Plains All American Pipeline (PAA) 10-Q 8 May 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015	1-May-15
Document and Entity Information
Entity Registrant Name	PLAINS ALL AMERICAN PIPELINE LP
Entity Central Index Key	1070423
Document Type	10-Q
Document Period End Date	31-Mar-15
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		397,241,697
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1

CONDENSED_CONSOLIDATED_BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
CURRENT ASSETS
Cash and cash equivalents	$458	$403
Trade accounts receivable and other receivables, net	1,817	2,615
Inventory	929	891
Other current assets	249	270
Total current assets	3,453	4,179
PROPERTY AND EQUIPMENT	14,436	14,178
Accumulated depreciation	-1,952	-1,906
Property and equipment, net	12,484	12,272
OTHER ASSETS
Goodwill	2,435	2,465
Investments in unconsolidated entities	1,784	1,735
Linefill and base gas	960	930
Long-term inventory	149	186
Other long-term assets, net	459	489
Total assets	21,724	22,256
CURRENT LIABILITIES
Accounts payable and accrued liabilities	2,491	2,986
Short-term debt	553	1,287
Other current liabilities	487	482
Total current liabilities	3,531	4,755
LONG-TERM LIABILITIES
Senior notes, net of unamortized discount of $17 and $18, respectively	8,758	8,757
Other long-term debt	5	5
Other long-term liabilities and deferred credits	594	548
Total long-term liabilities	9,357	9,310
COMMITMENTS AND CONTINGENCIES (NOTE 10)
PARTNERS' CAPITAL
Common unitholders (397,241,697 and 375,107,793 units outstanding, respectively)	8,413	7,793
General partner	365	340
Total partners' capital excluding noncontrolling interests	8,778	8,133
Noncontrolling interests	58	58
Total partners' capital	8,836	8,191
Total liabilities and partners' capital	$21,724	$22,256

CONDENSED_CONSOLIDATED_BALANCE1

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, except Share data, unless otherwise specified
CONDENSED CONSOLIDATED BALANCE SHEETS
Senior notes, unamortized discount	$17	$18
Common unitholders, units outstanding (in units)	397,241,697	375,107,793

CONDENSED_CONSOLIDATED_STATEME

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
REVENUES
Supply and Logistics segment revenues	$5,632	$11,346
Transportation segment revenues	185	181
Facilities segment revenues	125	157
Total revenues	5,942	11,684
COSTS AND EXPENSES
Purchases and related costs	5,042	10,670
Field operating costs	346	336
General and administrative expenses	78	89
Depreciation and amortization	107	96
Total costs and expenses	5,573	11,191
OPERATING INCOME	369	493
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	37	20
Interest expense (net of capitalized interest of $14 and $11, respectively)	-102	-78
Other expense, net	-4	-2
INCOME BEFORE TAX	300	433
Current income tax expense	-42	-36
Deferred income tax benefit/(expense)	26	-12
NET INCOME	284	385
Net income attributable to noncontrolling interests	-1	-1
NET INCOME ATTRIBUTABLE TO PAA	283	384
NET INCOME ATTRIBUTABLE TO PAA:
LIMITED PARTNERS	138	268
GENERAL PARTNER	$145	$116
BASIC NET INCOME PER LIMITED PARTNER UNIT	$0.36	$0.74
DILUTED NET INCOME PER LIMITED PARTNER UNIT	$0.35	$0.73
BASIC WEIGHTED AVERAGE LIMITED PARTNER UNITS OUTSTANDING	383	360
DILUTED WEIGHTED AVERAGE LIMITED PARTNER UNITS OUTSTANDING	385	363

CONDENSED_CONSOLIDATED_STATEME1

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Interest expense, Capitalized interest	$14	$11

CONDENSED_CONSOLIDATED_STATEME2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)
Net income	$284	$385
Other comprehensive loss	-376	-136
Comprehensive income/(loss)	-92	249
Comprehensive income attributable to noncontrolling interests	-1	-1
Comprehensive income/(loss) attributable to PAA	($93)	$248

CONDENSED_CONSOLIDATED_STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME / (LOSS) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period	($467)	($97)
Reclassification adjustments	-6	20
Deferred loss on cash flow hedges, net of tax	-72	-32
Currency translation adjustments	-298	-124
Total period activity	-376	-136
Balance at end of period	-843	-233
Derivative Instruments
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period	-159	-77
Reclassification adjustments	-6	20
Deferred loss on cash flow hedges, net of tax	-72	-32
Total period activity	-78	-12
Balance at end of period	-237	-89
Translation Adjustments
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period	-308	-20
Currency translation adjustments	-298	-124
Total period activity	-298	-124
Balance at end of period	($606)	($144)

CONDENSED_CONSOLIDATED_STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$284	$385
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	107	96
Equity-indexed compensation expense	19	34
Inventory valuation adjustments	24	37
Deferred income tax (benefit)/expense	-26	12
(Gain)/loss on foreign currency revaluation	-27	5
Equity earnings in unconsolidated entities	-37	-20
Distributions from unconsolidated entities	54	25
Other	-9	-6
Changes in assets and liabilities, net of acquisitions	343	254
Net cash provided by operating activities	732	822
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	-64
Additions to property, equipment and other	-441	-468
Investment in unconsolidated entities	-65	-26
Cash received for sales of linefill and base gas		11
Cash paid for purchases of linefill and base gas	-96	-44
Proceeds from sales of assets	1	2
Other investing activities	-1	1
Net cash used in investing activities	-666	-524
CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments under commercial paper program (Note 6)	-734	-128
Net proceeds from the issuance of common units (Note 7)	1,099	148
Contributions from general partner	22	3
Distributions paid to common unitholders (Note 7)	-254	-221
Distributions paid to general partner (Note 7)	-136	-107
Distributions paid to noncontrolling interests	-1	-1
Other financing activities	-2	-1
Net cash used in financing activities	-6	-307
Effect of translation adjustment on cash	-5	-2
Net increase/(decrease) in cash and cash equivalents	55	-11
Cash and cash equivalents, beginning of period	403	41
Cash and cash equivalents, end of period	458	30
Cash paid for:
Interest, net of amounts capitalized	74	78
Income taxes, net of amounts refunded	$11	$66

CONDENSED_CONSOLIDATED_STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL (USD $)	Common Units	General Partner	Partners' Capital Excluding Noncontrolling Interests	Noncontrolling Interests	Total
In Millions, except Share data, unless otherwise specified
Balance, beginning of period at Dec. 31, 2013	$7,349	$295	$7,644	$59	$7,703
Balance, beginning of period (in units) at Dec. 31, 2013	359,100,000
Increase (Decrease) in Partners' Capital
Net income	268	116	384	1	385
Distributions	-221	-107	-328	-1	-329
Issuance of common units	148	3	151		151
Issuance of common units (in units)	2,800,000
Issuance of common units under LTIP, net of units tendered by employees to satisfy tax withholding obligations	-2		-2		-2
Issuance of common units under LTIP, net of units tendered by employees to satisfy tax withholding obligations (in units)	100,000
Equity-indexed compensation expense	11	1	12		12
Distribution equivalent right payments	-1		-1		-1
Other comprehensive loss	-133	-3	-136		-136
Balance, end of period at Mar. 31, 2014	7,419	305	7,724	59	7,783
Balance, end of period (in units) at Mar. 31, 2014	362,000,000
Balance, beginning of period at Dec. 31, 2014	7,793	340	8,133	58	8,191
Balance, beginning of period (in units) at Dec. 31, 2014	375,100,000				375,107,793
Increase (Decrease) in Partners' Capital
Net income	138	145	283	1	284
Distributions	-254	-136	-390	-1	-391
Issuance of common units	1,099	22	1,121		1,121
Issuance of common units (in units)	22,100,000
Equity-indexed compensation expense	8	1	9		9
Distribution equivalent right payments	-2		-2		-2
Other comprehensive loss	-369	-7	-376		-376
Balance, end of period at Mar. 31, 2015	$8,413	$365	$8,778	$58	$8,836
Balance, end of period (in units) at Mar. 31, 2015	397,200,000				397,241,697

Organization_and_Basis_of_Cons

Organization and Basis of Consolidation and Presentation	3 Months Ended
	Mar. 31, 2015
Organization and Basis of Consolidation and Presentation
Organization and Basis of Consolidation and Presentation
	Note 1—Organization and Basis of Consolidation and Presentation
	Organization
	Plains All American Pipeline, L.P. 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,” “Plains,” “PAA,” “we,” “us,” “our,” “ours” and similar terms refer to Plains All American Pipeline, L.P. 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 11 for further discussion of our operating segments.
	Our 2% general partner interest is held by PAA GP LLC, 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 LLC, 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 March 31, 2015, owned an approximate 37% limited partner interest in AAP.
	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 LLC, AAP and GP LLC.
	Definitions
	Additional defined terms are used in this Form 10-Q and shall have the meanings indicated below:
	AOCI	=font>	Accumulated other comprehensive income / (loss)
	Bcf	=font>	Billion cubic feet
	Btu	=font>	British thermal unit
	CAD	=font>	Canadian dollar
	DERs	=font>	Distribution equivalent rights
	EPA	=font>	United States Environmental Protection Agency
	FASB	=font>	Financial Accounting Standards Board
	GAAP	=font>	Generally accepted accounting principles in the United States
	ICE	=font>	Intercontinental Exchange
	LIBOR	=font>	London Interbank Offered Rate
	LTIP	=font>	Long-term incentive plan
	Mcf	=font>	Thousand cubic feet
	MLP	=font>	Master limited partnership
	NGL	=font>	Natural gas liquids, including ethane, propane and butane
	NYMEX	=font>	New York Mercantile Exchange
	Oxy	=font>	Occidental Petroleum Corporation or its subsidiaries
	PLA	=font>	Pipeline loss allowance
	USD	=font>	United States dollar
	WTI	=font>	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 2014 Annual Report on Form 10-K. The accompanying 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. These reclassifications do not affect net income attributable to PAA. The condensed consolidated balance sheet data as of December 31, 2014 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three months ended March 31, 2015 should not be taken as indicative of results to be expected for the entire year.
	Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable.

