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Document and Entity Information - USD ($) $ in Billions	12 Months Ended
Document and Entity Information - USD ($) $ in Billions	Dec. 31, 2011	Feb. 22, 2012	Jun. 30, 2011
Document and Entity Information
Entity Registrant Name	PLAINS ALL AMERICAN PIPELINE LP
Entity Central Index Key	0001070423
Document Type	10-K
Document Period End Date	Dec. 31, 2011
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 8.4
Entity Common Stock, Shares Outstanding		155,568,749
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
CURRENT ASSETS
Cash and cash equivalents	$ 26	$ 36
Restricted cash		20
Trade accounts receivable and other receivables, net	3,190	2,746
Inventory	978	1,491
Other current assets	157	88
Total current assets	4,351	4,381
PROPERTY AND EQUIPMENT	9,029	7,814
Accumulated depreciation	(1,289)	(1,123)
Property and equipment, net	7,740	6,691
OTHER ASSETS
Goodwill	1,854	1,376
Linefill and base gas	564	519
Long-term inventory	135	154
Investments in unconsolidated entities	191	200
Other, net	546	382
Total assets	15,381	13,703
CURRENT LIABILITIES
Accounts payable and accrued liabilities	3,599	2,738
Short-term debt	679	1,326
Other current liabilities	233	151
Total current liabilities	4,511	4,215
LONG-TERM LIABILITIES
Senior notes, net of unamortized discount of $13 and $12, respectively	4,262	4,363
Long-term debt under credit facilities and other	258	268
Other long-term liabilities and deferred credits	376	284
Total long-term liabilities	4,896	4,915
COMMITMENTS AND CONTINGENCIES (NOTE 11)
PARTNERS' CAPITAL
Common unitholders (155,376,937 and 141,199,175 units outstanding, respectively)	5,249	4,189
General partner	201	153
Total partners' capital excluding noncontrolling interests	5,450	4,342
Noncontrolling interests	524	231
Total partners' capital	5,974	4,573
Total liabilities and partners' capital	$ 15,381	$ 13,703

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
CONSOLIDATED BALANCE SHEETS
Senior notes, unamortized discount (in dollars)	$ 13	$ 12
Common unitholders, units outstanding (in units)	155,376,937	141,199,175

- Definition

The amount of debt discount (net of debt premium) that was originally recognized at the issuance of the instrument that has yet to be amortized.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 21
-Paragraph 16
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

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-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28555-108399

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-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6584090&loc=d3e28878-108400

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

CONSOLIDATED STATEMENTS OF OPERATIONS shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($) $ / shares shares	Dec. 31, 2010 USD ($) $ / shares shares	Dec. 31, 2009 USD ($) $ / shares shares
REVENUES
Supply and Logistics segment revenues	$ 33,065	$ 24,989	$ 17,757
Transportation segment revenues	572	565	536
Facilities segment revenues	638	339	227
Total revenues	34,275	25,893	18,520
COSTS AND EXPENSES
Purchases and related costs	31,564	23,921	16,656
Field operating costs	870	689	638
General and administrative expenses	294	260	211
Depreciation and amortization	249	256	236
Total costs and expenses	32,977	25,126	17,741
OPERATING INCOME	1,298	767	779
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	13	3	15
Interest expense (net of capitalized interest of $25, $16 and $15, respectively)	(253)	(248)	(224)
Other income/(expense), net	(19)	(9)	16
INCOME BEFORE TAX	1,039	513	586
Current income tax benefit/(expense)	(38)	1	(15)
Deferred income tax benefit/(expense)	(7)		9
NET INCOME	994	514	580
Less: Net income attributable to noncontrolling interests	(28)	(9)	(1)
NET INCOME ATTRIBUTABLE TO PLAINS	966	505	579
NET INCOME ATTRIBUTABLE TO PLAINS:
LIMITED PARTNERS	730	330	434
GENERAL PARTNER	$ 236	$ 175	$ 145
BASIC NET INCOME PER LIMITED PARTNER UNIT (in dollars per unit) \| $ / shares	4.91	2.41	3.34
DILUTED NET INCOME PER LIMITED PARTNER UNIT (in dollars per unit) \| $ / shares	4.88	2.40	3.32
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING (in units) \| shares	149	137	130
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING (in units) \| shares	150	138	131

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
CONSOLIDATED STATEMENTS OF OPERATIONS
Interest expense, capitalized interest	$ 25	$ 16	$ 15

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 994	$ 514	$ 580
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	249	256	236
Equity compensation expense	110	98	68
Gain on sale of linefill and base gas	(21)	(21)	(4)
Deferred income tax (benefit)/expense	7		(9)
Equity earnings in unconsolidated entities, net of distributions	10	6	(8)
Net cash received/(paid) for terminated interest rate or foreign currency hedging instruments	12		(9)
Net gain on purchase of remaining 50% interest in PNGS			(9)
Other	2	11	(19)
Changes in assets and liabilities, net of acquisitions:
Trade accounts receivable and other	83	(59)	(744)
Inventory	518	(336)	(319)
Accounts payable and other current liabilities	401	(210)	602
Net cash provided by operating activities	2,365	259	365
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired (Note 3)	(1,390)	(407)	(219)
Change in restricted cash	20	(20)
Additions to property, equipment and other	(635)	(451)	(460)
Investment in unconsolidated entities			(4)
Net cash received/(paid) for sales and purchases of linefill and base gas	(22)	25	(9)
Proceeds from sales of assets and other investing activities	7	2	6
Net cash used in investing activities	(2,020)	(851)	(686)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) on PAA's revolving credit facility	(793)	49	(19)
Net borrowings/(repayments) on PAA's hedged inventory facility	(425)	200	20
Net borrowings on PNG's credit agreements	62	260
Repayment of PNGS debt			(446)
Proceeds from the issuance of senior notes	597	400	1,346
Repayments of senior notes	(200)	(175)	(430)
Net proceeds from the issuance of common units (Note 5)	889	296	458
Cash received for sale of noncontrolling interest in a subsidiary	370	268	26
Distributions paid to common unitholders (Note 5)	(575)	(512)	(468)
Distributions paid to general partner (Note 5)	(216)	(170)	(137)
Distributions to noncontrolling interests	(40)	(10)	(2)
Other financing activities	(14)	(2)	(10)
Net cash provided by/(used in) financing activities	(345)	604	338
Effect of translation adjustment on cash	(10)	(1)	(3)
Net increase/(decrease) in cash and cash equivalents	(10)	11	14
Cash and cash equivalents, beginning of period	36	25	11
Cash and cash equivalents, end of period	26	36	25
Cash paid for interest, net of amounts capitalized	254	253	214
Cash (received)/paid for income taxes, net of amounts refunded	$ 11	$ 21	$ (5)

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions	Total	Common Units	General Partner	Partners' Capital Excluding Noncontrolling Interests	Noncontrolling Interests
Balance at Dec. 31, 2008	$ 3,552	$ 3,441	$ 111	$ 3,552	$ 0
Balance (in units) at Dec. 31, 2008		123,000,000
Increase (Decrease) in Partners' Capital
Net income	580	$ 434	145	579	1
Sale of noncontrolling interest in a subsidiary (Note 5)	26	(37)	(1)	(38)	64
Distributions	(607)	(468)	(137)	(605)	(2)
Issuance of common units	$ 456	$ 447	9	456
Issuance of common units (in units)	11,040,000	11,000,000
Issuance of common units in connection with the PNGS Acquisition	$ 93	$ 91	2	93
Issuance of common units in connection with the PNGS Acquisition (in units)		2,000,000
Issuance of common units under LTIP	12	$ 12		12
Equity compensation expense (Note 10)	5	2	3	5
Other comprehensive income (loss)	48	46	2	48
Other	(6)	(3)	(3)	(6)
Balance at Dec. 31, 2009	4,159	$ 3,965	131	4,096	63
Balance (in units) at Dec. 31, 2009		136,000,000
Increase (Decrease) in Partners' Capital
Net income	514	$ 330	175	505	9
Sale of noncontrolling interest in a subsidiary (Note 5)	268	99	2	101	167
Distributions	(692)	(512)	(170)	(682)	(10)
Issuance of common units	$ 296	$ 290	6	296
Issuance of common units (in units)	4,780,000	5,000,000
Issuance of common units under LTIP	$ 16	$ 16		16
Equity compensation expense (Note 10)	16	4	9	13	3
Other comprehensive income (loss)	(5)	(5)		(5)
Other	1	2		2	(1)
Balance at Dec. 31, 2010	$ 4,573	$ 4,189	153	4,342	231
Balance (in units) at Dec. 31, 2010	141,199,175	141,000,000
Increase (Decrease) in Partners' Capital
Net income	$ 994	$ 730	236	966	28
Sale of noncontrolling interest in a subsidiary (Note 5)	370	63	1	64	306
Distributions	(831)	(575)	(216)	(791)	(40)
Issuance of common units	$ 889	$ 870	19	889
Issuance of common units (in units)	13,935,000	14,000,000
Issuance of common units under LTIP	$ 15	$ 15		15
Equity compensation expense (Note 10)	28	16	9	25	3
Other comprehensive income (loss)	(64)	(59)	(1)	(60)	(4)
Balance at Dec. 31, 2011	$ 5,974	$ 5,249	$ 201	$ 5,450	$ 524
Balance (in units) at Dec. 31, 2011	155,376,937	155,000,000

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net income	$ 994	$ 514	$ 580
Other comprehensive income/(loss)	(64)	(5)	48
Comprehensive income	930	509	628
Less: Comprehensive income attributable to noncontrolling interests	(24)	(9)	(1)
Comprehensive income attributable to Plains	$ 906	$ 500	$ 627

- Definition

The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to the reporting entity. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, but excludes any and all transactions which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 8, 9, 10, 11, 12, 13, 14
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 30
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph A5
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6518256

Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Glossary Other Comprehensive Income
-URI http://asc.fasb.org/extlink&oid=6519514

Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-URI http://asc.fasb.org/extlink&oid=6508144

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
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-Paragraph 38
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

- Definition

The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to noncontrolling interests, if any. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent.

+ References + Details

- Definition

The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to the economic entity, including both controlling (parent) and noncontrolling interests. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, including any and all transactions which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent.

+ References + Details

- Definition

This element represents Other Comprehensive Income or Loss, Net of Tax, for the period. Includes deferred gains or losses on qualifying hedges, unrealized holding gains or losses on available-for-sale securities, minimum pension liability, and cumulative translation adjustment. While for technical reasons this element has no balance attribute, the default assumption is a credit balance consistent with its label.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 12
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 31
-Article 5

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 22, 23, 24, 25
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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+ Details

- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 29
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period	$ 118	$ 123	$ 75
Reclassification adjustments	131	(24)	8
Deferred loss on cash flow hedges, net of tax	(154)	(73)	(151)
Currency translation adjustment	(42)	92	192
Proportionate share of our unconsolidated entities' other comprehensive income (loss)	1		(1)
Total period activity	(64)	(5)	48
Balance at end of period	54	118	123
Derivative Instruments
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period	(79)	18	161
Reclassification adjustments	131	(24)	8
Deferred loss on cash flow hedges, net of tax	(154)	(73)	(151)
Total period activity	(23)	(97)	(143)
Balance at end of period	(102)	(79)	18
Translation Adjustments
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period	198	106	(86)
Currency translation adjustment	(42)	92	192
Total period activity	(42)	92	192
Balance at end of period	156	198	106
Other
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period	(1)	(1)
Proportionate share of our unconsolidated entities' other comprehensive income (loss)	1		(1)
Total period activity	$ 1		(1)
Balance at end of period		$ (1)	$ (1)

Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2011

Organization and Basis of Presentation

Organization and Basis of Presentation

Note 1—Organization and Basis of 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-K 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 engage in the transportation, storage, terminalling and marketing of crude oil and refined products, as well as in the processing, transportation, fractionation, storage and marketing of natural gas liquids (“NGL”). The term NGL includes ethane and natural gasoline products as well as propane and butane, products which are also commonly referred to as liquid petroleum gas (“LPG”). The terms NGL and LPG are sometimes used interchangeably within this document depending on the context. Through our general partner interest and majority equity ownership position in PAA Natural Gas Storage, L.P. (NYSE: PNG), we also own and operate natural gas storage facilities. Our business activities are conducted through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. See Note 13 for further discussion of our three 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., a Delaware limited partnership. Plains All American GP LLC, a Delaware limited liability company, is Plains AAP, L.P.’s general partner. Plains All American 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. References to our “general partner,” as the context requires, include any or all of PAA GP LLC, Plains AAP, L.P. and Plains All American GP LLC. Plains AAP, L.P. and Plains All American GP LLC are essentially held by 18 owners with interests ranging from approximately 35% to less than 1%.

Definitions

Additional defined terms are used in the following notes and shall have the meanings indicated below:

AOCI	=	Accumulated other comprehensive income
Bcf	=	Billion cubic feet
Btu	=	British thermal unit
CAD	=	Canadian dollar
CERCLA	=	Federal Comprehensive Environmental Response, Compensation and Liability Act, as amended
DERs	=	Distribution equivalent rights
EBITDA	=	Earnings before interest taxes depreciation and amortization
FASB	=	Financial Accounting Standards Board
FERC	=	Federal Energy Regulatory Commission
GAAP	=	Generally accepted accounting principles in the United States
GATX	=	GATX Corporation
ICE	=	IntercontinentalExchange
IPO	=	Initial public offering
LIBOR	=	London Interbank Offered Rate
Link	=	Link Energy LLC
LLS	=	Light Louisiana Sweet
LTIP	=	Long-term incentive plan
Mcf	=	Thousand cubic feet
MLP	=	Master limited partnership
MTBE	=	Methyl tertiary-butyl ether
MQD	=	Minimum quarterly distribution
Nexen	=	Nexen Holdings U.S.A. Inc.
NJDEP	=	New Jersey Department of Environmental Protection
NPNS	=	Normal purchase normal sale
NYMEX	=	New York Mercantile Exchange
NYSE	=	New York Stock Exchange
PAA/Vulcan	=	PAA/Vulcan Gas Storage, LLC
Pacific	=	Pacific Energy Partners, L.P.
PLA	=	Pipeline loss allowance
PNG	=	PAA Natural Gas Storage, L.P.
PNGS	=	PAA Natural Gas Storage, LLC
PPT	=	Plains Products Terminals LLC (formerly known as Pacific Atlantic Terminals LLC)
Rainbow	=	Rainbow Pipe Line Company, Ltd.
RCRA	=	Federal Resource Conservation and Recovery Act, as amended
SG Resources	=	SG Resources Mississippi, LLC
SLC Pipeline	=	SLC Pipeline LLC
SOP	=	Shell Oil Products
TNM	=	Texas New Mexico
USD	=	United States dollar
Velocity	=	Velocity South Texas Gathering, LLC
White Cliffs	=	White Cliffs Pipeline, LLC
WTI	=	West Texas Intermediate
WTS	=	West Texas Sour

Basis of Consolidation and Presentation

The accompanying financial statements and related notes present and discuss our consolidated financial position as of December 31, 2011 and 2010, and the consolidated results of our operations, cash flows, changes in partners’ capital, comprehensive income and changes in accumulated other comprehensive income for the years ended December 31, 2011, 2010 and 2009. 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 Plains. The accompanying consolidated financial statements include Plains and all of its wholly owned subsidiaries. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We evaluate our equity investments for impairment in accordance with FASB guidance with respect to the equity method of accounting for investments in common stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature.

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

Revision of Prior Period Financial Statements

Limited Partner and General Partner Income Allocation

During 2011, we identified an error in the manner in which we allocate net income to our limited partners and general partner. Previously, we calculated net income available to limited partners based on the distribution paid during the period by first allocating the incentive distribution paid during the period to the general partner and then allocating the remaining net income based on ownership interests (98% limited partner and 2% general partner). We have revised this allocation to utilize the distributions pertaining to the period, a portion of which are paid in the subsequent period. This revision does not impact Net Income, Net Income Attributable to Plains, Net Income Per Limited Partner Unit or total Partners’ Capital. We have determined that the impact of this error is not material to the previously issued financial statements. We have presented these changes retrospectively in the Consolidated Balance Sheet, the Consolidated Statement of Operations and the Consolidated Statements of Changes in Partners’ Capital, which resulted in the following changes (in millions):

	As		As
	Reported		Revised
Net Income Attributable to Plains
For the Year Ended December 31, 2009:
Limited Partners	$	443	$	434
General Partner	136		145
	$	579	$	579

For the Year Ended December 31, 2010:
Limited Partners	$	338	$	330
General Partner	167		175
	$	505	$	505

Partners’ Capital
As of December 31, 2008:
Limited Partners	$	3,469	$	3,441
General Partner	83		111
	$	3,552	$	3,552

As of December 31, 2009:
Limited Partners	$	4,002	$	3,965
General Partner	94		131
	$	4,096	$	4,096

As of December 31, 2010:
Limited Partners	$	4,234	$	4,189
General Partner	108		153
	$	4,342	$	4,342

Revision of Prior Period Consolidated Statement of Cash Flows

During the second quarter of 2010, PNG completed its IPO of 13.5 million common units representing limited partner interests for net proceeds of approximately $268 million. Additionally, during the first quarter of 2009, a third party contributed approximately $26 million in cash for a 25% ownership interest in SLC Pipeline, a joint venture. The proceeds from these sales to noncontrolling interests were presented in our financial statements for the years ended December 31, 2010 and 2009 as cash flows from investing activities. Upon further evaluation, we now believe that this activity should have been presented as cash flows from financing activities. We have determined that the impact of this reclassification on our consolidated statement of cash flows for the years ended December 31, 2010 and 2009 is not material.

The following captions within the prior period consolidated statements of cash flows were impacted (in millions):

	Amounts Previously Reported						As Revised
	Year Ended December 31,						Year Ended December 31,
	2010			2009			2010			2009
Net cash used in investing activities	$	(583	)	$	(660	)	$	(851	)	$	(686	)
Net cash provided by financing activities	$	336		$	312		$	604		$	338
Net	$	(247	)	$	(348	)	$	(247	)	$	(348	)

- Definition

The entire disclosure for organization, consolidation and basis of presentation of financial statements disclosure.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 2-6
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Name Statement of Position (SOP)
-Publisher AICPA
-Number 94-6
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Name FASB Interpretation (FIN)
-Publisher FASB
-Number 46R
-Paragraph 4, 14, 15
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Note 2—Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We make significant estimates with respect to (i) purchases and sales accruals, (ii) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (iii) mark-to-market gains and losses on derivative instruments (pursuant to guidance issued by the FASB regarding fair value measurements), (iv) accruals and contingent liabilities, (v) equity compensation plan accruals, (vi) property and equipment and depreciation expense and (vii) allowance for doubtful accounts. Although we believe these estimates are reasonable, actual results could differ from these estimates.

Revenue Recognition

Supply and Logistics Segment Revenues. Revenues from sales of crude oil, LPG and refined products are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. Sales of crude oil, LPG and refined products consist of outright sales contracts and buy/sell arrangements as well as exchanges. Inventory purchases and sales under buy/sell transactions are treated as inventory exchanges and are presented net within Supply and Logistics segment revenues in our consolidated statements of operations.

Additionally, we may utilize derivatives in connection with the transactions described above. For commodity derivatives that are designated as cash flow hedges, derivative gains and losses are deferred to AOCI and recognized in revenues in the periods during which the underlying physical hedged transaction impacts earnings. Also, the ineffective portion of the change in fair value of cash flow hedges is recognized in revenues each period along with the change in fair value of derivatives that do not qualify for or are not designated for hedge accounting.

Transportation Segment Revenues. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil and refined products at a published tariff, as well as revenues associated with line leases for committed space on a particular system that may or may not be utilized. Tariff revenues are recognized either at the point of delivery or at the point of receipt pursuant to specifications outlined in the regulated and non-regulated tariffs. Revenues associated with line-lease fees are recognized in the month to which the lease applies, whether or not the space is actually utilized. The majority of our pipeline tariff and fee revenues are based on actual volumes and rates. As is common in the industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We value the variance of allowance volumes to actual losses at the estimated net realizable value (including the impact of gains and losses from derivative related activities) at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues. In addition, we have certain agreements that require counterparties to ship a minimum volume over an agreed upon period. Revenue is recognized at the latter of when the volume is shipped (pursuant to specifications outlined in the tariffs) or when the counterparty’s ability to make up the minimum volume has expired.

Facilities Segment Revenues. Our facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products, LPG and natural gas, LPG fractionation and isomerization services and natural gas processing services. Revenues generated in this segment include (i) storage fees that are generated when we lease storage capacity, (ii) terminalling fees, or throughput fees, that are generated when we receive crude oil, refined products or LPG from one connecting pipeline and redeliver the applicable product to another connecting carrier, (iii) hub service fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services, (iv) revenues from the sale of natural gas, (v) fees from LPG fractionation and isomerization and (vi) fees from gas processing services. We generate revenue through a combination of month-to-month and multi-year leases and processing arrangements. Storage fees resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized. Terminal fees are recognized as the crude oil, LPG or refined product exits the terminal and is delivered to the connecting carrier or third-party terminal. Hub service fees are recognized in the period the natural gas moves across our header system. Fees from LPG fractionation, isomerization services and gas processing services are recognized in the period when the services are performed. Revenues associated with the sale of natural gas are recognized at the time title to the product sold transfers to the purchaser or its designee. In addition, we have certain agreements that require counterparties to throughput a minimum volume over an agreed upon period. Revenue is recognized at the latter of when the volume exits the terminal or when the counterparty’s ability to make up the minimum volume has expired.

Purchases and Related Costs

Purchases and related costs include (i) the cost of crude oil, LPG, natural gas and refined products obtained in outright purchases, (ii) fees incurred for third-party transportation and storage, whether by pipeline, truck, rail, ship or barge, (iii) interest cost attributable to borrowings for inventory stored in a contango market and (iv) performance-related bonus accruals. These costs are recognized when incurred except in the case of products purchased, which are recognized at the time title transfers to us.

Field Operating Costs and General and Administrative Expenses

Field operating costs consist of various field operating expenses, including fuel and power costs, telecommunications, payroll and benefit costs (including equity compensation expense) for truck drivers and field personnel, third-party trucking transportation costs for our U.S. crude oil operations, maintenance and integrity management costs, regulatory compliance, environmental remediation, insurance, vehicle leases, and property taxes. General and administrative expenses consist primarily of payroll and benefit costs (including equity compensation expense), certain information systems and legal costs, office rent, contract and consultant costs and audit and tax fees.

Foreign Currency Transactions

Certain of our subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of subsidiaries with a Canadian dollar functional currency are translated at period-end rates of exchange, and revenues and expenses are translated at average exchange rates prevailing for each month. The resulting translation adjustments are made directly to a separate component of other comprehensive income in Partners’ Capital reflected on our consolidated balance sheet.

Certain of our subsidiaries also enter into transactions and have monetary assets and liabilities that are denominated in a currency other than the entities’ respective functional currencies. Gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities are included in the consolidated statements of operations. The revaluation of foreign currency transactions and monetary assets and liabilities resulted in a loss of approximately $2 million for the year ended December 31, 2011 and gains of approximately $2 million and $13 million for the years ended December 31, 2010 and 2009, respectively.

Cash and Cash Equivalents

Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. In accordance with our policy, outstanding checks are classified as accounts payable rather than negative cash. As of December 31, 2011 and 2010, accounts payable included approximately $58 million and $40 million, respectively, of outstanding checks that were reclassified from cash and cash equivalents.

Restricted Cash

Restricted cash at December 31, 2010 consisted of $20 million held by an escrow agent in connection with PNG’s February 2011 acquisition of SG Resources. See Note 3 for further discussion of this acquisition. We had no restricted cash at December 31, 2011.

Accounts Receivable

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of LPG, refined products and natural gas storage. These purchasers include, but are not limited to refineries, 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 risks related to our accounts receivable, we have in place a rigorous credit review process. We closely monitor market conditions in order to make a determination with respect to the amount, if any, of 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 standby letters of credit, “parental” guarantees or advance cash payments. At December 31, 2011 and 2010, we had received approximately $186 million and $197 million, respectively, of advance cash payments from third parties to mitigate credit risk. In addition, we enter into netting arrangements (contractual agreements that allow us and the counterparty to offset receivables and payables between the two) that cover a significant part of our transactions and also serve to mitigate credit risk.

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 December 31, 2011 and 2010, 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 approximately $5 million at both December 31, 2011 and 2010. Although we consider our allowance for doubtful trade accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

Inventory, Linefill, Base Gas and Long-term Inventory

Inventory primarily consists of crude oil, LPG and natural gas in pipelines, storage facilities and rail cars that are valued at the lower of cost or market, with cost determined using an average cost method within specific inventory pools.

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. During 2011, 2010 and 2009, we did not recognize material writedowns of such inventory. Linefill, base gas and minimum working inventory requirements in assets we own are recorded at historical cost and consist of crude oil, LPG and natural gas. We classify as linefill or base gas (i) our proportionate share of barrels used to fill a pipeline such that when an incremental barrel is pumped into or enters a pipeline it forces product out at another location, (ii) barrels that represent the minimum working requirements in tanks that we own and (iii) natural gas required to maintain the minimum operating pressure of natural gas storage facilities we own. During 2011, 2010 and 2009, we recorded gains of approximately $21 million, $21 million and $4 million, respectively, on the sale of pipeline linefill for proceeds of approximately $56 million, $72 million and $24 million, respectively.

Minimum working inventory requirements in third-party assets and other working inventory in our assets that is needed for our commercial operations are included within specific inventory pools in inventory (a current asset) in determining the average cost of operating inventory. At the end of each period, we reclassify the inventory not expected to be liquidated within the succeeding twelve months out of inventory, at average cost, and into long-term inventory, which is reflected as a separate line item within other assets on the consolidated balance sheet.

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

	December 31, 2011						December 31, 2010
	Volumes	Unit of Measure	Total Value		Price/ Unit (1)		Volumes	Unit of Measure	Total Value		Price/ Unit (1)
Inventory
Crude oil	5,361	barrels	$	483	$	90.10	14,132	barrels	$	1,100	$	77.84
LPG	6,885	barrels	438		$	63.62	7,395	barrels	366		$	49.49
Natural gas (2)	16,170	Mcf	51		$	3.15	13	Mcf	—		$	3.87
Other	N/A		6		N/A		N/A		25		N/A
Inventory subtotal			978						1,491

Linefill and base gas
Crude oil	9,366	barrels	514		$	54.88	9,159	barrels	478		$	52.19
Natural gas (2)	14,105	Mcf	48		$	3.40	11,194	Mcf	37		$	3.31
LPG	31	barrels	2		$	64.52	77	barrels	4		$	51.95
Linefill and base gas subtotal			564						519

Long-term inventory
Crude oil	1,714	barrels	127		$	74.10	1,761	barrels	128		$	72.69
LPG	150	barrels	8		$	53.33	505	barrels	26		$	51.49
Long-term inventory subtotal			135						154

Total			$	1,677					$	2,164

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

(2) The volumetric ratio of Mcf of natural gas to crude Btu equivalent is 6:1; thus, natural gas volumes can be approximately converted to barrels by dividing by 6.

Property and Equipment

In accordance with our capitalization policy, costs associated with acquisitions and improvements that expand our existing capacity, including related interest costs, are capitalized. For the years ended December 31, 2011, 2010 and 2009, capitalized interest was $25 million, $16 million and $15 million, respectively. We also capitalize expenditures for the replacement of partially or fully depreciated assets in order to maintain the service capability, level of production and/or functionality of our existing assets. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are expensed as incurred.

Property and equipment, net is stated at cost and consisted of the following (in millions):

	Estimated Useful	December 31,
	Lives (Years)	2011			2010
Crude oil pipelines and facilities	10 - 70	$	4,467		$	4,303
Storage and terminal facilities	30 - 70	3,385			2,740
Trucking equipment and other	3 - 15	110			106
Construction in progress	—	693			304
Office property and equipment	2 - 50	99			95
Land and other	N/A	275			266
		9,029			7,814
Accumulated depreciation		(1,289		)	(1,123		)

Property and equipment, net		$	7,740		$	6,691

Depreciation expense for the years ended December 31, 2011, 2010 and 2009 was $196 million, $235 million and $216 million, respectively.

We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets. During 2011 and 2010, we extended the depreciable lives of several of our crude oil and other storage facilities and pipeline systems based on an ongoing review to assess the useful lives of our property and equipment and to adjust those lives, if appropriate, to reflect current expectations given actual experience and current technology. These depreciable life extensions will prospectively reduce depreciation expense. For the years ended December 31, 2011 and 2010, these extensions reduced depreciation expense by approximately $60 million (incrementally by $37 million as compared to the prior year) and $23 million, respectively.

We also classify gains and losses on sales of assets and asset impairments as a component of depreciation and amortization in the consolidated statements of operations. During the years ended 2011 and 2010, we recognized losses on disposition of certain assets and impairments for assets taken out of service of approximately $11 million and $13 million, respectively.

