and amortization" on our Condensed Consolidated Statement of Operations. Such amount is comprised of gains of approximately $155 million and losses of $56 million, including $15 million of impairment of goodwill that was included in a disposal group classified as held for sale prior to the closing of such transaction. As of September 30, 2016, we classified approximately $275 million of assets as held for sale on our Condensed Consolidated Balance Sheet (in “Other current assets”) primarily related to definitive agreements to sell non-core assets, a majority of which are included in our Facilities segment. We expect the sales to be consummated in the fourth quarter of 2016 or the first half of 2017, 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

9 Months Ended

Sep. 30, 2016

Simplification Transactions

Simplification Transactions

On July 11, 2016, PAA, PAGP, 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 September 30, 2016, approximately $603 million but expected to be approximately $641 million as of November 15, 2016), 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”), which is expected to occur on November 15, 2016, both PAA and PAGP will continue to be publicly traded. PAA will be required to repay AAP's outstanding debt within two business days after the consummation of the Simplification Transactions.

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 GP Holdings 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 GP Holdings will have oversight responsibility over both PAA and PAGP. In addition, starting in 2018, PAGP Class A and Class B shareholders and PAA common and preferred unitholders will have the right to participate in the election of directors of GP Holdings whose terms expire. Under the current structure, PAA common unitholders are not eligible to participate in the election of directors of GP Holdings and PAGP Class A and Class B shareholders only participate in such elections following a reduction in ownership of the private general partner 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 initial outstanding AAP units (i.e., as of the closing of the Simplification Transactions), such party will continue to be entitled to designate one director to the Board of Directors of GP Holdings. The calculation of such qualifying interest will include, in addition to any PAGP 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 Class A units (assuming the conversion of AAP Class B units into AAP Class A units) equals the number of PAA Common Units received by AAP at the closing of the Simplification Transactions. Simultaneously, PAGP will execute a reverse split to adjust the number of PAGP Class A and Class B shares outstanding to equal the number of AAP units it owns following AAP’s reverse unit split. As a result of these reverse splits, each PAGP Class A share will correspond, on a one-to-one basis, to an underlying PAA Common Unit held by AAP which is attributable to PAGP’s ownership in AAP.

•

Holders of AAP Class A units other than PAGP and GP LLC will continue to have the right to exchange their AAP Class A units (together with the corresponding PAGP Class B shares and, if applicable, GP Holdings company units) for PAGP 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 Class A units receiving PAA Common Units will have registration rights with respect to such PAA Common Units.

Pursuant to the terms of the Simplification Agreement, AAP agreed that if (i) the closing of the Simplification Transactions does not occur prior to the record date for PAA’s distribution of available cash in respect of the third quarter of 2016 and (ii) the amount of such distribution is below a 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. As the Simplification Transactions did not close prior to the PAA third quarter distribution record date of October 31, 2016 and PAA declared a quarterly distribution of $0.55 per common unit for its third quarter distribution, it is currently estimated that the incremental borrowings that will be made by AAP will be approximately $33 million.

The consummation of the matters contemplated by the Simplification Agreement is subject to customary closing conditions and may be terminated under certain conditions. On September 26, 2016, PAGP announced November 15, 2016 as the date for the special meeting of its shareholders to consider and vote upon a proposal to approve the Simplification Transactions. We currently expect that the closing of the Simplification Transactions will take place on November 15, 2016.

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.

Pro Forma Results

Selected PAA historical consolidated financial information has been adjusted below to give effect to pro forma events that are directly attributable to the proposed Simplification Transactions and are based upon currently available information and certain estimates and assumptions made by management. Therefore, the unaudited pro forma amounts presented below are not necessarily reflective of the results of operations or financial position of PAA that would have resulted had the Simplification Transactions been consummated as of the dates indicated, and are not necessarily indicative of the future results of operations or the future financial position of PAA following completion of the proposed Simplification Transactions.

Selected unaudited pro forma results of operations for the three and nine months ended September 30, 2016 are presented below giving effect to the Simplification Transactions as if they had occurred on January 1, 2016 (amounts in millions, except per unit data):



	Three Months Ended September 30, 2016		Nine Months Ended September 30, 2016
Net income attributable to PAA	$	294	$	589
Basic net income per common unit	$	0.40	$	0.77
Diluted net income per common unit	$	0.40	$	0.77

Selected unaudited pro forma balance sheet amounts as of September 30, 2016 are presented below giving effect to the Simplification Transactions as if they had occurred on September 30, 2016 (amounts in millions):



	As of September 30, 2016
LONG-TERM LIABILITIES
Other long-term debt, net of unamortized debt issuance costs	$	1,114

PARTNERS’ CAPITAL
Common unitholders	$	6,898
General partner	$	—
Total partners’ capital	$	8,464

Organization and Basis of Consolidation and Presentation (Policies)	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Income Allocation	Income Allocation Net income for partners’ capital presentation purposes is allocated in accordance with our partnership agreement. Our general partner and common unitholders are allocated income based on their respective partnership percentages, after giving effect to income allocations for (i) incentive distributions, if any, to our general partner (the holder of the IDRs pursuant to our partnership agreement) for distributions declared and paid following the close of each quarter and (ii) cash distributions to our preferred unitholders. In accordance with our partnership agreement, our preferred unitholders are not allocated income for paid-in-kind distributions. For purposes of determining basic and diluted net income per common unit, income is allocated as prescribed in FASB guidance for calculating earnings per unit including application of the two-class method for MLPs. See Note 3 for additional information.

Net Income Per Common Unit (Tables)

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Computation of basic and diluted net income per common unit

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Basic Net Income per Common Unit
Net income attributable to PAA	$	297		$	249		$	599		$	657
Distributions to Series A preferred units ⁽¹⁾	(33		)	—			(88		)	—
Distributions to general partner ⁽¹⁾	(102		)	(154		)	(412		)	(454		)
Distributions to participating securities⁽¹⁾	(1		)	(1		)	(3		)	(4		)
Undistributed loss allocated to general partner⁽¹⁾	1			4			14			12
Net income allocated to common unitholders in accordance with application of the two-class method for MLPs	$	162		$	98		$	110		$	211

Basic weighted average common units outstanding	401			398			399			393

Basic net income per common unit	$	0.40		$	0.25		$	0.27		$	0.54

Diluted Net Income per Common Unit
Net income attributable to PAA	$	297		$	249		$	599		$	657
Distributions to Series A preferred units ⁽¹⁾	(33		)	—			(88		)	—
Distributions to general partner ⁽¹⁾	(102		)	(154		)	(412		)	(454		)
Distributions to participating securities⁽¹⁾	(1		)	(1		)	(3		)	(4		)
Undistributed loss allocated to general partner⁽¹⁾	1			4			14			12
Net income allocated to common unitholders in accordance with application of the two-class method for MLPs	$	162		$	98		$	110		$	211

Basic weighted average common units outstanding	401			398			399			393
Effect of dilutive securities: Weighted average LTIP units	1			1			1			2
Diluted weighted average common units outstanding	402			399			400			395