Recent_Accounting_Pronouncemen

Recent Accounting Pronouncements	3 Months Ended
	Mar. 31, 2015
Recent Accounting Pronouncements
Recent Accounting Pronouncements
	Note 2—Recent Accounting Pronouncements
	In April 2015, the FASB issued guidance to simplify the presentation of debt issuance costs in entities’ financial statements. Under this revised guidance, an entity will present such costs as a direct reduction from the related debt liability (rather than as an asset under current guidance). Additionally, amortization of the debt issuance costs will be reported as interest expense. This guidance will become effective for interim and annual periods beginning after December 15, 2015 and will be adopted retrospectively to all prior periods. Early adoption is permitted for financial statements that have not been previously issued. We expect to adopt this guidance on January 1, 2016, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows.
	In February 2015, the FASB issued guidance that revises the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. All legal entities are subject to reevaluation under the revised consolidation model. Among other things, this guidance (i) modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (ii) eliminates the presumption that a general partner should consolidate a limited partnership and (iii) affects the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships. This guidance will become effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. We expect to adopt this guidance on January 1, 2016, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows.
	In January 2015, as part of its initiative to reduce complexity in accounting standards, the FASB issued guidance to eliminate the concept of extraordinary items from GAAP. This guidance will become effective for interim and annual periods beginning after December 15, 2015. We expect to adopt this guidance on January 1, 2016. We do not believe our adoption will have a material impact on our financial position, results of operations or cash flows.
	In May 2014, the FASB issued guidance regarding the recognition of revenue from contracts with customers with the underlying principle that an entity will recognize revenue to reflect amounts expected to be received in exchange for the provision of goods and services to customers upon the transfer of those goods or services. The guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. This guidance becomes effective for interim and annual periods beginning after December 15, 2016 and can be adopted either with a full retrospective approach or a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. We currently expect to adopt this guidance on January 1, 2017, and we are evaluating which transition approach to apply and the effect that adopting this guidance will have on our financial position, results of operations and cash flows. In April 2015, the FASB proposed a one year deferral of the effective date of this standard.
	In April 2014, the FASB issued guidance that modifies the criteria under which assets to be disposed of are evaluated to determine if such assets qualify as a discontinued operation and requires new disclosures for both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. This guidance is effective prospectively for annual and interim reporting periods beginning after December 15, 2014. We adopted this guidance on January 1, 2015. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

Net_Income_Per_Limited_Partner

Net Income Per Limited Partner Unit	3 Months Ended
	Mar. 31, 2015
Net Income Per Limited Partner Unit
Net Income Per Limited Partner Unit
	Note 3—Net Income Per Limited Partner Unit
	Basic and diluted net income per limited partner 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, common unitholders 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 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 limited partner unit by dividing net income attributable to PAA (after deducting the amount allocated to the general partner’s interest, IDRs and participating securities) by the basic and diluted weighted-average number of limited partner 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 limited partner unit is computed based on the weighted average number of limited partner units plus the effect of dilutive potential limited partner units outstanding during the period using the two-class method.  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 limited partner unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.  See Note 16 to our Consolidated Financial Statements included in Part IV of our 2014 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 limited partner unit for the three months ended March 31, 2015 and 2014 (in millions, except per unit data):
			Three Months Ended
			March 31,
			2015			2014
	Basic Net Income per Limited Partner Unit
	Net income attributable to PAA		$	283		$	384
	Less: General partner’s incentive distribution (1)		(142		)	(110		)
	Less: General partner 2% ownership (1)		(3		)	(6		)
	Net income available to limited partners		138			268
	Less: Undistributed earnings allocated and distributions to participating securities (1)		(2		)	(2		)
	Net income available to limited partners in accordance with application of the two-class method for MLPs		$	136		$	266
	Basic weighted average limited partner units outstanding		383			360
	Basic net income per limited partner unit		$	0.36		$	0.74
	Diluted Net Income per Limited Partner Unit
	Net income attributable to PAA		$	283		$	384
	Less: General partner’s incentive distribution (1)		(142		)	(110		)
	Less: General partner 2% ownership (1)		(3		)	(6		)
	Net income available to limited partners		138			268
	Less: Undistributed earnings allocated and distributions to participating securities (1)		(2		)	(2		)
	Net income available to limited partners in accordance with application of the two-class method for MLPs		$	136		$	266
	Basic weighted average limited partner units outstanding		383			360
	Effect of dilutive securities: Weighted average LTIP units		2			3
	Diluted weighted average limited partner units outstanding		385			363
	Diluted net income per limited partner unit		$	0.35		$	0.73
		-1		We calculate net income available to limited partners 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, limited partners and participating securities in accordance with the contractual terms of the 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 the 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 limited partner unit.  If, however, undistributed earnings were allocated to our IDRs beyond amounts distributed to them under the terms of the partnership agreement, basic and diluted net income per limited partner unit as reflected in the table above would be impacted as follows:
			Three Months Ended
			March 31,
			2015			2014
	Basic net income per limited partner unit impact		$	—		$	(0.05	)
	Diluted net income per limited partner unit impact		$	—		$	(0.05	)

Accounts_Receivable

Accounts Receivable	3 Months Ended
	Mar. 31, 2015
Accounts Receivable
Accounts Receivable
	Note 4—Accounts Receivable
	Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas storage. These purchasers include, but are not limited to, refiners, producers, marketing and trading companies and financial institutions that are active in the physical and financial commodity markets. The majority of our accounts receivable relate to our crude oil supply and logistics activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes.
	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 March 31, 2015 and December 31, 2014, we had received $130 million and $180 million, respectively, of advance cash payments from third parties to mitigate credit risk. Furthermore, as of March 31, 2015 and December 31, 2014, we had received $12 million and $198 million, respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. The decrease in standby letters of credit and advance cash payments from third parties as of March 31, 2015 compared to December 31, 2014 is largely due to a decrease in exposure to various customers requiring letters of credit.  Furthermore, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Further, we 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 March 31, 2015 and December 31, 2014, substantially all of our accounts receivable (net of allowance for doubtful accounts) were less than 30 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled $4 million as of both March 31, 2015 and December 31, 2014. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

Inventory_Linefill_and_Base_Ga

Inventory, Linefill and Base Gas and Long-term Inventory	3 Months Ended
	Mar. 31, 2015
Inventory, Linefill and Base Gas and Long-term Inventory
Inventory, Linefill and Base Gas and Long-term Inventory
	Note 5—Inventory, Linefill and Base Gas and Long-term Inventory
	Inventory, linefill and base gas and long-term inventory consisted of the following as of the dates indicated (barrels and natural gas volumes in thousands and carrying value in millions):
			March 31, 2015							December 31, 2014
			Volumes		Unit of	Carrying		Price/		Volumes	Unit of	Carrying		Price/
					Measure	Value		Unit (1)			Measure	Value		Unit (1)
	Inventory
	Crude oil		15,351		barrels	$	686	$	44.69	6,465	barrels	$	304	$	47.02
	NGL		7,277		barrels	154		$	21.16	13,553	barrels	454		$	33.50
	Natural gas		10,965		Mcf	31		$	2.83	32,317	Mcf	102		$	3.16
	Other		N/A			58		N/A		N/A		31		N/A
	Inventory subtotal					929						891
	Linefill and base gas
	Crude oil		12,970		barrels	777		$	59.91	11,810	barrels	744		$	63.00
	NGL		1,215		barrels	48		$	39.51	1,212	barrels	52		$	42.90
	Natural gas		28,612		Mcf	135		$	4.72	28,612	Mcf	134		$	4.68
	Linefill and base gas subtotal					960						930
	Long-term inventory
	Crude oil		2,646		barrels	117		$	44.22	2,582	barrels	136		$	52.67
	NGL		1,681		barrels	32		$	19.04	1,681	barrels	50		$	29.74
	Long-term inventory subtotal					149						186
	Total					$	2,038					$	2,007
		-1		Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products.
	At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Condensed Consolidated Statements of Operations. We recorded a charge of $24 million during the three months ended March 31, 2015 primarily related to the writedown of our NGL inventory due to declines in prices. The loss was substantially offset by a portion of the derivative mark-to-market gain that was recognized in the fourth quarter of 2014 for which the related derivatives were still open as of March 31, 2015. See Note 8 for discussion of our derivative and risk management activities. During the three months ended March 31, 2014, we recorded a charge of $37 million related to the writedown of our natural gas inventory that was purchased in conjunction with managing natural gas storage deliverability requirements during the extended period of severe cold weather in the first quarter of 2014.

Debt

Debt	3 Months Ended
	Mar. 31, 2015
Debt
Debt
	Note 6—Debt
	Debt consisted of the following as of the dates indicated (in millions):
			March 31,		December 31,
			2015		2014
	SHORT-TERM DEBT
	Commercial paper notes, bearing a weighted-average interest rate of 0.46% at December 31, 2014 (1)		$	—	$	734
	Senior notes:
	5.25% senior notes due June 2015		150		150
	3.95% senior notes due September 2015		400		400
	Other		3		3
	Total short-term debt		553		1,287
	LONG-TERM DEBT
	Senior notes, net of unamortized discount of $17 and $18, respectively		8,758		8,757
	Other		5		5
	Total long-term debt		8,763		8,762
	Total debt (2)		$	9,316	$	10,049
		-1		At December 31, 2014, we classified all of the borrowings under our commercial paper program as short-term as these borrowings were primarily designated as working capital borrowings, must be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.
		-2		Our fixed-rate senior notes (including current maturities) had a face value of approximately $9.3 billion as of both March 31, 2015 and December 31, 2014. We estimated the aggregate fair value of these notes as of March 31, 2015 and December 31, 2014 to be approximately $10.0 billion and $9.9 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 quarter end. 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
	PAA senior unsecured 364-day revolving credit facility. In January 2015, we entered into a 364-day senior unsecured credit agreement with a borrowing capacity of $1.0 billion. Borrowings will accrue interest based, at our election, on either the Eurocurrency Rate or the Base Rate, as defined in the agreement, in each case plus a margin based on our credit rating at the applicable time.
	Borrowings and Repayments
	Total borrowings under our credit agreements and commercial paper program for the three months ended March 31, 2015 and 2014 were approximately $7.0 billion and $19.2 billion, respectively. Total repayments under our credit agreements and commercial paper program were approximately $7.7 billion and $19.3 billion for the three months ended March 31, 2015 and 2014, 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 and construction activities. At March 31, 2015 and December 31, 2014, we had outstanding letters of credit of $83 million and $87 million, respectively.