Equity Method of Accounting

Our investments in the following entities are accounted for under the equity method of accounting:

Entity	Type of Operation	Our Ownership Interest
Settoon Towing, LLC	Barge Transportation Services	50	%
White Cliffs Pipeline, L.L.C.	Crude Oil Pipeline	34	%
Frontier Pipeline Company	Crude Oil Pipeline	22	%
Butte Pipe Line Company	Crude Oil Pipeline	22	%

We do not consolidate any part of the assets or liabilities of our equity investees. Our share of net income or loss is reflected as one line item on the income statement entitled “Equity earnings in unconsolidated entities” and will increase or decrease, as applicable, the carrying value of our investments in unconsolidated entities on the balance sheet. In addition, we include a proportionate share of our equity method investees’ unrealized gains and losses in other comprehensive income on our consolidated balance sheet. We also adjust our investment balances in these investees by the like amount. Distributions to the Partnership will reduce the carrying value of our investments and will be reflected on our cash flow statement netted against equity in earnings. In turn, contributions will increase the carrying value of our investments and will be reflected on our cash flow statement within investing activities.

Noncontrolling Interests

We account for noncontrolling interests in subsidiaries in accordance with FASB guidance specific to noncontrolling interests. FASB guidance requires all entities to report noncontrolling interests in subsidiaries as a component of equity in the consolidated financial statements. Noncontrolling interest represents the portion of assets and liabilities in a consolidated subsidiary that is owned by a third-party. See Note 5 for additional discussion regarding our noncontrolling interests.

Asset Retirement Obligations

FASB guidance establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including estimates related to (i) the time of the liability recognition, (ii) initial measurement of the liability, (iii) allocation of asset retirement cost to expense, (iv) subsequent measurement of the liability and (v) financial statement disclosures. FASB guidance also requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method.

Some of our assets, primarily related to our transportation and facilities segments, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. These assets have been in existence for many years and with regular maintenance will continue to be in service for many years to come. It is not possible to predict when demand for these transportation or storage services will cease, and we do not believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations. We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonably determine the settlement dates.

A small portion of our contractual or regulatory obligations is related to assets that are inactive or that we plan to take out of service and, although the ultimate timing and costs to settle these obligations are not known with certainty, we have recorded a reasonable estimate of these obligations. We have estimated that the fair value of these obligations was approximately $9 million and $5 million, respectively, at December 31, 2011 and 2010.

Impairment of Long-Lived Assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value in accordance with FASB guidance with respect to the accounting for the impairment or disposal of long-lived assets. Under this guidance, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized.

We periodically evaluate property and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. The subjective assumptions used to determine the existence of an impairment in carrying value include:

· whether there is an indication of impairment;

· the grouping of assets;

· the intention of “holding,” “abandoning” or “selling” an asset;

· the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and

· if an impairment exists, the fair value of the asset or asset group.

During 2011, 2010 and 2009, impairments of approximately $5 million, $13 million and less than $1 million, respectively, were recognized related predominately to assets that were taken out of service. These assets did not support spending the capital necessary to continue service and, in most instances, we utilized other assets to handle these activities.

Goodwill

Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized. In accordance with FASB guidance, we test goodwill at least annually (as of June 30) and on an interim basis if a triggering event occurs, such as an adverse change in business climate, to determine whether an impairment has occurred. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. A reporting unit is an operating segment or one level below an operating segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are our operating segments. FASB guidance requires a two step approach to testing goodwill for impairment. In Step 1, we compare the fair value of the reporting unit with the respective book values, including goodwill, by using an income approach based on a discounted cash flow analysis. This approach requires us to make long-term forecasts of future revenues, expenses and other expenditures. Those forecasts require the use of various assumptions and estimates, the most significant of which are net revenues (total revenues less purchases and related costs), operating expenses, general and administrative expenses and the weighted average cost of capital. Fair value of the reporting units is determined using significant unobservable inputs, or level 3 inputs in the fair value hierarchy. When the fair value is greater than book value, then the reporting unit’s goodwill is not considered impaired. If the book value is greater than fair value, then we proceed to Step 2. In Step 2, we compare the implied fair value of the reporting unit’s goodwill with the book value. A goodwill impairment loss is recognized if the carrying amount exceeds its fair value.

Through Step 1 of our annual testing of goodwill for potential impairment, which also includes a sensitivity analysis regarding the excess of our reporting unit’s fair value over book value, we determined that the fair value of each reporting unit was substantially greater than its respective book value, and therefore goodwill was not considered impaired. We will continue to monitor various potential indicators (including the financial markets) to determine if a triggering event occurs and will perform another goodwill impairment analysis if necessary.

The table below reflects our changes in goodwill (in millions):

	Transportation			Facilities		Supply & Logistics			Total (1)

Balance at December 31, 2009	$	608		$	308	$	371		$	1,287

2010 Goodwill Related Activity:
Nexen acquisition	18			—		54			72
Purchase price accounting adjustments (2)	3			—		—			3
Foreign currency translation adjustments	11			—		3			14
Balance at December 31, 2010	$	640		$	308	$	428		$	1,376

2011 Goodwill Related Activity:
Southern Pines acquisition (2)	—			301		—			301
Gardendale Gathering System acquisition(2)	155			—		—			155
Foreign currency translation adjustments	(5		)	—		(1		)	(6		)
Purchase price accounting adjustments and other (2)	28			—		—			28
Balance at December 31, 2011	$	818		$	609	$	427		$	1,854

(1) As of December 31, 2011, the total carrying amount of goodwill is net of approximately $3 million of accumulated impairment losses.

(2) Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation. This preliminary goodwill balance may be adjusted when the purchase price allocation is finalized. See Note 3 for additional discussion of our acquisitions.

Other Assets, Net

Other assets, net of accumulated amortization, consist of the following (in millions):

	December 31,
	2011			2010
Debt issue costs	$	53		$	47
Fair value of derivative instruments	20			20
Intangible assets	498			311
Other	59			58
	630			436
Accumulated amortization	(84		)	(54		)
	$	546		$	382

Costs incurred in connection with the issuance of long-term debt and amendments to our credit facilities are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization. Fully amortized debt issue costs and the related accumulated amortization are written off in conjunction with the refinancing or termination of the applicable debt arrangement. We capitalized debt issue costs of approximately $18 million and $7 million in 2011 and 2010, respectively. Approximately $11 million of gross debt issue costs were removed from our Consolidated Balance Sheet during 2011, primarily related to the restructuring of our credit facilities in August 2011.

Amortization expense related to other assets (including finite-lived intangible assets) for the three years ended December 31, 2011, 2010 and 2009 was $44 million, $22 million and $19 million, respectively. Our amortization expense for finite-lived intangible assets for the years ended December 31, 2011, 2010 and 2009 was $36 million, $14 million and $14 million, respectively.

Intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. Our intangible assets that have finite lives consist of the following (in millions):


		December 31, 2011							December 31, 2010
	Estimated Useful			Accumulated							Accumulated
	Lives (Years)	Cost		Amortization			Net		Cost		Amortization			Net
Customer contracts and relationships	1-20	$	426	$	(61	)	$	365	$	221	$	(34	)	$	187
Property tax abatement	7-13	38		(6		)	32		23		(2		)	21
Other agreements	30-70	26		(1		)	25		22		(1		)	21
Emission reduction credits (1)	N/A	8		—			8		45		—			45
		$	498	$	(68	)	$	430	$	311	$	(37	)	$	274

(1) Emission reduction credits are finite-lived and are subject to surrender from the date that they are first utilized. During 2011, approximately $37 million of emission reduction credits were surrendered as part of the permitting process associated with facility construction and were reclassified into construction in progress, which is included within Property and equipment on our Consolidated Balance Sheet.

The increase in intangible assets from December 31, 2010 was primarily related to intangibles acquired in connection with the Southern Pines, Gardendale Gathering System and Western acquisitions. See Note 3 for further discussion of our acquisition activities.

We estimate that our amortization expense related to finite-lived intangible assets for the next five years will be as follows (in millions):

2012	$	50
2013	$	47
2014	$	44
2015	$	41
2016	$	36

Environmental Matters

We record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record receivables for amounts recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery.

We expense expenditures that relate to an existing condition caused by past operations that do not contribute to current or future profitability. We record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. See Note 11 for further discussion of environmental remediation matters.

Income and Other Taxes

We estimate (i) income taxes in the jurisdictions in which we operate, (ii) net deferred tax assets and liabilities based on temporary differences that are expected to be recovered or settled at the enacted tax rates expected in future periods, (iii) valuation allowances for deferred tax assets and (iv) contingent tax liabilities for estimated exposures related to our current tax positions.

We adopted the provisions of the FASB guidance related to accounting for uncertainty in income taxes on January 1, 2007. Pursuant to this guidance, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and precedents of the taxing authority. As of December 31, 2011 and 2010, we have not recognized any material amounts in connection with uncertainty in income taxes.

See Note 7 for discussion of U.S. federal and state taxes and Canadian federal and provincial taxes.

Derivative Instruments and Hedging Activities

We record all open derivative instruments on the balance sheet as either assets or liabilities measured at their fair value pursuant to FASB guidance. This guidance requires that changes in the fair value of derivative instruments be recognized currently in earnings unless specific hedge accounting criteria are met. For cash flow hedges, the effective portion of the change in fair value is deferred in AOCI and reclassified into earnings when the underlying transaction affects earnings. For fair value hedges, the change in fair value of the derivative instrument is recognized in earnings. Additionally, the change in fair value of the hedged item, attributable to the hedged risk, is recognized as a basis adjustment to the hedged item and is also recognized in earnings. See Note 6 for further discussion.

Equity Compensation

See Note 10 for information regarding our accounting for equity compensation awards.

Net Income Per Limited Partner Unit

Basic and diluted net income per unit is determined by dividing our limited partners’ interest in net income attributable to Plains by the weighted average number of limited partner units outstanding during the period. Pursuant to FASB guidance regarding the application of the two-class method for MLPs, the limited partners’ interest in net income attributable to Plains is calculated by first reducing net income attributable to Plains by the distribution pertaining to the current period’s net income (including the incentive distribution interest in excess of the 2% general partner interest). Then, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement.

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the years ended 2011, 2010 and 2009:

	Year Ended December 31,
	2011			2010			2009
Numerator for basic and diluted earnings per limited partner unit:
Net income attributable to Plains	$	966		$	505		$	579
Less: General partner’s incentive distribution (1)	(221		)	(168		)	(136		)
Less: General partner 2% ownership	(15		)	(7		)	(9		)
Net income available to limited partners in accordance with the application of the two-class method for MLPs	$	730		$	330		$	434

Denominator:
Basic weighted average number of limited partner units outstanding	149			137			130
Effect of dilutive securities:
Weighted average LTIP units (2)	1			1			1
Diluted weighted average number of limited partner units outstanding	150			138			131

Basic net income per limited partner unit	$	4.91		$	2.41		$	3.34

Diluted net income per limited partner unit	$	4.88		$	2.40		$	3.32

(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 and limited partners in accordance with the contractual terms of the partnership agreement.

(2) Our LTIP awards (described in Note 10) 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 unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.

Recent Accounting Pronouncements

In December 2010, the FASB issued updated accounting guidance related to the calculation of the carrying amount of a reporting unit when performing the first step of a goodwill impairment test. More specifically, this update will require an entity to use an equity premise when performing the first step of a goodwill impairment test, and if a reporting unit has a zero or negative carrying amount, the entity must assess and consider qualitative factors to determine whether it is more likely than not that a goodwill impairment exists. The new accounting guidance is effective for impairment tests performed during fiscal years (and interim periods within those years) that begin after December 15, 2010. We adopted this guidance on January 1, 2011; however, as we currently do not have any reporting units with a zero or negative carrying amount, our adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

In December 2010, the FASB issued updated accounting guidance to clarify that pro forma disclosures should be presented as if a business combination that is determined to be material on an individual or aggregate basis occurred at the beginning of the prior annual period for purposes of preparing both the current reporting period and the prior reporting period pro forma financial information. These disclosures should be accompanied by a narrative description about the nature and amount of material, nonrecurring pro forma adjustments. The new accounting guidance is effective for business combinations consummated in periods beginning after December 15, 2010 and should be applied prospectively as of the date of adoption. We adopted this guidance on January 1, 2011. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

In January 2010, the FASB issued guidance to enhance disclosures related to the existing fair value hierarchy disclosure requirements. The fair value hierarchy consists of designation to one of three levels based on the nature of the inputs used in the valuation process. Level 1 measurements generally reflect quoted market prices in active markets for identical assets or liabilities, level 2 measurements generally reflect the use of significant observable inputs, and level 3 measurements typically utilize significant unobservable inputs. This new guidance requires a gross presentation of activities within the level 3 rollforward. This guidance was effective for annual and interim reporting periods beginning after December 15, 2010. We adopted this guidance on January 1, 2011. See Note 6 for additional disclosure. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

Accounting Pronouncements Not Yet Effective

In December 2011, the FASB issued an accounting standard update that will require disclosure of information to help reconcile differences in the offsetting requirements for assets and liabilities under U.S. GAAP and IFRS. Under this new guidance entities are required to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position, as well as instruments and transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires disclosure of collateral received and posted in connection with master netting agreements or similar arrangements. Entities will need to provide the following enhanced disclosures for both assets and liabilities within the scope of the new standard: (i) the gross amounts of those recognized assets and those recognized liabilities; (ii) the amounts offset to determine the net amounts presented in the statement of financial position; (iii) the net amounts presented in the statement of financial position; (iv) the amounts subject to an enforceable master netting arrangement or similar agreement not otherwise included in (ii); and (v) the net amount after deducting the amounts in (iv) from the amounts in (iii). The standard affects all entities with balances presented on a net basis in the financial statements, derivative assets and derivative liabilities, repurchase agreements, and financial assets and financial liabilities executed under a master netting or similar arrangement. Accordingly, the adoption of this guidance is not expected to have a material impact on our financial position as this standard only impacts the presentation of such financial information. This guidance is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods.

In September 2011, the FASB issued guidance to simplify the goodwill impairment test by permitting entities to perform a qualitative assessment to determine whether further impairment testing is necessary. If qualitative factors indicate that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, an entity need not perform the two-step goodwill impairment test. This guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, with earlier adoption permitted. The adoption of this guidance is not expected to have a material impact on our financial position, results of operations or cash flows.

In June 2011, the FASB issued new guidance regarding the presentation of comprehensive income. This guidance requires entities to present reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement in which the components of net income and components of other comprehensive income are presented. It also eliminates the current option under U.S. GAAP to present components of other comprehensive income within the statement of changes in stockholders’ equity. The components of comprehensive income will be required to be presented within either (i) a single continuous statement of comprehensive income or (ii) two separate but consecutive statements. This guidance is effective for interim and annual periods beginning after December 15, 2011, with earlier adoption permitted. Since this issuance only impacts the presentation of such financial information, adoption of this guidance is not expected to have a material impact on our financial position, results of operations or cash flows. On December 23, 2011, the FASB issued guidance to defer the new requirement to present reclassifications of other comprehensive income on the face of the income statement. Companies will still be required to adopt the other requirements contained in the new accounting standard for the presentation of comprehensive income.

In May 2011, the FASB issued guidance to amend certain measurement and disclosure requirements related to fair value in an effort to improve consistency with international reporting standards. This guidance is effective prospectively for interim and annual reporting periods beginning after December 15, 2011. Early adoption is not permitted. The adoption of this guidance is not expected to have a material impact on our financial position, results of operations or cash flows.

Acquisitions and Dispositions

12 Months Ended

Dec. 31, 2011

Acquisitions and Dispositions

Acquisitions and Dispositions

Note 3—Acquisitions and Dispositions

Pending Acquisition

BP NGL Acquisition. On December 1, 2011, we entered into a definitive agreement to acquire all outstanding shares of BP Canada Energy Company, a wholly owned subsidiary of BP Corporation North America Inc. (“BP North America”). Total consideration for the acquisition, which will be based on an October 1, 2011 effective date, is approximately $1.67 billion, subject to working capital and other adjustments. A cash deposit of $50 million was paid upon signing, and the balance, plus 2% interest from October 1, 2011, is payable in cash upon closing. Subject to Canadian and U.S. regulatory approvals and other customary closing conditions, the acquisition is expected to close in the second quarter of 2012.

Upon completion of this acquisition, we will become the indirect owner of all of BP North America’s Canadian-based NGL business and certain of BP North America’s NGL assets located in the upper-Midwest United States (collectively the “BP NGL Assets”). The BP NGL Assets to be acquired include varying ownership interests, and contractual rights relating to approximately 2,600 miles of NGL pipelines; approximately 20 million barrels of NGL storage capacity; seven fractionation plants with an aggregate net capacity of approximately 232,000 barrels per day; four straddle plants and two field gas processing plants with an aggregate net capacity of approximately six Bcf per day; and long-term and seasonal NGL inventories of approximately 10 million barrels as of October 1, 2011. Certain of these pipelines and storage assets are currently inactive. The acquired business also includes various third-party supply contracts at other field gas processing plants and a supply contract relating to a third-party owned straddle plant with throughput capacity of 2.5 Bcf per day, shipping arrangements on third-party NGL pipelines and long-term leases on 720 rail cars used to move product among various locations. Collectively, these assets and activities provide access to approximately 140,000 to 150,000 barrels per day of NGL supply that are transported through an integrated network to fractionation facilities and markets in Western and Eastern Canada and in the U.S. Subject to closing the transaction, we have also entered into an Integrated Supply and Trading Agreement, pursuant to which an affiliate of BP North America will, for a period of two years following the closing of the acquisition, continue to provide sourcing services for gas supply to feed certain of the straddle plants to be acquired as a result of the acquisition.

The following acquisitions were accounted for using the purchase method of accounting and the purchase price was determined in accordance with such method.

2011 Acquisitions

Southern Pines Acquisition

On February 9, 2011, PNG acquired 100% of the equity interests in SG Resources from SGR Holdings, L.L.C. (the “Southern Pines Acquisition”) for an aggregate purchase price of approximately $765 million in cash (approximately $750 million, net of cash and other working capital acquired). The primary asset of SG Resources is the Southern Pines Energy Center (“Southern Pines”), a FERC-regulated, salt-cavern natural gas storage facility located in Greene County, Mississippi. In connection with this acquisition, PNG obtained financing through a private placement of PNG common units to third-party purchasers and to us. See Note 5 for further discussion.

The preliminary fair value of assets acquired and liabilities assumed is as follows (in millions):

			Average
			Depreciable
Description	Amount		Life (in years)
Inventory	$	14	N/A
Property and equipment, net	341		5 - 70
Base gas	3		N/A
Other working capital (including $13 million of cash)	14		N/A
Intangible assets	92		2 - 10
Goodwill	301		N/A
Total	$	765

The fair value of assets acquired and liabilities assumed is preliminary and subject to change, pending completion of internal valuation procedures primarily related to the valuation of intangible assets and the various components of the property and equipment acquired. The preliminary allocation of fair value to intangible assets above is comprised of a tax abatement valued at approximately $15 million and contracts valued at approximately $77 million, which have lives ranging from 2 to 10 years. Amortization of customer contracts under the declining balance method of amortization was approximately $13 million during the year ended December 31, 2011 and is estimated to be approximately $14 million, $13 million, $11 million and $8 million for the years ending December 31, 2012, 2013, 2014 and 2015, respectively. Goodwill or indefinite lived intangible assets will not be subject to depreciation or amortization, but will be subject to periodic impairment testing and, if necessary, will be written down to fair value should circumstances warrant. We expect to finalize our purchase price allocation during the first quarter of 2012.

Several factors contributed to a purchase price in excess of the fair value of the net tangible and intangible assets acquired. Such factors included the strategic location of the Southern Pines facility, the limited alternative locations and the extended lead times required to develop and construct such facility, along with its operational flexibility, organic expansion capabilities and synergies anticipated to be obtained from combining Southern Pines with our existing asset base. This acquisition is reflected within our facilities segment.

Also in connection with the Southern Pines Acquisition, PNG became the owner, with the ability to remarket in the future, and ultimate obligor of the $100,000,000 Mississippi Business Finance Corporation Gulf Opportunity Zone Industrial Development Revenue Bonds (SG Resources Mississippi, LLC Project), Series 2009 and the $100,000,000 Mississippi Business Finance Corporation Gulf Opportunity Zone Industrial Development Revenue Bonds (SG Resources Mississippi, LLC Project), Series 2010 (collectively, the “GO Bonds”). These were originally issued to fund the expansion of the Southern Pines facility. PNG remarketed the GO Bonds in August 2011 (see Note 4).

In May 2011, PNG entered into an agreement with the former owners of SG Resources with respect to certain outstanding issues and purchase price adjustments as well as the distribution of the remaining 5% of the purchase price that was escrowed at closing (totaling $37 million). Pursuant to this agreement, PNG received approximately $10 million and the balance was remitted to the former owners. Funds received by PNG have been and will continue to be used to fund anticipated facility development and other related costs identified subsequent to closing. Approximately $3 million of capital expenditures were incurred related to matters covered by the agreement through December 31, 2011. Remaining amounts will be utilized to offset applicable cavern development expenditures as incurred. Any remaining amounts upon completion of applicable cavern development procedures will reduce goodwill. Additionally, the parties executed releases of any existing and future claims, subject to customary carve-outs.

Other 2011 Acquisitions

Western Acquisition. On December 29, 2011, we completed two transactions with Western Refining for a combined purchase price of approximately $220 million in cash. Through the first transaction, we acquired crude oil, refined products and LPG storage and the associated manifold and pumping equipment located at Western’s Yorktown, Virginia refinery site, which we will operate as a terminal, as well as certain intangible assets. The second transaction included an 82-mile, 16-inch segment of pipeline that originates in Chaves County, New Mexico and connects into our Basin Pipeline system at Jal, New Mexico. The transaction includes associated tankage, piping and other related assets at the Lynch and Jal Stations.

Gardendale Gathering System Acquisition. On November 29, 2011, we completed the acquisition of 100% of the member interests in Velocity from Velocity Midstream Partners, LLC for an aggregate purchase price of approximately $349 million in cash. The assets acquired included approximately 120 miles of crude oil and condensate gathering and transportation pipelines (the “Gardendale Gathering System”) in the Eagle Ford Shale. We recognized goodwill of approximately $155 million associated with this acquisition, which was primarily related to the potential incremental income from anticipated growth projects.

Additional 2011 Acquisitions. During 2011, we completed six additional acquisitions for an aggregate consideration of approximately $20 million. These acquisitions included propane storage and terminal facilities included within our facilities segment, a trucking business included in our transportation segment as well as the right to ship on third-party pipelines, the revenues of which are included in our supply and logistics segment.

The preliminary determination of fair value of assets acquired and liabilities assumed for all other acquisitions completed during 2011, including the Western and Gardendale Gathering System acquisitions, is as follows (in millions):

Description	Amount
Linefill	$	2
Property and equipment, net	282
Other working capital	(7		)
Intangible assets	152
Environmental liability	(9		)
Goodwill	169
Total	$	589

2010 Acquisitions

Nexen Acquisition. On December 30, 2010, we acquired from Nexen Holdings U.S.A. Inc. entities that hold crude oil gathering and transportation assets that primarily service Bakken area producers. The purchase price was approximately $229 million, in cash, including approximately $170 million for the business and physical assets and approximately $59 million for approximately 460,000 barrels of inventory and other working capital adjustments. The assets are primarily located in Northwestern North Dakota and Northeastern Montana and include (i) a lease gathering business, (ii) the Robinson Lake pipeline, a FERC-regulated 20-mile, 8-inch pipeline, (iii) eight truck terminals and (iv) various other contractual rights. These assets are included within our transportation and supply and logistics segments. We recognized goodwill of approximately $83 million associated with this acquisition.

Other 2010 Acquisitions. During 2010, we completed five additional acquisitions for aggregate consideration of approximately $178 million. These acquisitions included (i) a 34% interest in White Cliffs that is reflected within our transportation segment, (ii) an additional 11% interest in Capline pipeline that is reflected within our transportation segment and (iii) various other assets reflected within both our transportation and facilities segments. We did not recognize any goodwill for these acquisitions.

2009 Acquisitions

PNGS Acquisition. On September 3, 2009, we acquired the remaining 50% indirect interest in PAA/Vulcan for an aggregate purchase price of $215 million (“PNGS Acquisition”). The $215 million purchase price consisted of $90 million in cash paid at closing, approximately $91 million in equivalent value of PAA common units (1,907,305 PAA common units based on a 20 business-day average closing price per unit) issued to Vulcan Gas Storage LLC at closing, and up to $40 million of deferred/contingent cash consideration. The deferred/contingent consideration is payable in cash in two installments of $20 million each upon the achievement of certain performance milestones and events expected to occur over the next several years. Upon completion of the PNG IPO in May 2010, we paid the first $20 million installment. See Note 5 for additional discussion of the PNG IPO. The fair value of the remaining contingent consideration is approximately $19 million at December 31, 2011.

As a result of the transaction, we owned 100% of PNGS’s natural gas storage business and related operating entities, which were accounted for on a consolidated basis beginning in September 2009. We historically accounted for our 50% indirect interest in PAA/Vulcan under the equity method. We recorded a net gain of approximately $9 million, recorded in other income, in connection with (i) adjusting our previously owned 50% investment in PAA/Vulcan to fair value and (ii) terminating an agreement to supply natural gas to PNGS.

At the time of the PNGS Acquisition, PNGS owned and operated two natural gas storage facilities located in Louisiana and Michigan that had an aggregate working gas storage capacity of 40 Bcf and an aggregate peak injection and withdrawal capacity of 1.7 Bcf per day and 3.2 Bcf per day, respectively. Substantially all of PNGS’s revenues were derived from the provision of firm storage services under multi-year, fee-based contracts. The gas storage operations are reflected in our facilities segment.

The purchase price consisted of the following (in millions):

Cash	$	90
PAA equity	91
Paid at closing	181
Fair value of contingent consideration (1)	34
Total purchase price	$	215

(1) The deferred contingent cash consideration is payable in cash in two installments of $20 million each upon the achievement of certain performance milestones and events expected to occur over the next several years. The fair value of the deferred contingent cash consideration was based on a discounted cash flow model utilizing a discount rate of approximately 9%. Upon completion of the PNG IPO in May 2010, we paid the first $20 million contingent consideration installment.

The determination of fair value of the assets and liabilities related to the PNGS Acquisition was as follows (in millions):

Property, plant and equipment	$	791
Base gas	28
Goodwill	25
Intangible assets	23
Working capital and other long-term assets and liabilities	9
Debt	(446		)
Total	$	430

Other 2009 Acquisitions. During 2009, we completed six additional acquisitions for an aggregate consideration of approximately $178 million. These acquisitions included an additional 21% undivided joint interest in Capline and associated tankage, as well as various crude oil pipelines and pipeline systems that are all included within our transportation segment. We also acquired a natural gas processing business, a refined products terminal and various crude oil storage tanks and other related assets that are all included within our facilities segment. The goodwill associated with such acquisitions was approximately $27 million as of December 31, 2011.

Dispositions

During 2011, 2010 and 2009, we sold various property and equipment for proceeds totaling approximately $12 million, $3 million and $4 million, respectively. A loss of approximately $6 million, a gain of less than $1 million and a loss of less than $1 million were recognized in 2011, 2010 and 2009, respectively, related to these sales.

Debt

12 Months Ended

Dec. 31, 2011

Debt

Debt

Note 4—Debt

Debt consisted of the following (in millions):

	December 31,			December 31,
	2011			2010
SHORT-TERM DEBT
Credit Facilities (1):
Senior secured hedged inventory facility bearing a weighted-average interest rate of 1.5% and 2.1% at December 31, 2011 and December 31, 2010, respectively	$	75		$	500
PAA senior unsecured revolving credit facility, bearing a weighted-average interest rate of 1.6% and 0.7% at December 31, 2011 and December 31, 2010, respectively (2)	32			824
PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.1% and 3.2% at December 31, 2011 and December 31, 2010, respectively (3)	68			—
4.25% senior notes due September 2012 (4)	500			—
Other	4			2
Total short-term debt	679			1,326

LONG-TERM DEBT
Senior Notes:
4.25% senior notes due September 2012 (4)	—			500
7.75% senior notes due October 2012	—			200
5.63% senior notes due December 2013	250			250
5.25% senior notes due June 2015	150			150
3.95% senior notes due September 2015	400			400
5.88% senior notes due August 2016	175			175
6.13% senior notes due January 2017	400			400
6.50% senior notes due May 2018	600			600
8.75% senior notes due May 2019	350			350
5.75% senior notes due January 2020	500			500
5.00% senior notes due February 2021	600			—
6.70% senior notes due May 2036	250			250
6.65% senior notes due January 2037	600			600
Unamortized discounts	(13		)	(12		)
Senior notes, net of unamortized discounts	4,262			4,363
Credit Facilities and Other:
PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.1% and 3.2% at December 31, 2011 and December 31, 2010, respectively (3)	54			260
PNG GO Zone term loans, bearing a weighted-average interest rate of 1.5% at December 31, 2011	200			—
Other	4			8
Total long-term debt (2)	4,520			4,631
Total debt (5)	$	5,199		$	5,957

(1) During August 2011, we renewed, extended or refinanced our principal bank credit facilities, including PNG’s credit facility. See “Credit Facilities” below for further discussion.

(2) We classify as short-term certain borrowings under our PAA senior unsecured revolving credit facility. These borrowings are primarily designated as working capital borrowings, must be repaid within one year and are primarily for hedged LPG and crude oil inventory and NYMEX and ICE margin deposits.

(3) PNG classifies as short-term debt any borrowings under the PNG senior unsecured revolving credit facility that have been designated as working capital borrowings and must be repaid within one year. Such borrowings are primarily related to a portion of PNG’s hedged natural gas inventory.