Diluted net income per common unit	$	0.40		$	0.24		$	0.27		$	0.53

___________________________________________

⁽¹⁾

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

9 Months Ended

Sep. 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):



	September 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	20,494	barrels	$	879	$	42.89	16,345	barrels	$	608	$	37.20
NGL	21,087	barrels	321		$	15.22	13,907	barrels	218		$	15.68
Natural gas	15,116	Mcf	32		$	2.12	22,080	Mcf	53		$	2.40
Other	N/A		26		N/A		N/A		37		N/A
Inventory subtotal			1,258						916

Linefill and base gas
Crude oil	12,215	barrels	712		$	58.29	12,298	barrels	713		$	57.98
NGL	1,490	barrels	46		$	30.87	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			899						898

Long-term inventory
Crude oil	3,428	barrels	124		$	36.17	3,417	barrels	106		$	31.02
NGL	1,418	barrels	22		$	15.51	1,652	barrels	23		$	13.92
Long-term inventory subtotal			146						129

Total			$	2,303					$	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 (Tables)

9 Months Ended

Sep. 30, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

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	12			5			2		19
Dispositions and reclassifications to assets held for sale	(15		)	(56		)	—		(71		)
Balance at September 30, 2016	$	812		$	1,036		$	505	$	2,353

Debt (Tables)

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Schedule of debt

Debt consisted of the following (in millions):



	September 30, 2016		December 31, 2015
SHORT-TERM DEBT
Commercial paper notes, bearing a weighted-average interest rate of 1.3% and 1.1%, respectively⁽¹⁾	$	256	$	696
Senior secured hedged inventory facility, bearing a weighted-average interest rate of 1.5% and 1.4%, respectively⁽¹⁾	725		300
Senior notes:
6.13% senior notes due January 2017	400		—
Other	3		3
Total short-term debt	1,384		999

LONG-TERM DEBT
Senior notes, net of unamortized discounts and debt issuance costs of $70 and $77, respectively	9,130		9,698
Commercial paper notes, bearing a weighted-average interest rate of 1.3% and 1.1%, respectively ⁽²⁾	500		672
Other	4		5
Total long-term debt	9,634		10,375
Total debt ⁽³⁾	$	11,018	$	11,374

___________________________________________


⁽¹⁾	We classified these commercial paper notes and credit facility borrowings as short-term as of September 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⁾	As of September 30, 2016 and December 31, 2015, we classified a portion of our commercial paper notes as long-term based on our ability and intent to refinance such amounts on a long-term basis under our credit facilities.

⁽³⁾

Partners' Capital and Distributions (Tables)

9 Months Ended

Sep. 30, 2016

Partners' Capital Notes [Abstract]

Schedule of activity for Series A preferred units and common units

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



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



	Limited Partners
	Common Units
Outstanding at December 31, 2014	375,107,793
Sale of common units	22,133,904
Issuance of common units under LTIP	485,927
Outstanding at September 30, 2015	397,727,624

Schedule of distributions paid in cash, net of reductions to the general partner's incentive distributions

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



	Distributions						Distributions per common unit
Distribution Date	Common Unitholders		General Partner		Total		Distributions per common unit
November 14, 2016 ⁽¹⁾	$	227	$	101	$	328	$	0.55
August 12, 2016	$	278	$	155	$	433	$	0.70
May 13, 2016	$	278	$	155	$	433	$	0.70
February 12, 2016	$	278	$	155	$	433	$	0.70

___________________________________________


⁽¹⁾	Payable to unitholders of record at the close of business on October 31, 2016 for the period July 1, 2016 through September 30, 2016.

Derivatives and Risk Management Activities (Tables)

9 Months Ended

Sep. 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 September 30, 2016									Three Months Ended September 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		$	10		$	11		$	42		$	14		$	56

Transportation segment revenues	—			1			1			—			2			2

Field operating costs	—			(2		)	(2		)	—			(9		)	(9		)

Interest Rate Derivatives

Interest expense, net	(2		)	—			(2		)	(4		)	—			(4		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			(1		)	(1		)	—			(9		)	(9		)

Preferred Distribution Rate Reset Option

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

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(1	)	$	25		$	24		$	38		$	(2	)	$	36



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

Supply and Logistics segment revenues	$	1		$	(118	)	$	(117	)	$	30		$	24		$	54

Transportation segment revenues	—			4			4			—			6			6

Field operating costs	—			(2		)	(2		)	—			(11		)	(11		)

Interest Rate Derivatives

Interest expense, net	(8		)	—			(8		)	(9		)	—			(9		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			4			4			—			(26		)	(26		)

Preferred Distribution Rate Reset Option

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

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(7	)	$	(70	)	$	(77	)	$	21		$	(7	)	$	14

___________________________________________

⁽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 September 30, 2016 (in millions):



	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	1

Interest rate derivatives				Other current liabilities	$	(72	)
				Other long-term liabilities and deferred credits	(103		)
Total derivatives designated as hedging instruments		$	1		$	(175	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	77	Other current assets	$	(119	)
	Other long-term liabilities and deferred credits	3		Other current liabilities	(10		)
				Other long-term liabilities and deferred credits	(18		)

Foreign currency derivatives	Other current liabilities	1		Other current liabilities	(4		)

Preferred Distribution Rate Reset Option				Other long-term liabilities and deferred credits	(18		)
Total derivatives not designated as hedging instruments		$	81		$	(169	)

Total derivatives		$	82		$	(344	)

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 Location	Fair Value		Balance Sheet Location	Fair 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 that are subject to offsetting, including enforceable master netting arrangements

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



	September 30, 2016						December 31, 2015
	Derivative Asset Positions			Derivative Liability Positions			Derivative Asset Positions			Derivative Liability Positions
Netting Adjustments:
Gross position - asset/(liability)	$	82		$	(344	)	$	280		$	(110	)
Netting adjustment	(123		)	123			(38		)	38
Cash collateral paid/(received)	142			—			(156		)	—
Net position - asset/(liability)	$	101		$	(221	)	$	86		$	(72	)

Balance Sheet Location After Netting Adjustments:
Other current assets	$	101		$	—		$	76		$	—
Other long-term assets, net	—			—			10			—
Other current liabilities	—			(85		)	—			(38		)
Other long-term liabilities and deferred credits	—			(136		)	—			(34		)
	$	101		$	(221	)	$	86		$	(72	)

Schedule of derivative financial liabilities that are subject to offsetting, including enforceable master netting arrangements

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



	September 30, 2016						December 31, 2015
	Derivative Asset Positions			Derivative Liability Positions			Derivative Asset Positions			Derivative Liability Positions
Netting Adjustments:
Gross position - asset/(liability)	$	82		$	(344	)	$	280		$	(110	)
Netting adjustment	(123		)	123			(38		)	38
Cash collateral paid/(received)	142			—			(156		)	—
Net position - asset/(liability)	$	101		$	(221	)	$	86		$	(72	)