Partners_Capital_and_Distribut

Partners' Capital and Distributions	3 Months Ended
	Mar. 31, 2015
Partners' Capital and Distributions
Partners' Capital and Distributions
	Note 7—Partners’ Capital and Distributions
	Distributions
	The following table details the distributions paid during or pertaining to the first three months of 2015, net of reductions to the general partner’s incentive distributions (in millions, except per unit data):
					Distributions Paid								Distributions
					Limited		General Partner						per limited
	Date Declared		Distribution Date		Partners		2%		Incentive		Total		partner unit
	April 7, 2015		May 15, 2015(1)		$	272	$	6	$	142	$	420	$	0.6850
	January 8, 2015		February 13, 2015		$	254	$	5	$	131	$	390	$	0.6750
		-1		Payable to unitholders of record at the close of business on May 1, 2015 for the period January 1, 2015 through March 31, 2015.
	PAA Equity Offerings
	Continuous Offering Program. During the three months ended March 31, 2015, we issued an aggregate of approximately 1.1 million common units under our continuous offering program, generating proceeds of $59 million, including our general partner’s proportionate capital contribution of $1 million, net of $1 million of commissions to our sales agents.
	Underwritten Offering. In March 2015, we completed an underwritten public offering of 21.0 million common units, generating proceeds of approximately $1.1 billion, including our general partner’s proportionate capital contribution of $21 million, net of costs associated with the offering.
	Noncontrolling Interests in Subsidiaries
	As of March 31, 2015, noncontrolling interests in our subsidiaries consisted of a 25% interest in SLC Pipeline LLC.

Derivatives_and_Risk_Managemen

Derivatives and Risk Management Activities	3 Months Ended
	Mar. 31, 2015
Derivatives and Risk Management Activities
Derivatives and Risk Management Activities
	Note 8—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 on an ongoing basis, we assess whether the derivatives used in a transaction are highly effective in offsetting changes in cash flows or the fair value of hedged items.
	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 March 31, 2015, net derivative positions related to these activities included:
		·		An average of 233,600 barrels per day net long position (total of 7.0 million barrels) associated with our crude oil purchases, which was unwound ratably during April 2015 to match monthly average pricing.
		·		A net short time spread position averaging 18,200 barrels per day (total of 7.2 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through June 2016.
		·		An average of 37,500 barrels per day (total of 9.1 million barrels) of crude oil grade spread positions through December 2015. These derivatives allow us to lock in grade basis differentials.
		·		A net short position of 6.8 Bcf through April 2016 related to anticipated sales of natural gas inventory and base gas requirements.
		·		A net short position of 16.8 million barrels through March 2017 related to anticipated purchases and sales of our crude oil, NGL and refined products inventory.
	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 March 31, 2015, we had a long natural gas position of 18.1 Bcf through December 2016, a short propane position of 3.5 million barrels through December 2016, a short butane position of 1.0 million barrels through December 2016 and a short WTI position of 0.4 million barrels through December 2016. 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 natural gas processing and fractionation plants through December 2016.
	To the extent they qualify and we decide to make the election, all of our commodity derivatives for which we elect hedge accounting are designated as cash flow hedges. 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 purchase and sale agreements 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 debt issuances and outstanding debt instruments.  The derivative instruments we use to manage this risk consist primarily of interest rate swaps and treasury locks.  As of March 31, 2015, AOCI includes deferred losses of $234 million that relate to open and terminated interest rate derivatives that were designated as cash flow hedges.  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 debt issuances through 2019. The following table summarizes the terms of our forward starting interest rate swaps as of March 31, 2015 (notional amounts in millions):
	Hedged Transaction		Number and Types of		Notional			Expected		Average Rate		Accounting
			Derivatives Employed		Amount			Termination Date		Locked		Treatment
	Anticipated debt offering		10 forward starting swaps (30-year)		$	250		6/15/15		3.60%		Cash flow hedge
	Anticipated debt offering		8 forward starting swaps (30-year)		$	200		6/15/16		3.06%		Cash flow hedge
	Anticipated debt offering		8 forward starting swaps (30-year)		$	200		6/15/17		3.14%		Cash flow hedge
	Anticipated debt offering		8 forward starting swaps (30-year)		$	200		6/15/18		3.20%		Cash flow hedge
	Anticipated debt offering		8 forward starting swaps (30-year)		$	200		6/14/19		2.83%		Cash flow hedge
	Currency Exchange Rate Risk Hedging
	Because a significant portion of our Canadian business is conducted in CAD and, at times, a portion of our debt is denominated in CAD, we use foreign currency derivatives to minimize the risk of unfavorable changes in exchange rates.  These instruments include foreign currency exchange contracts and forwards.
	As of March 31, 2015, our outstanding foreign currency derivatives include derivatives we use to (i) hedge currency exchange risk associated with USD-denominated commodity purchases and sales in Canada and (ii) hedge currency exchange risk created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales.
	The following table summarizes our open forward exchange contracts as of March 31, 2015 (in millions):
					USD			CAD			Average Exchange Rate
											USD to CAD
	Forward exchange contracts that exchange CAD for USD:
			2015		$	147		$	187		$1.00 - $1.27
			2016		5			7			$1.00 - $1.27
					$	152		$	194
	Forward exchange contracts that exchange USD for CAD:
			2015		$	181		$	225		$1.00 - $1.24
			2016		5			7			$1.00 - $1.27
					$	186		$	232
	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 for the three months ended March 31, 2015 and 2014 is as follows (in millions):
			Three Months Ended March 31, 2015										Three Months Ended March 31, 2014
	Location of gain/(loss)		Derivatives in			Derivatives			Total				Derivatives in			Derivatives			Total
			Hedging			Not Designated							Hedging			Not Designated
			Relationships (1)			as a Hedge							Relationships (1)			as a Hedge
	Commodity Derivatives
	Supply and Logistics segment revenues		$	7		$	(34	)	$	(27	)		$	(19	)	$	—		$	(19	)
	Transportation segment revenues		—			2			2				—			—			—
	Field operating costs		—			(4		)	(4		)		—			(1		)	(1		)
	Interest Rate Derivatives
	Interest expense		(1		)	—			(1		)		(1		)	—			(1		)
	Foreign Currency Derivatives
	Supply and Logistics segment revenues		—			(17		)	(17		)		—			(9		)	(9		)
	Total Gain/(Loss) on Derivatives Recognized in Net Income		$	6		$	(53	)	$	(47	)		$	(20	)	$	(10	)	$	(30	)
		-1		Represents gains/(losses) on cash flow hedges reclassified from AOCI to income during the period.
	The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of March 31, 2015 (in millions):
			Asset Derivatives						Liability Derivatives
			Balance Sheet						Balance Sheet
			Location		Fair Value				Location		Fair Value
	Derivatives designated as hedging instruments:
	Commodity derivatives		Other current assets		$	18			Other long-term liabilities and deferred credits		$	(2	)
			Other long-term liabilities and deferred credits		3
	Interest rate derivatives								Other current liabilities		(64		)
									Other long-term liabilities and deferred credits		(80		)
	Total derivatives designated as hedging instruments				$	21					$	(146	)
Derivatives not designated as hedging instruments:
Commodity derivatives		Other current assets		$	205			Other current assets		$	(47	)
		Other long-term assets, net		18				Other current liabilities		(40		)
		Other long-term liabilities and deferred credits		2				Other long-term liabilities and deferred credits		(13		)
Foreign currency derivatives								Other current liabilities		(4		)
Total derivatives not designated as hedging instruments				$	225					$	(104	)
Total derivatives				$	246					$	(250	)
The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of December 31, 2014 (in millions):
		Asset Derivatives						Liability Derivatives
		Balance Sheet		Fair				Balance Sheet		Fair
		Location		Value				Location		Value
Derivatives designated as hedging instruments:
Commodity derivatives		Other current assets		$	23			Other current assets		$	(12	)
		Other long-term assets, net		8				Other long-term assets, net		(1		)
Interest rate derivatives								Other current liabilities		(44		)
								Other long-term liabilities and deferred credits		(26		)
Total derivatives designated as hedging instruments				$	31					$	(83	)
Derivatives not designated as hedging instruments:
Commodity derivatives		Other current assets		$	439			Other current assets		$	(246	)
		Other long-term assets, net		23				Other long-term assets, net		(3		)
								Other current liabilities		(35		)
								Other long-term liabilities and deferred credits		(5		)
Foreign currency derivatives								Other current liabilities		(12		)
Total derivatives not designated as hedging instruments				$	462					$	(301	)
Total derivatives				$	493					$	(384	)
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 our 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 March 31, 2015, we had a net broker payable of $112 million (consisting of initial margin of $61 million reduced by $173 million of variation margin that had been returned to us). As of December 31, 2014, we had a net broker payable of $133 million (consisting of initial margin of $126 million reduced by $259 million of variation margin that had been returned to us).
The following tables present information about derivatives and financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements as of the dates indicated (in millions):
		March 31, 2015							December 31, 2014
		Derivative			Derivative				Derivative			Derivative
		Asset Positions			Liability Positions				Asset Positions			Liability Positions
Netting Adjustments:
Gross position - asset/(liability)		$	246		$	(250	)		$	493		$	(384	)
Netting adjustment		(52		)	52				(262		)	262
Cash collateral paid/(received)		(112		)	—				(133		)	—
Net position - asset/(liability)		$	82		$	(198	)		$	98		$	(122	)
Balance Sheet Location After Netting Adjustments:
Other current assets		$	64		$	—			$	71		$	—
Other long-term assets, net		18			—				27			—
Other current liabilities		—			(108		)		—			(91		)
Other long-term liabilities and deferred credits		—			(90		)		—			(31		)
		$	82		$	(198	)		$	98		$	(122	)
As of March 31, 2015, there was a net loss of $237 million deferred in AOCI including tax effects.  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 March 31, 2015, we expect to reclassify a net gain of $9 million to earnings in the next twelve months.  The remaining deferred loss of $246 million is expected to be reclassified to earnings through 2049. A portion of these amounts are based on market prices as of March 31, 2015; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.
The net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives for the three months ended March 31, 2015 and 2014 was as follows (in millions):
		Three Months Ended
		March 31,
		2015			2014
Commodity derivatives, net		$	3		$	(12	)
Interest rate derivatives, net		(75		)	(20		)
Total		$	(72	)	$	(32	)
At March 31, 2015 and December 31, 2014, 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 as of March 31, 2015 and December 31, 2014 (in millions):
		Fair Value as of March 31, 2015													Fair Value as of December 31, 2014
Recurring Fair Value Measures (1)		Level 1			Level 2			Level 3			Total				Level 1			Level 2			Level 3		Total
Commodity derivatives		$	16		$	123		$	5		$	144			$	(85	)	$	261		$	15	$	191
Interest rate derivatives		—			(144		)	—			(144		)		—			(70		)	—		(70		)
Foreign currency derivatives		—			(4		)	—			(4		)		—			(12		)	—		(12		)
Total net derivative asset/(liability)		$	16		$	(25	)	$	5		$	(4	)		$	(85	)	$	179		$	15	$	109
	-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. 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 Level 3 derivatives. We reported unrealized gains and losses associated with Level 3 commodity derivatives in our Condensed Consolidated Statements of Operations as Supply and Logistics segment revenues.
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 for the three months ended March 31, 2015 and 2014 (in millions):
		Three Months Ended
		March 31,
		2015			2014
Beginning Balance		$	15		$	(3	)
Total gains/(losses) for the period:
Settlements		(12		)	3
Derivatives entered into during the period		2			1
Ending Balance		$	5		$	1
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period		$	2		$	1