(4) Our $500 million 4.25% senior notes will mature in September 2012 and thus are classified as short-term at December 31, 2011. The proceeds from the the issuance of these notes are being used to supplement capital available from our hedged inventory facility to fund working capital needs associated with base levels of routine waterborne cargos and for seasonal LPG inventory requirements. At December 31, 2010, approximately $466 million had been used to fund hedged inventory and would have been classified as short-term debt if funded on our credit facilities. After the $500 million 4.25% senior notes mature, we intend to use our recently renewed and expanded credit facilities to finance hedged inventory. Concurrent with the issuance of these senior notes, we entered into interest rate swaps whereby we receive fixed payments at 4.25% and pay three-month LIBOR plus a spread. See Note 6 for further discussion of our interest rate swaps.

(5) Our fixed-rate senior notes have a face value of approximately $4.8 billion and $4.4 billion as of December 31, 2011 and December 31, 2010, respectively. We estimate the aggregate fair value of these notes as of December 31, 2011 and December 31, 2010 to be approximately $5.4 billion and $4.7 billion, respectively. Our fixed-rate senior notes are traded among institutions, which 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 agreements approximates fair value as interest rates reflect current market rates.

Credit Facilities

PAA senior unsecured 364-day revolving credit agreement. In December 2011, we entered into a 364-day credit facility agreement with a borrowing capacity of $1.2 billion. As of December 31, 2011, this facility had not been activated. Pursuant to its terms, PAA may activate the facility at any time over a six-month period, resulting in a maturity 364 days from the activation date. Borrowings accrue interest based, at our election, on either the Eurocurrency Rate or the Base Rate, in each case plus a margin based on our credit rating at the applicable time.

During August 2011, we renewed, extended or refinanced our principal bank credit facilities, as discussed further below. In connection with these transactions, we terminated a $500 million, 364-day senior unsecured credit facility that was scheduled to expire in January 2012.

PAA senior unsecured revolving credit facility. In August 2011, we entered into an unsecured revolving credit agreement with a committed borrowing capacity of $1.6 billion (including a $600 million Canadian sub-facility) which contains an accordion feature that enables us to increase the committed capacity to $2.1 billion, subject to obtaining additional or increased lender commitments. The credit agreement provides for the issuance of letters of credit and has a maturity date in August 2016. Borrowings accrue interest based, at our election, on the Eurocurrency Rate, the Base Rate or the Canadian Prime Rate, in each case plus a margin based on our credit rating at the applicable time. This facility replaced a similar $1.6 billion senior unsecured revolving credit facility that was scheduled to mature in July 2012. Amounts outstanding were approximately $32 million at December 31, 2011 under this facility and approximately $824 million at December 31, 2010 under our previous revolving credit facility.

Senior secured hedged inventory facility. In August 2011, we replaced our previous $500 million senior secured hedged inventory facility that was scheduled to mature in October 2011 with a new $850 million senior secured hedged inventory facility (of which $250 million is available for the issuance of letters of credit) that expires in August 2013. Initial proceeds from the facility were used to refinance the outstanding balance of the previous facility, and subsequent proceeds from this facility will be used to finance purchased or stored hedged inventory. Subject to obtaining additional or increased lender commitments, the committed amount of this new facility may be increased to $1.35 billion. Obligations under the new committed facility are secured by the financed inventory and the associated accounts receivable and will be repaid from the proceeds of the sale of the financed inventory. Borrowings accrue interest based, at our election, on either the Eurocurrency Rate or the Base Rate, in each case plus a margin based on our credit rating at the applicable time. Amounts outstanding were approximately $75 million at December 31, 2011 under this facility and approximately $500 million at December 31, 2010 under our previous hedged inventory facility.

PNG senior unsecured credit agreement. In August 2011, PNG entered into a new $450 million, five-year senior unsecured credit agreement, which provides for (i) $250 million under a revolving credit facility, which may be increased at PNG’s option to $450 million (subject to receipt of additional or increased lender commitments) and (ii) two $100 million term loan facilities (the “GO Zone term loans”) pursuant to the purchase, at par, of the GO Bonds acquired by PNG in conjunction with the Southern Pines Acquisition (see Note 3). The revolving credit facility expires in August 2016, and the purchasers of the two GO Zone term loans have the right to put, at par, to PNG the GO Zone term loans in August 2016. The GO Bonds mature by their terms in May 2032 and August 2035, respectively. Borrowings under the revolving credit facility accrue interest, at PNG’s election, on either the Eurodollar Rate or the Base Rate, in each case plus an applicable margin. The GO Zone term loans accrue interest in accordance with the interest payable on the related GO Bonds purchased with respect thereto as provided in such GO Bonds and the GO Bonds Indenture pursuant to which such GO Bonds are issued and governed. This new PNG facility replaced a $400 million, three year senior unsecured revolving credit facility that was scheduled to mature in May 2013. Amounts outstanding were approximately $322 million at December 31, 2011 under the PNG credit agreement and approximately $260 million at December 31, 2010 under PNG’s previous revolving credit facility.

Senior Note Issuances

In January 2011, we completed the issuance of $600 million of 5.00% senior notes due February 1, 2021. The senior notes were sold at 99.521% of face value. Interest payments are due on February 1 and August 1 of each year, beginning on August 1, 2011. We used the net proceeds from this offering to reduce outstanding borrowings under our credit facilities and for general partnership purposes.

In July 2010, we completed the issuance of $400 million of 3.95% senior notes due September 15, 2015. The senior notes were sold at 99.889% of face value. Interest payments are due on March 15 and September 15 of each year, which began on September 15, 2010. We used the net proceeds from this offering to repay outstanding indebtedness under our credit facilities.

Our senior notes are co-issued, jointly and severally, by Plains All American Pipeline, L.P. and a 100%-owned consolidated finance subsidiary (neither of which have independent assets or operations). In August 2011, as permitted under the indentures governing the senior notes, PAA released the guarantees of each subsidiary guarantor in conjunction with the refinancing of our credit facilities. As such, our senior notes are no longer guaranteed by any of our subsidiaries.

Senior Note Repayments and Redemptions

On February 7, 2011, our $200 million 7.75% senior notes due 2012 were redeemed in full. In conjunction with the early redemption, we recognized a loss of approximately $23 million, recorded to Other income/(expense), net in our consolidated statement of operations. We utilized cash on hand and available capacity under our credit facilities to redeem these notes.

On September 15, 2010, our $175 million, 6.25% senior notes due 2015 were redeemed in full. In conjunction with the early redemption, we recognized a loss of approximately $6 million. We utilized cash on hand and available capacity under our credit facilities to redeem these notes.

Maturities

The weighted average life of our long-term debt outstanding at December 31, 2011 was approximately 10 years and the aggregate maturities for the next five years and thereafter are as follows (in millions):

Calendar Year	Payment
2012 (1)	$	—
2013	250
2014	—
2015	550
2016	429
Thereafter	3,300
Total (2)	$	4,529

(1) Our $500 million 4.25% senior notes will mature in September 2012 and thus are classified as short-term at December 31, 2011.

(2) Excludes aggregate unamortized net discount of $13 million and other long-term obligations of $4 million.

Covenants and Compliance

Our credit agreements and the indentures governing the senior notes contain cross-default provisions. Our credit agreements prohibit declaration or payments of distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting our ability to, among other things:

· grant liens on certain property;

· incur indebtedness, including capital leases;

· sell substantially all of our assets or enter into a merger or consolidation;

· engage in certain transactions with affiliates; and

· enter into certain burdensome agreements.

The PAA senior unsecured revolving credit facility, the senior secured hedged inventory facility and the PAA senior unsecured 364-day revolving credit facility treat a change of control as an event of default and also require us to maintain a debt-to-EBITDA coverage ratio that will not be greater than 5.00 to 1.00 or 5.50 to 1.00 on all outstanding debt during an acquisition period (generally, the period consisting of three fiscal quarters following an acquisition greater than $150 million).

For covenant compliance purposes, letters of credit and borrowings to fund hedged inventory and margin requirements are excluded when calculating the debt coverage ratio.

A default under our credit facilities would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with our credit agreements, our ability to make distributions of available cash is not restricted. As of December 31, 2011, we were in compliance with the covenants contained in our credit agreements and indentures.

PNG’s credit agreement contains covenants and events of default provisions that are substantially consistent with those contained in PNG’s previous credit facility. This new agreement restricts, among other things, PNG’s ability to make distributions of available cash to unitholders if any default or event of default, as defined in the credit agreement, exists or would result therefrom. In addition, the credit agreement contains restrictive covenants, including those that restrict PNG’s ability to grant liens, incur additional indebtedness, engage in certain transactions with affiliates, engage in substantially unrelated businesses, sell substantially all of its assets or enter into a merger or consolidation, and enter into certain burdensome agreements. In addition, the credit agreement contains certain financial covenants which, among other things, require PNG to maintain a debt-to-EBITDA coverage ratio that will not be greater than 5.00 to 1.00 on outstanding debt (5.50 to 1.00 during an acquisition period) and also require that PNG maintain an EBITDA-to-interest coverage ratio that will not be less than 3.00 to 1.00, as such terms are defined in the credit agreement.

Letters of Credit

In connection with our crude oil supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil. These letters of credit are issued under our PAA senior unsecured revolving credit facility, our senior secured hedged inventory facility and PNG’s senior unsecured revolving credit facility, and our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. At December 31, 2011 and 2010, we had outstanding letters of credit of approximately $33 million and $75 million, respectively.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References + Details

Partners' Capital and Distributions

12 Months Ended

Dec. 31, 2011

Partners' Capital and Distributions

Partners' Capital and Distributions

Note 5—Partners’ Capital and Distributions

Units Outstanding

Partners’ capital at December 31, 2011 consists of 155,376,937 common units outstanding, representing a 98% effective aggregate ownership interest in the Partnership and its subsidiaries after giving effect to the 2% general partner interest.

Distributions

We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter, less reserves established by our general partner for future requirements.

General Partner Incentive Distributions

Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, the general partner is typically entitled, without duplication, to 15% of amounts we distribute in excess of $0.450 per unit, referred to as our MQD, 25% of the amounts we distribute in excess of $0.495 per unit and 50% of amounts we distribute in excess of $0.675 per unit (referred to as “incentive distributions”).

Per unit cash distributions on our outstanding units and the portion of the distributions representing an excess over the MQD were as follows:

	Year
	2011				2010				2009
			Excess				Excess				Excess
	Distribution (1)		over MQD		Distribution		over MQD		Distribution		over MQD
First Quarter	$	0.9575	$	0.5075	$	0.9275	$	0.4775	$	0.8925	$	0.4425
Second Quarter	$	0.9700	$	0.5200	$	0.9350	$	0.4850	$	0.9050	$	0.4550
Third Quarter	$	0.9825	$	0.5325	$	0.9425	$	0.4925	$	0.9050	$	0.4550
Fourth Quarter	$	0.9950	$	0.5450	$	0.9500	$	0.5000	$	0.9200	$	0.4700

(1) Distributions represent those declared and paid in the applicable period.

In order to enhance our distribution coverage ratio and liquidity following a significant acquisition, our general partner may agree to reduce the amounts due to it as incentive distributions. Upon closing of the Pacific acquisition in November 2006, the Rainbow acquisition in May 2008 and the PNGS Acquisition in September 2009, our general partner agreed to reduce the amounts due to it as incentive distributions by a total of $83 million as displayed on an annual basis in the following table (in millions):

Acquisition	2007		2008		2009		2010		2011		Total
Pacific	$	20	$	15	$	15	$	10	$	5	$	65
Rainbow	—		3		6		1		—		10
PNGS	—		—		1		5		2		8
Total	$	20	$	18	$	22	$	16	$	7	$	83

The final $1 million of incentive distribution reductions related to these acquisitions was applied to the November 2011 distribution.

Beginning with the first distribution paid after closing the BP NGL acquisition, which is anticipated to occur in the second quarter of 2012, our general partner has agreed to reduce the amount of its incentive distributions by $15 million per year for two years and $10 million per year thereafter. See Note 3 to our Consolidated Financial Statements for further discussion of the BP NGL acquisition.

Total cash distributions made were as follows (in millions, except per unit amounts):

	Distributions Paid								Distributions
	Common		General Partner						per limited
Year	Units		Incentive		2%		Total		partner unit
2011	$	575	$	204	$	12	$	791	$	3.91
2010	$	512	$	160	$	10	$	682	$	3.76
2009	$	468	$	127	$	10	$	605	$	3.62

On January 10, 2012, we declared a cash distribution of $1.025 per unit on our outstanding common units. The distribution was paid on February 14, 2012 to unitholders of record on February 3, 2012, for the period October 1, 2011 through December 31, 2011. The total distribution paid was approximately $225 million, with approximately $159 million paid to our common unitholders and $3 million and $63 million paid to our general partner for its general partner and incentive distribution interests, respectively.

Noncontrolling Interests in a Subsidiary

As of December 31, 2011, noncontrolling interests in a subsidiary consisted of the following: (i) the approximate 36% interest in PNG and (ii) the 25% interest in SLC Pipeline.

PNG Initial Public Offering

On May 5, 2010, PNG completed its IPO of 13,478,000 common units representing limited partner interests at $21.50 per common unit. The number of units issued at closing included 1,758,000 common units issued pursuant to the full exercise of the underwriters’ over-allotment option. Net proceeds received by PNG from the sale of the 13,478,000 common units were approximately $268 million and were used to repay amounts outstanding under our credit facilities and for general partnership purposes. The common units offered represented approximately 23% of the outstanding equity of PNG.

Prior to the PNG IPO, we owned 100% of PNGS’ natural gas storage business, the predecessor of PNG, and related operating entities. Immediately prior to the closing of the IPO, we contributed 100% of the equity interests in PNGS and its subsidiaries to PNG in exchange for approximately 18.1 million common units, approximately 13.9 million Series A subordinated units, 11.5 million Series B subordinated units and a 2% general partner interest and incentive distribution rights. In conjunction with the PNG IPO, we recorded noncontrolling interest of $167 million associated with the book value of PNG sold to the public. We also recorded an increase to our partners’ capital of approximately $101 million associated with the net increase from our share of the proceeds received in the offering partially offset by the dilution of our interest in PNG resulting from the IPO.

Series A and Series B Subordinated Units. The Series A subordinated units are not entitled to receive any distributions until the common units have received the MQD ($1.35 on an annualized basis) plus any arrearages in the payment of the MQD from prior quarters. The Series A subordinated units will convert to common units once certain earnings and distribution targets are met for three consecutive, non-overlapping four-quarter periods. The Series B subordinated units are not entitled to participate in quarterly distributions. Instead, the Series B subordinated units convert to Series A subordinated units in distinct tranches upon the achievement of defined benchmarks tied to the amount of capacity in service at Pine Prairie and increases in PNG’s quarterly distributions. The Series B subordinated units will convert into Series A subordinated units on a one-for-one basis for each tranche when the respective benchmarks are reached for (i) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service, (ii) the distributable cash flow generated by PNG for two consecutive quarters sufficient to pay a quarterly distribution of at least the annualized distribution benchmark on the weighted average number of outstanding common units and Series A subordinated units and all of such Series B subordinated units and (iii) the quarterly distribution of available cash of at least the annualized distribution benchmark for two consecutive quarters on all outstanding common units and Series A subordinated units and the corresponding distributions on PNG’s general partner’s 2% interest and the related distributions on the incentive distribution rights.

Modifications of Holdings in and Conversion of PNG Subordinated Units

On August 16, 2010, the Amended and Restated Agreement of Limited Partnership of PNG was amended and restated (the “Second Amended and Restated Agreement”) to reduce the number of Series A subordinated units by 2.0 million and increase the number of Series B subordinated units by an equivalent amount. The Second Amended and Restated Agreement also increased the number of potential conversion tranches on Series B subordinated units from three to five. In addition, the terms of the Series B subordinated units were modified to extend the conversion period by raising the operating and financial performance benchmarks of approximately one-third of the Series B subordinated units outstanding prior to this modification. This amendment was intended to increase the distribution coverage and organic growth profile of PNG’s common and Series A subordinated units and improve PNG’s posture with respect to potential acquisitions. We accounted for this transaction as an exchange between entities under common control and accordingly, we reclassified the book value of the 2.0 million Series A subordinated units at the time of the modification to Series B subordinated units.

The following table sets forth the changes made to our holdings in the limited partner units of PNG as a result of the August 2010 modification (units in millions):

	Prior to Modification	Modification		Post Modification
PNG Units Owned by PAA:
Common Units	18.1	—		18.1
Series A Subordinated Units	13.9	(2.0	)	11.9
Common & Series A Subordinated Unit Subtotal	32.0	(2.0	)	30.0
Series B Subordinated Units (Performance Thresholds):
Tranche 1 ($1.44 / 29.6 Bcf)	4.6	(2.0	)	2.6
Tranche 2 ($1.53 / 35.6 Bcf)	3.8	(1.0	)	2.8
Tranche 3 ($1.63 / 41.6 Bcf)	3.1	(1.0	)	2.1
Tranche 4 ($1.71 / 48.0 Bcf)	—	3.0		3.0
Tranche 5 ($1.80 / 48.0 Bcf)	—	3.0		3.0
Series B Subordinated Unit Subtotal	11.5	2.0		13.5
Total PNG Units Owned by PAA (1)	43.5	—		43.5

(1) See “PNG Transaction Grants” in Note 10.

In February 2012, PNG modified the terms of the first three tranches of the PNG Series B subordinated units held by PAA. The modification increases the quarterly distribution benchmark for the first three of the five tranches to an annualized level of $1.71 per unit.

The following table presents the operational and financial benchmarks, as modified in February 2012 for conversion of the Series B subordinated units into Series A subordinated units for each tranche (units in millions):

	Series B Subordinated Units to Convert into Series A Subordinated Units	Working Gas Storage Capacity (Bcf)	Annualized Distribution Level
Tranche 1	2.6	29.6	$	1.71
Tranche 2	2.8	35.6	$	1.71
Tranche 3	2.1	41.6	$	1.71
Tranche 4	3.0	48.0	$	1.71
Tranche 5	3.0	48.0	$	1.80

PNG’s general partner will determine whether the in-service operational tests set forth above have been satisfied. To the extent that the operational tests described above are satisfied prior to or during the two-quarter period applicable to the financial tests described above, the holder of the Series B subordinated units subject to conversion will be entitled to receive the quarterly distribution payable with respect to the second quarter of such two-quarter period. In all other circumstances, where the operational tests are satisfied following the two-quarter period applicable to the financial tests, the holder of the Series B subordinated units subject to conversion will be entitled to receive any distribution payable following the satisfaction of such operational tests.

Any Series B subordinated units that remain outstanding as of December 31, 2018 will automatically be cancelled.

Following conversion of any Series B subordinated units into Series A subordinated units, such converted Series B subordinated units will further convert into common units (together with any other outstanding Series A subordinated units) to the extent that the tests for conversion of the Series A subordinated units are satisfied. In determining whether such conversion tests have been satisfied, the Series B subordinated units that have converted into Series A subordinated units will be treated as Series A subordinated units from and after the date of their conversion into Series A subordinated units.

If at the time the above operational and financial tests are satisfied, the subordination period has already ended and all outstanding Series A subordinated units have converted into common units, the Series B subordinated units will instead convert directly into common units on a one-for-one basis and participate in the quarterly distribution payable to common units.

PNG Common Unit Issuance

During February 2011, in connection with the Southern Pines Acquisition, PNG completed a private placement of approximately 17.4 million PNG common units to third-party purchasers for net proceeds of approximately $370 million. In addition, we purchased approximately 10.2 million PNG common units for approximately $230 million, including our proportionate general partner contribution of $12 million (collectively, “the PNG offering”). Also, during May 2011, a portion of the PNG Transaction Grants vested and was settled with 58,672 PNG units, which were owned by us. See Note 10 for further detail. As a result of these transactions, our aggregate ownership interest in PNG decreased from approximately 77% to approximately 64%. The following table sets forth our ownership changes in the limited partner units of PNG from December 31, 2010 to December 31, 2011 (units in millions):

	December 31, 2010	February 2011 PNG Issuance	Transaction Grants		December 31, 2011
PNG Units Owned by PAA:
Common Units	18.1	10.2	(0.1	)	28.2
Series A Subordinated Units	11.9	—	—		11.9
Series B Subordinated Units	13.5	—	—		13.5
Total PNG Units Owned by PAA	43.5	10.2	(0.1	)	53.6

In addition to our limited partner interest, we also own the general partner’s 2% interest and the incentive distribution rights in PNG.

In conjunction with the PNG offering, we recorded an increase in noncontrolling interest of $306 million and an increase to our partners’ capital of approximately $64 million. The increases result from the portion of the proceeds attributable to the respective ownership interests in PNG, adjusted for the impact of the dilution of our ownership interest resulting from the transaction.

Formation of SLC Pipeline LLC

During the fourth quarter of 2008, we completed construction on a 94-mile expansion of the Salt Lake City Area system from Wahsatch, Utah to Salt Lake City. During the first quarter of 2009, this pipeline became fully operational. Pursuant to a master formation agreement, we contributed the pipeline with a book value of approximately $254 million to a newly formed joint venture, SLC Pipeline. Holly Energy Partners-Operating, L.P. (“HEP”) contributed approximately $26 million in cash for a 25% ownership in SLC Pipeline. We own the remaining 75% interest in SLC Pipeline and control the joint venture, and therefore, have consolidated the financial results. We recognized a loss in partners’ capital of approximately $38 million related to the formation of the SLC Pipeline joint venture during 2009. This loss represented the difference between HEP’s contribution of cash and the book value of its 25% interest in the net assets of SLC Pipeline.

Noncontrolling Interests Rollforward

The following table reflects the changes in the noncontrolling interests in partners’ capital (in millions):

	For the Year Ended December 31,
	2011			2010			2009
Beginning balance	$	231		$	63		$	—
Sale of noncontrolling interests in subsidiaries	306			167			64
Net income attributable to noncontrolling interests	28			9			1
Distributions to noncontrolling interests	(40		)	(10		)	(2		)
Equity compensation expense	3			3			—
Net deferred loss on cash flow hedges	(4		)	—			—
Other	—			(1		)	—
Ending Balance	$	524		$	231		$	63

The following table sets forth the impact upon net income attributable to Plains given effect to the changes in our ownership interest in PNG and SLC Pipeline, which is recognized in partners’ capital (in millions):

	Year Ended December 31,
	2011		2010		2009
Net income attributable to Plains	$	966	$	505	$	579
Transfers to the noncontrolling interests:
Increase in capital from sale of PNG units	64		101		—
Decrease in capital from sale of interest in SLC Pipeline	—		—		(38		)
Change from net income attributable to Plains and net transfers to the noncontrolling interest	$	1,030	$	606	$	541

LTIP Vesting

In connection with the settlement of vested LTIP awards, we issued 242,762 common units during 2011 with a fair value of approximately $15 million.

Equity Offerings

During the three years ended December 31, 2011, we completed the following equity offerings of our common units as shown in the table below (in millions, except unit and per unit data). See “PNGS Acquisition” below for discussion of additional common units issued in 2009 in connection with such acquisition.

						General
		Gross		Proceeds		Partner					Net
Period	Units Issued	Unit Price		from Sale		Contribution		Costs			Proceeds
November 2011 (1)	6,000,000	$	65.03	$	390	$	9	$	(13	)	$	386
March 2011 (1)	7,935,000	$	64.00	508		10		(15		)	503
2011 Total	13,935,000			$	898	$	19	$	(28	)	$	889

November 2010 (1)	4,780,000	$	62.60	$	299	$	6	$	(9	)	$	296
2010 Total	4,780,000			$	299	$	6	$	(9	)	$	296

September 2009 (1)	5,290,000	$	46.70	$	247	$	5	$	(6	)	$	246
March 2009 (1)	5,750,000	$	36.90	212		4		(6		)	210
2009 Total	11,040,000			$	459	$	9	$	(12	)	$	456

(1) These offerings of common units were underwritten transactions that required us to pay a gross spread. The net proceeds from these offerings were used to reduce outstanding borrowings under our credit facilities and for general partnership purposes.

PNGS Acquisition

In September 2009, we issued 1,907,305 common units valued at approximately $91 million in order to satisfy a portion of the PNGS Acquisition purchase price. In conjunction with the issuance, we received a contribution from our general partner of approximately $2 million. See Note 3 for further discussion.

Class B Units of Plains AAP, L.P.

In August 2007, the owners of Plains AAP, L.P. authorized the board of directors of Plains All American GP LLC to issue Class B units of Plains AAP, L.P. (“AAP LP Class B units”). At December 31, 2011, approximately 183,500 AAP LP Class B units were outstanding, of which 80,063 had been earned. A total of 16,500 AAP LP Class B units are reserved for future issuances. See Note 10 for further discussion of the AAP LP Class B units.

- Definition

The entire disclosure for the formation, structure, control and ownership of the partnership. Disclosures related to accounts comprising partners' capital. Includes balances of general partners' capital account, limited partners' capital account, preferred partners' capital account and total partners' capital account and units outstanding; accumulated other comprehensive income; amount and nature of changes to amount of partner's capital and units outstanding by class, rights and privileges for each class of units; distribution policies and distributions paid by unit class; impact of and correction of an error in previously issued financial statements; limitations of partners' liability; redemption, conversion and distribution policies; and deferred compensation related to the issuance of units.

+ References + Details

Derivatives and Hedging Instruments

12 Months Ended

Dec. 31, 2011

Derivatives and Hedging Instruments

Derivatives and Hedging Instruments

Note 6—Derivatives and Hedging Instruments

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 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 NYMEX, ICE and over-the-counter 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 positions and ensure that those positions are consistent with our objectives and approved strategies. 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 contain certain commodity price-related risks that we manage in various ways, including the use of derivative instruments. Our policy is (i) to only purchase product for which we have a market, (ii) to structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not to 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 summarized 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 December 31, 2011, net derivative positions related to these activities included:

· An approximate 177,300 barrels per day net long position (total of 5.3 million barrels) associated with our crude oil purchases, which was unwound ratably during January 2012 to match monthly average pricing.

· A net short spread position averaging approximately 30,800 barrels per day (total of 10.3 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through January 2013. These derivatives are time spreads consisting of offsetting purchases and sales between two different months. Our use of these derivatives does not expose us to outright price risk.

· Approximately 9,200 barrels per day on average (total of 6.7 million barrels) of WTS/WTI crude oil basis swaps through December 2013, which hedge anticipated sales of crude oil (WTI). These derivatives are grade spreads between two different grades of crude oil. Our use of these derivatives does not expose us to outright price risk.

· Approximately 6,000 barrels per day on average (total of 2.2 million barrels) of LLS/WTI crude oil basis swaps January 2012 through December 2012, which hedge anticipated sales of crude oil (LLS). These derivatives are grade spreads between two different grades of crude oil. Our use of these derivatives does not expose us to outright price risk.

· A short swap position of approximately 14.6 Bcf through April 2012 related to anticipated sales of natural gas.

· A long swap position of approximately 0.6 Bcf through April 2013 related to anticipated purchases of natural gas.

Storage Capacity Utilization — We own approximately 80 million barrels of crude oil, LPG and refined products storage capacity other than that used in our transportation operations. This storage may be leased to third parties or utilized in our own supply and logistics activities, including for the storage of inventory in a contango market. For capacity allocated to our supply and logistics operations, we have utilization risk if the market structure is backwardated. As of December 31, 2011, we used derivatives to manage the risk of not utilizing approximately 3.7 million barrels per month of storage capacity through 2012. These positions are a combination of calendar spread options and futures contracts. These positions involve no outright price exposure, but instead represent potential offsetting purchases and sales between time periods (first month versus second month for example).

Inventory Storage — At times, we elect to purchase and store crude oil, LPG and refined products inventory in conjunction with our supply and logistics activities. When we purchase and store inventory, we enter into physical sales contracts or use derivatives to mitigate price risk associated with the inventory. As of December 31, 2011, we had derivatives totaling approximately 5.0 million barrels hedging our inventory. These positions are a combination of futures, swaps and option contracts.

Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We utilize derivative instruments to hedge a portion of the anticipated sales of the allowance oil that is to be collected under our tariffs. As of December 31, 2011, our PLA hedges included (i) a net short position consisting of crude oil futures and swaps for an average of approximately 1,500 barrels per day (total of 2.2 million barrels) through December 2015, (ii) a long put option position of approximately 0.4 million barrels through December 2012 and (iii) a long call option position of approximately 0.9 million barrels through December 2015.

Base Gas Management –– Our gas storage facilities require minimum levels of base gas to operate. For our natural gas storage facilities that are under construction, we anticipate purchasing base gas in future periods as construction is completed. We use derivatives to hedge such anticipated purchases of natural gas. As of December 31, 2011, we have a long swap position of approximately 3.0 Bcf through April 2013 related to anticipated base gas purchases.

All of our commodity derivatives that qualify for hedge accounting are designated as cash flow hedges. We have determined that substantially all of our physical purchase and sale agreements qualify for the NPNS exclusion. Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the NPNS scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings.

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 December 31, 2011, AOCI includes deferred losses of $133 million that relate to open and terminated interest rate derivatives that were designated for hedge accounting. The terminated interest rate derivatives were cash-settled in connection with the issuance or refinancing of debt agreements. The deferred gain related to these instruments is being amortized to interest expense over the terms of the hedged debt instruments.