Balance Sheet Location After Netting Adjustments:
Other current assets	$	101		$	—		$	76		$	—
Other long-term assets, net	—			—			10			—
Other current liabilities	—			(85		)	—			(38		)
Other long-term liabilities and deferred credits	—			(136		)	—			(34		)
	$	101		$	(221	)	$	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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Commodity derivatives, net	$	—		$	37		$	—		$	12
Interest rate derivatives, net	(20		)	(85		)	(178		)	(40		)
Total	$	(20	)	$	(48	)	$	(178	)	$	(28	)

Schedule of derivative financial assets and liabilities accounted for at fair value on a recurring basis, by level within the fair value hierarchy

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions):



	Fair Value as of September 30, 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	$	(27	)	$	(40	)	$	1		$	(66	)	$	126	$	90		$	11	$	227
Interest rate derivatives	—			(175		)	—			(175		)	—		(49		)	—		(49		)
Foreign currency derivatives	—			(3		)	—			(3		)	—		(8		)	—		(8		)
Preferred Distribution Rate Reset Option	—			—			(18		)	(18		)	—		—			—		—
Total net derivative asset/(liability)	$	(27	)	$	(218	)	$	(17	)	$	(262	)	$	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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Beginning Balance	$	(35	)	$	9		$	11		$	15
Gains for the period included in earnings	17			2			41			1
Settlements	—			(2		)	(10		)	(13		)
Derivatives entered into during the period	1			2			(59		)	8
Ending Balance	$	(17	)	$	11		$	(17	)	$	11

Change in unrealized gains included in earnings relating to Level 3 derivatives still held at the end of the period	$	18		$	4		$	43		$	9

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 September 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

Summary of open forward exchange contracts

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



		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2016	$	222	$	291	$1.00 - $1.31
	2017	$	51	$	67	$1.00 - $1.31

Forward exchange contracts that exchange USD for CAD:
	2016	$	273	$	355	$1.00 - $1.30
	2017	$	126	$	164	$1.00 - $1.30

Related Party Transactions (Tables)

9 Months Ended

Sep. 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 September 30,					Nine Months Ended September 30,
	2016		2015			2016			2015
Revenues	$	171	$	187		$	424		$	745

Purchases and related costs ⁽¹⁾	$	4	$	(34	)	$	(46	)	$	112

___________________________________________


⁽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 were as follows (in millions):



	September 30, 2016		December 31, 2015
Trade accounts receivable and other receivables	$	610	$	405

Accounts payable	$	587	$	363

Operating Segments (Tables)

9 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Segment financial data

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



Three Months Ended September 30, 2016	Transportation		Facilities		Supply and Logistics			Total
Revenues:
External customers	$	159	$	135	$	4,876		$	5,170
Intersegment ⁽¹⁾	242		147		3			392
Total revenues of reportable segments	$	401	$	282	$	4,879		$	5,562
Equity earnings in unconsolidated entities	$	46	$	—	$	—		$	46
Segment profit/(loss) ^(2) (3)	$	261	$	173	$	(6	)	$	428
Maintenance capital	$	29	$	15	$	3		$	47



Three Months Ended September 30, 2015	Transportation		Facilities		Supply and Logistics		Total
Revenues:
External customers	$	172	$	132	$	5,247	$	5,551
Intersegment ⁽¹⁾	229		131		7		367
Total revenues of reportable segments	$	401	$	263	$	5,254	$	5,918
Equity earnings in unconsolidated entities	$	45	$	—	$	—	$	45
Segment profit ^(2) (3)	$	254	$	146	$	87	$	487
Maintenance capital	$	34	$	16	$	2	$	52



Nine Months Ended September 30, 2016	Transportation		Facilities		Supply and Logistics		Total
Revenues:
External customers	$	482	$	405	$	13,344	$	14,231
Intersegment ⁽¹⁾	706		412		9		1,127
Total revenues of reportable segments	$	1,188	$	817	$	13,353	$	15,358
Equity earnings in unconsolidated entities	$	133	$	—	$	—	$	133
Segment profit ^(2) (3)	$	760	$	488	$	13	$	1,261
Maintenance capital	$	86	$	32	$	10	$	128



Nine Months Ended September 30, 2015	Transportation		Facilities		Supply and Logistics		Total
Revenues:
External customers	$	538	$	393	$	17,225	$	18,156
Intersegment ⁽¹⁾	665		396		13		1,074
Total revenues of reportable segments	$	1,203	$	789	$	17,238	$	19,230
Equity earnings in unconsolidated entities	$	134	$	—	$	—	$	134
Segment profit ^(2) (3)	$	681	$	432	$	258	$	1,371
Maintenance capital	$	101	$	48	$	5	$	154

___________________________________________

⁽¹⁾


⁽²⁾	Supply and Logistics segment profit includes interest expense (related to hedged inventory purchases) of $5 million and $1 million for the three months ended September 30, 2016 and 2015, respectively, and $10 million and $4 million for the nine months ended September 30, 2016 and 2015, respectively.


⁽³⁾	The following table reconciles segment profit to net income attributable to PAA (in millions):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Segment profit	$	428		$	487		$	1,261		$	1,371
Depreciation and amortization	(33		)	(107		)	(351		)	(319		)
Interest expense, net	(113		)	(109		)	(339		)	(320		)
Other income/(expense), net	17			(4		)	46			(7		)
Income before tax	299			267			617			725
Income tax expense	(1		)	(17		)	(15		)	(66		)
Net income	298			250			602			659
Net income attributable to noncontrolling interests	(1		)	(1		)	(3		)	(2		)
Net income attributable to PAA	$	297		$	249		$	599		$	657

Reconciliation of segment profit to net income attributable to PAA

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Segment profit	$	428		$	487		$	1,261		$	1,371
Depreciation and amortization	(33		)	(107		)	(351		)	(319		)
Interest expense, net	(113		)	(109		)	(339		)	(320		)
Other income/(expense), net	17			(4		)	46			(7		)
Income before tax	299			267			617			725
Income tax expense	(1		)	(17		)	(15		)	(66		)
Net income	298			250			602			659
Net income attributable to noncontrolling interests	(1		)	(1		)	(3		)	(2		)
Net income attributable to PAA	$	297		$	249		$	599		$	657

Simplification Transactions (Tables)

9 Months Ended

Sep. 30, 2016

Simplification Transactions

Selected unaudited pro forma results of operations and balance sheet amounts giving effect to the Simplification Transactions



	Three Months Ended September 30, 2016		Nine Months Ended September 30, 2016
Net income attributable to PAA	$	294	$	589
Basic net income per common unit	$	0.40	$	0.77
Diluted net income per common unit	$	0.40	$	0.77



	As of September 30, 2016
LONG-TERM LIABILITIES
Other long-term debt, net of unamortized debt issuance costs	$	1,114

PARTNERS’ CAPITAL
Common unitholders	$	6,898
General partner	$	—
Total partners’ capital	$	8,464

Organization and Basis of Consolidation and Presentation - Segments and Ownership (Details)	9 Months Ended
	Sep. 30, 2016 segment
Organization
Operating segments number	3
AAP \| PAGP
Organization
Limited partner interest	42.00%
PAA GP
Organization
General partner ownership interest	2.00%