EquityIndexed_Compensation_Pla

Equity-Indexed Compensation Plans	3 Months Ended
	Mar. 31, 2015
Equity-Indexed Compensation Plans
Equity-Indexed Compensation Plans
	Note 9—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 16 to our Consolidated Financial Statements included in Part IV of our 2014 Annual Report on Form 10-K.
	PAA LTIP Awards
	Activity for LTIP awards under our equity-indexed compensation plans denominated in PAA units is summarized in the following table (units in millions):
					Weighted Average
					Grant Date
			Units (1)		Fair Value per Unit
	Outstanding at December 31, 2014		7.3		$	41.45
	Granted		1.1		$	39.99
	Vested (2)		—		$	40.23
	Cancelled or forfeited		(0.1	)	$	39.69
	Outstanding at March 31, 2015		8.3		$	41.26
		-1		Amounts do not include AAP Management Units.
		-2		During the three months ended March 31, 2015, less than 0.1 million PAA LTIP awards were settled in cash.
	AAP Management Units
	Activity for AAP Management Units is summarized in the following table (in millions):
			Reserved for		Outstanding		Outstanding	Grant Date
			Future Grants				Units Earned	Fair Value of Outstanding
								AAP Management Units (1)
	Balance at December 31, 2014		3.0		49.1		47.8	$	64
	Earned		N/A		N/A		0.3	N/A
	Balance at March 31, 2015		3.0		49.1		48.1	$	64
		-1		Of the $64 million grant date fair value, $56 million had been recognized through March 31, 2015 on a cumulative basis. Of this amount, $1 million was recognized as expense during the three months ended March 31, 2015.
	Other Consolidated Equity-Indexed Compensation Plan Information
	The table below summarizes the expense recognized and the value of vested LTIP awards (settled both in common units and cash) under our equity-indexed compensation plans and includes both liability-classified and equity-classified awards (in millions):
			Three Months Ended
			March 31,
			2015			2014
	Equity-indexed compensation expense		$	19		$	34
	LTIP unit-settled vestings		$	—		$	5
	LTIP cash-settled vestings (1)		$	—		$	1
	DER cash payments		$	2		$	2
		-1		For the three months ended March 31, 2015, the value of PAA LTIP awards that were settled in cash was less than $1 million.

Commitments_and_Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2015
Commitments and Contingencies.
Commitments and Contingencies
	Note 10—Commitments and Contingencies
	Litigation
	In the ordinary course of business, we are involved in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, 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 the estimated amount.  We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.  Although we believe that our operations are presently in material compliance with applicable requirements, as we acquire and incorporate additional assets it is possible that the EPA or other governmental entities may seek to impose fines, penalties or performance obligations on us (or on a portion of our operations) as a result of any past noncompliance whether such noncompliance initially developed before or after our acquisition.
	Environmental
	General.  Although we believe that our efforts to enhance our leak prevention and detection capabilities have produced positive results, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail and storage operations. These releases can result from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. Whether current or past, damages and liabilities associated with any such releases from our assets may substantially affect our business.
	At March 31, 2015, our estimated undiscounted reserve for environmental liabilities totaled $75 million, of which $11 million was classified as short-term and $64 million was classified as long-term. At December 31, 2014, our estimated undiscounted reserve for environmental liabilities totaled $82 million, of which $13 million was classified as short-term and $69 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 March 31, 2015 and December 31, 2014, we had recorded receivables totaling $7 million and $8 million, respectively, for amounts probable of recovery under insurance and from third parties under indemnification agreements, which are predominantly reflected in “Trade accounts receivable and other receivables, net” on our Condensed Consolidated Balance Sheets.
	In some cases, the actual cash expenditures may not occur for three years or longer. Our estimates used in 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 legal claims giving rise to additional liabilities. Therefore, although we believe that the reserve is adequate, costs incurred may be in excess of the reserve and may potentially have a material adverse effect on our financial condition, results of operations or cash flows.
	Bay Springs Pipeline Release.  During February 2013, we experienced a crude oil release of approximately 120 barrels on a portion of one of our pipelines near Bay Springs, Mississippi. Most of the released crude oil was contained within our pipeline right of way, but some of the released crude oil entered a nearby waterway where it was contained with booms.  The EPA has issued an administrative order requiring us to take various actions in response to the release, including remediation, reporting and other actions. We have satisfied the requirements of the administrative order; however, we may be subjected to a civil penalty. The aggregate cost to clean up and remediate the site was $6 million.
	Kemp River Pipeline Releases. During May and June 2013, two separate releases were discovered on our Kemp River pipeline in Northern Alberta, Canada that, in the aggregate, resulted in the release of approximately 700 barrels of condensate and light crude oil.  Clean-up and remediation activities are being conducted in cooperation with the applicable regulatory agencies. Final investigation by the Alberta Energy Regulator is not complete. To date, no charges, fines or penalties have been assessed against PMC with respect to these releases; however, it is possible that fines or penalties may be assessed against PMC in the future. We estimate that the aggregate clean-up and remediation costs associated with these releases will be $15 million. Through March 31, 2015, we spent $9 million in connection with clean-up and remediation activities.
	National Energy Board Audit.  In the third quarter of 2014, the National Energy Board (“NEB”) of Canada notified PMC that various corrective actions from a 2010 audit had not been completed to the satisfaction of the NEB. The NEB initiated a process to assess PMC’s approach to compliance with the NEB’s Onshore Pipeline Regulations, which process resulted in the issuance by the NEB of an order on January 15, 2015 that imposed six conditions on PMC designed to enhance PMC’s ability to operate its pipelines in a manner that protects the public and the environment.  The conditions include the filing of certain safety critical tasks, controls and programs with the NEB, external audits of certain PMC programs and systems, and periodic update meetings with NEB staff regarding the status and progress of corrective actions.  In early February 2015, the NEB imposed a penalty on PMC of $76,000 CAD related to these issues.  It is possible that additional fines and penalties may be assessed against PMC in the future related to this matter.
	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 PAA’s Bakersfield Crude Terminal LLC 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.

Operating_Segments

Operating Segments	3 Months Ended
	Mar. 31, 2015
Operating Segments
Operating Segments
	Note 11—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 for the periods indicated (in millions):
			Transportation			Facilities			Supply and		Total
									Logistics
	Three Months Ended March 31, 2015
	Revenues:
	External Customers		$	185		$	125		$	5,632	$	5,942
	Intersegment (1)		215			132			2		349
	Total revenues of reportable segments		$	400		$	257		$	5,634	$	6,291
	Equity earnings in unconsolidated entities		$	37		$	—		$	—	$	37
	Segment profit (2) (3)		$	241		$	142		$	130	$	513
	Maintenance capital		$	33		$	15		$	2	$	50
			Transportation			Facilities			Supply and		Total
									Logistics
	Three Months Ended March 31, 2014
	Revenues:
	External Customers		$	181		$	157		$	11,346	$	11,684
	Intersegment (1)		206			142			22		370
	Total revenues of reportable segments		$	387		$	299		$	11,368	$	12,054
	Equity earnings in unconsolidated entities		$	20		$	—		$	—	$	20
	Segment profit (2) (3)		$	206		$	154		$	249	$	609
	Maintenance capital		$	34		$	10		$	2	$	46
		-1		Segment revenues and purchases and related costs include intersegment amounts. Intersegment sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market. For further discussion, see “Analysis of Operating Segments” under Item 7 of our 2014 Annual Report on Form 10-K.
		-2		Supply and Logistics segment profit includes interest expense (related to hedged inventory purchases) of $1 million and $2 million for the three months ended March 31, 2015 and 2014, respectively.
		-3		The following table reconciles segment profit to net income attributable to PAA (in millions):
			Three Months Ended
			March 31,
			2015			2014
	Segment profit		$	513		$	609
	Depreciation and amortization		(107		)	(96		)
	Interest expense, net		(102		)	(78		)
	Other expense, net		(4		)	(2		)
	Income before tax		300			433
	Income tax expense		(16		)	(48		)
	Net income		284			385
	Net income attributable to noncontrolling interests		(1		)	(1		)
	Net income attributable to PAA		$	283		$	384

Related_Party_Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2015
Related Party Transactions
Related Party Transactions
	Note 12—Related Party Transactions
	See Note 15 to our Consolidated Financial Statements included in Part IV of our 2014 Annual Report on Form 10-K for a complete discussion of our related party transactions.
	Transactions with Oxy
	As of March 31, 2015, Oxy owned approximately 13% of the limited partner interests in our general partner and had a representative on the board of directors of GP LLC. During the three months ended March 31, 2015 and 2014, 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. See detail below (in millions):
		Three Months Ended
		March 31,
		2015		2014
	Revenues	$	176	$	92
	Purchases and related costs	$	104	$	259
	We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with Oxy were as follows (in millions):
		March 31,		December 31,
		2015		2014
	Trade accounts receivable and other receivables	$	465	$	489
	Accounts payable	$	410	$	441