During the second and third quarters of 2011, we entered into forward starting interest rate swaps to hedge the underlying benchmark interest rate related to forecasted debt issuances through 2015. The following table summarizes the terms of our forward starting interest rate swaps (notional amounts in millions):

Hedged Transaction	Number and Types of Derivatives Employed	Notional Amount		Expected Termination Date	Average Rate Locked		Accounting Treatment
Anticipated debt offering	4 forward starting swaps (10-year)	$	200	6/15/2012	3.46	%	Cash flow hedge
Anticipated debt offering	6 forward starting swaps (30-year)	$	250	6/17/2013	4.24	%	Cash flow hedge
Anticipated debt offering	2 forward starting swaps (30-year)	$	50	6/16/2014	3.94	%	Cash flow hedge
Anticipated debt offering	10 forward starting swaps (30-year)	$	250	6/15/2015	3.60	%	Cash flow hedge

During June 2011 and August 2011, PNG entered into three interest rate swaps to fix the interest rate on a portion of PNG’s outstanding debt. The swaps have an aggregate notional amount of $100 million with an average fixed rate of 0.95%. Two of these swaps terminate in June 2014 and the remaining swap terminates in August 2014. These swaps are designated as cash flow hedges.

Concurrent with our January 2011 senior notes issuance, we terminated three forward starting interest rate swaps. These swaps had an aggregate notional amount of $100 million and an average fixed rate of 3.6%. We received cash proceeds of $12 million associated with the termination of these swaps.

During July 2009, we entered into four interest rate swaps for which we receive fixed interest payments and pay floating-rate interest payments based on three-month LIBOR plus an average spread of 2.42% on a semi-annual basis. The swaps have an aggregate notional amount of $300 million with fixed rates of 4.25%. Two of the swaps terminated in September 2011, and two of the swaps will terminate in September 2012. The swaps that terminate in 2012 are designated as fair value hedges.

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 risks of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts, forwards and options. As of December 31, 2011, AOCI includes net deferred gains of approximately $10 million that relate to open and settled foreign currency derivatives that were designated for hedge accounting. These foreign currency derivatives hedge the cash flow variability associated with CAD-denominated interest payments on CAD-denominated intercompany notes as a result of changes in the exchange rate.

As of December 31, 2011, our outstanding foreign currency derivatives also include derivatives we use to hedge USD-denominated crude oil purchases and sales in Canada. In addition, we may from time to time hedge the commodity price risk associated with a CAD-denominated commodity transaction with a USD-denominated commodity derivative. In conjunction with entering into the commodity derivative, we may enter into a foreign currency derivative to hedge the resulting foreign currency risk. These foreign currency derivatives are generally short-term in nature and are not designated for hedge accounting.

The following table summarizes our open forward exchange contracts that exchange CAD for USD on a net basis (in millions):

	CAD		USD		Average Exchange Rate
2012	$	15	$	15	CAD $1.01 to USD $1.00
2013	$	9	$	9	CAD $1.00 to USD $1.00

Summary of Financial Impact

For derivatives that qualify as a cash flow hedge, changes in fair value of the effective portion of the hedges are deferred to AOCI and recognized in earnings in the periods during which the underlying physical transactions impact earnings. For our interest rate swaps that qualify as a fair value hedge, changes in the fair value of the derivative and changes in the fair value of the underlying hedged item, attributable to the hedged risk, are recognized in earnings each period. 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 reflected as operating cash flows in our consolidated statements of cash flows.

A summary of the impact of our derivative activities recognized in earnings for the years ended December 31, 2011 and 2010 is as follows (in millions):

	Year Ended December 31, 2011								Year Ended December 31, 2010
				Derivatives							Derivatives
	Derivatives in			Not					Derivatives in		Not
	Hedging			Designated					Hedging		Designated
Location of gain/(loss)	Relationships (1)(2)(3)(5)			as a Hedge (4)		Total			Relationships (1)(2)(3)		as a Hedge (4)			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	(161	)	$	99	$	(62	)	$	14	$	2		$	16

Transportation segment revenues	—			—		—			2		—			2

Facilities segment revenues	11			—		11			—		—			—

Purchases and related costs	6			—		6			8		(12		)	(4		)

Field operating costs	—			1		1			—		3			3

Interest Rate Derivatives

Interest expense	1			—		1			1		2			3

Foreign Exchange Derivatives

Supply and Logistics segment revenues	—			1		1			—		2			2

Purchases and related costs	—			—		—			—		2			2

Other income/(expense), net	6			—		6			—		(1		)	(1		)

Total Gain/(Loss) on Derivatives Recognized in Income	$	(137	)	$	101	$	(36	)	$	25	$	(2	)	$	23

(1)	Amounts represent derivative gains and losses that were reclassified from AOCI to earnings during the period to coincide with the earnings impact of the respective hedged transaction.
(2)	Amounts include losses of approximately $8 million and $1 million for the years ended December 31, 2011 and 2010, respectively, that represent the ineffective portion of our cash flow hedges. These amounts relate to commodity derivatives and were recognized in Supply and Logistics segment revenues during the respective periods.
(3)	Interest expense includes net gains of approximately $2 million and approximately $1 million for the years ended December 31, 2011 and 2010, respectively, associated with outstanding interest rate swaps, which are designated as a fair value hedge.
(4)	Includes realized and unrealized gains or losses for derivatives not designated for hedge accounting during the period.
(5)	Includes unrealized gains of approximately $6 million reclassified from AOCI to earnings during the period to offset a lower of cost or market adjustment relating to the carrying value of PNG’s inventory.

The following table summarizes the derivative assets and liabilities on our consolidated balance sheet on a gross basis as of December 31, 2011 (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	$	72	Other current assets	$	(47	)
	Other long-term assets	20		Other long-term assets	(2		)
Interest rate derivatives	Other current assets	1		Other current liabilities	(24		)
				Other long-term liabilities	(114		)
Foreign currency derivatives	Other current assets	1

Total derivatives designated as hedging instruments		$	94		$	(187	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	87	Other current assets	$	(39	)
	Other long-term assets	6		Other long-term assets	(3		)
				Other current liabilities	(1		)
Total derivatives not designated as hedging instruments		$	93		$	(43	)

Total derivatives		$	187		$	(230	)

The following table summarizes the derivative assets and liabilities on our consolidated balance sheet on a gross basis as of December 31, 2010 (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	$	71	Other current assets	$	(70	)
				Other long-term assets	(1		)
				Other current liabilities	(1		)
Interest rate derivatives	Other current assets	10
Total derivatives designated as hedging instruments		$	81		$	(72	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	11	Other current assets	$	(68	)
	Other long-term assets	20
	Other current liabilities	2		Other current liabilities	(10		)
Interest rate derivatives	Other current assets	4
	Other long-term assets	1
Foreign currency derivatives	Other current assets	1
Total derivatives not designated as hedging instruments		$	39		$	(78	)

Total derivatives		$	120		$	(150	)

As of December 31, 2011, there was a net loss of approximately $99 million deferred in AOCI, excluding tax effects. The total amount of 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, (ii) interest expense accruals associated with underlying debt instruments or (iii) the recognition of a foreign currency gain or loss upon the remeasurement of certain CAD-denominated intercompany balances. Of the total net loss deferred in AOCI at December 31, 2011, we expect to reclassify a net gain of approximately $21 million to earnings in the next twelve months. Of the remaining deferred loss in AOCI, a net gain of approximately $9 million is expected to be reclassified to earnings prior to 2015 with the remaining deferred loss of $129 million being reclassified to earnings through 2045. These amounts are predominantly based on market prices at the current period end, thus actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

During the year ended December 31, 2011, we reclassified a gain of approximately $2 million from AOCI to earnings as a result of anticipated hedged transactions that are probable of not occurring. During the year ended December 31, 2010, all of our hedged transactions were probable of occurring. The net deferred gain/(loss), excluding tax effects, recognized in AOCI for derivatives during the years ended December 31, 2011 and 2010 are as follows (in millions):

	For the Years Ended December 31,
	2011			2010
Commodity derivatives, net	$	(15	)	$	(82	)
Foreign exchange derivatives, net	—			(2		)
Interest rate derivatives, net	(136		)	8
Total	$	(151	)	$	(76	)

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting agreement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through 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 December 31, 2011, we had a net broker payable of approximately $7 million (consisting of initial margin of $52 million reduced by $59 million of variation margin that had been returned to us). As of December 31, 2010, we had a net broker receivable of approximately $99 million (consisting of initial margin of $56 million increased by $43 million of variation margin that had been posted by us). At December 31, 2011 and 2010, 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.

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 December 31, 2011 and 2010. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which affects the placement of assets and liabilities within the fair value hierarchy levels.

	Fair Value as of December 31, 2011 (in millions)										Fair Value as of December 31, 2010 (in millions)
Recurring Fair Value Measures (1)	Level 1		Level 2			Level 3		Total			Level 1			Level 2		Level 3			Total
Commodity derivatives	$	80	$	1		$	12	$	93		$	(16	)	$	—	$	(30	)	$	(46	)
Interest rate derivatives	—		(137		)	—		(137		)	—			—		15			15
Foreign currency derivatives	—		1			—		1			—			—		1			1
Total	$	80	$	(135	)	$	12	$	(43	)	$	(16	)	$	—	$	(14	)	$	(30	)

(1) Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.

The determination of the fair values above includes not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit) but also the impact of our nonperformance risk on our liabilities. The fair value of our commodity derivatives, interest-rate derivatives and foreign currency derivatives includes adjustments for credit risk. Our credit adjustment methodology uses market observable inputs and requires judgment. There were no changes to any of our valuation techniques during the period.

Level 1

Included within level 1 of the fair value hierarchy are exchange-traded commodity derivatives such as futures, options and swaps. The fair value of exchange-traded commodity derivatives is based on unadjusted quoted prices in active markets and is therefore classified within level 1 of the fair value hierarchy.

Level 2

Included within level 2 of the fair value hierarchy are over-the-counter commodity, interest rate and foreign currency derivatives that are traded in active markets. The fair value of these derivatives is based on broker or dealer price quotations which are corroborated with market observable inputs.

Level 3

Included within level 3 of the fair value hierarchy are over-the-counter commodity derivatives that are traded in markets that are active but not sufficiently active to warrant level 2 classification in our judgment and certain physical commodity contracts. The fair value of our level 3 commodity derivatives is based on broker or dealer price quotations or a valuation model. Our valuation models utilize inputs such as forward prices but do not involve significant management judgments.

Rollforward of Level 3 Net Liability

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

	Year Ended December 31,
	2011			2010
Beginning Balance	$	(14	)	$	(28	)
Unrealized gains/(losses):
Included in earnings (1)	17			(22		)
Included in other comprehensive income	2			3
Settlements	21			42
Derivatives entered into during the period	3			(9		)
Transfers out of level 3	(17		)	—
Ending Balance	$	12		$	(14	)

Change in unrealized gains/(losses) included in earnings relating to level 3 derivatives still held at the end of the periods	$	22		$	(27	)

(1) We reported unrealized gains and losses associated with level 3 commodity derivatives in our consolidated statements of operations as Supply and Logistics segment revenues. Gains and losses associated with interest rate derivatives are reported in our consolidated statements of operations as Interest expense. Gains and losses associated with foreign currency derivatives are reported in our consolidated statements of operations as either Supply and Logistics segment revenues, Purchases and related costs, or Other income/(expense), net.

During the first quarter of 2011, we transferred interest rate and commodity derivatives with an aggregate fair value of $17 million from level 3 to level 2. This transfer resulted from the implementation of additional valuation procedures, using market observable inputs, to validate the broker or dealer price quotations used for fair value measurement. Our policy is to recognize transfers between levels as of the beginning of the reporting period in which the transfer occurred.

We believe that a proper analysis of our level 3 gains or losses must incorporate the understanding that these items are generally used to hedge our commodity price risk, interest rate risk and foreign currency exchange risk and will therefore be offset by gains or losses on the underlying transactions.

- Definition

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 45
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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+ Details

Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes

Income Taxes

Note 7—Income Taxes

U.S. Federal and State Taxes

As an MLP, we are not subject to U.S. federal income taxes; rather the tax effect of our operations is passed through to our unitholders. Although we are subject to state income taxes in some states, the impact to the years ended December 31, 2011, 2010, and 2009 was immaterial.

Canadian Federal and Provincial Taxes

In 2010 and prior years, our Canadian operations were operated through a combination of corporate entities subject to Canadian federal and provincial taxes and a limited partnership which was treated as a flow-through entity for tax purposes. Due to changes in Canadian legislation and the Fifth Protocol to the U.S./Canada Tax Treaty, we restructured our Canadian investment on January 1, 2011. As of this date, all of our Canadian operations are conducted within entities that are treated as corporations for Canadian tax purposes (flow through for U.S. tax purposes) and that are subject to Canadian federal and provincial taxes. Additionally, payments of interest and dividends from Canada to other Plains entities are subject to Canadian withholding tax that is treated as income tax expense.

Tax Components

Components of income tax expense are as follows (in millions):

	Year Ended December 31,
	2011			2010			2009
Current tax (benefit)/expense:
State income tax	$	2		$	1		$	2
Canadian federal and provincial income tax	36			(2		)	13
Total current tax (benefit)/ expense	$	38		$	(1	)	$	15

Deferred tax (benefit)/expense:
State income tax	$	(2	)	$	1		$	—
Canadian federal and provincial income tax	9			(1		)	(9		)
Total deferred tax (benefit)/expense	$	7		$	—		$	(9	)
Total income tax (benefit)/expense	$	45		$	(1	)	$	6

The difference between tax expense based on the statutory federal income tax rate and our effective tax expense is summarized as follows (in millions):

	Year Ended December 31,
	2011				2010				2009
Income before tax	$	1,039			$	513			$	586
Partnership earnings not subject to current Canadian tax	(909			)	(509			)	(585			)
	$	130			$	4			$	1
Canadian federal and provincial corporate tax rate	27			%	28			%	29			%
Income tax at statutory rate	$	35			$	1			$	—

Current tax (benefit)/expense:
Canadian withholding tax	$	12			$	—			$	—
Canadian period tax as a result of book versus tax differences	(9			)	—				4
Canadian permanent differences between book and tax	(2			)	(3			)	9
State income tax	2				1				2
Current income tax (benefit)/expense	$	38			$	(1		)	$	15

Deferred tax expense:
State deferred income tax	$		(2	)	$		1		$		—
Canadian deferred tax (benefit)/expense as a result of book versus tax differences	9				(1			)	(9			)
Deferred income tax (benefit)/expense	$	7			$	—			$	(9		)
Total income tax (benefit)/expense	$	45			$	(1		)	$	6

Deferred tax assets and liabilities, which are included net within other long-term liabilities and deferred credits in our consolidated balance sheet, result from the following (in millions):

	December 31,
	2011			2010
Deferred tax assets:
Book accruals in excess of current tax deductions	$	18		$	4
Total deferred tax assets	18			4

Deferred tax liabilities:
Property, plant and equipment in excess of tax values	(147		)	(128		)
Total deferred tax liabilities	(147		)	(128		)
Net deferred tax liabilities	$	(129	)	$	(124	)

Generally, tax returns for our Canadian entities are open to audit from 2007 through 2011. Our U.S. and state tax years are generally open to examination from 2008 to 2011.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 136, 172
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 43, 44, 45, 46, 47, 48, 49
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
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-Section 50
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-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32718-109319

Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Paragraph 9
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

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-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32559-109319

+ Details

Major Customers and Concentration of Credit Risk

12 Months Ended

Dec. 31, 2011

Major Customers and Concentration of Credit Risk

Major Customers and Concentration of Credit Risk

Note 8—Major Customers and Concentration of Credit Risk

Marathon Petroleum Corporation and its affiliates accounted for 16%, 14% and 14% of our revenues for each of the three years ended December 31, 2011, 2010 and 2009, respectively. ConocoPhillips Company accounted for 10%, 10% and 12% of our revenues for the years ended December 31, 2011, 2010 and 2009, respectively. No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2011. The majority of revenues from these customers pertain to our supply and logistics operations. We believe that the loss of these customers would have only a short-term impact on our operating results. There is risk, however, that we would not be able to identify and access a replacement market at comparable margins.

Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers and shippers of crude oil. This industry concentration has the potential to impact our overall exposure to credit risk in that the customers may be similarly affected by changes in economic, industry or other conditions. We review credit exposure and financial information of our counterparties and generally require letters of credit for receivables from customers that are not considered creditworthy, unless the credit risk can otherwise be reduced. See Note 2 for additional discussion of our accounts receivable and our review of credit exposure.

- Definition

The entire disclosure for any concentrations existing at the date of the financial statements that make an entity vulnerable to a reasonably possible, near-term, severe impact. This disclosure informs financial statement users about the general nature of the risk associated with the concentration, and may indicate the percentage of concentration risk as of the balance sheet date.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15A
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Statement of Position (SOP)
-Number 94-6
-Paragraph 21, 22, 24
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 21
-URI http://asc.fasb.org/extlink&oid=6947722&loc=d3e13537-108611

Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 275
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-Section 50
-Paragraph 16
-URI http://asc.fasb.org/extlink&oid=6927468&loc=d3e6327-108592

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
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-Paragraph 20
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-SubTopic 10
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-Paragraph 18
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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-Topic 275
-SubTopic 10
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-Paragraph 21
-URI http://asc.fasb.org/extlink&oid=6927468&loc=d3e6442-108592

+ Details

Related Party Transactions

12 Months Ended

Dec. 31, 2011

Related Party Transactions

Related Party Transactions

Note 9—Related Party Transactions

Reimbursement of Expenses of Our General Partner and its Affiliates

We do not pay our general partner a management fee, but we do reimburse our general partner for all direct and indirect costs of services provided to us or incurred on our behalf, including the costs of employee, officer and director compensation and benefits allocable to us as well as all other expenses necessary or appropriate to the conduct of our business (other than expenses related to grants of AAP LP Class B units). We record these costs on the accrual basis in the period in which our general partner incurs them. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Total costs reimbursed by us to our general partner for the years ended December 31, 2011, 2010 and 2009 were $419 million, $374 million and $328 million, respectively.

Vulcan Energy Corporation

In December 2010, Vulcan Energy Corporation sold its 50.1% ownership interest in our general partner. Substantially all of the interest sold was acquired by existing owners of our general partner or their affiliates.

Occidental Petroleum Corporation

As of December 31, 2011, a subsidiary of Occidental Petroleum Corporation (“Oxy”) owned approximately 35% of our general partner interest and had a representative on the board of directors of Plains All American GP LLC. During the three years ended December 31, 2011, we recognized sales and transportation storage revenues and purchased petroleum products from companies affiliated with Oxy. These transactions were conducted at posted tariff rates or prices that we believe approximate market. See detail below (in millions):

	For the Year Ended December 31,
	2011		2010		2009
Revenues	$	2,568	$	2,189	$	181

Purchases and related costs	$	361	$	221	$	164

We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with affiliates of Oxy were as follows (in millions):

	At December 31,
	2011		2010
Trade accounts receivable and other receivables	$	132	$	379

Accounts payable	$	155	$	124

Other

We also have transactions with companies in which we hold an investment accounted for under the equity method of accounting (see Note 2 for information related to these investments). During the three years ended December 31, 2011, we utilized transportation services provided by these companies. Costs related to these services totaled approximately $33 million, $36 million and $34 million for the years ended December 31, 2011, 2010 and 2009, respectively. Accounts payable at December 31, 2011 and 2010 were approximately $5 million and $3 million, respectively. These transactions were conducted at posted tariff rates or contracted rates that we believe approximate market rates.

- Definition

The entire disclosure for related party transactions, including the nature of the relationship(s), a description of the transactions, the amount of the transactions, the effects of any change in the method of establishing the terms of the transaction from the previous period, stated interest rate, expiration date, terms and manner of settlement per the agreement with the related party, and amounts due to or from related parties. If the entity and one or more other entities are under common ownership or management control and this control affects the operating results or financial position, disclosure includes the nature of the control relationship even if there are no transactions between the entities. Disclosure may also include the aggregate amount of current and deferred tax expense for each statement of earnings presented where the entity is a member of a group that files a consolidated tax return, the amount of any tax related balances due to or from affiliates as of the date of each statement of financial position presented, the principal provisions of the method by which the consolidated amount of current and deferred tax expense is allocated to the members of the group and the nature and effect of any changes in that method. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Article 4
-Section 08
-Paragraph k

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Article 3A
-Section 04
-Paragraph b

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 57
-Paragraph 1-4
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39622-107864

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39549-107864

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39603-107864

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(k))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39691-107864

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39678-107864

+ Details

Equity Compensation Plans

12 Months Ended

Dec. 31, 2011

Equity Compensation Plans

Equity Compensation Plans

Note 10—Equity Compensation Plans

PAA Long-Term Incentive Plan Awards

Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan (the “1998 Plan”), the 2005 Long-Term Incentive Plan (the “2005 Plan”) and the PPX Successor Long-Term Incentive Plan (the “PPX Successor Plan”) for employees and directors, as well as the Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan (the “2006 Plan”) for non-officer employees. The 1998 Plan, 2005 Plan and PPX Successor Plan authorize the issuance of an aggregate of 5.4 million common units deliverable upon vesting. Although other types of awards are contemplated under the plans, currently outstanding awards are limited to “phantom units,” which mature into the right to receive common units of PAA (or cash equivalent) upon vesting. Some awards also include distribution equivalent rights (“DERs”). Subject to applicable vesting criteria, a DER entitles the grantee to a cash payment equal to the cash distribution paid on an outstanding common unit. The 2006 Plan authorizes the grant of approximately 2.1 million “tracking units” which, upon vesting, represent the right to receive a cash payment in an amount based upon the market value of a common unit at the time of vesting. Our general partner is entitled to reimbursement by us for any costs incurred in settling obligations under the plans.

At December 31, 2011, the following LTIP awards, denominated in PAA units, were outstanding (units in millions):

		PAA
LTIP Units		Distribution	Estimated Unit Vesting Date
Outstanding		Required	2012	2013	2014	2015	Thereafter
2.6	(1)	$3.75 - $4.45	0.9	0.6	0.5	0.6	—
1.4	(2)	$3.80 - $4.25	0.6	0.5	0.2	0.1	—
4.0	(3) (4)		1.5	1.1	0.7	0.7	—

(1) These LTIP awards have performance conditions requiring the attainment of an annualized PAA distribution of between $3.75 and $4.45 and vest upon the later of a certain date or the attainment of such levels. If the performance conditions are not attained while the grantee remains employed by us, or the grantee does not meet employment requirements, these awards will be forfeited. For purposes of this disclosure, vesting dates are based on an estimate of future distribution levels and assume that all grantees remain employed by us through the vesting date.

(2) These LTIP awards have performance conditions requiring the attainment of an annualized PAA distribution of between $3.80 and $4.25. For these LTIP awards, fifty percent will vest at specified dates regardless of whether the performance conditions are attained. For purposes of this disclosure, vesting dates are based on an estimate of future distribution levels and assume that all grantees remain employed by us through the vesting date.

(3) Approximately 2.2 million of the 4.0 million outstanding PAA LTIP awards also include DERs, of which 1.7 million had vested as of December 31, 2011.

(4) LTIP units outstanding do not include Class B units of Plains AAP, L.P. (“AAP LP Class B units”) described below.

Class B Units of Plains AAP, L.P.

In August 2007, the owners of Plains AAP, L.P. authorized the issuance of up to 200,000 AAP LP Class B Units. AAP LP Class B units become earned in various increments upon the achievement of PAA distribution levels of between $3.50 and $4.80 (or in some cases, within 180 days thereof). When earned, the AAP LP Class B unit awards are entitled to participate in distributions paid by Plains AAP, L.P. in excess of $11 million (as adjusted for debt service costs and excluding special distributions funded by debt) per quarter. Assuming all 200,000 AAP LP Class B units were granted and earned, the maximum participation would be 8% of Plains AAP, L.P.’s distribution in excess of $11 million (as adjusted) each quarter. The following table contains a summary of AAP LP Class B unit awards:

	Reserved for Future Grants		Outstanding	Outstanding Units Earned	Grant Date Fair Value Of Outstanding Class B Units (1)
					(in millions)
Balance as of December 31, 2010	24,500		175,500	80,063	$	40
Class B unit issuances	(8,000	)	8,000	—	4
Class B unit forfeitures	—		—	—	—
Class B units earned	—		—	—	—
Balance as of December 31, 2011	16,500		183,500	80,063	$	44

(1) Of the grant date fair value, approximately $9 million was recognized as expense during both years ended December 31, 2011 and 2010.

Although the entire economic burden of the AAP LP Class B units, which are equity classified, is borne solely by Plains AAP, L.P. and does not impact our cash or units outstanding, the intent of the AAP LP Class B units is to provide a performance incentive and encourage retention for certain members of our senior management. Therefore, we recognize the grant date fair value of the AAP LP Class B units as compensation expense over the service period. The expense is also reflected as a capital contribution and thus, results in a corresponding credit to Partners’ Capital in our Consolidated Financial Statements.

PNG Long-Term Incentive Plan Awards

During April 2010, PNG’s general partner adopted the PAA Natural Gas Storage, L.P. 2010 Long Term Incentive Plan (the “PNG Plan”) for employees, directors and consultants. The PNG Plan limits the number of PNG common units that may be delivered pursuant to awards under the plan to 3 million units. Although other types of awards are contemplated under the plan, currently outstanding awards are limited to phantom units, which mature into the right to receive common units of PNG (or cash equivalent) upon vesting. Some awards also include DERs.

At December 31, 2011, the following LTIP awards, denominated in PNG units, were outstanding (units in millions):

		PNG
LTIP Units		Distribution	Estimated Unit Vesting Date
Outstanding		Required	2012	2013	2014	2015	Thereafter
0.3	(1)	$1.55 - $1.90	—	—	—	0.1	0.2
0.2	(2)	Other	—	0.1	0.1	—	—
0.5	(3) (4)		—	0.1	0.1	0.1	0.2

(1) These LTIP awards have performance conditions requiring the attainment of an annualized PNG distribution of between $1.55 and $1.90 and vest upon the later of a certain date or the attainment of such levels. For purposes of this disclosure, vesting dates are based on an estimate of future distribution levels and assume that all grantees remain employed by us through the vesting date.

(2) These LTIP awards have performance conditions requiring the conversion of PNG’s Series A and Series B subordinated units (see Note 5). For purposes of this disclosure, vesting dates are based on an estimate of future distribution levels and assume that all grantees remain employed by us through the vesting date.

(3) Approximately 0.3 million of the 0.5 million outstanding PNG LTIP awards also include DERs, of which less than 0.1 million had vested as of December 31, 2011.

(4) LTIP units outstanding do not include the PNG Transaction Grants or Class B units of PNGS GP LLC described below.

PNG Long-term Incentive Plan Award Modification. On February 2, 2012, the Board of Directors of PNG’s general partner approved the modification of certain awards previously granted under the PNG Plan. As a result of the modification, approximately 232,500 equity-classified phantom unit awards will now vest in the following manner: (i) approximately 70,000 awards, with distribution equivalent rights also modified to begin payment in February 2012, will vest upon the date PNG pays an annualized distribution of at least $1.45, (ii) approximately 70,000 awards, with distribution equivalent rights also modified to begin payment in May 2013, will vest upon the date PNG pays an annualized distribution of at least $1.50 and (ii) the remainder, with distribution equivalent rights also modified to begin payment in May 2014, will vest upon the date PNG pays an annualized distribution of at least $1.55. Fifty percent of any awards that have not vested as of the November 2016 distribution date will vest at that time and the remainder will expire. Additionally, 232,500 of equity-classified phantom unit awards with vesting terms originally tied to the conversion of PNG’s Series A and Series B subordinated units were modified such that all these awards will now fully vest upon conversion of the Series A subordinated units to common units. Distribution equivalent rights were also granted with respect to these awards beginning February 2012. There was no financial impact at the time of the modification; however, we anticipate that we will recognize additional equity compensation expense in the future as a result of the modification.

PNG Transaction Grants

During September 2010, we entered into agreements with certain of our officers, pursuant to which these officers acquired an aggregate of 375,000 phantom common units, phantom Series A subordinated units, and phantom Series B subordinated units representing a portion of the limited partner interests of PNG issued to us in the PNG IPO. The awards, referred to herein as “PNG Transaction Grants,” will vest upon the completion of the service period and certain performance conditions, including the conversion of PNG’s Series A subordinated units into common units of PNG and the conversion of PNG’s Series B subordinated units into Series A subordinated units of PNG. Upon vesting, these awards will be settled with outstanding common or Series A subordinated units of PNG currently owned by us, resulting in a dilution of our interest in PNG. As of December 31, 2011, 62,500 PNG Transaction Grants had vested in common units.

Class B Units of PNGS GP LLC

During July 2010, the Board of Directors of PNG’s general partner authorized the issuance of 165,000 Class B units of PNGS GP LLC (“PNGS GP LLC Class B units”). During 2011, 16,500 PNGS GP LLC Class B units were forfeited. As of December 31, 2011, 74,250 units were outstanding, and the remaining 90,750 units are reserved for future grants. The PNGS GP LLC Class B units earn the right to participate in distributions (i.e. become “earned”) in 25% increments 180 days following annualized PNG distribution levels of $2.00, $2.30, $2.50 and $2.70. In addition, 50% of the applicable earned units vest immediately upon becoming earned units and the remaining 50% vest on the fifth anniversary of the date of grant. If PNGS GP LLC Class B units become earned units after the fifth anniversary of the date of grant, 100% of such units will vest immediately upon becoming earned units. When earned, the PNGS GP LLC Class B units participate in quarterly distributions paid to PNG’s general partner to the extent such distributions exceed $2.5 million per quarter. Assuming all 165,000 PNGS GP LLC Class B units were granted and earned, the maximum participation rate would be 6% of PNG’s quarterly general partner distribution in excess of $2.5 million. As the PNG distribution levels required for vesting are not currently considered to be probable of occurring, no expense was recognized for the PNGS GP LLC Class B Units during the year ended December 31, 2011.