Organization and Basis of Consolidation and Presentation - Simplification Agreement (Details) - Forecast - Simplification Agreement shares in Millions	Nov. 15, 2016 shares
PAA GP
Simplification Transactions
Economic general partner interest converted into non-economic interest	2.00%
AAP
Simplification Transactions
Issuance of common units (units)	245.5

Organization and Basis of Consolidation and Presentation - Debt Issuance Costs (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Basis of Consolidation and Presentation
Depreciation and amortization	$ 33	$ 107	$ 351	$ 319
Interest expense, net	$ 113	109	$ 339	320
ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs \| Reclassification due to retrospective application of revised guidance
Basis of Consolidation and Presentation
Depreciation and amortization		(2)		(7)
Interest expense, net		$ 2		$ 7

Net Income Per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Basic Net Income per Common Unit
Net income attributable to PAA	$ 297	$ 249	$ 599	$ 657
Distributions to Series A preferred units	(33)		(88)
Distributions to general partner	(102)	(154)	(412)	(454)
Distributions to participating securities	(1)	(1)	(3)	(4)
Undistributed loss allocated to general partner	1	4	14	12
Net income allocated to common unitholders in accordance with application of the two-class method for MLPs	162	98	110	211
Diluted Net Income per Common Unit
Net income attributable to PAA	297	249	599	657
Distributions to Series A preferred units	(33)		(88)
Distributions to general partner	(102)	(154)	(412)	(454)
Distributions to participating securities	(1)	(1)	(3)	(4)
Undistributed loss allocated to general partner	1	4	14	12
Net income allocated to common unitholders in accordance with application of the two-class method for MLPs	$ 162	$ 98	$ 110	$ 211
Common Units
Basic Net Income per Common Unit
Basic weighted average common units outstanding (units)	401	398	399	393
Basic net income per common unit (usd per unit)	$ 0.40	$ 0.25	$ 0.27	$ 0.54
Diluted Net Income per Common Unit
Basic weighted average common units outstanding (units)	401	398	399	393
Effect of dilutive securities: Weighted average LTIP units (units)	1	1	1	2
Diluted weighted average common units outstanding (units)	402	399	400	395
Diluted net income per common unit (usd per unit)	$ 0.40	$ 0.24	$ 0.27	$ 0.53

Accounts Receivable, Net (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
Accounts Receivable, Net (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Accounts Receivable, Net
Advance cash payments received from third parties to mitigate credit risk	$ 62	$ 88
Standby letters of credit	$ 103	$ 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	$ 3	$ 4

Inventory, Linefill and Base Gas and Long-term Inventory (Details) bbl in Thousands, Mcf in Thousands, $ in Millions	Sep. 30, 2016 USD ($) $ / Mcf $ / bbl bbl Mcf	Dec. 31, 2015 USD ($) $ / Mcf $ / bbl bbl Mcf
Inventory by category
Inventory	$ 1,258	$ 916
Linefill and base gas	899	898
Long-term inventory	146	129
Total	2,303	1,943
Crude oil
Inventory by category
Inventory	879	608
Linefill and base gas	712	713
Long-term inventory	$ 124	$ 106
Inventory, Volumes (in barrels or in Mcf) \| bbl	20,494	16,345
Linefill and base gas, Volumes (in barrels or in Mcf) \| bbl	12,215	12,298
Long-term inventory, Volumes (in barrels or in Mcf) \| bbl	3,428	3,417
Inventory, Price/Unit of measure \| $ / bbl	42.89	37.20
Linefill and base gas, Price/Unit of measure \| $ / bbl	58.29	57.98
Long-term inventory, Price/Unit of measure \| $ / bbl	36.17	31.02
NGL
Inventory by category
Inventory	$ 321	$ 218
Linefill and base gas	46	44
Long-term inventory	$ 22	$ 23
Inventory, Volumes (in barrels or in Mcf) \| bbl	21,087	13,907
Linefill and base gas, Volumes (in barrels or in Mcf) \| bbl	1,490	1,348
Long-term inventory, Volumes (in barrels or in Mcf) \| bbl	1,418	1,652
Inventory, Price/Unit of measure \| $ / bbl	15.22	15.68
Linefill and base gas, Price/Unit of measure \| $ / bbl	30.87	32.64
Long-term inventory, Price/Unit of measure \| $ / bbl	15.51	13.92
Natural gas
Inventory by category
Inventory	$ 32	$ 53
Linefill and base gas	$ 141	$ 141
Inventory, Volumes (in barrels or in Mcf) \| Mcf	15,116	22,080
Linefill and base gas, Volumes (in barrels or in Mcf) \| Mcf	30,812	30,812
Inventory, Price/Unit of measure \| $ / Mcf	2.12	2.40
Linefill and base gas, Price/Unit of measure \| $ / Mcf	4.58	4.58
Other
Inventory by category
Inventory	$ 26	$ 37

Goodwill (Details) - USD ($)		9 Months Ended
Goodwill (Details) - USD ($)	Jun. 30, 2016	Sep. 30, 2016
Changes in goodwill
Balance at December 31, 2015		$ 2,405,000,000
Foreign currency translation adjustments		19,000,000
Dispositions and reclassifications to assets held for sale		(71,000,000)
Balance at September 30, 2016		2,353,000,000
Impairment of goodwill	$ 0
Operating Segments \| Transportation
Changes in goodwill
Balance at December 31, 2015		815,000,000
Foreign currency translation adjustments		12,000,000
Dispositions and reclassifications to assets held for sale		(15,000,000)
Balance at September 30, 2016		812,000,000
Operating Segments \| Facilities
Changes in goodwill
Balance at December 31, 2015		1,087,000,000
Foreign currency translation adjustments		5,000,000
Dispositions and reclassifications to assets held for sale		(56,000,000)
Balance at September 30, 2016		1,036,000,000
Operating Segments \| Supply and Logistics
Changes in goodwill
Balance at December 31, 2015		503,000,000
Foreign currency translation adjustments		2,000,000
Balance at September 30, 2016		$ 505,000,000

Debt - Components (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Short-term debt:
Total short-term debt	$ 1,384	$ 999
Long-term debt:
Senior notes, net of unamortized discounts and debt issuance costs of $70 and $77, respectively	9,130	9,698
Other long-term debt	504	677
Total long-term debt	9,634	10,375
Total debt	11,018	11,374
Senior notes
Long-term debt:
Unamortized discounts and debt issuance costs	70	77
Senior notes, net of unamortized discounts and debt issuance costs of $70 and $77, respectively	9,130	9,698
Other
Long-term debt:
Other long-term debt	$ 4	$ 5
Commercial paper notes
Long-term debt:
Weighted average interest rate, long-term	1.30%	1.10%
Other long-term debt	$ 500	$ 672
Commercial paper notes
Short-term debt:
Weighted average interest rate, short-term	1.30%	1.10%
Short-term debt	$ 256	$ 696
Other
Short-term debt:
Other short-term debt	$ 3	$ 3
Senior secured hedged inventory facility \| Credit facility
Short-term debt:
Weighted average interest rate, short-term	1.50%	1.40%
Short-term debt	$ 725	$ 300
6.13% senior notes due January 2017 \| Senior notes
Short-term debt:
Debt instrument, interest rate	6.13%
Senior notes, current	$ 400