Net_Income_Per_Limited_Partner1

Net Income Per Limited Partner Unit (Tables)	3 Months Ended
	Mar. 31, 2015
Net Income Per Limited Partner Unit
Computation of basic and diluted net income per limited partner unit
	The following table sets forth the computation of basic and diluted net income per limited partner unit for the three months ended March 31, 2015 and 2014 (in millions, except per unit data):
			Three Months Ended
			March 31,
			2015			2014
	Basic Net Income per Limited Partner Unit
	Net income attributable to PAA		$	283		$	384
	Less: General partner’s incentive distribution (1)		(142		)	(110		)
	Less: General partner 2% ownership (1)		(3		)	(6		)
	Net income available to limited partners		138			268
	Less: Undistributed earnings allocated and distributions to participating securities (1)		(2		)	(2		)
	Net income available to limited partners in accordance with application of the two-class method for MLPs		$	136		$	266
	Basic weighted average limited partner units outstanding		383			360
	Basic net income per limited partner unit		$	0.36		$	0.74
	Diluted Net Income per Limited Partner Unit
	Net income attributable to PAA		$	283		$	384
	Less: General partner’s incentive distribution (1)		(142		)	(110		)
	Less: General partner 2% ownership (1)		(3		)	(6		)
	Net income available to limited partners		138			268
	Less: Undistributed earnings allocated and distributions to participating securities (1)		(2		)	(2		)
	Net income available to limited partners in accordance with application of the two-class method for MLPs		$	136		$	266
	Basic weighted average limited partner units outstanding		383			360
	Effect of dilutive securities: Weighted average LTIP units		2			3
	Diluted weighted average limited partner units outstanding		385			363
	Diluted net income per limited partner unit		$	0.35		$	0.73
		-1		We calculate net income available to limited partners 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, limited partners and participating securities in accordance with the contractual terms of the partnership agreement and as further prescribed under the two-class method.
Undistributed earnings allocation to IDRs impact on basic and diluted net income per limited partner unit
			Three Months Ended
			March 31,
			2015			2014
	Basic net income per limited partner unit impact		$	—		$	(0.05	)
	Diluted net income per limited partner unit impact		$	—		$	(0.05	)

Inventory_Linefill_and_Base_Ga1

Inventory, Linefill and Base Gas and Long-term Inventory (Tables)	3 Months Ended
	Mar. 31, 2015
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 as of the dates indicated (barrels and natural gas volumes in thousands and carrying value in millions):
			March 31, 2015							December 31, 2014
			Volumes		Unit of	Carrying		Price/		Volumes	Unit of	Carrying		Price/
					Measure	Value		Unit (1)			Measure	Value		Unit (1)
	Inventory
	Crude oil		15,351		barrels	$	686	$	44.69	6,465	barrels	$	304	$	47.02
	NGL		7,277		barrels	154		$	21.16	13,553	barrels	454		$	33.50
	Natural gas		10,965		Mcf	31		$	2.83	32,317	Mcf	102		$	3.16
	Other		N/A			58		N/A		N/A		31		N/A
	Inventory subtotal					929						891
	Linefill and base gas
	Crude oil		12,970		barrels	777		$	59.91	11,810	barrels	744		$	63.00
	NGL		1,215		barrels	48		$	39.51	1,212	barrels	52		$	42.90
	Natural gas		28,612		Mcf	135		$	4.72	28,612	Mcf	134		$	4.68
	Linefill and base gas subtotal					960						930
	Long-term inventory
	Crude oil		2,646		barrels	117		$	44.22	2,582	barrels	136		$	52.67
	NGL		1,681		barrels	32		$	19.04	1,681	barrels	50		$	29.74
	Long-term inventory subtotal					149						186
	Total					$	2,038					$	2,007
		-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.

Debt_Tables

Debt (Tables)	3 Months Ended
	Mar. 31, 2015
Debt
Schedule of debt
	Debt consisted of the following as of the dates indicated (in millions):
			March 31,		December 31,
			2015		2014
	SHORT-TERM DEBT
	Commercial paper notes, bearing a weighted-average interest rate of 0.46% at December 31, 2014 (1)		$	—	$	734
	Senior notes:
	5.25% senior notes due June 2015		150		150
	3.95% senior notes due September 2015		400		400
	Other		3		3
	Total short-term debt		553		1,287
	LONG-TERM DEBT
	Senior notes, net of unamortized discount of $17 and $18, respectively		8,758		8,757
	Other		5		5
	Total long-term debt		8,763		8,762
	Total debt (2)		$	9,316	$	10,049
		-1		At December 31, 2014, we classified all of the borrowings under our commercial paper program as short-term as these borrowings were primarily designated as working capital borrowings, must be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.
		-2		Our fixed-rate senior notes (including current maturities) had a face value of approximately $9.3 billion as of both March 31, 2015 and December 31, 2014. We estimated the aggregate fair value of these notes as of March 31, 2015 and December 31, 2014 to be approximately $10.0 billion and $9.9 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 quarter end. 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.

Partners_Capital_and_Distribut1

Partners' Capital and Distributions (Tables)	3 Months Ended
	Mar. 31, 2015
Partners' Capital and Distributions
Schedule of distributions paid, net of reductions in the general partner's incentive distributions
	The following table details the distributions paid during or pertaining to the first three months of 2015, net of reductions to the general partner’s incentive distributions (in millions, except per unit data):
					Distributions Paid								Distributions
					Limited		General Partner						per limited
	Date Declared		Distribution Date		Partners		2%		Incentive		Total		partner unit
	April 7, 2015		May 15, 2015(1)		$	272	$	6	$	142	$	420	$	0.6850
	January 8, 2015		February 13, 2015		$	254	$	5	$	131	$	390	$	0.6750
		-1		Payable to unitholders of record at the close of business on May 1, 2015 for the period January 1, 2015 through March 31, 2015.

Derivatives_and_Risk_Managemen1

Derivatives and Risk Management Activities (Tables)	3 Months Ended
	Mar. 31, 2015
Derivative disclosures
Impact of derivative activities recognized in earnings
	A summary of the impact of our derivative activities recognized in earnings for the three months ended March 31, 2015 and 2014 is as follows (in millions):
			Three Months Ended March 31, 2015										Three Months Ended March 31, 2014
	Location of gain/(loss)		Derivatives in			Derivatives			Total				Derivatives in			Derivatives			Total
			Hedging			Not Designated							Hedging			Not Designated
			Relationships (1)			as a Hedge							Relationships (1)			as a Hedge
	Commodity Derivatives
	Supply and Logistics segment revenues		$	7		$	(34	)	$	(27	)		$	(19	)	$	—		$	(19	)
	Transportation segment revenues		—			2			2				—			—			—
	Field operating costs		—			(4		)	(4		)		—			(1		)	(1		)
	Interest Rate Derivatives
	Interest expense		(1		)	—			(1		)		(1		)	—			(1		)
	Foreign Currency Derivatives
	Supply and Logistics segment revenues		—			(17		)	(17		)		—			(9		)	(9		)
	Total Gain/(Loss) on Derivatives Recognized in Net Income		$	6		$	(53	)	$	(47	)		$	(20	)	$	(10	)	$	(30	)
		-1		Represents gains/(losses) on cash flow hedges reclassified from AOCI to income during the period.
Summary of derivative assets and liabilities on condensed consolidated balance sheet 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 March 31, 2015 (in millions):
			Asset Derivatives						Liability Derivatives
			Balance Sheet						Balance Sheet
			Location		Fair Value				Location		Fair Value
	Derivatives designated as hedging instruments:
	Commodity derivatives		Other current assets		$	18			Other long-term liabilities and deferred credits		$	(2	)
			Other long-term liabilities and deferred credits		3
	Interest rate derivatives								Other current liabilities		(64		)
									Other long-term liabilities and deferred credits		(80		)
	Total derivatives designated as hedging instruments				$	21					$	(146	)
	Derivatives not designated as hedging instruments:
	Commodity derivatives		Other current assets		$	205			Other current assets		$	(47	)
			Other long-term assets, net		18				Other current liabilities		(40		)
			Other long-term liabilities and deferred credits		2				Other long-term liabilities and deferred credits		(13		)
	Foreign currency derivatives								Other current liabilities		(4		)
	Total derivatives not designated as hedging instruments				$	225					$	(104	)
	Total derivatives				$	246					$	(250	)
	The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of December 31, 2014 (in millions):
			Asset Derivatives						Liability Derivatives
			Balance Sheet		Fair				Balance Sheet		Fair
			Location		Value				Location		Value
	Derivatives designated as hedging instruments:
	Commodity derivatives		Other current assets		$	23			Other current assets		$	(12	)
			Other long-term assets, net		8				Other long-term assets, net		(1		)
	Interest rate derivatives								Other current liabilities		(44		)
									Other long-term liabilities and deferred credits		(26		)
	Total derivatives designated as hedging instruments				$	31					$	(83	)
	Derivatives not designated as hedging instruments:
	Commodity derivatives		Other current assets		$	439			Other current assets		$	(246	)
			Other long-term assets, net		23				Other long-term assets, net		(3		)
									Other current liabilities		(35		)
									Other long-term liabilities and deferred credits		(5		)
	Foreign currency derivatives								Other current liabilities		(12		)
	Total derivatives not designated as hedging instruments				$	462					$	(301	)
	Total derivatives				$	493					$	(384	)
Schedule of derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements
	The following tables present information about derivatives and financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements as of the dates indicated (in millions):
			March 31, 2015							December 31, 2014
			Derivative			Derivative				Derivative			Derivative
			Asset Positions			Liability Positions				Asset Positions			Liability Positions
	Netting Adjustments:
	Gross position - asset/(liability)		$	246		$	(250	)		$	493		$	(384	)
	Netting adjustment		(52		)	52				(262		)	262
	Cash collateral paid/(received)		(112		)	—				(133		)	—
	Net position - asset/(liability)		$	82		$	(198	)		$	98		$	(122	)
	Balance Sheet Location After Netting Adjustments:
	Other current assets		$	64		$	—			$	71		$	—
	Other long-term assets, net		18			—				27			—
	Other current liabilities		—			(108		)		—			(91		)
	Other long-term liabilities and deferred credits		—			(90		)		—			(31		)
			$	82		$	(198	)		$	98		$	(122	)
Net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives
	The net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives for the three months ended March 31, 2015 and 2014 was as follows (in millions):
			Three Months Ended
			March 31,
			2015			2014
	Commodity derivatives, net		$	3		$	(12	)
	Interest rate derivatives, net		(75		)	(20		)
	Total		$	(72	)	$	(32	)
Schedule of derivative financial assets and liabilities by level within the fair value hierarchy accounted for at fair value on a recurring basis
	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 as of March 31, 2015 and December 31, 2014 (in millions):
			Fair Value as of March 31, 2015													Fair Value as of December 31, 2014
	Recurring Fair Value Measures (1)		Level 1			Level 2			Level 3			Total				Level 1			Level 2			Level 3		Total
	Commodity derivatives		$	16		$	123		$	5		$	144			$	(85	)	$	261		$	15	$	191
	Interest rate derivatives		—			(144		)	—			(144		)		—			(70		)	—		(70		)
	Foreign currency derivatives		—			(4		)	—			(4		)		—			(12		)	—		(12		)
	Total net derivative asset/(liability)		$	16		$	(25	)	$	5		$	(4	)		$	(85	)	$	179		$	15	$	109
		-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 for the three months ended March 31, 2015 and 2014 (in millions):
			Three Months Ended
			March 31,
			2015			2014
	Beginning Balance		$	15		$	(3	)
	Total gains/(losses) for the period:
	Settlements		(12		)	3
	Derivatives entered into during the period		2			1
	Ending Balance		$	5		$	1
	Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period		$	2		$	1
Interest Rate Swaps
Derivative disclosures
Schedule of terms of forward starting interest rate swaps
	The following table summarizes the terms of our forward starting interest rate swaps as of March 31, 2015 (notional amounts in millions):
	Hedged Transaction		Number and Types of		Notional			Expected		Average Rate		Accounting
			Derivatives Employed		Amount			Termination Date		Locked		Treatment
	Anticipated debt offering		10 forward starting swaps (30-year)		$	250		6/15/15		3.60%		Cash flow hedge
	Anticipated debt offering		8 forward starting swaps (30-year)		$	200		6/15/16		3.06%		Cash flow hedge
	Anticipated debt offering		8 forward starting swaps (30-year)		$	200		6/15/17		3.14%		Cash flow hedge
	Anticipated debt offering		8 forward starting swaps (30-year)		$	200		6/15/18		3.20%		Cash flow hedge
	Anticipated debt offering		8 forward starting swaps (30-year)		$	200		6/14/19		2.83%		Cash flow hedge
Foreign Currency Derivatives
Derivative disclosures
Open forward exchange contracts
	The following table summarizes our open forward exchange contracts as of March 31, 2015 (in millions):
					USD			CAD			Average Exchange Rate
											USD to CAD
	Forward exchange contracts that exchange CAD for USD:
			2015		$	147		$	187		$1.00 - $1.27
			2016		5			7			$1.00 - $1.27
					$	152		$	194
	Forward exchange contracts that exchange USD for CAD:
			2015		$	181		$	225		$1.00 - $1.24
			2016		5			7			$1.00 - $1.27
					$	186		$	232