Other Consolidated Equity Compensation Information

Our LTIP awards include both liability classified and equity classified awards. In accordance with FASB guidance regarding share-based payments, the fair value of our liability classified LTIP awards is calculated based on the closing market price of the underlying PAA or PNG units at each balance sheet date and adjusted for the present value of any distributions that are estimated to occur on the underlying units over the vesting period that will not be received by the award recipients. The fair value of our equity classified LTIP awards is calculated based on the closing market price of the PAA or PNG units on the respective grant dates and adjusted for the present value of any distributions that are estimated to occur on the underlying units over the vesting period that will not be received by the award recipient. This fair value is recognized as compensation expense over the service period.

Our LTIP awards typically contain performance conditions based on the attainment of certain annualized distribution levels and vest upon the later of a certain date or the attainment of such levels. For awards with performance conditions (such as distribution targets), expense is accrued over the service period only if the performance condition is considered to be probable of occurring. When awards with performance conditions that were previously considered improbable become probable, we incur additional expense in the period that our probability assessment changes. This is necessary to bring the accrued obligation associated with these awards up to the level it would be as if we had been accruing for these awards since the grant date. Our DER awards typically contain performance conditions based on the attainment of certain annualized distribution levels and become earned upon the attainment of such levels. The DERs terminate with the vesting or forfeiture of the underlying LTIP award. For liability classified awards, we recognize DER payments in the period the payment is earned as compensation expense. For equity classified awards, we recognize DER payments in the period it is paid as a reduction of partners’ capital.

Prior to PNG’s IPO and adoption of the PNG Plan, certain PNG officers and other individuals were granted LTIP awards under the PAA LTIP Plans. In connection with the adoption of the PNG plan, substantially all of the then outstanding PAA LTIP awards held by PNG officers were converted to PNG LTIP awards. We recognized incremental compensation expense of less than $1 million during the twelve months ended December 31, 2010 as a result of this modification.

Our accrued liability at December 31, 2011 related to all outstanding liability-classified LTIP awards and DERs is approximately $138 million. This liability includes accruals associated with our assessments that the following performance conditions are probable of occurring: (i) an annualized PAA distribution of $4.35, (ii) an annualized PNG distribution of $1.45 and (iii) the conversion of PNG’s Series A subordinated units and the first tranche of PNG’s Series B subordinated units. At December 31, 2010, the accrued liability was approximately $102 million, which includes accruals associated with our assessments that the following performance conditions were probable of occurring: (i) an annualized PAA distribution of $4.00, (ii) an annualized PNG distribution of $1.45 and (iii) the conversion of PNG’s Series A subordinated units and the first tranche of PNG’s Series B subordinated units. In February 2012, the performance conditions related to PNG’s Series B subordinated units were modified. See “PNG Long- Term Incentive Plan Award Modification” above for further discussion.

Our equity compensation activity for awards denominated in PAA and PNG units is summarized in the following table (units in millions):

	PAA Units (1)				PNG Units (2)(3)
			Weighted Average				Weighted Average
			Grant Date				Grant Date
	Units		Fair Value per Unit		Units		Fair Value per Unit
Outstanding, December 31, 2008	3.9		$	36.44	—		$	—
Granted	0.6		$	32.20	—		$	—
Vested	(0.6	)	$	34.55	—		$	—
Cancelled or forfeited	(0.1	)	$	37.82	—		$	—
Acquired	0.1		$	26.24	—		$	—
Outstanding, December 31, 2009	3.9		$	36.40	—		$	—
Granted	2.0		$	45.66	1.1		$	20.49
Vested	(1.1	)	$	32.20	—		$	—
Cancelled or forfeited	(0.4	)	$	35.62	(0.1	)	$	19.22
Outstanding, December 31, 2010	4.4		$	41.69	1.0		$	20.55
Granted	0.5		$	55.05	—		$	—
Vested	(0.7	)	$	40.68	(0.1	)	$	23.62
Cancelled or forfeited	(0.2	)	$	41.97	(0.1	)	$	19.20
Outstanding, December 31, 2011	4.0		$	43.53	0.8		$	20.55

(1) Amounts do not include Class B units of Plains AAP, L.P. as discussed above.

(2) Amounts do not include Class B units of PNGS GP LLC as discussed above.

(3) Amounts include PNG Transaction Grants.

We refer to our LTIP Plans, PNG Transaction Grants, AAP LP Class B units and PNGS GP LLC Class B units collectively as “Equity compensation plans.” The table below summarizes the expense recognized and the value of vesting (settled both in units and cash) related to our equity compensation plans (in millions):

	2011		2010		2009
Equity compensation expense	$	110	$	98	$	68
LTIP unit settled vestings (1)	$	24	$	26	$	19
LTIP cash settled vestings	$	19	$	36	$	8
DER cash payments	$	4	$	4	$	4

(1) For the year ended December 31, 2011, approximately $2 million relates to unit vestings which were settled with PNG units.

Approximately 0.2 million, 0.3 million, and 0.3 million PAA units were issued net of tax withholding of approximately 0.1 million, 0.2 million and 0.2 million units, in 2011, 2010, and 2009 respectively, in connection with the settlement of vested awards. The remaining 0.4 million, 0.6 million and 0.1 million of awards that vested during 2011, 2010 and 2009 respectively, were settled in cash. Based on the December 31, 2011 fair value measurement and probability assessment regarding future distributions, we expect to recognize approximately $90 million of additional expense over the life of our outstanding awards related to the remaining unrecognized fair value. Actual amounts may differ materially as a result of a change in the market price of our units and/or probability assessments regarding future distributions. We estimate that the remaining fair value will be recognized in expense as shown below (in millions):

	Equity Compensation
	Plan Fair Value
Year	Amortization (1) (2)
2012	$	50
2013	26
2014	11
2015	3
2016	—
Total	$	90

(1) Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at December 31, 2011.

(2) Includes unamortized fair value associated with AAP LP Class B units, PNGS GP LLC Class B units and PNG Transaction Grants.

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph 64, 65, A240
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Statement of Position (SOP)
-Number 93-6
-Paragraph 53
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 14

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 50
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6406099&loc=d3e25284-112666

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5047-113901

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5070-113901

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5444-113901

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 40
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6418621&loc=d3e17540-113929

+ Details

Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies

Commitments and Contingencies

Note 11—Commitments and Contingencies

Commitments

We have commitments, some of which are leases, related to real property, equipment and operating facilities. We also incur costs associated with leased land, rights-of-way, permits and regulatory fees. Future non-cancelable commitments related to these items at December 31, 2011, are summarized below (in millions):

	2012		2013		2014		2015		2016		Thereafter		Total
Leases (1)	$	71	$	55	$	47	$	41	$	33	$	292	$	539
Other commitments (2)	34		21		19		15		11		47		147
Total	$	105	$	76	$	66	$	56	$	44	$	339	$	686

(1) Includes capital and operating leases as defined by the FASB guidance.

(2) Primarily includes third-party storage and transportation agreements and pipeline throughput agreements.

Expenditures related to leases for 2011, 2010 and 2009 were $60 million, $52 million and $55 million, respectively.

Litigation

General. 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 materially 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 Environmental Protection Agency (“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.

New Jersey Department of Environmental Protection v. ExxonMobil Corp. et al. In June 2007, the NJDEP brought suit in the Superior Court of New Jersey against GATX, ExxonMobil and our subsidiary, Plains Products Terminals LLC (“PPT”), to recover natural resources damages associated with, and to require remediation of, contamination at our Paulsboro terminal facility. ExxonMobil and GATX filed third-party demands against PPT, seeking indemnity and contribution. The natural resources damages were settled with the State of New Jersey. The Settlement Agreement was approved by the court in September 2011. PPT’s allocated share of this liability was $550,000, which was paid in November 2011. We remain in dispute with ExxonMobil regarding future remediation responsibility as well as allocation of prior remediation costs.

Bay Area Air Quality Management District (“BAAQMD”). During the time period from 2008 to the present, we have received from BAAQMD various notices of violation for alleged violations of California air emissions regulations at our Martinez terminal. In December 2011, we entered into a settlement agreement with BAAQMD, pursuant to which we paid $116,000 in penalties.

Pemex Exploración y Producción v. Big Star Gathering Ltd L.L.P. et al. In a case filed in the Texas Southern District Court, Pemex Exploración y Producción (“PEP”) alleges that certain parties stole condensate from pipelines and gathering stations and conspired with U.S. companies (primarily in Texas) to import and market the stolen condensate. PEP does not allege that Plains was part of any conspiracy, but that it dealt in the condensate only after it had been obtained by others and resold to Plains Marketing, L.P. PEP seeks actual damages, attorney’s fees, and statutory penalties from Plains Marketing, L.P. At a hearing held on October 20, 2011, the Court ruled that Texas law (not Mexican law) governs the actions.

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 and storage operations. As we expand our pipeline assets through acquisitions, we typically improve on (reduce) the releases from such assets (in terms of frequency or volume) as we implement our integrity management procedures, remove selected assets from service and invest capital to upgrade the assets. However, the inclusion of additional miles of pipe in our operations may result in an increase in the absolute number of releases company-wide compared to prior periods. These releases can result from unpredictable man-made or natural forces and may reach “navigable waters” 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 December 31, 2011, our estimated undiscounted reserve for environmental liabilities, including the reserve related to our Rainbow Pipeline release as discussed further below, totaled approximately $74 million, of which approximately $12 million was classified as short-term and $62 million was classified as long-term. At December 31, 2010, our estimated undiscounted reserve for environmental liabilities totaled approximately $66 million, of which approximately $10 million was classified as short-term and $56 million was classified as long-term. At December 31, 2011 and December 31, 2010, we had recorded receivables totaling approximately $47 million and $5 million, respectively, for amounts probable of recovery under insurance and from third parties under indemnification agreements.

In some cases, the actual cash expenditures may not occur for three to five years. 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 claims. 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.

Rainbow Pipeline Release

On April 29, 2011, we experienced a crude oil release on a remote section of our Rainbow Pipeline located in Alberta, Canada. Upon detection of the release, approximately 45 miles of the pipeline were isolated and depressurized and emergency response personnel were mobilized to conduct clean-up operations in cooperation with the Alberta Energy Resources Conservation Board (“ERCB”). After completing the pipeline repair and responding to additional regulatory requested pipeline inspections and information requests, we received regulatory approval and restarted full operation of the pipeline on August 30, 2011. We completed the remaining site clean-up, reclamation and remediation activities in December 2011, and have demobilized all equipment and personnel from the site. Post-reclamation environmental monitoring will continue in accordance with regulatory requirements.

The aggregate total estimated cost to clean up and remediate the site, before insurance recoveries, was approximately $70 million, which was accrued to field operating costs on our consolidated statement of operations. While we believe this amount to be final, there is a small amount of work that will require completion during the spring of 2012 with regard to monitoring and land contouring. The costs associated with this work are not expected to be material.

As of December 31, 2011, we have a remaining undiscounted gross environmental remediation liability for the release of approximately $2 million. This liability is presented as a current liability within the caption “Accounts payable and accrued liabilities” on our consolidated balance sheet. We maintain insurance coverage, which is subject to certain exclusions and deductibles, to protect us against such environmental liabilities. As of December 31, 2011 we have a remaining receivable of approximately $41 million for the portion of this liability that we believe is probable of recovery from insurance, net of deductibles. This receivable has been recognized as a current asset within the caption “Trade accounts receivable and other receivables, net” on our consolidated balance sheet with the offset reducing operating expense on our consolidated statement of operations.

Environmental Remediation

We currently own or lease, and in the past have owned and leased, properties where hazardous liquids, including hydrocarbons, are or have been handled. These properties and the hazardous liquids or associated wastes disposed thereon may be subject to CERCLA, RCRA and state and Canadian federal and provincial laws and regulations. Under such laws and regulations, we could be required to remove or remediate hazardous liquids or associated wastes (including wastes disposed of or released by prior owners or operators) and to clean up contaminated property (including contaminated groundwater).

We maintain insurance of various types with varying levels of coverage that we consider adequate under the circumstances to cover our operations and properties. The insurance policies are subject to deductibles and retention levels that we consider reasonable and not excessive. Consistent with insurance coverage generally available in the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences.

In conjunction with our acquisitions, we typically make an assessment of potential environmental exposure and determine whether to negotiate an indemnity, what the terms of any indemnity should be and whether to obtain environmental risk insurance, if available. These contractual indemnifications typically are subject to specific monetary requirements that must be satisfied before indemnification will apply, and have term and total dollar limits. For instance, in connection with the purchase of former TNM pipeline assets from Link in 2004, we identified a number of environmental liabilities for which we received a purchase price reduction from Link and recorded a total environmental reserve of $20 million, of which we agreed in an arrangement with TNM to bear the first $11 million in costs of pre-May 1999 environmental issues. TNM also agreed to pay all costs in excess of $20 million (excluding certain deductibles). TNM’s obligations are guaranteed by SOP. As of December 31, 2011, we had incurred approximately $22 million of remediation costs associated with these sites, while SOP’s share has been approximately $11 million.

Other assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified.

We have in the past experienced and in the future likely will experience releases of crude oil into the environment from our pipeline and storage operations. We also may discover environmental impacts from past releases that were previously unidentified.

Insurance

A pipeline, terminal or other facility may experience damage as a result of an accident, natural disaster or terrorist activity. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance of various types that we consider adequate to cover our operations and certain assets. The insurance policies are subject to deductibles or self-insured retentions that we consider reasonable. Our insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues.

The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. As a result, we may elect to self-insure or utilize higher deductibles in certain insurance programs. For example, the market for hurricane-or windstorm-related property damage coverage has remained difficult the last few years. The amount of coverage available has been limited, and costs have increased substantially with the combination of premiums and deductibles for the 2010 renewal totaling 20% or more of the coverage limit.

For the two years prior to June 2011, we purchased a hurricane limit of $10 million to cover property and business interruption, representing substantially the level of insurance that was available. The coverage provided by these policies contained much stricter limitations than the insurance policies available prior to hurricanes Rita and Katrina. As a result of these conditions, we did not renew this coverage in June 2011 and do not plan to purchase this coverage for 2012. We will, instead, self-insure this risk. This decision does not affect our third-party liability insurance, which still covers hurricane-related liability claims and which we have renewed at our historic levels. In addition, although we believe that we have established adequate reserves to the extent such risks are not insured, costs incurred in excess of these reserves may be higher and may potentially have a material adverse effect on our financial conditions, results of operations or cash flows.

- Definition

The entire disclosure for commitments and contingencies.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 14
-Paragraph 3
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 9, 10, 11, 12
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.25)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14435-108349

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 460
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6398077&loc=d3e12565-110249

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 440
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6394976&loc=d3e25287-109308

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6449706&loc=d3e16207-108621

+ Details

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2011

Quarterly Financial Data (Unaudited)

Quarterly Financial Data (Unaudited)

Note 12—Quarterly Financial Data (Unaudited)

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total (1)
	(in millions, except per unit data)
2011
Revenues	$	7,694	$	8,859	$	8,837	$	8,884	$	34,275
Gross margin (2)	$	355	$	371	$	413	$	453	$	1,592
Operating income	$	285	$	298	$	357	$	359	$	1,298
Net income	$	185	$	233	$	288	$	288	$	994
Net income attributable to Plains	$	182	$	225	$	281	$	278	$	966
Basic net income per limited partner unit	$	0.90	$	1.14	$	1.48	$	1.38	$	4.91
Diluted net income per limited partner unit	$	0.90	$	1.13	$	1.47	$	1.37	$	4.88
Cash distributions per common unit (3)	$	0.9575	$	0.9700	$	0.9825	$	0.9950	$	3.91

2010
Revenues	$	6,125	$	6,124	$	6,414	$	7,231	$	25,893
Gross margin (2)	$	273	$	248	$	206	$	300	$	1,027
Operating income	$	211	$	192	$	150	$	213	$	767
Net income	$	151	$	133	$	84	$	146	$	514
Net income attributable to Plains	$	151	$	131	$	81	$	142	$	505
Basic net income per limited partner unit	$	0.80	$	0.65	$	0.28	$	0.68	$	2.41
Diluted net income per limited partner unit	$	0.80	$	0.65	$	0.28	$	0.67	$	2.40
Cash distributions per common unit (3)	$	0.9275	$	0.9350	$	0.9425	$	0.9500	$	3.76

(1) The sum of the four quarters may not equal the total year due to rounding.

(2) Gross margin is calculated as Total revenues less (i) Purchases and related costs, (ii) Field operating costs and (iii) Depreciation and amortization.

(3) Represents cash distributions declared and paid in the applicable period.

- Definition

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

+ References + Details

Operating Segments

12 Months Ended

Dec. 31, 2011

Operating Segments

Operating Segments

Note 13—Operating Segments

We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. See “Revenue Recognition” within Note 2 for a summary of the types of products and services from which each segment derives its revenues.

Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including segment profit, segment volumes, segment profit per barrel and maintenance capital investment. We define segment profit as revenues and equity earnings in unconsolidated entities less (i) purchases and related costs, (ii) field operating costs and (iii) segment general and administrative (“G&A”) expenses. Each of the items above excludes depreciation and amortization.

As an MLP, we make quarterly distributions of our “available cash” (as defined in our partnership agreement) to our unitholders. We look at each period’s earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of segment profit as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as crude oil pipelines and facilities, caused by age-related decline and wear and tear. We compensate for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance investments, which acts to partially offset the aging and wear and tear in the value of our principal fixed assets. These maintenance investments are a component of field operating costs included in segment profit or in maintenance capital, depending on the nature of the cost. Maintenance capital, which is deducted in determining “available cash,” consists of capital expenditures for the replacement of partially or fully depreciated assets in order to maintain the service capability, level of production and/or functionality of our existing assets. Capital expenditures made to expand the existing earnings capacity of our assets are considered expansion capital expenditures, not maintenance capital. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are charged to expense as incurred. The following table reflects certain financial data for each segment for the periods indicated (in millions):

	Transportation		Facilities		Supply & Logistics		Total
Twelve Months Ended December 31, 2011
Revenues:
External Customers	$	572	$	638	$	33,065	$	34,275
Intersegment (1)	593		158		3		754
Total revenues of reportable segments	$	1,165	$	796	$	33,068	$	35,029
Equity earnings in unconsolidated entities	$	13	$	—	$	—	$	13
Segment profit (2) (3)	$	555	$	358	$	647	$	1,560
Capital expenditures (4)	$	600	$	1,317	$	18	$	1,935
Total assets	$	5,156	$	4,506	$	5,719	$	15,381
Maintenance capital	$	86	$	22	$	12	$	120

Twelve Months Ended December 31, 2010
Revenues:
External Customers	$	565	$	339	$	24,989	$	25,893
Intersegment (1)	480		151		1		632
Total revenues of reportable segments	$	1,045	$	490	$	24,990	$	26,525
Equity earnings in unconsolidated entities	$	3	$	—	$	—	$	3
Segment profit (2) (3)	$	516	$	270	$	240	$	1,026
Capital expenditures	$	329	$	270	$	163	$	762
Total assets	$	4,701	$	3,303	$	5,699	$	13,703
Maintenance capital	$	67	$	17	$	9	$	93

Twelve Months Ended December 31, 2009
Revenues:
External Customers	$	536	$	227	$	17,757	$	18,520
Intersegment (1)	425		135		2		562
Total revenues of reportable segments	$	961	$	362	$	17,759	$	19,082
Equity earnings in unconsolidated entities	$	7	$	8	$	—	$	15
Segment profit (2) (3)	$	477	$	208	$	345	$	1,030
Capital expenditures	$	183	$	564	$	10	$	757
Total assets	$	4,468	$	3,097	$	4,793	$	12,358
Maintenance capital	$	57	$	16	$	8	$	81

(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 rates.

(2) Supply and logistics segment profit includes interest expense (related to hedged inventory purchases) of $20 million, $17 million and $11 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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

	Year Ended December 31,
	2011			2010			2009
Segment profit	$	1,560		$	1,026		$	1,030
Depreciation and amortization	(249		)	(256		)	(236		)
Interest expense	(253		)	(248		)	(224		)
Other income/(expense), net	(19		)	(9		)	16
Income tax benefit/(expense)	(45		)	1			(6		)
Net income	994			514			580
Less: Net income attributable to noncontrolling interests	(28		)	(9		)	(1		)
Net income attributable to Plains	$	966		$	505		$	579

(4) Facilities segment capital expenditures includes a cash deposit of $50 million (reflected within “Other current assets” on our Consolidated Balance Sheet) paid upon signing a definitive agreement related to the pending BP NGL acquisition, which is expected to close in the second quarter of 2012. Upon completion of this acquisition, we will allocate the assets to our segments, which may result in a different allocation than reflected above. See Note 3 for further discussion of the pending BP NGL acquisition.

Geographic Data

We have operations in the United States and Canada. Set forth below are revenues and long-lived assets attributable to these geographic areas (in millions):

	For the Year Ended December 31,
Revenues (1)	2011		2010		2009
United States	$	28,181	$	21,471	$	15,439
Canada	6,094		4,422		3,081
	$	34,275	$	25,893	$	18,520

(1) Revenues are primarily attributed to each region based on where the services are provided or the product is shipped.

	As of December 31,
Long-Lived Assets (1)	2011		2010
United States	$	9,127	$	7,502
Canada	1,883		1,800
	$	11,010	$	9,302

(1) Excludes long-term derivative assets.

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8981-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 35
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8984-108599

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9054-108599

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
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+ Details

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies

Use of Estimates

Use of Estimates

Revenue Recognition

Revenue Recognition

Purchases and Related Costs

Purchases and Related Costs

Field Operating Costs and General and Administrative Expenses

Field Operating Costs and General and Administrative Expenses

Foreign Currency Transactions

Foreign Currency Transactions

Cash and Cash Equivalents

Cash and Cash Equivalents

Restricted Cash

Restricted Cash

Accounts Receivable

Accounts Receivable

Inventory, Linefill, Base Gas and Long-term Inventory

Inventory, Linefill, Base Gas and Long-term Inventory

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

	December 31, 2011						December 31, 2010
	Volumes	Unit of Measure	Total Value		Price/ Unit (1)		Volumes	Unit of Measure	Total Value		Price/ Unit (1)
Inventory
Crude oil	5,361	barrels	$	483	$	90.10	14,132	barrels	$	1,100	$	77.84
LPG	6,885	barrels	438		$	63.62	7,395	barrels	366		$	49.49
Natural gas (2)	16,170	Mcf	51		$	3.15	13	Mcf	—		$	3.87
Other	N/A		6		N/A		N/A		25		N/A
Inventory subtotal			978						1,491

Linefill and base gas
Crude oil	9,366	barrels	514		$	54.88	9,159	barrels	478		$	52.19
Natural gas (2)	14,105	Mcf	48		$	3.40	11,194	Mcf	37		$	3.31
LPG	31	barrels	2		$	64.52	77	barrels	4		$	51.95
Linefill and base gas subtotal			564						519

Long-term inventory
Crude oil	1,714	barrels	127		$	74.10	1,761	barrels	128		$	72.69
LPG	150	barrels	8		$	53.33	505	barrels	26		$	51.49
Long-term inventory subtotal			135						154

Total			$	1,677					$	2,164

(2) The volumetric ratio of Mcf of natural gas to crude Btu equivalent is 6:1; thus, natural gas volumes can be approximately converted to barrels by dividing by 6.

Property and Equipment

Property and Equipment

Property and equipment, net is stated at cost and consisted of the following (in millions):

	Estimated Useful	December 31,
	Lives (Years)	2011			2010
Crude oil pipelines and facilities	10 - 70	$	4,467		$	4,303
Storage and terminal facilities	30 - 70	3,385			2,740
Trucking equipment and other	3 - 15	110			106
Construction in progress	—	693			304
Office property and equipment	2 - 50	99			95
Land and other	N/A	275			266
		9,029			7,814
Accumulated depreciation		(1,289		)	(1,123		)

Property and equipment, net		$	7,740		$	6,691

Depreciation expense for the years ended December 31, 2011, 2010 and 2009 was $196 million, $235 million and $216 million, respectively.

Equity Method of Accounting

Equity Method of Accounting

Our investments in the following entities are accounted for under the equity method of accounting:

Entity	Type of Operation	Our Ownership Interest
Settoon Towing, LLC	Barge Transportation Services	50	%
White Cliffs Pipeline, L.L.C.	Crude Oil Pipeline	34	%
Frontier Pipeline Company	Crude Oil Pipeline	22	%
Butte Pipe Line Company	Crude Oil Pipeline	22	%

Noncontrolling Interest

Noncontrolling Interests

Asset Retirement Obligations

Asset Retirement Obligations

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets

· whether there is an indication of impairment;

· the grouping of assets;

· the intention of “holding,” “abandoning” or “selling” an asset;

· the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and

· if an impairment exists, the fair value of the asset or asset group.

Goodwill

Goodwill

The table below reflects our changes in goodwill (in millions):

	Transportation			Facilities		Supply & Logistics			Total (1)

Balance at December 31, 2009	$	608		$	308	$	371		$	1,287

2010 Goodwill Related Activity:
Nexen acquisition	18			—		54			72
Purchase price accounting adjustments (2)	3			—		—			3
Foreign currency translation adjustments	11			—		3			14
Balance at December 31, 2010	$	640		$	308	$	428		$	1,376

2011 Goodwill Related Activity:
Southern Pines acquisition (2)	—			301		—			301
Gardendale Gathering System acquisition(2)	155			—		—			155
Foreign currency translation adjustments	(5		)	—		(1		)	(6		)
Purchase price accounting adjustments and other (2)	28			—		—			28
Balance at December 31, 2011	$	818		$	609	$	427		$	1,854

(1) As of December 31, 2011, the total carrying amount of goodwill is net of approximately $3 million of accumulated impairment losses.

Other Assets, Net

Other Assets, Net

Other assets, net of accumulated amortization, consist of the following (in millions):

	December 31,
	2011			2010
Debt issue costs	$	53		$	47
Fair value of derivative instruments	20			20
Intangible assets	498			311
Other	59			58
	630			436
Accumulated amortization	(84		)	(54		)
	$	546		$	382

Intangible Assets


		December 31, 2011							December 31, 2010
	Estimated Useful			Accumulated							Accumulated
	Lives (Years)	Cost		Amortization			Net		Cost		Amortization			Net
Customer contracts and relationships	1-20	$	426	$	(61	)	$	365	$	221	$	(34	)	$	187
Property tax abatement	7-13	38		(6		)	32		23		(2		)	21
Other agreements	30-70	26		(1		)	25		22		(1		)	21
Emission reduction credits (1)	N/A	8		—			8		45		—			45
		$	498	$	(68	)	$	430	$	311	$	(37	)	$	274

We estimate that our amortization expense related to finite-lived intangible assets for the next five years will be as follows (in millions):

2012	$	50
2013	$	47
2014	$	44
2015	$	41
2016	$	36

Environmental Matters

Environmental Matters

Income and Other Taxes

Income and Other Taxes

See Note 7 for discussion of U.S. federal and state taxes and Canadian federal and provincial taxes.

Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities

Equity Compensation

Equity Compensation

See Note 10 for information regarding our accounting for equity compensation awards.

Net Income Per Limited Partner Unit

Net Income Per Limited Partner Unit

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the years ended 2011, 2010 and 2009:

	Year Ended December 31,
	2011			2010			2009
Numerator for basic and diluted earnings per limited partner unit:
Net income attributable to Plains	$	966		$	505		$	579
Less: General partner’s incentive distribution (1)	(221		)	(168		)	(136		)
Less: General partner 2% ownership	(15		)	(7		)	(9		)
Net income available to limited partners in accordance with the application of the two-class method for MLPs	$	730		$	330		$	434

Denominator:
Basic weighted average number of limited partner units outstanding	149			137			130
Effect of dilutive securities:
Weighted average LTIP units (2)	1			1			1
Diluted weighted average number of limited partner units outstanding	150			138			131

Basic net income per limited partner unit	$	4.91		$	2.41		$	3.34

Diluted net income per limited partner unit	$	4.88		$	2.40		$	3.32

Acquisitions and Dispositions

The following acquisitions were accounted for using the purchase method of accounting and the purchase price was determined in accordance with such method.

Legal Contingencies

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 materially 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 Environmental Protection Agency (“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.