Debt - Fair Value, Activity, Letters of Credit, Borrowings and Repayments (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Aug. 31, 2016	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Debt
Repayments of senior notes		$ 175	$ 549
Letters of credit
Debt
Outstanding letters of credit		47		$ 46
Senior notes
Debt
Debt instrument face value		9,600		9,800
Senior notes \| 5.88% senior notes due August 2016
Debt
Repayments of senior notes	$ 175
Debt instrument, interest rate	5.88%
Senior notes \| Level 2
Debt
Debt instrument fair value		9,700		$ 8,600
Credit facilities and commercial paper program
Debt
Total borrowings		41,400	37,100
Total repayments		$ 41,600	$ 36,900

Partners' Capital and Distributions - Units Outstanding (Details) - shares		9 Months Ended
	Jan. 28, 2016	Sep. 30, 2016	Sep. 30, 2015
Series A Preferred Units
Activity for preferred units and common units
Outstanding, end of period (units)		63,126,331
Series A Preferred Units \| Limited Partners
Activity for preferred units and common units
Sale of preferred units (units)	61,000,000
Series A Preferred Units \| Limited Partners \| Partners’ Capital Excluding Noncontrolling Interests
Activity for preferred units and common units
Sale of preferred units (units)		61,030,127
Issuance of preferred units in connection with in-kind distributions (units)		2,096,204
Outstanding, end of period (units)		63,126,331
Common Units
Activity for preferred units and common units
Outstanding, beginning of period (units)		397,727,624
Outstanding, end of period (units)		408,107,646
Common Units \| Limited Partners \| Partners’ Capital Excluding Noncontrolling Interests
Activity for preferred units and common units
Outstanding, beginning of period (units)		397,727,624	375,107,793
Sale of common units (units)		9,922,733	22,133,904
Issuance of common units under LTIP (units)		457,289	485,927
Outstanding, end of period (units)		408,107,646	397,727,624

Partners' Capital and Distributions - Equity Offerings (Details) $ / shares in Units, shares in Millions, $ in Millions		9 Months Ended
	Jan. 28, 2016 $ / shares shares	Sep. 30, 2016 USD ($) item $ / shares shares
Series A Preferred Units \| Limited Partners
Partners Capital and Distributions
Sale of preferred units (units) \| shares	61.0
Cash purchase price (usd per unit) \| $ / shares	$ 26.25
Quarterly distribution rate (usd per unit) \| $ / shares		$ 0.525
Annualized distribution rate (usd per unit) \| $ / shares		$ 2.10
Preferred unit conversion ratio		1
Common unit closing price as a percentage of Issue Price, over which the entity has conversion option		150.00%
Period for closing price of common units to be above threshold, to trigger conversion option		20 days
Series A Preferred Units \| Limited Partners \| 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		5.85%
Period after sixth anniversary of issuance, after which units may be redeemed if distribution rate has been reset		30 days
Value of common units if exchanged for redemption of preferred units, as a percentage of volume-weighted average price		95.00%
Redemption price as a percentage of Issue Price		110.00%
Continuous Offering Program
Partners Capital and Distributions
Sale of common units (units) \| shares		9.9
Sale of common units, net proceeds \| $		$ 289
Commissions paid to sales agents \| $		2
Continuous Offering Program \| General Partner
Partners Capital and Distributions
General partners' proportionate capital contributions \| $		$ 6

Partners' Capital and Distributions - Distributions (Details) - USD ($) $ / shares in Units, $ in Millions						9 Months Ended
	Nov. 14, 2016	Oct. 31, 2016	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016	Sep. 30, 2016	Sep. 30, 2015
Partners Capital and Distributions
Total distributions paid						$ 1,302	$ 1,240
Third Quarter Distribution \| Forecast
Partners Capital and Distributions
Distribution payment date	Nov. 14, 2016
Second Quarter Distribution
Partners Capital and Distributions
Distribution payment date			Aug. 12, 2016
First Quarter Distribution
Partners Capital and Distributions
Distribution payment date				May 13, 2016
Fourth Quarter Distribution
Partners Capital and Distributions
Distribution payment date					Feb. 12, 2016
Partners’ Capital Excluding Noncontrolling Interests
Partners Capital and Distributions
Total distributions paid						$ 1,299	$ 1,238
Partners’ Capital Excluding Noncontrolling Interests \| Cash Distributions \| Third Quarter Distribution \| Forecast
Partners Capital and Distributions
Distributions paid to General Partner	$ 101
Total distributions paid	$ 328
Partners’ Capital Excluding Noncontrolling Interests \| Cash Distributions \| Second Quarter Distribution
Partners Capital and Distributions
Distributions paid to General Partner			$ 155
Total distributions paid			$ 433
Partners’ Capital Excluding Noncontrolling Interests \| Cash Distributions \| First Quarter Distribution
Partners Capital and Distributions
Distributions paid to General Partner				$ 155
Total distributions paid				$ 433
Partners’ Capital Excluding Noncontrolling Interests \| Cash Distributions \| Fourth Quarter Distribution
Partners Capital and Distributions
Distributions paid to General Partner					$ 155
Total distributions paid					$ 433
Common Units \| Cash Distributions \| Third Quarter Distribution \| Forecast
Partners Capital and Distributions
Distributions per common unit, paid (usd per unit)	$ 0.55
Common Units \| Cash Distributions \| Second Quarter Distribution
Partners Capital and Distributions
Distributions per common unit, paid (usd per unit)			$ 0.70
Common Units \| Cash Distributions \| First Quarter Distribution
Partners Capital and Distributions
Distributions per common unit, paid (usd per unit)				$ 0.70
Common Units \| Cash Distributions \| Fourth Quarter Distribution
Partners Capital and Distributions
Distributions per common unit, paid (usd per unit)					$ 0.70
Common Units \| Partners’ Capital Excluding Noncontrolling Interests \| Cash Distributions \| Third Quarter Distribution \| Forecast
Partners Capital and Distributions
Distributions paid to Unitholders	$ 227
Common Units \| Partners’ Capital Excluding Noncontrolling Interests \| Cash Distributions \| Second Quarter Distribution
Partners Capital and Distributions
Distributions paid to Unitholders			$ 278
Common Units \| Partners’ Capital Excluding Noncontrolling Interests \| Cash Distributions \| First Quarter Distribution
Partners Capital and Distributions
Distributions paid to Unitholders				$ 278
Common Units \| Partners’ Capital Excluding Noncontrolling Interests \| Cash Distributions \| Fourth Quarter Distribution
Partners Capital and Distributions
Distributions paid to Unitholders					$ 278
Series A Preferred Units \| Partners’ Capital Excluding Noncontrolling Interests \| In-Kind Distributions \| Third Quarter Distribution \| Forecast
Partners Capital and Distributions
Distributions paid to Unitholders	$ 33
Distribution of units in lieu of cash (units)	1,262,522
Series A Preferred Units \| Partners’ Capital Excluding Noncontrolling Interests \| In-Kind Distributions \| Second Quarter Distribution
Partners Capital and Distributions
Distributions paid to Unitholders			$ 33
Distribution of units in lieu of cash (units)			1,237,765
Series A Preferred Units \| Partners’ Capital Excluding Noncontrolling Interests \| In-Kind Distributions \| First Quarter Distribution
Partners Capital and Distributions
Distributions paid to Unitholders				$ 23
Distribution of units in lieu of cash (units)				858,439
Subsequent Event \| Third Quarter Distribution
Partners Capital and Distributions
Unitholders of record, date		Oct. 31, 2016