EquityIndexed_Compensation_Pla1

Equity-Indexed Compensation Plans (Tables)	3 Months Ended
	Mar. 31, 2015
Summary of expense recognized and the value of vested LTIP awards under equity-indexed compensation plans
	The table below summarizes the expense recognized and the value of vested LTIP awards (settled both in common units and cash) under our equity-indexed compensation plans and includes both liability-classified and equity-classified awards (in millions):
			Three Months Ended
			March 31,
			2015			2014
	Equity-indexed compensation expense		$	19		$	34
	LTIP unit-settled vestings		$	—		$	5
	LTIP cash-settled vestings (1)		$	—		$	1
	DER cash payments		$	2		$	2
		-1		For the three months ended March 31, 2015, the value of PAA LTIP awards that were settled in cash was less than $1 million.
Long-Term Incentive Plan Awards
Summary of activity for equity-indexed compensation plans
	Activity for LTIP awards under our equity-indexed compensation plans denominated in PAA units is summarized in the following table (units in millions):
					Weighted Average
					Grant Date
			Units (1)		Fair Value per Unit
	Outstanding at December 31, 2014		7.3		$	41.45
	Granted		1.1		$	39.99
	Vested (2)		—		$	40.23
	Cancelled or forfeited		(0.1	)	$	39.69
	Outstanding at March 31, 2015		8.3		$	41.26
		-1		Amounts do not include AAP Management Units.
		-2		During the three months ended March 31, 2015, less than 0.1 million PAA LTIP awards were settled in cash.
AAP Management Units
Summary of activity for equity-indexed compensation plans
	Activity for AAP Management Units is summarized in the following table (in millions):
			Reserved for		Outstanding		Outstanding	Grant Date
			Future Grants				Units Earned	Fair Value of Outstanding
								AAP Management Units (1)
	Balance at December 31, 2014		3.0		49.1		47.8	$	64
	Earned		N/A		N/A		0.3	N/A
	Balance at March 31, 2015		3.0		49.1		48.1	$	64
		-1		Of the $64 million grant date fair value, $56 million had been recognized through March 31, 2015 on a cumulative basis. Of this amount, $1 million was recognized as expense during the three months ended March 31, 2015.

Operating_Segments_Tables

Operating Segments (Tables)	3 Months Ended
	Mar. 31, 2015
Operating Segments
Segment financial data
	The following table reflects certain financial data for each segment for the periods indicated (in millions):
			Transportation			Facilities			Supply and		Total
									Logistics
	Three Months Ended March 31, 2015
	Revenues:
	External Customers		$	185		$	125		$	5,632	$	5,942
	Intersegment (1)		215			132			2		349
	Total revenues of reportable segments		$	400		$	257		$	5,634	$	6,291
	Equity earnings in unconsolidated entities		$	37		$	—		$	—	$	37
	Segment profit (2) (3)		$	241		$	142		$	130	$	513
	Maintenance capital		$	33		$	15		$	2	$	50
			Transportation			Facilities			Supply and		Total
									Logistics
	Three Months Ended March 31, 2014
	Revenues:
	External Customers		$	181		$	157		$	11,346	$	11,684
	Intersegment (1)		206			142			22		370
	Total revenues of reportable segments		$	387		$	299		$	11,368	$	12,054
	Equity earnings in unconsolidated entities		$	20		$	—		$	—	$	20
	Segment profit (2) (3)		$	206		$	154		$	249	$	609
	Maintenance capital		$	34		$	10		$	2	$	46
		-1		Segment revenues and purchases and related costs include intersegment amounts. Intersegment sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market. For further discussion, see “Analysis of Operating Segments” under Item 7 of our 2014 Annual Report on Form 10-K.
		-2		Supply and Logistics segment profit includes interest expense (related to hedged inventory purchases) of $1 million and $2 million for the three months ended March 31, 2015 and 2014, respectively.
		-3		The following table reconciles segment profit to net income attributable to PAA (in millions):
			Three Months Ended
			March 31,
			2015			2014
	Segment profit		$	513		$	609
	Depreciation and amortization		(107		)	(96		)
	Interest expense, net		(102		)	(78		)
	Other expense, net		(4		)	(2		)
	Income before tax		300			433
	Income tax expense		(16		)	(48		)
	Net income		284			385
	Net income attributable to noncontrolling interests		(1		)	(1		)
	Net income attributable to PAA		$	283		$	384
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
			March 31,
			2015			2014
	Segment profit		$	513		$	609
	Depreciation and amortization		(107		)	(96		)
	Interest expense, net		(102		)	(78		)
	Other expense, net		(4		)	(2		)
	Income before tax		300			433
	Income tax expense		(16		)	(48		)
	Net income		284			385
	Net income attributable to noncontrolling interests		(1		)	(1		)
	Net income attributable to PAA		$	283		$	384

Related_Party_Transactions_Tab

Related Party Transactions (Tables) (Oxy)	3 Months Ended
	Mar. 31, 2015
Oxy
Related party transaction
Schedule of related party transactions
	These transactions were conducted at posted tariff rates or prices that we believe approximate market. See detail below (in millions):
		Three Months Ended
		March 31,
		2015		2014
	Revenues	$	176	$	92
	Purchases and related costs	$	104	$	259
	We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with Oxy were as follows (in millions):
		March 31,		December 31,
		2015		2014
	Trade accounts receivable and other receivables	$	465	$	489
	Accounts payable	$	410	$	441

Organization_and_Basis_of_Pres

Organization and Basis of Presentation (Details)	3 Months Ended
	Mar. 31, 2015
	segment
Organization
Operating segments number	3
General partner ownership interest (as a percent)	2.00%
PAGP | AAP
Organization
PAGP limited partner interest in AAP (as a percent)	37.00%

Net_Income_Per_Limited_Partner2

Net Income Per Limited Partner Unit (Details) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Net Income Per Limited Partner Unit
General partner ownership interest (as a percent)	2.00%
Basic Net Income per Limited Partner Unit
Net income attributable to PAA	$283	$384
Less: General partner's incentive distribution	-142	-110
Less: General partner 2% ownership	-3	-6
Net income available to limited partners	138	268
Less: Undistributed earnings allocated and distributions to participating securities	-2	-2
Net income available to limited partners in accordance with application of the two-class method for MLPs	136	266
Basic weighted average limited partner units outstanding	383	360
Basic net income per limited partner unit	$0.36	$0.74
Diluted Net Income per Limited Partner Unit
Net income attributable to PAA	283	384
Less: General partner's incentive distribution	-142	-110
Less: General partner 2% ownership	-3	-6
Net income available to limited partners	138	268
Less: Undistributed earnings allocated and distributions to participating securities	-2	-2
Net income available to limited partners in accordance with application of the two-class method for MLPs	$136	$266
Basic weighted average limited partner units outstanding	383	360
Effect of dilutive securities:
Weighted average LTIP units	2	3
Diluted weighted average limited partner units outstanding	385	363
Diluted net income per limited partner unit	$0.35	$0.73

Net_Income_Per_Limited_Partner3

Net Income Per Limited Partner Unit (Details 2) (USD $)	3 Months Ended
	Mar. 31, 2014
Basic and Diluted Net Income per Limited Partner Unit
Basic net income per limited partner unit impact	($0.05)
Diluted net income per limited partner unit impact	($0.05)

Accounts_Receivable_Details

Accounts Receivable (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Accounts Receivable
Advance cash payments received from third parties to mitigate credit risk	$130	$180
Standby letters of credit	12	198
Substantially all accounts receivable, net, maximum age of balances past their scheduled invoice date	30 days	30 days
Allowance for doubtful accounts receivable	$4	$4