Organization and Basis of Presentation (Tables)

12 Months Ended

Dec. 31, 2011

Organization and Basis of Presentation

Schedule of Revision of Prior Period Limited Partner and General Partner Income Allocation

	As		As
	Reported		Revised
Net Income Attributable to Plains
For the Year Ended December 31, 2009:
Limited Partners	$	443	$	434
General Partner	136		145
	$	579	$	579

For the Year Ended December 31, 2010:
Limited Partners	$	338	$	330
General Partner	167		175
	$	505	$	505

Partners’ Capital
As of December 31, 2008:
Limited Partners	$	3,469	$	3,441
General Partner	83		111
	$	3,552	$	3,552

As of December 31, 2009:
Limited Partners	$	4,002	$	3,965
General Partner	94		131
	$	4,096	$	4,096

As of December 31, 2010:
Limited Partners	$	4,234	$	4,189
General Partner	108		153
	$	4,342	$	4,342

Schedule of Revision of Prior Period Consolidated Statement of Cash Flows

	Amounts Previously Reported						As Revised
	Year Ended December 31,						Year Ended December 31,
	2010			2009			2010			2009
Net cash used in investing activities	$	(583	)	$	(660	)	$	(851	)	$	(686	)
Net cash provided by financing activities	$	336		$	312		$	604		$	338
Net	$	(247	)	$	(348	)	$	(247	)	$	(348	)

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies

Components of inventory, linefill, base gas and long-term inventory

	December 31, 2011						December 31, 2010
	Volumes	Unit of Measure	Total Value		Price/ Unit (1)		Volumes	Unit of Measure	Total Value		Price/ Unit (1)
Inventory
Crude oil	5,361	barrels	$	483	$	90.10	14,132	barrels	$	1,100	$	77.84
LPG	6,885	barrels	438		$	63.62	7,395	barrels	366		$	49.49
Natural gas (2)	16,170	Mcf	51		$	3.15	13	Mcf	—		$	3.87
Other	N/A		6		N/A		N/A		25		N/A
Inventory subtotal			978						1,491

Linefill and base gas
Crude oil	9,366	barrels	514		$	54.88	9,159	barrels	478		$	52.19
Natural gas (2)	14,105	Mcf	48		$	3.40	11,194	Mcf	37		$	3.31
LPG	31	barrels	2		$	64.52	77	barrels	4		$	51.95
Linefill and base gas subtotal			564						519

Long-term inventory
Crude oil	1,714	barrels	127		$	74.10	1,761	barrels	128		$	72.69
LPG	150	barrels	8		$	53.33	505	barrels	26		$	51.49
Long-term inventory subtotal			135						154

Total			$	1,677					$	2,164

(2) The volumetric ratio of Mcf of natural gas to crude Btu equivalent is 6:1; thus, natural gas volumes can be approximately converted to barrels by dividing by 6.

Components of property, plant and equipment, net

	Estimated Useful	December 31,
	Lives (Years)	2011			2010
Crude oil pipelines and facilities	10 - 70	$	4,467		$	4,303
Storage and terminal facilities	30 - 70	3,385			2,740
Trucking equipment and other	3 - 15	110			106
Construction in progress	—	693			304
Office property and equipment	2 - 50	99			95
Land and other	N/A	275			266
		9,029			7,814
Accumulated depreciation		(1,289		)	(1,123		)

Property and equipment, net		$	7,740		$	6,691

Investments in entities accounted for under the equity method of accounting

Entity	Type of Operation	Our Ownership Interest
Settoon Towing, LLC	Barge Transportation Services	50	%
White Cliffs Pipeline, L.L.C.	Crude Oil Pipeline	34	%
Frontier Pipeline Company	Crude Oil Pipeline	22	%
Butte Pipe Line Company	Crude Oil Pipeline	22	%

Changes in goodwill

	Transportation			Facilities		Supply & Logistics			Total (1)

Balance at December 31, 2009	$	608		$	308	$	371		$	1,287

2010 Goodwill Related Activity:
Nexen acquisition	18			—		54			72
Purchase price accounting adjustments (2)	3			—		—			3
Foreign currency translation adjustments	11			—		3			14
Balance at December 31, 2010	$	640		$	308	$	428		$	1,376

2011 Goodwill Related Activity:
Southern Pines acquisition (2)	—			301		—			301
Gardendale Gathering System acquisition(2)	155			—		—			155
Foreign currency translation adjustments	(5		)	—		(1		)	(6		)
Purchase price accounting adjustments and other (2)	28			—		—			28
Balance at December 31, 2011	$	818		$	609	$	427		$	1,854

(1) As of December 31, 2011, the total carrying amount of goodwill is net of approximately $3 million of accumulated impairment losses.

Components of other assets, net of accumulated amortization

	December 31,
	2011			2010
Debt issue costs	$	53		$	47
Fair value of derivative instruments	20			20
Intangible assets	498			311
Other	59			58
	630			436
Accumulated amortization	(84		)	(54		)
	$	546		$	382

Components of intangible assets that have finite lives


		December 31, 2011							December 31, 2010
	Estimated Useful			Accumulated							Accumulated
	Lives (Years)	Cost		Amortization			Net		Cost		Amortization			Net
Customer contracts and relationships	1-20	$	426	$	(61	)	$	365	$	221	$	(34	)	$	187
Property tax abatement	7-13	38		(6		)	32		23		(2		)	21
Other agreements	30-70	26		(1		)	25		22		(1		)	21
Emission reduction credits (1)	N/A	8		—			8		45		—			45
		$	498	$	(68	)	$	430	$	311	$	(37	)	$	274

Estimated amortization expense related to finite-lived intangible assets for the next five years

2012	$	50
2013	$	47
2014	$	44
2015	$	41
2016	$	36

Computation of basic and diluted earnings per limited partner unit

	Year Ended December 31,
	2011			2010			2009
Numerator for basic and diluted earnings per limited partner unit:
Net income attributable to Plains	$	966		$	505		$	579
Less: General partner’s incentive distribution (1)	(221		)	(168		)	(136		)
Less: General partner 2% ownership	(15		)	(7		)	(9		)
Net income available to limited partners in accordance with the application of the two-class method for MLPs	$	730		$	330		$	434

Denominator:
Basic weighted average number of limited partner units outstanding	149			137			130
Effect of dilutive securities:
Weighted average LTIP units (2)	1			1			1
Diluted weighted average number of limited partner units outstanding	150			138			131

Basic net income per limited partner unit	$	4.91		$	2.41		$	3.34

Diluted net income per limited partner unit	$	4.88		$	2.40		$	3.32

- Definition

Tabular disclosure of goodwill by reportable segment and in total. Disclosure details may include, but are not limited to, the carrying amount of goodwill, goodwill acquired during the year, goodwill impairment losses recognized, goodwill written-off due to the sale of a business unit, goodwill not yet allocated, and any other changes to goodwill.

+ References + Details

Acquisitions and Dispositions (Tables)

12 Months Ended

Dec. 31, 2011

Acquisitions and Dispositions

Business acquisition purchase price allocation - Southern Pines Acquisition

			Average
			Depreciable
Description	Amount		Life (in years)
Inventory	$	14	N/A
Property and equipment, net	341		5 - 70
Base gas	3		N/A
Other working capital (including $13 million of cash)	14		N/A
Intangible assets	92		2 - 10
Goodwill	301		N/A
Total	$	765

Business acquisition purchase price allocation - Other

Description	Amount
Linefill	$	2
Property and equipment, net	282
Other working capital	(7		)
Intangible assets	152
Environmental liability	(9		)
Goodwill	169
Total	$	589

Business acquisition purchase price consideration - PNGS Acquisition

Cash	$	90
PAA equity	91
Paid at closing	181
Fair value of contingent consideration (1)	34
Total purchase price	$	215

Business acquisition fair value of assets and liabilities allocation - PNGS Acquisition

Property, plant and equipment	$	791
Base gas	28
Goodwill	25
Intangible assets	23
Working capital and other long-term assets and liabilities	9
Debt	(446		)
Total	$	430

Debt (Tables)

12 Months Ended

Dec. 31, 2011

Debt

Components of debt

	December 31,			December 31,
	2011			2010
SHORT-TERM DEBT
Credit Facilities (1):
Senior secured hedged inventory facility bearing a weighted-average interest rate of 1.5% and 2.1% at December 31, 2011 and December 31, 2010, respectively	$	75		$	500
PAA senior unsecured revolving credit facility, bearing a weighted-average interest rate of 1.6% and 0.7% at December 31, 2011 and December 31, 2010, respectively (2)	32			824
PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.1% and 3.2% at December 31, 2011 and December 31, 2010, respectively (3)	68			—
4.25% senior notes due September 2012 (4)	500			—
Other	4			2
Total short-term debt	679			1,326

LONG-TERM DEBT
Senior Notes:
4.25% senior notes due September 2012 (4)	—			500
7.75% senior notes due October 2012	—			200
5.63% senior notes due December 2013	250			250
5.25% senior notes due June 2015	150			150
3.95% senior notes due September 2015	400			400
5.88% senior notes due August 2016	175			175
6.13% senior notes due January 2017	400			400
6.50% senior notes due May 2018	600			600
8.75% senior notes due May 2019	350			350
5.75% senior notes due January 2020	500			500
5.00% senior notes due February 2021	600			—
6.70% senior notes due May 2036	250			250
6.65% senior notes due January 2037	600			600
Unamortized discounts	(13		)	(12		)
Senior notes, net of unamortized discounts	4,262			4,363
Credit Facilities and Other:
PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.1% and 3.2% at December 31, 2011 and December 31, 2010, respectively (3)	54			260
PNG GO Zone term loans, bearing a weighted-average interest rate of 1.5% at December 31, 2011	200			—
Other	4			8
Total long-term debt (2)	4,520			4,631
Total debt (5)	$	5,199		$	5,957

(1) During August 2011, we renewed, extended or refinanced our principal bank credit facilities, including PNG’s credit facility. See “Credit Facilities” below for further discussion.

Long-term debt maturities

Calendar Year	Payment
2012 (1)	$	—
2013	250
2014	—
2015	550
2016	429
Thereafter	3,300
Total (2)	$	4,529

(1) Our $500 million 4.25% senior notes will mature in September 2012 and thus are classified as short-term at December 31, 2011.

(2) Excludes aggregate unamortized net discount of $13 million and other long-term obligations of $4 million.

Partners' Capital and Distributions (Tables)

12 Months Ended

Dec. 31, 2011

Partners' Capital and Distributions

Per unit cash distributions and the portion of the distributions representing an excess over the MQD

	Year
	2011				2010				2009
			Excess				Excess				Excess
	Distribution (1)		over MQD		Distribution		over MQD		Distribution		over MQD
First Quarter	$	0.9575	$	0.5075	$	0.9275	$	0.4775	$	0.8925	$	0.4425
Second Quarter	$	0.9700	$	0.5200	$	0.9350	$	0.4850	$	0.9050	$	0.4550
Third Quarter	$	0.9825	$	0.5325	$	0.9425	$	0.4925	$	0.9050	$	0.4550
Fourth Quarter	$	0.9950	$	0.5450	$	0.9500	$	0.5000	$	0.9200	$	0.4700

(1) Distributions represent those declared and paid in the applicable period.

Reduction in incentive distributions related to acquisitions

Acquisition	2007		2008		2009		2010		2011		Total
Pacific	$	20	$	15	$	15	$	10	$	5	$	65
Rainbow	—		3		6		1		—		10
PNGS	—		—		1		5		2		8
Total	$	20	$	18	$	22	$	16	$	7	$	83

Total cash distributions made

	Distributions Paid								Distributions
	Common		General Partner						per limited
Year	Units		Incentive		2%		Total		partner unit
2011	$	575	$	204	$	12	$	791	$	3.91
2010	$	512	$	160	$	10	$	682	$	3.76
2009	$	468	$	127	$	10	$	605	$	3.62

Schedule of changes made to holdings in limited partner units of PNG result of modification

	Prior to Modification	Modification		Post Modification
PNG Units Owned by PAA:
Common Units	18.1	—		18.1
Series A Subordinated Units	13.9	(2.0	)	11.9
Common & Series A Subordinated Unit Subtotal	32.0	(2.0	)	30.0
Series B Subordinated Units (Performance Thresholds):
Tranche 1 ($1.44 / 29.6 Bcf)	4.6	(2.0	)	2.6
Tranche 2 ($1.53 / 35.6 Bcf)	3.8	(1.0	)	2.8
Tranche 3 ($1.63 / 41.6 Bcf)	3.1	(1.0	)	2.1
Tranche 4 ($1.71 / 48.0 Bcf)	—	3.0		3.0
Tranche 5 ($1.80 / 48.0 Bcf)	—	3.0		3.0
Series B Subordinated Unit Subtotal	11.5	2.0		13.5
Total PNG Units Owned by PAA (1)	43.5	—		43.5

(1) See “PNG Transaction Grants” in Note 10.

Operational and financial conditions necessary for conversion of Series B subordinated units to Series A subordinated units

	Series B Subordinated Units to Convert into Series A Subordinated Units	Working Gas Storage Capacity (Bcf)	Annualized Distribution Level
Tranche 1	2.6	29.6	$	1.71
Tranche 2	2.8	35.6	$	1.71
Tranche 3	2.1	41.6	$	1.71
Tranche 4	3.0	48.0	$	1.71
Tranche 5	3.0	48.0	$	1.80

Changes made to holdings in limited partner units of PNG

	December 31, 2010	February 2011 PNG Issuance	Transaction Grants		December 31, 2011
PNG Units Owned by PAA:
Common Units	18.1	10.2	(0.1	)	28.2
Series A Subordinated Units	11.9	—	—		11.9
Series B Subordinated Units	13.5	—	—		13.5
Total PNG Units Owned by PAA	43.5	10.2	(0.1	)	53.6

Schedule of changes in noncontrolling interests in partners' capital

	For the Year Ended December 31,
	2011			2010			2009
Beginning balance	$	231		$	63		$	—
Sale of noncontrolling interests in subsidiaries	306			167			64
Net income attributable to noncontrolling interests	28			9			1
Distributions to noncontrolling interests	(40		)	(10		)	(2		)
Equity compensation expense	3			3			—
Net deferred loss on cash flow hedges	(4		)	—			—
Other	—			(1		)	—
Ending Balance	$	524		$	231		$	63

Schedule of impact of changes in the entity ownership interest in subsidiary on the entity's capital

	Year Ended December 31,
	2011		2010		2009
Net income attributable to Plains	$	966	$	505	$	579
Transfers to the noncontrolling interests:
Increase in capital from sale of PNG units	64		101		—
Decrease in capital from sale of interest in SLC Pipeline	—		—		(38		)
Change from net income attributable to Plains and net transfers to the noncontrolling interest	$	1,030	$	606	$	541

Equity offerings of common units

						General
		Gross		Proceeds		Partner					Net
Period	Units Issued	Unit Price		from Sale		Contribution		Costs			Proceeds
November 2011 (1)	6,000,000	$	65.03	$	390	$	9	$	(13	)	$	386
March 2011 (1)	7,935,000	$	64.00	508		10		(15		)	503
2011 Total	13,935,000			$	898	$	19	$	(28	)	$	889

November 2010 (1)	4,780,000	$	62.60	$	299	$	6	$	(9	)	$	296
2010 Total	4,780,000			$	299	$	6	$	(9	)	$	296

September 2009 (1)	5,290,000	$	46.70	$	247	$	5	$	(6	)	$	246
March 2009 (1)	5,750,000	$	36.90	212		4		(6		)	210
2009 Total	11,040,000			$	459	$	9	$	(12	)	$	456

Derivatives and Hedging Instruments (Tables)

12 Months Ended

Dec. 31, 2011

Derivatives and Hedging Instruments

Terms of forward starting interest rate swaps

Hedged Transaction	Number and Types of Derivatives Employed	Notional Amount		Expected Termination Date	Average Rate Locked		Accounting Treatment
Anticipated debt offering	4 forward starting swaps (10-year)	$	200	6/15/2012	3.46	%	Cash flow hedge
Anticipated debt offering	6 forward starting swaps (30-year)	$	250	6/17/2013	4.24	%	Cash flow hedge
Anticipated debt offering	2 forward starting swaps (30-year)	$	50	6/16/2014	3.94	%	Cash flow hedge
Anticipated debt offering	10 forward starting swaps (30-year)	$	250	6/15/2015	3.60	%	Cash flow hedge

Open foreign currency exchange contracts

	CAD		USD		Average Exchange Rate
2012	$	15	$	15	CAD $1.01 to USD $1.00
2013	$	9	$	9	CAD $1.00 to USD $1.00

Impact of derivative activities recognized in earnings

	Year Ended December 31, 2011								Year Ended December 31, 2010
				Derivatives							Derivatives
	Derivatives in			Not					Derivatives in		Not
	Hedging			Designated					Hedging		Designated
Location of gain/(loss)	Relationships (1)(2)(3)(5)			as a Hedge (4)		Total			Relationships (1)(2)(3)		as a Hedge (4)			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	(161	)	$	99	$	(62	)	$	14	$	2		$	16

Transportation segment revenues	—			—		—			2		—			2

Facilities segment revenues	11			—		11			—		—			—

Purchases and related costs	6			—		6			8		(12		)	(4		)

Field operating costs	—			1		1			—		3			3

Interest Rate Derivatives

Interest expense	1			—		1			1		2			3

Foreign Exchange Derivatives

Supply and Logistics segment revenues	—			1		1			—		2			2

Purchases and related costs	—			—		—			—		2			2

Other income/(expense), net	6			—		6			—		(1		)	(1		)

Total Gain/(Loss) on Derivatives Recognized in Income	$	(137	)	$	101	$	(36	)	$	25	$	(2	)	$	23

(1)	Amounts represent derivative gains and losses that were reclassified from AOCI to earnings during the period to coincide with the earnings impact of the respective hedged transaction.
(2)	Amounts include losses of approximately $8 million and $1 million for the years ended December 31, 2011 and 2010, respectively, that represent the ineffective portion of our cash flow hedges. These amounts relate to commodity derivatives and were recognized in Supply and Logistics segment revenues during the respective periods.
(3)	Interest expense includes net gains of approximately $2 million and approximately $1 million for the years ended December 31, 2011 and 2010, respectively, associated with outstanding interest rate swaps, which are designated as a fair value hedge.
(4)	Includes realized and unrealized gains or losses for derivatives not designated for hedge accounting during the period.
(5)	Includes unrealized gains of approximately $6 million reclassified from AOCI to earnings during the period to offset a lower of cost or market adjustment relating to the carrying value of PNG’s inventory.

Summary of derivative assets and liabilities on consolidated balance sheet

	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	72	Other current assets	$	(47	)
	Other long-term assets	20		Other long-term assets	(2		)
Interest rate derivatives	Other current assets	1		Other current liabilities	(24		)
				Other long-term liabilities	(114		)
Foreign currency derivatives	Other current assets	1

Total derivatives designated as hedging instruments		$	94		$	(187	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	87	Other current assets	$	(39	)
	Other long-term assets	6		Other long-term assets	(3		)
				Other current liabilities	(1		)
Total derivatives not designated as hedging instruments		$	93		$	(43	)

Total derivatives		$	187		$	(230	)

	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	71	Other current assets	$	(70	)
				Other long-term assets	(1		)
				Other current liabilities	(1		)
Interest rate derivatives	Other current assets	10
Total derivatives designated as hedging instruments		$	81		$	(72	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	11	Other current assets	$	(68	)
	Other long-term assets	20
	Other current liabilities	2		Other current liabilities	(10		)
Interest rate derivatives	Other current assets	4
	Other long-term assets	1
Foreign currency derivatives	Other current assets	1
Total derivatives not designated as hedging instruments		$	39		$	(78	)

Total derivatives		$	120		$	(150	)

Amounts of gain/(loss) recognized in AOCI on derivatives (effective portion)

	For the Years Ended December 31,
	2011			2010
Commodity derivatives, net	$	(15	)	$	(82	)
Foreign exchange derivatives, net	—			(2		)
Interest rate derivatives, net	(136		)	8
Total	$	(151	)	$	(76	)

Financial assets and liabilities within the fair value hierarchy accounted for at fair value on a recurring basis

	Fair Value as of December 31, 2011 (in millions)										Fair Value as of December 31, 2010 (in millions)
Recurring Fair Value Measures (1)	Level 1		Level 2			Level 3		Total			Level 1			Level 2		Level 3			Total
Commodity derivatives	$	80	$	1		$	12	$	93		$	(16	)	$	—	$	(30	)	$	(46	)
Interest rate derivatives	—		(137		)	—		(137		)	—			—		15			15
Foreign currency derivatives	—		1			—		1			—			—		1			1
Total	$	80	$	(135	)	$	12	$	(43	)	$	(16	)	$	—	$	(14	)	$	(30	)

(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

	Year Ended December 31,
	2011			2010
Beginning Balance	$	(14	)	$	(28	)
Unrealized gains/(losses):
Included in earnings (1)	17			(22		)
Included in other comprehensive income	2			3
Settlements	21			42
Derivatives entered into during the period	3			(9		)
Transfers out of level 3	(17		)	—
Ending Balance	$	12		$	(14	)

Change in unrealized gains/(losses) included in earnings relating to level 3 derivatives still held at the end of the periods	$	22		$	(27	)

- Definition

Tabular disclosure of the location and amount of gains and losses reported in the statement of financial performance, or when applicable, the statement of financial position. For example, (a) gains and losses recognized in the income statement on derivative instruments designated and qualifying as hedging instruments in fair value hedges and related hedged items designated and qualifying in fair value hedges and (b) gains and losses initially recognized in other comprehensive income on derivative instruments designated and qualifying as cash flow hedges.

+ References + Details

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6935481&loc=SL5579245-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=6935481&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=6935481&loc=SL5624171-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6935481&loc=d3e41678-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6935481&loc=d3e41638-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=6935481&loc=SL5580258-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6935481&loc=SL5579240-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6935481&loc=d3e41641-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6935481&loc=d3e41620-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

+ Details

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Taxes

Components of income tax expense

	Year Ended December 31,
	2011			2010			2009
Current tax (benefit)/expense:
State income tax	$	2		$	1		$	2
Canadian federal and provincial income tax	36			(2		)	13
Total current tax (benefit)/ expense	$	38		$	(1	)	$	15

Deferred tax (benefit)/expense:
State income tax	$	(2	)	$	1		$	—
Canadian federal and provincial income tax	9			(1		)	(9		)
Total deferred tax (benefit)/expense	$	7		$	—		$	(9	)
Total income tax (benefit)/expense	$	45		$	(1	)	$	6

Summary of differences between tax expense based on the statutory federal income tax rate and the entity's effective tax expense

	Year Ended December 31,
	2011				2010				2009
Income before tax	$	1,039			$	513			$	586
Partnership earnings not subject to current Canadian tax	(909			)	(509			)	(585			)
	$	130			$	4			$	1
Canadian federal and provincial corporate tax rate	27			%	28			%	29			%
Income tax at statutory rate	$	35			$	1			$	—

Current tax (benefit)/expense:
Canadian withholding tax	$	12			$	—			$	—
Canadian period tax as a result of book versus tax differences	(9			)	—				4
Canadian permanent differences between book and tax	(2			)	(3			)	9
State income tax	2				1				2
Current income tax (benefit)/expense	$	38			$	(1		)	$	15

Deferred tax expense:
State deferred income tax	$		(2	)	$		1		$		—
Canadian deferred tax (benefit)/expense as a result of book versus tax differences	9				(1			)	(9			)
Deferred income tax (benefit)/expense	$	7			$	—			$	(9		)
Total income tax (benefit)/expense	$	45			$	(1		)	$	6

Deferred tax assets and liabilities

	December 31,
	2011			2010
Deferred tax assets:
Book accruals in excess of current tax deductions	$	18		$	4
Total deferred tax assets	18			4

Deferred tax liabilities:
Property, plant and equipment in excess of tax values	(147		)	(128		)
Total deferred tax liabilities	(147		)	(128		)
Net deferred tax liabilities	$	(129	)	$	(124	)

Related Party Transactions (Tables) - Oxy

12 Months Ended

Dec. 31, 2011

Related party transaction

Revenues and purchases related to transactions with related parties

	For the Year Ended December 31,
	2011		2010		2009
Revenues	$	2,568	$	2,189	$	181

Purchases and related costs	$	361	$	221	$	164

Receivable and payable amounts with related parties

	At December 31,
	2011		2010
Trade accounts receivable and other receivables	$	132	$	379

Accounts payable	$	155	$	124

Equity Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2011

Equity Compensation Plans

Schedule of estimated vesting date for PAA long term incentive plan awards outstanding

		PAA
LTIP Units		Distribution	Estimated Unit Vesting Date
Outstanding		Required	2012	2013	2014	2015	Thereafter
2.6	(1)	$3.75 - $4.45	0.9	0.6	0.5	0.6	—
1.4	(2)	$3.80 - $4.25	0.6	0.5	0.2	0.1	—
4.0	(3) (4)		1.5	1.1	0.7	0.7	—

(3) Approximately 2.2 million of the 4.0 million outstanding PAA LTIP awards also include DERs, of which 1.7 million had vested as of December 31, 2011.

(4) LTIP units outstanding do not include Class B units of Plains AAP, L.P. (“AAP LP Class B units”) described below.

Summary of Class B unit awards

	Reserved for Future Grants		Outstanding	Outstanding Units Earned	Grant Date Fair Value Of Outstanding Class B Units (1)
					(in millions)
Balance as of December 31, 2010	24,500		175,500	80,063	$	40
Class B unit issuances	(8,000	)	8,000	—	4
Class B unit forfeitures	—		—	—	—
Class B units earned	—		—	—	—
Balance as of December 31, 2011	16,500		183,500	80,063	$	44

(1) Of the grant date fair value, approximately $9 million was recognized as expense during both years ended December 31, 2011 and 2010.

Schedule of estimated vesting date for PNG long term incentive plan awards outstanding

		PNG
LTIP Units		Distribution	Estimated Unit Vesting Date
Outstanding		Required	2012	2013	2014	2015	Thereafter
0.3	(1)	$1.55 - $1.90	—	—	—	0.1	0.2
0.2	(2)	Other	—	0.1	0.1	—	—
0.5	(3) (4)		—	0.1	0.1	0.1	0.2

(3) Approximately 0.3 million of the 0.5 million outstanding PNG LTIP awards also include DERs, of which less than 0.1 million had vested as of December 31, 2011.

(4) LTIP units outstanding do not include the PNG Transaction Grants or Class B units of PNGS GP LLC described below.

Summary of LTIP activity

	PAA Units (1)				PNG Units (2)(3)
			Weighted Average				Weighted Average
			Grant Date				Grant Date
	Units		Fair Value per Unit		Units		Fair Value per Unit
Outstanding, December 31, 2008	3.9		$	36.44	—		$	—
Granted	0.6		$	32.20	—		$	—
Vested	(0.6	)	$	34.55	—		$	—
Cancelled or forfeited	(0.1	)	$	37.82	—		$	—
Acquired	0.1		$	26.24	—		$	—
Outstanding, December 31, 2009	3.9		$	36.40	—		$	—
Granted	2.0		$	45.66	1.1		$	20.49
Vested	(1.1	)	$	32.20	—		$	—
Cancelled or forfeited	(0.4	)	$	35.62	(0.1	)	$	19.22
Outstanding, December 31, 2010	4.4		$	41.69	1.0		$	20.55
Granted	0.5		$	55.05	—		$	—
Vested	(0.7	)	$	40.68	(0.1	)	$	23.62
Cancelled or forfeited	(0.2	)	$	41.97	(0.1	)	$	19.20
Outstanding, December 31, 2011	4.0		$	43.53	0.8		$	20.55

(1) Amounts do not include Class B units of Plains AAP, L.P. as discussed above.

(2) Amounts do not include Class B units of PNGS GP LLC as discussed above.

(3) Amounts include PNG Transaction Grants.

Summary of expense recognized and value of vesting related to outstanding equity compensation awards

	2011		2010		2009
Equity compensation expense	$	110	$	98	$	68
LTIP unit settled vestings (1)	$	24	$	26	$	19
LTIP cash settled vestings	$	19	$	36	$	8
DER cash payments	$	4	$	4	$	4

(1) For the year ended December 31, 2011, approximately $2 million relates to unit vestings which were settled with PNG units.

Equity compensation plan fair value amortization

	Equity Compensation
	Plan Fair Value
Year	Amortization (1) (2)
2012	$	50
2013	26
2014	11
2015	3
2016	—
Total	$	90

(1) Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at December 31, 2011.

(2) Includes unamortized fair value associated with AAP LP Class B units, PNGS GP LLC Class B units and PNG Transaction Grants.

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies

Future non-cancelable commitments relating to operating and capital leases

	2012		2013		2014		2015		2016		Thereafter		Total
Leases (1)	$	71	$	55	$	47	$	41	$	33	$	292	$	539
Other commitments (2)	34		21		19		15		11		47		147
Total	$	105	$	76	$	66	$	56	$	44	$	339	$	686

(1) Includes capital and operating leases as defined by the FASB guidance.

(2) Primarily includes third-party storage and transportation agreements and pipeline throughput agreements.

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2011

Quarterly Financial Data (Unaudited)

Quarterly Financial Data (Unaudited)

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total (1)
	(in millions, except per unit data)
2011
Revenues	$	7,694	$	8,859	$	8,837	$	8,884	$	34,275
Gross margin (2)	$	355	$	371	$	413	$	453	$	1,592
Operating income	$	285	$	298	$	357	$	359	$	1,298
Net income	$	185	$	233	$	288	$	288	$	994
Net income attributable to Plains	$	182	$	225	$	281	$	278	$	966
Basic net income per limited partner unit	$	0.90	$	1.14	$	1.48	$	1.38	$	4.91
Diluted net income per limited partner unit	$	0.90	$	1.13	$	1.47	$	1.37	$	4.88
Cash distributions per common unit (3)	$	0.9575	$	0.9700	$	0.9825	$	0.9950	$	3.91

2010
Revenues	$	6,125	$	6,124	$	6,414	$	7,231	$	25,893
Gross margin (2)	$	273	$	248	$	206	$	300	$	1,027
Operating income	$	211	$	192	$	150	$	213	$	767
Net income	$	151	$	133	$	84	$	146	$	514
Net income attributable to Plains	$	151	$	131	$	81	$	142	$	505
Basic net income per limited partner unit	$	0.80	$	0.65	$	0.28	$	0.68	$	2.41
Diluted net income per limited partner unit	$	0.80	$	0.65	$	0.28	$	0.67	$	2.40
Cash distributions per common unit (3)	$	0.9275	$	0.9350	$	0.9425	$	0.9500	$	3.76

(1) The sum of the four quarters may not equal the total year due to rounding.