Partners' Capital and Distributions - Noncontrolling Interests (Details)	Sep. 30, 2016
SLC Pipeline LLC
Partners Capital and Distributions
Noncontrolling interests in subsidiaries (percent)	25.00%

Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions, Mcf in Millions, MWh in Millions	9 Months Ended
	Sep. 30, 2016 MWh bbl Mcf
Net long position associated with crude oil purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	4.4
Net short time spread position hedging anticipated crude oil lease gathering purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	3.1
Crude oil grade spread position
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	16.0
Net short position related to anticipated sales of natural gas inventory
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf) \| Mcf	12.9
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)	34.7
PLA oil long call option position
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	1.1
Long natural gas position for natural gas purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf) \| Mcf	31.6
Natural gas processing needs
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf) \| Mcf	27.7
Natural gas operational needs
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf) \| Mcf	3.9
Short propane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	5.1
Short butane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	1.6
Short WTI position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	0.7
Long power position for power supply requirements
Commodity Price Risk Hedging:
Derivative position notional amount (in megawatt hours) \| MWh	0.4

Derivatives and Risk Management Activities - Interest Rate Risk Hedging (Details) $ in Millions	1 Months Ended	9 Months Ended
	Jun. 30, 2016 USD ($) contract	Sep. 30, 2016 USD ($) contract	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Interest Rate Risk Hedging
Net deferred gains/(losses) included in AOCI		$ (1,081)	$ (985)	$ (1,081)	$ (467)
Cash paid in connection with termination of interest rate derivatives		50	$ 48
Interest Rate Derivatives
Interest Rate Risk Hedging
Net deferred gains/(losses) included in AOCI		$ (353)
8 forward starting interest rate swaps (30-year), 2.02% \| Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives \| contract		8
Notional amount of derivatives		$ 200
Average rate locked (percent)		2.02%
8 forward starting interest rate swaps (30-year), 3.14% \| Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives \| contract		8
Notional amount of derivatives		$ 200
Average rate locked (percent)		3.14%
8 forward starting interest rate swaps (30-year), 3.20% \| Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives \| contract		8
Notional amount of derivatives		$ 200
Average rate locked (percent)		3.20%
8 forward starting interest rate swaps (30-year), 2.83% \| Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives \| contract		8
Notional amount of derivatives		$ 200
Average rate locked (percent)		2.83%
8 forward starting interest rate swaps (30-year), 3.06%
Interest Rate Risk Hedging
Net deferred gains/(losses) included in AOCI	$ (50)
Notional amount of derivatives	$ 200
Average rate locked (percent)	3.06%
Cash paid in connection with termination of interest rate derivatives	$ 52
Number of interest rate derivatives terminated \| contract	8
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	Sep. 30, 2016 USD ($) $ / $	Sep. 30, 2016 CAD ($) $ / $
Forward exchange contracts that exchange CAD for USD maturing in 2016
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 222	$ 291
Average exchange rate	1.31	1.31
Forward exchange contracts that exchange CAD for USD maturing in 2017
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 51	$ 67
Average exchange rate	1.31	1.31
Forward exchange contracts that exchange USD for CAD maturing in 2016
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 273	$ 355
Average exchange rate	1.30	1.30
Forward exchange contracts that exchange USD for CAD maturing in 2017
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 126	$ 164
Average exchange rate	1.30	1.30

Derivatives and Risk Management Activities - Embedded Derivatives (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2016 USD ($)	Sep. 30, 2016 USD ($)
Embedded Derivatives
Gain recognized due to changes in fair value		$ 42
Preferred Distribution Rate Reset Option \| Series A Preferred Units
Embedded Derivatives
Fair value of derivative liability	$ 18	18
Gain recognized due to changes in fair value	$ 17	$ 42

Derivatives and Risk Management Activities - Financial Impact (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	$ 24	$ 36	$ (77)	$ 14
Commodity Derivatives \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	11	56	(117)	54
Commodity Derivatives \| Transportation segment revenues
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	1	2	4	6
Commodity Derivatives \| Field operating costs
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	(2)	(9)	(2)	(11)
Interest Rate Derivatives \| Interest expense, net
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	(2)	(4)	(8)	(9)
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)	(9)	4	(26)
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	17		42
Derivatives in Hedging Relationships
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	(1)	38	(7)	21
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
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	4
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	42	1	30
Derivatives in Hedging Relationships \| Interest Rate Derivatives \| Interest expense, net
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	(2)	(4)	(8)	(9)
Derivatives Not Designated as a Hedge
Impact of derivative activities recognized in earnings
Total gain/(loss) on derivatives recognized in net income	25	(2)	(70)	(7)
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	10	14	(118)	24
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	4	6
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)	(9)	(2)	(11)
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)	$ (9)	4	$ (26)
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	$ 17		$ 42

Derivatives and Risk Management Activities - Assets and Liabilities (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016 USD ($) contract	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) contract	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($) contract
Derivative assets and liabilities
Asset Derivatives Fair Value	$ 82		$ 82		$ 280
Liability Derivatives Fair Value	(344)		(344)		(110)
Broker receivable	142		142
Initial margin	96		96		91
Variation margin posted/(returned)	46		46		(247)
Broker payable					$ 156
Net loss deferred in AOCI	374		374
Net loss expected to be reclassified to earnings in the next twelve months			7
Remaining loss expected to be reclassified to earnings through 2049			367
Net deferred gain/(loss) recognized in AOCI on derivatives	$ (20)	$ (48)	$ (178)	$ (28)
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		37		12
Interest Rate Derivatives
Derivative assets and liabilities
Net deferred gain/(loss) recognized in AOCI on derivatives	$ (20)	$ (85)	$ (178)	$ (40)
Derivatives in Hedging Relationships
Derivative assets and liabilities
Asset Derivatives Fair Value	1		1		$ 5
Liability Derivatives Fair Value	(175)		(175)		(52)
Derivatives in Hedging Relationships \| Commodity Derivatives \| Other current assets
Derivative assets and liabilities
Asset Derivatives Fair Value	1		1		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	(72)		(72)		(17)
Derivatives in Hedging Relationships \| Interest Rate Derivatives \| Other long-term liabilities and deferred credits
Derivative assets and liabilities
Liability Derivatives Fair Value	(103)		(103)		(33)
Derivatives Not Designated as a Hedge
Derivative assets and liabilities
Asset Derivatives Fair Value	81		81		275
Liability Derivatives Fair Value	(169)		(169)		(58)
Derivatives Not Designated as a Hedge \| Commodity Derivatives \| Other current assets
Derivative assets and liabilities
Asset Derivatives Fair Value	77		77		265
Liability Derivatives Fair Value	(119)		(119)		(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	(10)		(10)		(13)
Derivatives Not Designated as a Hedge \| Commodity Derivatives \| Other long-term liabilities and deferred credits
Derivative assets and liabilities
Asset Derivatives Fair Value	3		3
Liability Derivatives Fair Value	(18)		(18)		(1)
Derivatives Not Designated as a Hedge \| Foreign Currency Derivatives \| Other current liabilities
Derivative assets and liabilities
Asset Derivatives Fair Value	1		1
Liability Derivatives Fair Value	(4)		(4)		$ (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	$ (18)		$ (18)