Inventory_Linefill_and_Base_Ga2

Inventory, Linefill and Base Gas and Long-term Inventory (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Inventory-related disclosures
Charge related to the write-down of inventory	$24	$37
Inventory by category
Inventory	929		891
Linefill and base gas	960		930
Long-term inventory	149		186
Total	2,038		2,007
Crude oil
Inventory by category
Inventory	686		304
Linefill and base gas	777		744
Long-term inventory	117		136
Inventory, Volumes (in barrels or in Mcf)	15,351,000		6,465,000
Linefill and base gas, Volumes (in barrels or in Mcf)	12,970,000		11,810,000
Long-term inventory, Volumes (in barrels or in Mcf)	2,646,000		2,582,000
Inventory, Price/Unit of measure (in dollars per unit)	44.69		47.02
Linefill and base gas, Price/Unit of measure (in dollars per unit)	59.91		63
Long-term inventory, Price/Unit of measure (in dollars per unit)	44.22		52.67
NGL
Inventory by category
Inventory	154		454
Linefill and base gas	48		52
Long-term inventory	32		50
Inventory, Volumes (in barrels or in Mcf)	7,277,000		13,553,000
Linefill and base gas, Volumes (in barrels or in Mcf)	1,215,000		1,212,000
Long-term inventory, Volumes (in barrels or in Mcf)	1,681,000		1,681,000
Inventory, Price/Unit of measure (in dollars per unit)	21.16		33.5
Linefill and base gas, Price/Unit of measure (in dollars per unit)	39.51		42.9
Long-term inventory, Price/Unit of measure (in dollars per unit)	19.04		29.74
Natural gas
Inventory by category
Inventory	31		102
Linefill and base gas	135		134
Inventory, Volumes (in barrels or in Mcf)	10,965,000		32,317,000
Linefill and base gas, Volumes (in barrels or in Mcf)	28,612,000		28,612,000
Inventory, Price/Unit of measure (in dollars per unit)	2.83		3.16
Linefill and base gas, Price/Unit of measure (in dollars per unit)	4.72		4.68
Other
Inventory by category
Inventory	$58		$31

Debt_Details

Debt (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Mar. 31, 2015
Short-term debt:
Other short-term debt	$3	$3
Total short-term debt	1,287	553
Long-term debt:
Senior notes, net of unamortized discount of $17 and $18, respectively	8,757	8,758
Unamortized discount	18	17
Long-term debt, other	5	5
Total long-term debt	8,762	8,763
Total debt	10,049	9,316
Commercial paper program
Short-term debt:
Commercial paper notes, bearing a weighted-average interest rate of 0.46% at December 31, 2014	734
Repayment period	1 year
Weighted average interest rate, short-term (as a percent)	0.46%
5.25% senior notes due June 2015
Short-term debt:
Senior Notes, Current	150	150
Long-term debt:
Debt instrument, interest rate (as a percent)	5.25%	5.25%
3.95% senior notes due September 2015
Short-term debt:
Senior Notes, Current	$400	$400
Long-term debt:
Debt instrument, interest rate (as a percent)	3.95%	3.95%

Debt_Details_2

Debt (Details 2) (USD $)	1 Months Ended	3 Months Ended
	Jan. 31, 2015	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Letters of credit
Debt
Outstanding letters of credit		$83,000,000		$87,000,000
PAA senior unsecured 364-day revolving credit facility
Debt
Expiration period for credit facility	364 days
Borrowing capacity	1,000,000,000	1,000,000,000
Basis Variable interest rate used		Eurocurrency Rate or the Base Rate
Credit agreements and commercial paper program
Debt
Total borrowings		7,000,000,000	19,200,000,000
Total repayments		7,700,000,000	19,300,000,000
Senior notes
Debt
Debt instrument face value		9,300,000,000		9,300,000,000
Senior notes | Level 2
Debt
Debt instrument fair value		$10,000,000,000		$9,900,000,000

Partners_Capital_and_Distribut2

Partners' Capital and Distributions (Details) (USD $)	3 Months Ended		0 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Feb. 13, 2015	15-May-15
Partners Capital and Distribution
Total distributions paid during the period	$391	$329
Fourth Quarter Distribution
Partners Capital and Distribution
Distributions paid to Limited Partners			254
Distributions paid to General Partner - 2%			5
Distributions paid to General Partner - Incentive			131
Total distributions paid during the period			390
Distributions per limited partner unit			$0.68
Distribution declared, date	8-Jan-15
Distribution Date	13-Feb-15
Subsequent Event | First Quarter Distribution
Partners Capital and Distribution
Distributions paid to Limited Partners				272
Distributions paid to General Partner - 2%				6
Distributions paid to General Partner - Incentive				142
Total distributions paid during the period				$420
Distributions per limited partner unit				$0.69
Distribution declared, date	7-Apr-15
Distribution Date	15-May-15
Unitholders of record, date	1-May-15

Partners_Capital_and_Distribut3

Partners' Capital and Distributions (Details 2) (USD $)	3 Months Ended		1 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Mar. 31, 2015
Partners Capital and Distribution
Issuance of common units, net proceeds	$1,121	$151
SLC Pipeline LLC
Partners Capital and Distribution
Noncontrolling interests in subsidiaries (as a percent)	25.00%		25.00%
Continuous Offering Program
Partners Capital and Distribution
Issuance of common units (in units)	1.1
Issuance of common units, net proceeds	59
Contribution from general partner	1		1
Commissions paid	1
Underwritten Offering
Partners Capital and Distribution
Issuance of common units (in units)			21
Issuance of common units, net proceeds			1,100
Contribution from general partner	$21		$21

Derivatives_and_Risk_Managemen2

Derivatives and Risk Management Activities (Details)	3 Months Ended
	Mar. 31, 2015
	bbl
Net long position associated with crude oil purchases
Commodity Price Risk Hedging:
Average derivative positions notional amount per day (in barrels)	233,600
Derivative position notional amount (in barrels or Mcf)	7,000,000
Net short time spread position hedging anticipated crude oil lease gathering purchases
Commodity Price Risk Hedging:
Average derivative positions notional amount per day (in barrels)	18,200
Derivative position notional amount (in barrels or Mcf)	7,200,000
Crude oil grade spread positions
Commodity Price Risk Hedging:
Average derivative positions notional amount per day (in barrels)	37,500
Derivative position notional amount (in barrels or Mcf)	9,100,000
Net short position related to anticipated sales of natural gas inventory and base gas requirements
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	6,800,000
Net short position related to anticipated purchases and sales of crude oil, NGL and refined products inventory
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	16,800,000
Long natural gas position for natural gas purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	18,100,000
Short propane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	3,500,000
Short butane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	1,000,000
Short WTI position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	400,000
Long power position for power supply requirements
Commodity Price Risk Hedging:
Derivative position notional amount (in megawatt hours)	400,000

Derivatives_and_Risk_Managemen3

Derivatives and Risk Management Activities (Details 2) (USD $)	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Interest Rate Risk Hedging
Net deferred gains (losses) from interest rate risk hedging included in AOCI	($843)	($467)	($233)	($97)
Interest Rate Derivatives
Interest Rate Risk Hedging
Net deferred gains (losses) from interest rate risk hedging included in AOCI	-234
10 forward starting interest rate swaps (30-year) | Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives (in contracts)	10
Notional amount of derivatives	250
Rate of fixed interest to be received on interest rate swap (as a percent)	3.60%
8 forward starting interest rate swaps (30-year), one | Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives (in contracts)	8
Notional amount of derivatives	200
Rate of fixed interest to be received on interest rate swap (as a percent)	3.06%
8 forward starting interest rate swaps (30-year), two | Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives (in contracts)	8
Notional amount of derivatives	200
Rate of fixed interest to be received on interest rate swap (as a percent)	3.14%
8 forward starting interest rate swaps (30-year), three | Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives (in contracts)	8
Notional amount of derivatives	200
Rate of fixed interest to be received on interest rate swap (as a percent)	3.20%
8 forward starting interest rate swaps (30-year), four | Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives (in contracts)	8
Notional amount of derivatives	$200
Rate of fixed interest to be received on interest rate swap (as a percent)	2.83%

Derivatives_and_Risk_Managemen4

Derivatives and Risk Management Activities (Details 3)

Mar. 31, 2015

Mar. 31, 2015

Mar. 31, 2015

Mar. 31, 2015

Mar. 31, 2015

Mar. 31, 2015

Mar. 31, 2015

Mar. 31, 2015

Mar. 31, 2015

Mar. 31, 2015

Mar. 31, 2015

Mar. 31, 2015

In Millions, unless otherwise specified

Forward exchange contracts that exchange CAD for USD at the rate USD 1.00 to CAD 1.27 maturing in 2015

Forward exchange contracts that exchange CAD for USD at the rate USD 1.00 to CAD 1.27 maturing in 2015

Forward exchange contracts that exchange CAD for USD at the rate USD 1.00 to CAD 1.27 maturing in 2016

Forward exchange contracts that exchange CAD for USD at the rate USD 1.00 to CAD 1.27 maturing in 2016

Forward exchange contracts that exchange CAD for USD

Forward exchange contracts that exchange CAD for USD

Forward exchange contracts that exchange USD for CAD at the rate USD 1.00 to CAD 1.24 maturing in 2015

Forward exchange contracts that exchange USD for CAD at the rate USD 1.00 to CAD 1.24 maturing in 2015

Forward exchange contracts that exchange USD for CAD at the rate USD 1.00 to CAD 1.27 maturing in 2016

Forward exchange contracts that exchange USD for CAD at the rate USD 1.00 to CAD 1.27 maturing in 2016

Forward exchange contracts that exchange USD for CAD

Forward exchange contracts that exchange USD for CAD

USD ($)

CAD

USD ($)

CAD

USD ($)

CAD

USD ($)

CAD

USD ($)

CAD

USD ($)

CAD

Currency Exchange Rate Risk Hedging:

Notional amount of derivatives

$147

187

$5

7

$152

194

$181

225

$5

7

$186

232

Average exchange rate

1.27

1.27

1.24

1.27

Derivatives_and_Risk_Managemen5

Derivatives and Risk Management Activities (Details 4) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Impact of derivative activities recognized in earnings
Total	($47)	($30)
Commodity Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	-27	-19
Commodity Derivatives | Transportation segment revenues
Impact of derivative activities recognized in earnings
Total	2
Commodity Derivatives | Field operating costs
Impact of derivative activities recognized in earnings
Total	-4	-1
Interest Rate Derivatives | Interest expense
Impact of derivative activities recognized in earnings
Total	-1	-1
Foreign Currency Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	-17	-9
Derivatives in Hedging Relationships | Cash flow hedge
Impact of derivative activities recognized in earnings
Gain/(loss) reclassified from AOCI into income	6	-20
Derivatives in Hedging Relationships | Cash flow hedge | Commodity Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Gain/(loss) reclassified from AOCI into income	7	-19
Derivatives in Hedging Relationships | Cash flow hedge | Interest Rate Derivatives | Interest expense
Impact of derivative activities recognized in earnings
Gain/(loss) reclassified from AOCI into income	-1	-1
Derivatives Not Designated as a Hedge
Impact of derivative activities recognized in earnings
Total	-53	-10
Derivatives Not Designated as a Hedge | Commodity Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	-34
Derivatives Not Designated as a Hedge | Commodity Derivatives | Transportation segment revenues
Impact of derivative activities recognized in earnings
Total	2
Derivatives Not Designated as a Hedge | Commodity Derivatives | Field operating costs
Impact of derivative activities recognized in earnings
Total	-4	-1
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	($17)	($9)