(2) Gross margin is calculated as Total revenues less (i) Purchases and related costs, (ii) Field operating costs and (iii) Depreciation and amortization.

(3) Represents cash distributions declared and paid in the applicable period.

Operating Segments (Tables)

12 Months Ended

Dec. 31, 2011

Operating Segments

Segment financial data

	Transportation		Facilities		Supply & Logistics		Total
Twelve Months Ended December 31, 2011
Revenues:
External Customers	$	572	$	638	$	33,065	$	34,275
Intersegment (1)	593		158		3		754
Total revenues of reportable segments	$	1,165	$	796	$	33,068	$	35,029
Equity earnings in unconsolidated entities	$	13	$	—	$	—	$	13
Segment profit (2) (3)	$	555	$	358	$	647	$	1,560
Capital expenditures (4)	$	600	$	1,317	$	18	$	1,935
Total assets	$	5,156	$	4,506	$	5,719	$	15,381
Maintenance capital	$	86	$	22	$	12	$	120

Twelve Months Ended December 31, 2010
Revenues:
External Customers	$	565	$	339	$	24,989	$	25,893
Intersegment (1)	480		151		1		632
Total revenues of reportable segments	$	1,045	$	490	$	24,990	$	26,525
Equity earnings in unconsolidated entities	$	3	$	—	$	—	$	3
Segment profit (2) (3)	$	516	$	270	$	240	$	1,026
Capital expenditures	$	329	$	270	$	163	$	762
Total assets	$	4,701	$	3,303	$	5,699	$	13,703
Maintenance capital	$	67	$	17	$	9	$	93

Twelve Months Ended December 31, 2009
Revenues:
External Customers	$	536	$	227	$	17,757	$	18,520
Intersegment (1)	425		135		2		562
Total revenues of reportable segments	$	961	$	362	$	17,759	$	19,082
Equity earnings in unconsolidated entities	$	7	$	8	$	—	$	15
Segment profit (2) (3)	$	477	$	208	$	345	$	1,030
Capital expenditures	$	183	$	564	$	10	$	757
Total assets	$	4,468	$	3,097	$	4,793	$	12,358
Maintenance capital	$	57	$	16	$	8	$	81

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

	Year Ended December 31,
	2011			2010			2009
Segment profit	$	1,560		$	1,026		$	1,030
Depreciation and amortization	(249		)	(256		)	(236		)
Interest expense	(253		)	(248		)	(224		)
Other income/(expense), net	(19		)	(9		)	16
Income tax benefit/(expense)	(45		)	1			(6		)
Net income	994			514			580
Less: Net income attributable to noncontrolling interests	(28		)	(9		)	(1		)
Net income attributable to Plains	$	966		$	505		$	579

Reconciliation of segment profit to net income attributable to Plains

	Year Ended December 31,
	2011			2010			2009
Segment profit	$	1,560		$	1,026		$	1,030
Depreciation and amortization	(249		)	(256		)	(236		)
Interest expense	(253		)	(248		)	(224		)
Other income/(expense), net	(19		)	(9		)	16
Income tax benefit/(expense)	(45		)	1			(6		)
Net income	994			514			580
Less: Net income attributable to noncontrolling interests	(28		)	(9		)	(1		)
Net income attributable to Plains	$	966		$	505		$	579

Revenues attributable to geographical areas

	For the Year Ended December 31,
Revenues (1)	2011		2010		2009
United States	$	28,181	$	21,471	$	15,439
Canada	6,094		4,422		3,081
	$	34,275	$	25,893	$	18,520

(1) Revenues are primarily attributed to each region based on where the services are provided or the product is shipped.

Long-lived assets attributable to geographical areas

	As of December 31,
Long-Lived Assets (1)	2011		2010
United States	$	9,127	$	7,502
Canada	1,883		1,800
	$	11,010	$	9,302

(1) Excludes long-term derivative assets.

- Definition

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

+ References + Details

Organization and Basis of Presentation (Details) $ in Millions	1 Months Ended	3 Months Ended									12 Months Ended
	May 31, 2010 USD ($) shares	Dec. 31, 2011 USD ($) segment owner	Sep. 30, 2011 USD ($)	Jun. 30, 2011 USD ($)	Mar. 31, 2011 USD ($)	Dec. 31, 2010 USD ($) segment	Sep. 30, 2010 USD ($)	Jun. 30, 2010 USD ($) shares	Mar. 31, 2010 USD ($)	Mar. 31, 2009 USD ($)	Dec. 31, 2011 USD ($) segment owner	Dec. 31, 2010 USD ($) segment	Dec. 31, 2009 USD ($) segment	Dec. 31, 2008 USD ($)
Organization and Basis of Presentation
Operating segments number \| segment		3				3					3	3	3
Partners Capital and Distribution
Net cash used in investing activities											$ (2,020)	$ (851)	$ (686)
Net cash provided by financing activities											$ (345)	604	338
Maximum interest held by principal owners (as a percent)		35.00%									35.00%
Minimum interest held by principal owners (as a percent)		1.00%									1.00%
Limited partner ownership interest (as a percent)											98.00%
Net Income Attributable to Plains		$ 278	$ 281	$ 225	$ 182	$ 142	$ 81	$ 131	$ 151		$ 966	505	579
Net increase/(decrease) in cash and cash equivalents											(10)	11	14
Partners Capital		$ 5,974				4,573					$ 5,974	4,573	4,159	$ 3,552
General partner ownership interest (as a percent)											2.00%
Number of principal owners of Plains AAP, L.P., and Plains All American GP LLC \| owner		18									18
Limited Partner
Partners Capital and Distribution
Limited partner ownership interest (as a percent)											98.00%
Net Income Attributable to Plains													434
Partners Capital		$ 5,249				4,189					$ 5,249	4,189	3,965	3,441
General Partner
Partners Capital and Distribution
Net Income Attributable to Plains											236	175	145
Partners Capital		$ 201				153					$ 201	153	131	111
Amounts Previously Reported \| Limited Partner
Partners Capital and Distribution
Net Income Attributable to Plains												338	443
Partners Capital						4,234						4,234	4,002	3,469
Amounts Previously Reported \| General Partner
Partners Capital and Distribution
Net Income Attributable to Plains												167	136
Partners Capital						$ 108						108	94	$ 83
IPO
Partners Capital and Distribution
Net cash used in investing activities												(851)	(686)
Net cash provided by financing activities												604	338
Net increase/(decrease) in cash and cash equivalents												(247)	(348)
IPO \| Amounts Previously Reported
Partners Capital and Distribution
Net cash used in investing activities												(583)	(660)
Net cash provided by financing activities												$ 336	$ 312
PNG
Partners Capital and Distribution
Noncontrolling interests, ownership percentage of noncontrolling owners (as a percent)		36.00%									36.00%
PNG \| IPO
Partners Capital and Distribution
Number of common units issued representing limited partner interest (in units) \| shares	13,478,000							13,500,000
Net proceeds received by PNG from sale of common units	$ 268							$ 268
SLC Pipeline
Partners Capital and Distribution
Net proceeds received by PNG from a third party for an ownership percentage in a joint venture										$ 26
Noncontrolling interests, ownership percentage of noncontrolling owners (as a percent)		25.00%								25.00%	25.00%

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Foreign Currency Transactions
Gain (loss) on revaluation of foreign currency transactions and monetary assets and liabilities	$ (2)	$ 2	$ 13
Cash and Cash Equivalents
Maximum original maturity period of cash equivalent investments (in months)	3 months
Outstanding checks that were reclassified from cash and cash equivalents to be included in accounts payable	$ 58	40
Restricted Cash
Restricted cash		20
Accounts Receivable
Advance cash payments received from third parties to mitigate credit risk	$ 186	$ 197
Net accounts receivable, maximum age of balances past their scheduled invoice date (in days)	30 days	30 days
Allowance for doubtful accounts receivable	$ 5	$ 5
Asset Retirement Obligations
Fair value of asset retirement obligations	9	5
Impairment of Long-Lived Assets
Impairment charges - predominantly related to assets taken out of service	$ 5	$ 13
Maximum
Impairment of Long-Lived Assets
Impairment charges - predominantly related to assets taken out of service			$ 1

Summary of Significant Accounting Policies (Details 2) barrel in Thousands, cubicfeet in Millions	12 Months Ended
	Dec. 31, 2011 USD ($) denominator numerator barrel cubicfeet	Dec. 31, 2010 USD ($) denominator numerator barrel cubicfeet	Dec. 31, 2009 USD ($)
Inventory-related disclosures
Gain on sale of linefill	$ 21,000,000	$ 21,000,000	$ 4,000,000
Proceeds from sale of pipeline linefill	$ 56,000,000	$ 72,000,000	$ 24,000,000
Numerator for ratio of Mcf of natural gas to crude Btu \| numerator	6	6
Denominator for ratio of Mcf of natural gas to crude Btu \| denominator	1	1
Inventory by category
Inventory	$ 978,000,000	$ 1,491,000,000
Linefill and base gas	564,000,000	519,000,000
Long-term inventory	135,000,000	154,000,000
Total	1,677,000,000	2,164,000,000
Crude oil
Inventory by category
Inventory	483,000,000	1,100,000,000
Linefill and base gas	514,000,000	478,000,000
Long-term inventory	$ 127,000,000	$ 128,000,000
Inventory, Volumes (in barrels or cubic feet) \| barrel	5,361	14,132
Linefill and base gas, Volumes (in barrels or cubic feet) \| barrel	9,366	9,159
Long-term inventory, Volumes (in barrels or cubic feet) \| barrel	1,714	1,761
Inventory, Price/Unit of measure (in dollars per unit)	90.10	77.84
Linefill and base gas, Price/Unit of measure (in dollars per unit)	54.88	52.19
Long-term inventory, Price/Unit of measure (in dollars per unit)	74.10	72.69
LPG
Inventory by category
Inventory	$ 438,000,000	$ 366,000,000
Linefill and base gas	2,000,000	4,000,000
Long-term inventory	$ 8,000,000	$ 26,000,000
Inventory, Volumes (in barrels or cubic feet) \| barrel	6,885	7,395
Linefill and base gas, Volumes (in barrels or cubic feet) \| barrel	31	77
Long-term inventory, Volumes (in barrels or cubic feet) \| barrel	150	505
Inventory, Price/Unit of measure (in dollars per unit)	63.62	49.49
Linefill and base gas, Price/Unit of measure (in dollars per unit)	64.52	51.95
Long-term inventory, Price/Unit of measure (in dollars per unit)	53.33	51.49
Other
Inventory by category
Inventory	$ 6,000,000	$ 25,000,000
Natural gas
Inventory-related disclosures
Number used to divide into natural gas volumes to convert to barrels \| denominator	6
Inventory by category
Inventory	$ 51,000,000
Linefill and base gas	$ 48,000,000	$ 37,000,000
Inventory, Volumes (in barrels or cubic feet) \| cubicfeet	16,170	13
Linefill and base gas, Volumes (in barrels or cubic feet) \| cubicfeet	14,105	11,194
Inventory, Price/Unit of measure (in dollars per unit)	3.15	3.87
Linefill and base gas, Price/Unit of measure (in dollars per unit)	3.40	3.31

Summary of Significant Accounting Policies (Details 3) $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($) Y	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Property, Plant and Equipment.
Interest expense, capitalized interest	$ 25	$ 16	$ 15
PROPERTY AND EQUIPMENT	9,029	7,814
Accumulated depreciation	(1,289)	(1,123)
Property and equipment, net	7,740	6,691
Depreciation expense	196	235	$ 216
Approximate reduction in depreciation expense due to depreciable life extensions	60	23
Incremental reduction in depreciation expense due to depreciable life extensions	37
Losses on disposition of assets	(11)	(13)
Crude oil pipelines and facilities
Property, Plant and Equipment.
PROPERTY AND EQUIPMENT	$ 4,467	4,303
Average Depreciable Life, minimum (in years) \| Y	10
Average Depreciable Life, Maximum (in years) \| Y	70
Storage and terminal facilities
Property, Plant and Equipment.
PROPERTY AND EQUIPMENT	$ 3,385	2,740
Average Depreciable Life, minimum (in years) \| Y	30
Average Depreciable Life, Maximum (in years) \| Y	70
Trucking equipment and other
Property, Plant and Equipment.
PROPERTY AND EQUIPMENT	$ 110	106
Average Depreciable Life, minimum (in years) \| Y	3
Average Depreciable Life, Maximum (in years) \| Y	15
Construction in progress
Property, Plant and Equipment.
PROPERTY AND EQUIPMENT	$ 693	304
Office property and equipment
Property, Plant and Equipment.
PROPERTY AND EQUIPMENT	$ 99	95
Average Depreciable Life, minimum (in years) \| Y	2
Average Depreciable Life, Maximum (in years) \| Y	50
Land and other
Property, Plant and Equipment.
PROPERTY AND EQUIPMENT	$ 275	$ 266

Summary of Significant Accounting Policies (Details 4)	Dec. 31, 2011
Settoon Towing, LLC
Equity Method of Accounting
Ownership interest (as a percent)	50.00%
White Cliffs Pipeline, LLC
Equity Method of Accounting
Ownership interest (as a percent)	34.00%
Frontier Pipeline Company
Equity Method of Accounting
Ownership interest (as a percent)	22.00%
Butte Pipe Line Company
Equity Method of Accounting
Ownership interest (as a percent)	22.00%

Summary of Significant Accounting Policies (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Changes in goodwill
Balance at beginning of period	$ 1,376	$ 1,287
Purchase accounting adjustments		3
Purchase price accounting adjustments and other	28
Foreign currency translation adjustments	(6)	14
Balance at end of period	1,854	1,376
Accumulated impairment losses	3
Nexen Acquisition
Changes in goodwill
Acquisitions		72
Southern Pines Acquisition
Changes in goodwill
Acquisitions	301
Gardendale Gathering System Acquisition
Changes in goodwill
Acquisitions	155
Transportation
Changes in goodwill
Balance at beginning of period	640	608
Purchase accounting adjustments		3
Purchase price accounting adjustments and other	28
Foreign currency translation adjustments	(5)	11
Balance at end of period	818	640
Transportation \| Nexen Acquisition
Changes in goodwill
Acquisitions		18
Transportation \| Gardendale Gathering System Acquisition
Changes in goodwill
Acquisitions	155
Facilities
Changes in goodwill
Balance at beginning of period	308	308
Balance at end of period	609	308
Facilities \| Southern Pines Acquisition
Changes in goodwill
Acquisitions	301
Supply and Logistics
Changes in goodwill
Balance at beginning of period	428	371
Foreign currency translation adjustments	(1)	3
Balance at end of period	$ 427	428
Supply and Logistics \| Nexen Acquisition
Changes in goodwill
Acquisitions		$ 54

Summary of Significant Accounting Policies (Details 6) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Other Assets, Net
Debt issue costs	$ 53	$ 47
Fair value of derivative instruments	20	20
Intangible assets	498	311
Other	59	58
Other assets, gross	630	436
Accumulated amortization	(84)	(54)
Total Other Assets, Net	546	382
Debt issuance costs capitalized during the period	18	7
Write off of debt issuance cost	11
Amortization expense related to other assets (including finite-lived intangible assets)	44	22	$ 19
Amortization expense for finite-lived intangible assets	$ 36	$ 14	$ 14

Summary of Significant Accounting Policies (Details 7) $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($) Y	Dec. 31, 2010 USD ($)
Summary of Significant Accounting Policies
Emission reduction credits utilized	$ 37
Finite-Lived Intangible Assets
Cost	498	$ 311
Accumulated amortization	(68)	(37)
Net	430	274
Estimated amortization expense related to finite-lived intangible assets for the next five years
2012	50
2013	47
2014	44
2015	41
2016	$ 36
Customer contracts and relationships
Finite-Lived Intangible Assets
Average Depreciable Life, Minimum (in years) \| Y	1
Average Depreciable Life, maximum (in years) \| Y	20
Cost	$ 426	221
Accumulated amortization	(61)	(34)
Net	$ 365	187
Property tax abatement
Finite-Lived Intangible Assets
Average Depreciable Life, Minimum (in years) \| Y	7
Average Depreciable Life, maximum (in years) \| Y	13
Cost	$ 38	23
Accumulated amortization	(6)	(2)
Net	$ 32	21
Other agreements
Finite-Lived Intangible Assets
Average Depreciable Life, Minimum (in years) \| Y	30
Average Depreciable Life, maximum (in years) \| Y	70
Cost	$ 26	22
Accumulated amortization	(1)	(1)
Net	25	21
Emission reduction credits
Finite-Lived Intangible Assets
Cost	8	45
Net	$ 8	$ 45

Summary of Significant Accounting Policies (Details 8) shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2011 USD ($) $ / shares	Sep. 30, 2011 USD ($) $ / shares	Jun. 30, 2011 USD ($) $ / shares	Mar. 31, 2011 USD ($) $ / shares	Dec. 31, 2010 USD ($) $ / shares	Sep. 30, 2010 USD ($) $ / shares	Jun. 30, 2010 USD ($) $ / shares	Mar. 31, 2010 USD ($) $ / shares	Dec. 31, 2011 USD ($) $ / shares shares	Dec. 31, 2010 USD ($) $ / shares shares	Dec. 31, 2009 USD ($) $ / shares shares
Net Income Per Limited Partner Unit
General partner ownership interest (as a percent)									2.00%
Numerator for basic and diluted earnings per limited partner unit:
Net income attributable to Plains	$ 278	$ 281	$ 225	$ 182	$ 142	$ 81	$ 131	$ 151	$ 966	$ 505	$ 579
Less: General partner's incentive distribution paid									(221)	(168)	(136)
Less: General partner 2% ownership									(15)	(7)	(9)
Net income available to limited partners in accordance with the application of the two-class method for MLPs									$ 730	$ 330	$ 434
Denominator:
Basic weighted average number of limited partner units outstanding (in units) \| shares									149	137	130
Effect of dilutive securities:
Weighted average LTIP units (in units) \| shares									1	1	1
Diluted weighted average number of limited partner units outstanding (in units) \| shares									150	138	131
Basic net income per limited partner unit (in dollars per unit) \| $ / shares	1.38	1.48	1.14	0.90	0.68	0.28	0.65	0.80	4.91	2.41	3.34
Diluted net income per limited partner unit (in dollars per unit) \| $ / shares	1.37	1.47	1.13	0.90	0.67	0.28	0.65	0.80	4.88	2.40	3.32

Acquisitions and Dispositions (Details)	1 Months Ended			12 Months Ended
Acquisitions and Dispositions (Details)	Dec. 31, 2011 USD ($) transaction	Oct. 31, 2011 USD ($) Y	May 31, 2011 USD ($)	Dec. 31, 2011 USD ($) Y entity	Dec. 31, 2010 USD ($) entity	Dec. 29, 2011 USD ($) mi inch	Nov. 29, 2011 USD ($) mi	Oct. 02, 2011 USD ($) mi barrel barrelperday bcfperday plant railcar	Feb. 09, 2011 USD ($)	Dec. 30, 2010 USD ($) truckterminal mi inch barrel	Dec. 31, 2009
Business acquisition
Purchase accounting adjustments					$ 3,000,000
BP NGL Acquisition
Business acquisition
Purchase price: Cash		$ 50,000,000
Interest payable at closing (as a percent)		2.00%
Contractual rights related to NGL pipelines acquired (in miles) \| mi								2,600
NGL storage capacity acquired (in barrels) \| barrel								20,000,000
Number of fractionation plants acquired \| plant								7
Aggregate net capacity of fractionation plants acquired (in barrels per day) \| barrelperday								232,000
Number of straddle plants acquired \| plant								4
Number of field gas processing plants acquired \| plant								2
Aggregate capacity of field gas processing plants acquired (in Bcf per day) \| bcfperday								6
Long-term and seasonal NGL inventories acquired (in barrels) \| barrel								10,000,000
Throughput capacity of straddle plant acquired (in Bcf per day) \| bcfperday								2.5
Number of rail cars under long-term leases acquired \| railcar								720
Number of years sourcing services for gas supply will be provided after acquisition \| Y		2
Purchase price								$ 1,670,000,000
BP NGL Acquisition \| Minimum
Business acquisition
NGL supply (in barrels per day) \| barrelperday								140,000
BP NGL Acquisition \| Maximum
Business acquisition
NGL supply (in barrels per day) \| barrelperday								150,000
Southern Pines Acquisition
Business acquisition
Ownership interest (as a percent)									100.00%
Purchase price									$ 765,000,000
Purchase price net of cash and other working capital acquired									$ 750,000,000
Percentage of remaining purchase price (as a percent)			5.00%
Escrowed purchase price			$ 37,000,000
Adjustment amount received			$ 10,000,000
Capital expenditures related to acquisition	$ 3,000,000			$ 3,000,000
Business acquisition, allocation of fair value of assets and liabilities
Inventory	14,000,000			14,000,000
Property and equipment, net	341,000,000			341,000,000
Base Gas	3,000,000			3,000,000
Other working capital (including cash acquired)	14,000,000			14,000,000
Cash acquired	13,000,000			13,000,000
Intangible assets	92,000,000			92,000,000
Goodwill	301,000,000			301,000,000
Total assets and liabilities	765,000,000			765,000,000
Intangible assets, useful life
Tax abatement included in amortizable intangible assets	15,000,000			15,000,000
Contracts value included in amortizable intangible assets	77,000,000			77,000,000
Estimated amortization expense related to finite-lived intangible assets for the next five years
Future amortization expense remainder fiscal year				13,000,000
Future amortization expense first full fiscal year	14,000,000			14,000,000
Future amortization expense second full fiscal year	13,000,000			13,000,000
Future amortization expense third full fiscal year	11,000,000			11,000,000
Future amortization expense fourth full fiscal year	8,000,000			$ 8,000,000
Southern Pines Acquisition \| Minimum
Property and equipment, useful life
Average Depreciable Life, (in years) \| Y				5
Intangible assets, useful life
Average Depreciable Life, (in years) \| Y				2
Southern Pines Acquisition \| Maximum
Property and equipment, useful life
Average Depreciable Life, (in years) \| Y				70
Intangible assets, useful life
Average Depreciable Life, (in years) \| Y				10
SG Resources Mississippi, LLC Project, Series 2009
Business acquisition
GO Bonds obligor amount	100,000,000			$ 100,000,000
SG Resources Mississippi, LLC Project, Series 2010
Business acquisition
GO Bonds obligor amount	100,000,000			100,000,000
Other 2011 Acquisitions
Business acquisition, allocation of fair value of assets and liabilities
Inventory	2,000,000			2,000,000
Property and equipment, net	282,000,000			282,000,000
Other working capital	(7,000,000)			(7,000,000)
Intangible assets	152,000,000			152,000,000
Enviornmental liability	(9,000,000)			(9,000,000)
Goodwill	169,000,000			169,000,000
Total assets and liabilities	$ 589,000,000			$ 589,000,000
Western Acquisition
Business acquisition
Number of transactions completed \| transaction	2
Purchase price						$ 220,000,000
Gathering pipelines acquired (in miles) \| mi						82
Diameter of pipeline acquired (in inches) \| inch						16
Gardendale Gathering System Acquisition
Business acquisition
Ownership interest (as a percent)							100.00%
Purchase price							$ 349,000,000
Gathering pipelines acquired (in miles) \| mi							120
Business acquisition, allocation of fair value of assets and liabilities
Goodwill							$ 155,000,000
Additional 2011 acquisition
Business acquisition
Number of additional acquisitions completed (in entities) \| entity				6
Purchase price	$ 20,000,000			$ 20,000,000
Nexen Acquisition
Business acquisition
Purchase price										$ 229,000,000
Purchase price allocation: Business and physical assets										170,000,000
Purchase price allocation: Inventory and other working capital adjustments										$ 59,000,000
Inventory (volumes in barrels) \| barrel										460,000
Number of truck terminals acquired \| truckterminal										8
Business acquisition, allocation of fair value of assets and liabilities
Goodwill										$ 83,000,000
Robinson Lake pipeline
Business acquisition
Gathering pipelines acquired (in miles) \| mi										20
Diameter of pipeline acquired (in inches) \| inch										8
Other 2010 Acquisitions
Business acquisition
Number of additional acquisitions completed (in entities) \| entity					5
Purchase price					$ 178,000,000
White Cliffs Pipeline, LLC
Business acquisition
Ownership interest (as a percent)					34.00%
Capline And associated Tankage
Business acquisition
Ownership interest (as a percent)					11.00%						21.00%

Acquisitions and Dispositions (Details 2) $ in Millions	1 Months Ended	12 Months Ended
Acquisitions and Dispositions (Details 2) $ in Millions	Sep. 30, 2009 USD ($) Bcf installment facility shares	Dec. 31, 2009 USD ($) entity	Dec. 31, 2011 USD ($)	Dec. 31, 2010	May 31, 2010 USD ($)
Other 2009 Acquisitions
Business acquisition
Number of additional acquisitions completed (in entities) \| entity		6
Business acquisition, purchase price
Total purchase price		$ 178
Business acquisition, allocation of fair value of assets and liabilities
Purchase price allocation: Goodwill			$ 27
PNGS Acquisition
Business acquisition
Percentage of ownership acquired (as a percent)	50.00%
Ownership interest (in percent)	100.00%
Percent ownership in PAA/Vulcan prior to acquisition of additional interest (as a percent)	50.00%
Number of natural gas storage facilities owned and operated \| facility	2
Volume of aggregate working gas storage capacity of natural gas storage facilities (in Bcf) \| Bcf	40
Volume of aggregate peak injection capacity of natural gas storage facilities per day (in Bcf) \| Bcf	1.7
Volume of aggregate peak withdrawal capacity of natural gas storage facilities per day (in Bcf) \| Bcf	3.2
Business acquisition, purchase price
Purchase price: Cash	$ 90
Contingent consideration: Cash paid					$ 20
Remaining contingent consideration fair value			$ 19
Equivalent value of PAA common units issued at closing	$ 91
Equivalent value of PAA common units issued at closing (in common units) \| shares	1,907,305
Purchase price: Valuation method used for price per common unit	20 business-day average closing price per unit
Purchase price: Paid at closing	$ 181
Purchase price: Fair value of contingent consideration as of the acquisition date	$ 34
Number of installments for payment of contingent purchase consideration \| installment	2
Business acquisition contingent consideration potential cash payable in each installment	$ 20
Potential contingent consideration	$ 40
Discount rate used for calculating present value of deferred contingent cash consideration (as a percent)	9.00%
Total purchase price	$ 215
Net gain on pre-acquisition relationship	9
Business acquisition, allocation of fair value of assets and liabilities
Property, plant and equipment	791
Base gas	28
Purchase price allocation: Goodwill	25
Intangible assets	23
Working capital and other long-term assets and liabilities	9
Debt	(446)
Total assets and liabilities	$ 430
Capline And associated Tankage
Business acquisition
Percentage of ownership acquired (as a percent)		21.00%		11.00%

Acquisitions and Dispositions (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Dispositions
Proceeds from sale of various property and equipment	$ 12	$ 3	$ 4
Maximum
Dispositions
Gain (loss) on sale of various property and equipment	$ (6)	$ 1	$ (1)