Derivatives and Risk Management Activities - Offsetting (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Derivative Asset Positions
Gross Position - Asset	$ 82	$ 280
Netting adjustment	(123)	(38)
Cash collateral paid	142
Cash collateral received		(156)
Net Position - Asset	101	86
Derivative Liability Positions
Gross Position - Liability	(344)	(110)
Netting adjustment	123	38
Net Position - Liability	(221)	(72)
Other current assets
Derivative Asset Positions
Net Position - Asset	101	76
Other long-term assets, net
Derivative Asset Positions
Net Position - Asset		10
Other current liabilities
Derivative Liability Positions
Net Position - Liability	(85)	(38)
Other long-term liabilities and deferred credits
Derivative Liability Positions
Net Position - Liability	$ (136)	$ (34)

Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Level 3
Rollforward of Level 3 Net Asset/(Liability)
Beginning Balance	$ (35)	$ 9	$ 11	$ 15
Gains for the period included in earnings	17	2	41	1
Settlements		(2)	(10)	(13)
Derivatives entered into during the period	1	2	(59)	8
Ending Balance	(17)	11	(17)	11
Change in unrealized gains included in earnings relating to Level 3 derivatives still held at the end of the period	18	$ 4	43	$ 9
Recurring Fair Value Measures
Recurring Fair Value Measurements
Net derivative asset/(liability)	(262)		(262)		$ 170
Recurring Fair Value Measures \| Commodity Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(66)		(66)		227
Recurring Fair Value Measures \| Interest Rate Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(175)		(175)		(49)
Recurring Fair Value Measures \| Foreign Currency Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(3)		(3)		(8)
Recurring Fair Value Measures \| Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Net derivative asset/(liability)	(18)		(18)
Recurring Fair Value Measures \| Level 1
Recurring Fair Value Measurements
Net derivative asset/(liability)	(27)		(27)		126
Recurring Fair Value Measures \| Level 1 \| Commodity Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(27)		(27)		126
Recurring Fair Value Measures \| Level 2
Recurring Fair Value Measurements
Net derivative asset/(liability)	(218)		(218)		33
Recurring Fair Value Measures \| Level 2 \| Commodity Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(40)		(40)		90
Recurring Fair Value Measures \| Level 2 \| Interest Rate Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(175)		(175)		(49)
Recurring Fair Value Measures \| Level 2 \| Foreign Currency Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	(3)		(3)		(8)
Recurring Fair Value Measures \| Level 3
Recurring Fair Value Measurements
Net derivative asset/(liability)	(17)		(17)		11
Recurring Fair Value Measures \| Level 3 \| Commodity Derivatives
Recurring Fair Value Measurements
Net derivative asset/(liability)	1		1		$ 11
Recurring Fair Value Measures \| Level 3 \| Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Net derivative asset/(liability)	$ (18)		$ (18)

Related Party Transactions (Details) - Oxy - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Related Party Transactions
Related party ownership of general partner interest (as a percent)	12.00%		12.00%
Revenues	$ 171	$ 187	$ 424	$ 745
Purchases and related costs	4	$ (34)	(46)	$ 112
Trade accounts receivable and other receivables	610		610		$ 405
Accounts payable	$ 587		$ 587		$ 363

Equity-Indexed Compensation Plan - Modifications (Details) shares in Millions	3 Months Ended
	Sep. 30, 2016 $ / shares shares
PAA LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Modification of Awards \| shares	2.2
Quarterly performance thresholds modified (usd per share)	$ 0.70
Granted \| shares	1.7
Weighted Average Grant Date Fair Value (usd per unit)	$ 22.85
AAP Management Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Modification of Awards \| shares	2.2
AAP Management Units \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance conditions, annual distribution performance (usd per unit)	$ 2.20
AAP Management Units \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance conditions, annual distribution performance (usd per unit)	$ 2.40

Commitments and Contingencies (Details)					1 Months Ended	15 Months Ended	17 Months Ended
Commitments and Contingencies (Details)	May 16, 2016 item employee	Jan. 06, 2016 USD ($) item	Jul. 10, 2015 bbl	Jan. 01, 2015 bbl	May 31, 2015 bbl	Sep. 30, 2016 USD ($) lawsuit	Sep. 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						57,000,000	57,000,000	81,000,000
Estimated undiscounted reserve for environmental liabilities, long-term						103,000,000	103,000,000	104,000,000
Amounts probable of recovery under insurance and from third parties under indemnification agreements						79,000,000	79,000,000	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						57,000,000	57,000,000	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
Estimated undiscounted reserve for environmental liabilities						87,000,000	87,000,000
Amounts probable of recovery under insurance and from third parties under indemnification agreements						68,000,000	68,000,000
Aggregate total estimated costs						280,000,000	280,000,000
Recoveries from insurance carriers							129,000,000
Total release costs probable of recovery						197,000,000	197,000,000
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						48,000,000	48,000,000
Line 901 Incident \| Accounts payable and accrued liabilities
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities, short-term						47,000,000	$ 47,000,000
Line 901 Incident \| Maximum
Legal, Environmental or Regulatory Matters
Estimated size of release \| bbl					2,935
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							6
Line 901 Incident \| Securities Law Class Action Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed during the period \| lawsuit							2
Line 901 Incident \| Unitholder Derivative Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed during the period \| lawsuit							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
MP 29 Release
Legal, Environmental or Regulatory Matters
Estimated size of release \| 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 \| 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		9 Months Ended
	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) segment	Sep. 30, 2015 USD ($)
Operating Segments
Operating segments number \| segment			3
Revenues:
Revenues	$ 5,170	$ 5,551	$ 14,231	$ 18,156
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	46	45	133	134
Segment profit/(loss)	428	487	1,261	1,371
Maintenance capital	47	52	128	154
Transportation
Revenues:
Revenues	159	172	482	538
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	46	45	133	134
Segment profit/(loss)	261	254	760	681
Maintenance capital	29	34	86	101
Facilities
Revenues:
Revenues	135	132	405	393
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment profit/(loss)	173	146	488	432
Maintenance capital	15	16	32	48
Supply and Logistics
Revenues:
Revenues	4,876	5,247	13,344	17,225
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment profit/(loss)	(6)	87	13	258
Maintenance capital	3	2	10	5
Interest expense related to hedged inventory purchases	5	1	10	4
Operating Segments
Revenues:
Revenues	5,562	5,918	15,358	19,230
Operating Segments \| Transportation
Revenues:
Revenues	401	401	1,188	1,203
Operating Segments \| Facilities
Revenues:
Revenues	282	263	817	789
Operating Segments \| Supply and Logistics
Revenues:
Revenues	4,879	5,254	13,353	17,238
Intersegment
Revenues:
Revenues	392	367	1,127	1,074
Intersegment \| Transportation
Revenues:
Revenues	242	229	706	665
Intersegment \| Facilities
Revenues:
Revenues	147	131	412	396
Intersegment \| Supply and Logistics
Revenues:
Revenues	$ 3	$ 7	$ 9	$ 13