Derivatives_and_Risk_Managemen6

Derivatives and Risk Management Activities (Details 5) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
	contract		contract
Derivatives disclosures
Asset Derivatives Fair Value	$246		$493
Liability Derivatives Fair Value	-250		-384
Broker payable	112		133
Initial margin	61		126
Variation margin posted/(returned)	-173		-259
Net gain/(loss) deferred in AOCI	-237
Net gain/(loss) expected to be reclassified to earnings in next 12 months	9
Gain/(loss) expected to be reclassified to earnings through 2049	-246
Net deferred gain/(loss) recognized in AOCI on derivatives	-72	-32
Number of outstanding derivatives containing credit-risk related contingent features	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
Derivatives disclosures
Net deferred gain/(loss) recognized in AOCI on derivatives	3	-12
Interest Rate Derivatives
Derivatives disclosures
Net deferred gain/(loss) recognized in AOCI on derivatives	-75	-20
Derivatives in Hedging Relationships
Derivatives disclosures
Asset Derivatives Fair Value	21		31
Liability Derivatives Fair Value	-146		-83
Derivatives in Hedging Relationships | Commodity Derivatives | Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	18		23
Liability Derivatives Fair Value			-12
Derivatives in Hedging Relationships | Commodity Derivatives | Other long-term assets, net
Derivatives disclosures
Asset Derivatives Fair Value			8
Liability Derivatives Fair Value			-1
Derivatives in Hedging Relationships | Commodity Derivatives | Other long-term liabilities and deferred credits
Derivatives disclosures
Asset Derivatives Fair Value	3
Liability Derivatives Fair Value	-2
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other current liabilities
Derivatives disclosures
Liability Derivatives Fair Value	-64		-44
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other long-term liabilities and deferred credits
Derivatives disclosures
Liability Derivatives Fair Value	-80		-26
Derivatives Not Designated as a Hedge
Derivatives disclosures
Asset Derivatives Fair Value	225		462
Liability Derivatives Fair Value	-104		-301
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	205		439
Liability Derivatives Fair Value	-47		-246
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other long-term assets, net
Derivatives disclosures
Asset Derivatives Fair Value	18		23
Liability Derivatives Fair Value			-3
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other current liabilities
Derivatives disclosures
Liability Derivatives Fair Value	-40		-35
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other long-term liabilities and deferred credits
Derivatives disclosures
Asset Derivatives Fair Value	2
Liability Derivatives Fair Value	-13		-5
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Other current liabilities
Derivatives disclosures
Liability Derivatives Fair Value	($4)		($12)

Derivatives_and_Risk_Managemen7

Derivatives and Risk Management Activities (Details 6) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Derivative Asset Positions
Gross Position - Asset	$246	$493
Netting Adjustment	-52	-262
Cash collateral received	-112	-133
Net Position - Asset	82	98
Derivative Liability Positions
Gross Position - Liability	-250	-384
Netting Adjustment	52	262
Net Position - Liability	-198	-122
Other current assets
Derivative Asset Positions
Net Position - Asset	64	71
Other long-term assets, net
Derivative Asset Positions
Net Position - Asset	18	27
Other current liabilities
Derivative Liability Positions
Net Position - Liability	-108	-91
Other long-term liabilities and deferred credits
Derivative Liability Positions
Net Position - Liability	($90)	($31)

Derivatives_and_Risk_Managemen8

Derivatives and Risk Management Activities (Details 7) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Level 3
Rollforward of Level 3 Net Asset/(Liability)
Beginning Balance	$15	($3)
Total gains/(losses) for the period:
Settlements	-12	3
Derivatives entered into during the period	2	1
Ending Balance	5	1
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period	2	1
Recurring Fair Value Measures
Recurring Fair Value Measures
Net derivative asset/(liability)	-4		109
Recurring Fair Value Measures | Commodity Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	144		191
Recurring Fair Value Measures | Interest Rate Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	-144		-70
Recurring Fair Value Measures | Foreign Currency Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	-4		-12
Recurring Fair Value Measures | Level 1
Recurring Fair Value Measures
Net derivative asset/(liability)	16		-85
Recurring Fair Value Measures | Level 1 | Commodity Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	16		-85
Recurring Fair Value Measures | Level 2
Recurring Fair Value Measures
Net derivative asset/(liability)	-25		179
Recurring Fair Value Measures | Level 2 | Commodity Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	123		261
Recurring Fair Value Measures | Level 2 | Interest Rate Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	-144		-70
Recurring Fair Value Measures | Level 2 | Foreign Currency Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	-4		-12
Recurring Fair Value Measures | Level 3
Recurring Fair Value Measures
Net derivative asset/(liability)	5		15
Recurring Fair Value Measures | Level 3 | Commodity Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	$5		$15

EquityIndexed_Compensation_Pla2

Equity-Indexed Compensation Plans (Details) (Long-Term Incentive Plan Awards, USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015
Outstanding (in units)
Outstanding at beginning of period (in units)	7.3
Granted (in units)	1.1
Cancelled or forfeited (in units)	-0.1
Outstanding at end of period (in units)	8.3
Weighted Average Grant Date Fair Value per Unit
Outstanding at beginning of period (in dollars per unit)	$41.45
Granted (in dollars per unit)	$39.99
Vested (in dollars per unit)	$40.23
Cancelled or forfeited (in dollars per unit)	$39.69
Outstanding at end of period (in dollars per unit)	$41.26
Maximum
Weighted Average Grant Date Fair Value per Unit
Vested awards settled in cash (in units)	0.1

EquityIndexed_Compensation_Pla3

Equity-Indexed Compensation Plans (Details 2) (USD $)	3 Months Ended		92 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Mar. 31, 2015
Grant Date Fair Value of Outstanding AAP Management Units
Equity-indexed compensation expense	$19	$34
AAP Management Units
Reserved for Future Grants
Reserved for future grants, beginning balance (in units)	3
Reserved for future grants, ending balance (in units)	3		3
Outstanding
Outstanding, beginning balance (in units)	49.1
Outstanding, ending balance (in units)	49.1		49.1
Outstanding Units Earned
Outstanding Units Earned, beginning balance (in units)	47.8
Earned (in units)	0.3
Outstanding Units Earned, ending balance (in units)	48.1		48.1
Grant Date Fair Value of Outstanding AAP Management Units
Grant Date Fair Value of Outstanding AAP Management Units, beginning balance	64
Grant Date Fair Value of Outstanding AAP Management Units, ending balance	64		64
Equity-indexed compensation expense	$1		$56

EquityIndexed_Compensation_Pla4

Equity-Indexed Compensation Plans (Details 3) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Other Consolidated Equity-Indexed Compensation Plan Information
Equity-indexed compensation expense	$19	$34
LTIP unit-settled vestings		5
LTIP cash-settled vestings		1
DER cash payments	2	2
Maximum
Other Consolidated Equity-Indexed Compensation Plan Information
LTIP cash-settled vestings	$1

Commitments_and_Contingencies_

Commitments and Contingencies (Details)	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2015	Feb. 28, 2013	Mar. 31, 2015	Jun. 30, 2013	Mar. 31, 2015	Apr. 30, 2015	Jan. 15, 2015	Feb. 28, 2015	Mar. 31, 2015
	USD ($)	USD ($)	Minimum	Bay Springs Pipeline Release	Bay Springs Pipeline Release	Kemp River Pipeline Release	Kemp River Pipeline Release	In the Matter of Bakersfield Crude Terminal LLC et al	PMC	PMC	PMC
				bbl	USD ($)	item	USD ($)	Subsequent Event	National Energy Board Audit	National Energy Board Audit	Kemp River Pipeline Release
						bbl		USD ($)	item	CAD	USD ($)
								item
Environmental
Estimated undiscounted reserve for environmental liabilities	$75,000,000	$82,000,000
Estimated undiscounted reserve for environmental liabilities, short-term	11,000,000	13,000,000
Estimated undiscounted reserve for environmental liabilities, long-term	64,000,000	69,000,000
Amounts probable of recovery under insurance and from third parties under indemnification agreements	7,000,000	8,000,000
Actual cash expenditures for environmental liabilities, period paid			3 years
Number of events occurred						2
Estimated size of release (in barrels)				120		700
Number of conditions imposed related to regulatory compliance									6
Number of alleged rule violations								10
Charges, fines or penalties assessed								0		76,000	0
Total estimated cost to clean up and remediate the site							15,000,000
Total cost to clean up and remediate the site					6,000,000
Cost incurred, to date, to clean up and remediate the site							$9,000,000

Operating_Segments_Details

Operating Segments (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
	segment
Operating Segments
Operating segments number	3
Revenues:
Revenues	$5,942	$11,684
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	37	20
Segment profit	513	609
Maintenance capital	50	46
Transportation
Revenues:
Revenues	185	181
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	37	20
Segment profit	241	206
Maintenance capital	33	34
Facilities
Revenues:
Revenues	125	157
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment profit	142	154
Maintenance capital	15	10
Supply and Logistics
Revenues:
Revenues	5,632	11,346
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment profit	130	249
Maintenance capital	2	2
Interest expense related to hedged inventory purchases	1	2
Operating Segments
Revenues:
Revenues	6,291	12,054
Operating Segments | Transportation
Revenues:
Revenues	400	387
Operating Segments | Facilities
Revenues:
Revenues	257	299
Operating Segments | Supply and Logistics
Revenues:
Revenues	5,634	11,368
Intersegment
Revenues:
Revenues	-349	-370
Intersegment | Transportation
Revenues:
Revenues	-215	-206
Intersegment | Facilities
Revenues:
Revenues	-132	-142
Intersegment | Supply and Logistics
Revenues:
Revenues	($2)	($22)

Operating_Segments_Details_2

Operating Segments (Details 2) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Reconciliation of segment profit to net income attributable to PAA
Segment profit	$513	$609
Depreciation and amortization	-107	-96
Interest expense, net	-102	-78
Other expense, net	-4	-2
INCOME BEFORE TAX	300	433
Income tax expense	-16	-48
NET INCOME	284	385
Net income attributable to noncontrolling interests	-1	-1
NET INCOME ATTRIBUTABLE TO PAA	$283	$384

Related_Party_Transactions_Det

Related Party Transactions (Details) (Oxy, USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Oxy
Related party transaction
Related party ownership of general partner interest (as a percent)	13.00%
Revenues	$176	$92
Purchases and related costs	104	259
Trade accounts receivable and other receivables, gross	465		489
Accounts payable, gross	$410		$441