Operating Segments - Reconciliation of Segment Profit (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Reconciliation of segment profit to net income attributable to PAA
Segment profit	$ 428	$ 487	$ 1,261	$ 1,371
Depreciation and amortization	(33)	(107)	(351)	(319)
Interest expense, net	(113)	(109)	(339)	(320)
Other income/(expense), net	17	(4)	46	(7)
INCOME BEFORE TAX	299	267	617	725
Income tax expense	(1)	(17)	(15)	(66)
NET INCOME	298	250	602	659
Net income attributable to noncontrolling interests	(1)	(1)	(3)	(2)
NET INCOME ATTRIBUTABLE TO PAA	$ 297	$ 249	$ 599	$ 657

Acquisitions, Investments in Unconsolidated Entities, Dispositions and Impairments - Acquisitions (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($) acquisition
Acquisitions
Number of acquisitions completed \| acquisition	2
Cash consideration	$ 289
Integrated system of NGL assets
Acquisitions
Cash consideration	$ 204

Acquisitions, Investments in Unconsolidated Entities, Dispositions and Impairments - Dispositions and Divestitures (Details) - USD ($) $ in Millions	1 Months Ended		9 Months Ended
	Aug. 31, 2016	Jun. 30, 2016	Sep. 30, 2016
Disposed of by sale \| Depreciation and amortization
Dispositions
Recognized gains/(losses) related to sale of assets, net			$ 99
Recognized gains related to sale of assets			155
Recognized losses related to sales of assets			56
Disposed of by sale \| Cheyenne Pipeline LLC
Dispositions
Percentage of investment sold		50.00%
Disposed of by sale \| STACK Pipeline LLC [Member]
Dispositions
Percentage of investment sold	50.00%
Held for sale \| Other current assets
Dispositions
Assets classified as held for sale			275
Held for sale \| Goodwill \| Depreciation and amortization
Dispositions
Impairment losses			$ 15

Acquisitions, Investments in Unconsolidated Entities, 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 - Agreement Terms (Details) $ / shares in Units, shares in Millions, $ in Millions				9 Months Ended
	Nov. 15, 2016 USD ($) shares	Nov. 14, 2016 USD ($) $ / shares	Aug. 12, 2016 $ / shares	Sep. 30, 2016 USD ($)	Jul. 11, 2016 director	Dec. 31, 2015 USD ($)
Simplification Transactions
Other long-term debt				$ 504		$ 677
Indirect Ownership \| AAP
Simplification Transactions
General partner ownership interest				2.00%
Common Units \| Cash Distributions \| Second Quarter Distribution
Simplification Transactions
Distributions per common unit, paid \| $ / shares			$ 0.70
PAGP \| AAP
Simplification Transactions
Threshold of private general partner ownership below which shareholders are eligible to participate in general partner Board of Director elections (as a percent)				40.00%
PAA GP
Simplification Transactions
General partner ownership interest				2.00%
Simplification Agreement \| Exchange of AAP Class A Units and PAGP Class B Shares for PAGP Class A Shares
Simplification Transactions
Ratio for conversion or exchange of units					1
Simplification Agreement \| AAP \| GP Holdings \| Original Designating Parties
Simplification Transactions
Number of directors interest holder may designate to related party Board of Directors \| director					1
Simplification Agreement \| AAP \| GP Holdings \| Original Designating Parties \| Minimum
Simplification Transactions
Threshold ownership for interest holder to nominate a director to the related party Board of Directors (as a percent)					10.00%
Forecast \| Common Units \| Cash Distributions \| Third Quarter Distribution
Simplification Transactions
Distributions per common unit, paid \| $ / shares		$ 0.55
Quarterly level of distributions per common unit \| $ / shares		$ 0.55
Forecast \| Simplification Agreement \| AAP
Simplification Transactions
Issuance of common units (units) \| shares	245.5
Forecast \| Simplification Agreement \| PAGP \| AAP
Simplification Transactions
Ratio of PAGP Class A shares to underlying PAA Common Units held by AAP	1
Forecast \| Simplification Agreement \| PAA GP
Simplification Transactions
Economic general partner interest converted into non-economic interest	2.00%
AAP senior secured credit agreement \| AAP
Simplification Transactions
Other long-term debt				$ 603
AAP senior secured credit agreement \| Forecast \| Simplification Agreement \| AAP
Simplification Transactions
Assumption of outstanding debt	$ 641
AAP senior secured credit agreement \| Forecast \| Simplification Agreement \| Third Quarter Distribution \| AAP
Simplification Transactions
Estimated related party borrowings for true-up distribution if transactions not closed		$ 33

Simplification Transactions - Pro Forma (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014
Pro forma results of operations
Net income attributable to PAA	$ 297	$ 249	$ 599	$ 657
LONG-TERM LIABILITIES
Other long-term debt, net of unamortized debt issuance costs	504		504		$ 677
PARTNERS’ CAPITAL
General partner	268		268		301
Total partners’ capital	$ 9,074	$ 8,216	$ 9,074	$ 8,216	7,939	$ 8,191
Common Units
Pro forma results of operations
Basic net income per common unit (usd per unit)	$ 0.40	$ 0.25	$ 0.27	$ 0.54
Diluted net income per common unit (usd per unit)	$ 0.40	$ 0.24	$ 0.27	$ 0.53
PARTNERS’ CAPITAL
Unitholders	$ 7,240		$ 7,240		$ 7,580
Simplification Agreement \| Pro Forma Results
Pro forma results of operations
Net income attributable to PAA	294		589
LONG-TERM LIABILITIES
Other long-term debt, net of unamortized debt issuance costs	1,114		1,114
PARTNERS’ CAPITAL
Total partners’ capital	$ 8,464		$ 8,464
Simplification Agreement \| Pro Forma Results \| Common Units
Pro forma results of operations
Basic net income per common unit (usd per unit)	$ 0.40		$ 0.77
Diluted net income per common unit (usd per unit)	$ 0.40		$ 0.77
PARTNERS’ CAPITAL
Unitholders	$ 6,898		$ 6,898