Debt (Details) - USD ($) $ in Millions	12 Months Ended
Debt (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Feb. 07, 2011
Short-term debt:
Total short-term debt	$ 679	$ 1,326
Other short-term debt	4	2
Long-term debt:
Senior notes, net of unamortized discounts	4,262	4,363
Unamortized premium/(discount), net	(13)	(12)
Long-term debt, other	4	8
Total long-term debt	4,520	4,631
Total debt	$ 5,199	$ 5,957
Senior secured hedged inventory facility maturing in August 2013
Debt
Credit facility, interest rate (as a percent)	1.50%	2.10%
Short-term debt:
Credit Facility, Current	$ 75	$ 500
PAA senior unsecured revolving credit facility maturing in August 2016
Debt
Credit facility, interest rate (as a percent)	1.60%	0.70%
Short-term debt:
Credit Facility, Current	$ 32	$ 824
Repayment period (in years)	1 year	1 year
4.25% senior notes due September 2012
Debt
Debt instrument, interest rate (as a percent)	4.25%	4.25%
Short-term debt:
Senior Notes, Current	$ 500
Long-term debt:
Senior notes		$ 500
7.75% senior notes due October 2012
Debt
Debt instrument, interest rate (as a percent)		7.75%	7.75%
Long-term debt:
Senior notes		$ 200
5.63% senior notes due December 2013
Debt
Debt instrument, interest rate (as a percent)	5.63%	5.63%
Long-term debt:
Senior notes	$ 250	$ 250
5.25% senior notes due June 2015
Debt
Debt instrument, interest rate (as a percent)	5.25%	5.25%
Long-term debt:
Senior notes	$ 150	$ 150
3.95% senior notes due September 2015
Debt
Debt instrument, interest rate (as a percent)	3.95%	3.95%
Long-term debt:
Senior notes	$ 400	$ 400
5.88% senior notes due August 2016
Debt
Debt instrument, interest rate (as a percent)	5.88%	5.88%
Long-term debt:
Senior notes	$ 175	$ 175
6.13% senior notes due January 2017
Debt
Debt instrument, interest rate (as a percent)	6.13%	6.13%
Long-term debt:
Senior notes	$ 400	$ 400
6.50% senior notes due May 2018
Debt
Debt instrument, interest rate (as a percent)	6.50%	6.50%
Long-term debt:
Senior notes	$ 600	$ 600
8.75% senior notes due May 2019
Debt
Debt instrument, interest rate (as a percent)	8.75%	8.75%
Long-term debt:
Senior notes	$ 350	$ 350
5.75% senior notes due January 2020
Debt
Debt instrument, interest rate (as a percent)	5.75%	5.75%
Long-term debt:
Senior notes	$ 500	$ 500
5.00% senior notes due February 2021
Debt
Debt instrument, interest rate (as a percent)	5.00%
Long-term debt:
Senior notes	$ 600
6.70% senior notes due May 2036
Debt
Debt instrument, interest rate (as a percent)	6.70%	6.70%
Long-term debt:
Senior notes	$ 250	$ 250
6.65% senior notes due January 2037
Debt
Debt instrument, interest rate (as a percent)	6.65%	6.65%
Long-term debt:
Senior notes	$ 600	$ 600
PNG senior unsecured credit facility
Debt
Credit facility, interest rate (as a percent)	2.10%	3.20%
Short-term debt:
Credit Facility, Current	$ 68
Repayment period (in years)	1 year	1 year
Long-term debt:
Long-term debt under credit facilities	$ 54	$ 260
PNG GO Zone term loans
Debt
Credit facility, interest rate (as a percent)	1.50%
Long-term debt:
Long-term debt under credit facilities	$ 200

Debt (Details 2) $ in Millions	1 Months Ended	12 Months Ended
Debt (Details 2) $ in Millions	Aug. 31, 2011 USD ($) denominator numerator bond	Dec. 31, 2011 USD ($) denominator numerator	Dec. 31, 2010 USD ($)
Debt
Noncontrolling interests in subsidiary (as a percent)		100.00%
PAA senior unsecured revolving credit facility scheduled to mature in July 2012
Debt
Borrowing capacity	$ 1,600
Borrowings outstanding			$ 824
Senior secured hedged inventory debt facility scheduled to mature in October 2011
Debt
Borrowing capacity	500
Borrowings outstanding			500
PNG senior unsecured revolving credit facility scheduled to mature in May 2013
Debt
Borrowing capacity	$ 400
Tenure of credit facility	3 years
Borrowings outstanding			$ 260
PAA senior unsecured 364-day revolving credit facility scheduled to mature in January 2012
Debt
Borrowing capacity	$ 500
Inactive PAA senior unsecured 364-day revolving credit agreement
Debt
Borrowing capacity		$ 1,200
Period for activation of credit facility (in months)		6 months
Denominator for ratio of debt-to-EBITDA, maximum \| denominator		1.00
Denominator for ratio of debt-to-EBITDA during acquisition period, maximum \| denominator		1.00
Acquisition period		P3Q
Threshold for acquisition period qualification		$ 150
Tenure of credit facility		365 days
Numerator for ratio of debt-to-EBITDA, maximum \| numerator		5.00
Numerator for ratio of debt-to-EBITDA during acquisition period, maximum \| numerator		5.50
Senior secured hedged inventory facility maturing in August 2013
Debt
Borrowing capacity		$ 850
Maximum borrowing capacity	$ 1,350
Denominator for ratio of debt-to-EBITDA, maximum \| denominator	1.00
Denominator for ratio of debt-to-EBITDA during acquisition period, maximum \| denominator	1.00
Acquisition period	P3Q
Threshold for acquisition period qualification	$ 150
Numerator for ratio of debt-to-EBITDA, maximum \| numerator	5.00
Numerator for ratio of debt-to-EBITDA during acquisition period, maximum \| numerator	5.50
Borrowings outstanding		$ 75
Basis Variable interest rate used		Eurocurrency Rate or the Base Rate
Letters of credit
Debt
Borrowing capacity		$ 250
PAA senior unsecured revolving credit facility maturing in August 2016
Debt
Borrowing capacity		1,600
Maximum borrowing capacity	$ 2,100
Denominator for ratio of debt-to-EBITDA, maximum \| denominator	1.00
Denominator for ratio of debt-to-EBITDA during acquisition period, maximum \| denominator	1.00
Acquisition period	P3Q
Threshold for acquisition period qualification	$ 150
Numerator for ratio of debt-to-EBITDA, maximum \| numerator	5.00
Numerator for ratio of debt-to-EBITDA during acquisition period, maximum \| numerator	5.50
Borrowings outstanding		$ 32
Basis Variable interest rate used		Eurocurrency Rate or the Base Rate
Canadian sub-facility
Debt
Borrowing capacity		$ 600
Basis Variable interest rate used		Canadian Prime Rate
PNG senior unsecured credit agreement
Debt
Borrowing capacity		$ 450
Denominator for ratio of debt-to-EBITDA, maximum \| denominator	1.00
Denominator for ratio of debt-to-EBITDA during acquisition period, maximum \| denominator	1.00
Numerator for coverage ratio of EBITDA-to-interest, minimum \| numerator	3.00
Tenure of credit facility	5 years
Numerator for ratio of debt-to-EBITDA, maximum \| numerator	5.00
Numerator for ratio of debt-to-EBITDA during acquisition period, maximum \| numerator	5.50
Denominator for coverage ratio of EBITDA-to-interest, minimum \| denominator	1.00
Borrowings outstanding		322
PNG senior unsecured revolving credit facility maturing in August 2016
Debt
Borrowing capacity		$ 250
Maximum borrowing capacity	$ 450
Basis Variable interest rate used		Eurodollar Rate or the Base Rate
PNG GO Zone term loans
Debt
Borrowing capacity		$ 100
Tax-exempt term bonds, number \| bond	2

Debt (Details 3) - USD ($) $ in Millions	1 Months Ended				12 Months Ended
Debt (Details 3) - USD ($) $ in Millions	Feb. 28, 2011	Jan. 31, 2011	Sep. 30, 2010	Jul. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Feb. 07, 2011
Debt
Noncontrolling Interest, Ownership interest of reporting entity (as a percent)					100.00%
Fixed rate senior notes
Debt
Debt instrument face value					$ 4,800	$ 4,400
Debt instrument fair value					5,400	4,700
4.25% senior notes due September 2012
Debt
Senior Notes, Current					$ 500
Amount used to fund hedged inventory						$ 466
Debt instrument, interest rate (as a percent)					4.25%	4.25%
LIBOR					three-month LIBOR
7.75% senior notes due October 2012
Debt
Debt instrument, interest rate (as a percent)						7.75%	7.75%
Debt instrument face value							$ 200
Loss on early redemption of senior notes	$ (23)
5.00% senior notes due February 2021
Debt
Debt instrument, interest rate (as a percent)					5.00%
Debt instrument face value		$ 600
Percentage of face value at which senior notes are sold (as a percent)		99.521%
3.95% senior notes due September 2015
Debt
Debt instrument, interest rate (as a percent)					3.95%	3.95%
Debt instrument face value				$ 400
Percentage of face value at which senior notes are sold (as a percent)				99.889%
6.25% senior notes due September 2015
Debt
Debt instrument, interest rate (as a percent)			6.25%
Debt instrument face value			$ 175
Loss on early redemption of senior notes			$ (6)

Debt (Details 4) - USD ($) $ in Millions	12 Months Ended
Debt (Details 4) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Debt
Weighted-average life of long-term debt	10 years
Maturities
2013	$ 250
2015	550
2016	429
Thereafter	3,300
Total	4,529
Aggregate unamortized net discount	13	$ 12
Other long-term obligations excluded from debt maturities	$ 4
Debt Covenant Compliance	As of December 31, 2011, we were in compliance with the covenants contained in our credit agreements and indentures.
Issuance period for standby letters of credit, upper limit (in days)	70 days
Outstanding letters of credit	$ 33	$ 75

Partners' Capital and Distributions (Details) - $ / shares	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Partners' Capital and Distributions
Common unitholders, units outstanding (in units)	155,376,937	141,199,175
Effective aggregate common ownership interest in the Partnership and its subsidiaries (as a percent)	98.00%
General partner ownership interest (as a percent)	2.00%
Percentage of available cash distributed (as a percent)	100.00%
Number of days required for distribution to unit holders after end of quarter	45 days
General Partner Distribution - Level One
Partners Capital and Distribution
Percent for distribution to the general partner above threshold amount (as a percent)		15.00%
Quarterly incentive distribution threshold amount (in dollars per unit)		$ 0.45
General Partner Distribution - Level Two
Partners Capital and Distribution
Percent for distribution to the general partner above threshold amount (as a percent)		25.00%
Quarterly incentive distribution threshold amount (in dollars per unit)		$ 0.495
General Partner Distribution - Level Three
Partners Capital and Distribution
Percent for distribution to the general partner above threshold amount (as a percent)		50.00%
Quarterly incentive distribution threshold amount (in dollars per unit)		$ 0.675

Partners' Capital and Distributions (Details 2) - $ / shares	3 Months Ended												12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Jun. 30, 2009	Mar. 31, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Partners' Capital and Distributions
Cash distributions per common unit (in dollars per unit)	$ 0.9950	$ 0.9825	$ 0.9700	$ 0.9575	$ 0.9500	$ 0.9425	$ 0.9350	$ 0.9275	$ 0.9200	$ 0.9050	$ 0.9050	$ 0.8925	$ 3.91	$ 3.76	$ 3.62
Cash distributions per common unit excess over MQD (in dollars per unit)	$ 0.5450	$ 0.5325	$ 0.5200	$ 0.5075	$ 0.5000	$ 0.4925	$ 0.4850	$ 0.4775	$ 0.4700	$ 0.4550	$ 0.4550	$ 0.4425

Partners' Capital and Distributions (Details 3) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended			3 Months Ended												12 Months Ended
	Feb. 29, 2012	Jan. 31, 2012	Nov. 30, 2011	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Jun. 30, 2009	Mar. 31, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2007
Reduction in incentive distributions
Reduction in incentive distributions			$ 1													$ 7	$ 16	$ 22	$ 18	$ 20
Reduction in incentive distributions related to acquisition, total																$ 83
Period for reduction of incentive (in years)																2 years
Reduction in incentive distributions per year for the first two years (in dollars per year)																$ 15
Reduction in incentive distributions per year for the third year and thereafter (in dollars per year)				$ 10												10
Cash distributions paid to common unit holders																575	512	468
Cash distribution paid to General Partner - Incentive																204	160	127
Cash distributions paid to General Partner - 2%																12	10	10
Distributions paid to common unit holders and general partner																$ 791	$ 682	$ 605
Cash distributions per limited partner unit (in dollars per unit)				$ 0.9950	$ 0.9825	$ 0.9700	$ 0.9575	$ 0.9500	$ 0.9425	$ 0.9350	$ 0.9275	$ 0.9200	$ 0.9050	$ 0.9050	$ 0.8925	$ 3.91	$ 3.76	$ 3.62
Subsequent cash distribution declared (in dollars per unit)		$ 1.025
Subsequent cash distribution - date paid (in calendar date)	February 14 , 2012
Subsequent cash distribution paid to all ownership interests	$ 225
Subsequent cash distribution paid to common unit holders	159
Subsequent cash distribution paid to General Partner - 2% ownership interest	3
Subsequent cash distribution paid to General Partner - Incentive	$ 63
Pacific
Reduction in incentive distributions
Reduction in incentive distributions																$ 5	$ 10	$ 15	15	$ 20
Reduction in incentive distributions related to acquisition, total																65
Rainbow
Reduction in incentive distributions
Reduction in incentive distributions																	1	6	$ 3
Reduction in incentive distributions related to acquisition, total																10
PNGS Acquisition
Reduction in incentive distributions
Reduction in incentive distributions																2	$ 5	$ 1
Reduction in incentive distributions related to acquisition, total																$ 8

Partners' Capital and Distributions (Details 4) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended			3 Months Ended	12 Months Ended
	Feb. 28, 2011	May 31, 2010	Apr. 30, 2010	Jun. 30, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	May 05, 2010
Partners Capital and Distribution
Noncontrolling Interest, Ownership interest of reporting entity (as a percent)					100.00%
Non-controlling interests associated with the book value of PNG sold to third parties					$ 370	$ 268	$ 26
PNG units owned by PAA (in units)					53,600,000	43,500,000
Units purchased (in units)	10,200,000
Number of common units transfer to noncontrolling interests in connection with the settlement of equity compensation awards (in shares)					(100,000)
PNG
Partners Capital and Distribution
Noncontrolling interests, ownership percentage of noncontrolling owners (as a percent)					36.00%
PNG \| Series A Subordinated Units
Partners Capital and Distribution
PNG units owned by PAA (in units)					11,900,000	11,900,000
PNG \| Series B Subordinated Units
Partners Capital and Distribution
PNG units owned by PAA (in units)					13,500,000	13,500,000
PNG \| IPO
Partners Capital and Distribution
Number of common units issued representing limited partner interest (in units)		13,478,000		13,500,000
Price per unit of common units issued								$ 21.50
Number of common units issued at closing of the IPO pursuant to the full exercise of the underwriters's over-allotment option		1,758,000
Net proceeds received by PNG from sale of common units		$ 268		$ 268
Percent of equity represented by common units (as a percent)		23.00%
Number of common units issued to Plains (in units)		18,100,000
General Partner Interest in PNG (as a percent)								2.00%
Non-controlling interests associated with the book value of PNG sold to third parties		$ 167
Increase to partners' capital		$ 101
PNG \| IPO \| Series A Subordinated Units
Partners Capital and Distribution
Number of common units issued to Plains (in units)		13,900,000
PNG \| IPO \| Series B Subordinated Units
Partners Capital and Distribution
Number of common units issued to Plains (in units)		11,500,000
PNGS
Partners Capital and Distribution
Ownership interest in PNGS prior to IPO (as a percent)			100.00%
Equity interest in PNGS contributed to PNG (as a percent)		100.00%

Partners' Capital and Distributions (Details 5) shares in Millions	1 Months Ended		12 Months Ended
	Feb. 29, 2012 tranche $ / shares	Aug. 31, 2010 agreement shares	Dec. 31, 2011 Bcf tranche $ / shares shares	Dec. 31, 2010	Aug. 16, 2010 shares
Performance Thresholds
Conversion of subordinated units, terms				The Series A subordinated units will convert to common units once certain earnings and distribution targets are met for three consecutive, non-overlapping four-quarter periods.
PNG
Partners Capital and Distribution
Prior to Modification (in units)					43.5
Post Modification (in units)			43.5
Common and Series A Subordinated Unit Subtotal \| PNG
Partners Capital and Distribution
Prior to Modification (in units)					32.0
Modification (in units)		(2.0)
Post Modification (in units)			30.0
Performance Thresholds
General Partner Interest in PNG (as a percent)			2.00%
Common Units \| PNG
Partners Capital and Distribution
Prior to Modification (in units)					18.1
Post Modification (in units)			18.1
Series A Subordinated Units
Performance Thresholds
Number of distinct tranches \| tranche			5
Number of tranches increases annual distribution \| tranche	3
Series A Subordinated Units \| PNG
Partners Capital and Distribution
Prior to Modification (in units)					13.9
Modification (in units)		(2.0)
Post Modification (in units)			11.9
Performance Thresholds
Minimum distribution on annualized basis (in dollars per unit) \| $ / shares			$ 1.35
Number of consecutive quarters of cash distribution			P4Q
Number of consecutive periods of cash distribution			3 years
Series B Subordinated Units
Partners Capital and Distribution
Number of potential conversion tranches, before Second Amended and Restated Agreement \| agreement		3
Number of potential conversion tranches, after Second Amended and Restated Agreement \| agreement		5
Series B Subordinated Units \| PNG
Partners Capital and Distribution
Portion of Series B subordinated units for which performance thresholds modified	one third
Prior to Modification (in units)					11.5
Modification (in units)		2.0
Post Modification (in units)			13.5
Series B Subordinated Units \| Tranche 1 \| PNG
Partners Capital and Distribution
Prior to Modification (in units)					4.6
Modification (in units)		(2.0)
Post Modification (in units)			2.6
Performance Thresholds
Annualized distribution level (in dollars per unit) \| $ / shares	$ 1.71		$ 1.44
Working gas storage capacity (in Bcf) \| Bcf			29.6
Series B subordinated units that will convert into Series A subordinated units			2.6
Number of consecutive quarters of cash sufficiency			P2Q
Number of consecutive quarters of cash distribution			P2Q
General Partner Interest in PNG (as a percent)			2.00%
Series B Subordinated Units \| Tranche 2 \| PNG
Partners Capital and Distribution
Prior to Modification (in units)					3.8
Modification (in units)		(1.0)
Post Modification (in units)			2.8
Performance Thresholds
Annualized distribution level (in dollars per unit) \| $ / shares	1.71		$ 1.53
Working gas storage capacity (in Bcf) \| Bcf			35.6
Series B subordinated units that will convert into Series A subordinated units			2.8
Number of consecutive quarters of cash sufficiency			P2Q
Number of consecutive quarters of cash distribution			P2Q
General Partner Interest in PNG (as a percent)			2.00%
Series B Subordinated Units \| Tranche 3 \| PNG
Partners Capital and Distribution
Prior to Modification (in units)					3.1
Modification (in units)		(1.0)
Post Modification (in units)			2.1
Performance Thresholds
Annualized distribution level (in dollars per unit) \| $ / shares	1.71		$ 1.63
Working gas storage capacity (in Bcf) \| Bcf			41.6
Series B subordinated units that will convert into Series A subordinated units			2.1
Number of consecutive quarters of cash sufficiency			P2Q
Number of consecutive quarters of cash distribution			P2Q
General Partner Interest in PNG (as a percent)			2.00%
Series B Subordinated Units \| Tranche 4 \| PNG
Partners Capital and Distribution
Modification (in units)		3.0
Post Modification (in units)			3.0
Performance Thresholds
Annualized distribution level (in dollars per unit) \| $ / shares	1.71		$ 1.71
Working gas storage capacity (in Bcf) \| Bcf			48.0
Series B subordinated units that will convert into Series A subordinated units			3.0
Number of consecutive quarters of cash sufficiency			P2Q
Number of consecutive quarters of cash distribution			P2Q
General Partner Interest in PNG (as a percent)			2.00%
Series B Subordinated Units \| Tranche 5 \| PNG
Partners Capital and Distribution
Modification (in units)		3.0
Post Modification (in units)			3.0
Performance Thresholds
Annualized distribution level (in dollars per unit) \| $ / shares	$ 1.80		$ 1.80
Working gas storage capacity (in Bcf) \| Bcf			48.0
Series B subordinated units that will convert into Series A subordinated units			3.0
Number of consecutive quarters of cash sufficiency			P2Q
Number of consecutive quarters of cash distribution			P2Q
General Partner Interest in PNG (as a percent)			2.00%

Partners' Capital and Distributions (Details 6) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Feb. 28, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	May 31, 2011
Partners Capital and Distribution
Number of common units transfer to noncontrolling interests in connection with the settlement of equity compensation awards (in shares)		(100,000)
Noncontrolling Interest, Ownership interest of reporting entity (as a percent)		100.00%
PNG units owned by PAA (in units)		53,600,000	43,500,000
Units purchased (in units)	10,200,000
Non-controlling interests associated with the book value of PNG sold to third parties		$ 370	$ 268	$ 26
Common Units
Partners Capital and Distribution
Non-controlling interests associated with the book value of PNG sold to third parties		$ 63	$ 99	$ (37)
PNG \| Series A Subordinated Units
Partners Capital and Distribution
PNG units owned by PAA (in units)		11,900,000	11,900,000
PNG \| Series B Subordinated Units
Partners Capital and Distribution
PNG units owned by PAA (in units)		13,500,000	13,500,000
PNG \| Common Units
Partners Capital and Distribution
Number of common units transfer to noncontrolling interests in connection with the settlement of equity compensation awards (in shares)		(100,000)
PNG units owned by PAA (in units)		28,200,000	18,100,000
Units purchased (in units)	10,200,000
PNG \| Private Placement
Partners Capital and Distribution
Number of common units issued representing limited partner interest (in units)	17,400,000
Net proceeds from private placement on PNG common units	$ 370
Proceeds received by PNG from Plains for sale of common units	230
Contribution from general partner	$ 12
Number of common units transfer to noncontrolling interests in connection with the settlement of equity compensation awards (in shares)					58,672
Number of common units issued to Plains (in units)	10,200,000
General Partner Interest in PNG (as a percent)	2.00%
Units purchased (in units)	10,200,000
Non-controlling interests associated with the book value of PNG sold to third parties	$ 306
Increase to partners' capital	$ 64
PNGS \| Private Placement
Partners Capital and Distribution
Noncontrolling Interest, Ownership interest of reporting entity (as a percent)			77.00%		64.00%

Partners' Capital and Distributions (Details 7) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2009 USD ($)	Dec. 31, 2008 mi	Dec. 31, 2009 USD ($)	Dec. 31, 2011
Partners Capital and Distribution
Noncontrolling Interest, Ownership interest of reporting entity (as a percent)				100.00%
SLC Pipeline
Partners Capital and Distribution
Construction of pipeline completed in Salt Lake City Area system (in miles) \| mi		94
Book value of pipeline contributed	$ 254
Cash contribution made by Holly Energy Partners LP	$ 26
Ownership percentage acquired by Holly Energy Partners LP (as a percent)	25.00%
Noncontrolling Interest, Ownership interest of reporting entity (as a percent)				75.00%
Noncontrolling interests, ownership percentage of noncontrolling owners (as a percent)	25.00%			25.00%
Loss recognized in partners' capital relating to formation of joint venture			$ 38

Partners' Capital and Distributions (Details 8) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Partners' Capital and Distributions
Net income attributable to Plains	$ 278	$ 281	$ 225	$ 182	$ 142	$ 81	$ 131	$ 151	$ 966	$ 505	$ 579
Transfers to the noncontrolling interests:
Increase in capital from sale of PNG units									64	101
Decrease in capital from sale of interest in SLC Pipeline											(38)
Change from net income attributable to Plains and net transfers to the noncontrolling interest									1,030	606	541
Changes in the noncontrolling interests in partners' capital
Beginning balance				231					231
Sale of noncontrolling interest in a subsidiary (Note 5)									370	268	26
Net income attributable to noncontrolling interests									28	9	1
Equity compensation expense (Note 10)									28	16	5
Ending Balance	524				231				524	231
LTIP Vesting
LTIP unit vestings, fair value									24	26	19
Noncontrolling Interests
Changes in the noncontrolling interests in partners' capital
Beginning balance				$ 231				$ 63	231	63
Sale of noncontrolling interest in a subsidiary (Note 5)									306	167	64
Net income attributable to noncontrolling interests									28	9	1
Distribution to noncontrolling interest									(40)	(10)	(2)
Equity compensation expense (Note 10)									3	3
Net deferred loss on cash flow hedges									(4)
Other										(1)
Ending Balance	$ 524				$ 231				$ 524	$ 231	$ 63
PNG Long Term Incentive Plan Awards
LTIP Vesting
LTIP awards, issued (in units)									242,762
LTIP unit vestings, fair value									$ 15

Partners' Capital and Distributions (Details 9) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended					12 Months Ended
	Nov. 30, 2011	Mar. 31, 2011	Nov. 30, 2010	Sep. 30, 2009	Mar. 31, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Partners Capital and Distribution
Units Issued	6,000,000	7,935,000	4,780,000	5,290,000	5,750,000	13,935,000	4,780,000	11,040,000
Gross Unit Price (in dollars per unit)	$ 65.03	$ 64.00	$ 62.60	$ 46.70	$ 36.90
Proceeds from Sale	$ 390	$ 508	$ 299	$ 247	$ 212	$ 898	$ 299	$ 459
General Partner Contribution	9	10	6	5	4	19	6	9
Costs	(13)	(15)	(9)	(6)	(6)	(28)	(9)	(12)
Net Proceeds	$ 386	$ 503	$ 296	$ 246	$ 210	$ 889	$ 296	$ 456
PNGS Acquisition
Partners Capital and Distribution
Equivalent value of PAA common units issued at closing (in common units)				1,907,305
Equivalent value of PAA common units issued at closing				$ 91
Contributions from general partner				$ 2

Partners' Capital and Distributions (Details 10) - AAP LP Class B Units - shares	Dec. 31, 2011	Dec. 31, 2010
Partners Capital and Distribution
Units Outstanding (in units)	183,500	175,500
Outstanding Units Earned (in units)	80,063	80,063
Reserved for Future Grants, outstanding	16,500	24,500

Derivatives and Hedging Instruments (Details)	Dec. 31, 2011 Bcf barrel
Commodity Price Risk Hedging:
Total derivative positions	5,000,000
Storage capacity owned but not used in entity's transportation operations (in barrels)	80,000,000
Derivative hedges to manage the risk of not utilizing storage capacity (in barrels)	3,700,000
Net long crude oil derivative position
Commodity Price Risk Hedging:
Net derivative positions per day (in barrels)	177,300
Total derivative positions	5,300,000
Net short spread position hedging anticipated crude oil lease gathering purchases
Commodity Price Risk Hedging:
Net derivative positions per day (in barrels)	30,800
Total derivative positions	10,300,000
WTS/WTI crude oil basis swaps
Commodity Price Risk Hedging:
Net derivative positions per day (in barrels)	9,200
Total derivative positions	6,700,000
LLS/WTI crude oil basis swaps
Commodity Price Risk Hedging:
Net derivative positions per day (in barrels)	6,000
Total derivative positions	2,200,000
Crude oil net short position
Commodity Price Risk Hedging:
Net derivative positions per day (in barrels)	1,500
Total derivative positions	2,200,000
Crude oil long put option position
Commodity Price Risk Hedging:
Total derivative positions	400,000
Crude oil long call option position
Commodity Price Risk Hedging:
Total derivative positions	900,000
Long natural gas swaps position for anticipated base gas purchases
Commodity Price Risk Hedging:
Total derivative positions \| Bcf	3.0
Short natural gas swap position related to anticipated natural gas sales
Commodity Price Risk Hedging:
Total derivative positions \| Bcf	14.6
Long natural gas swap position related to anticipated natural gas purchases
Commodity Price Risk Hedging:
Total derivative positions \| Bcf	0.6

Derivatives and Hedging Instruments (Details 2) $ in Millions	1 Months Ended	12 Months Ended
	Jul. 31, 2009 USD ($) contract	Dec. 31, 2011 USD ($) contract
Interest Rate Risk Hedging
Net deferred losses from interest rate risk hedging included in AOCI \| $		$ 133
PNG
Interest Rate Risk Hedging
Number of outstanding interest rate swaps (in contracts)		3
Rate of fixed interest to be received on interest rate swap (as a percent)		0.95%
Notional amount of interest rate derivatives \| $		$ 100
Number of interest rate swaps that terminate in June 2014 (in contracts)		2
Number of interest rate swaps that terminate in August 2014 (in contracts)		1
Forward starting interest rate swaps terminated in January 2011
Interest Rate Risk Hedging
Number of terminated interest rate swaps (in contracts)		3
Rate of fixed interest to be received on interest rate swap (as a percent)		3.60%
Notional amount of interest rate derivatives \| $		$ 100
Cash proceeds associated with termination of interest rate swaps \| $		$ 12
4 forward starting swaps (10-year)
Interest Rate Risk Hedging
Number of outstanding interest rate swaps (in contracts)		4
Rate of fixed interest to be received on interest rate swap (as a percent)		3.46%
Notional amount of interest rate derivatives \| $		$ 200
6 forward starting swaps (30-year)
Interest Rate Risk Hedging
Number of outstanding interest rate swaps (in contracts)		6
Rate of fixed interest to be received on interest rate swap (as a percent)		4.24%
Notional amount of interest rate derivatives \| $		$ 250
2 forward starting swaps (30-year)
Interest Rate Risk Hedging
Number of outstanding interest rate swaps (in contracts)		2
Rate of fixed interest to be received on interest rate swap (as a percent)		3.94%
Notional amount of interest rate derivatives \| $		$ 50
10 forward starting swaps (30-year)
Interest Rate Risk Hedging
Number of outstanding interest rate swaps (in contracts)		10
Rate of fixed interest to be received on interest rate swap (as a percent)		3.60%
Notional amount of interest rate derivatives \| $		$ 250
Interest Rate Swaps
Interest Rate Risk Hedging
Number of outstanding interest rate swaps (in contracts)	4
Rate of fixed interest to be received on interest rate swap (as a percent)	4.25%
Notional amount of interest rate derivatives \| $	$ 300
Basis for variable interest rate	three-month LIBOR plus a spread on a notional principal amount
Additional average spread over LIBOR (as a percent)	2.42%
Number of interest rate swaps that terminated in 2011 (in contracts)		2
Number of interest rate swaps that terminate in 2012 (in contracts)		2

Derivatives and Hedging Instruments (Details 3) $ in Millions, $ in Millions	Dec. 31, 2011 USD ($) rate	Dec. 31, 2011 CAD ($) rate
Currency Exchange Rate Risk Hedging:
Net deferred gains from currency risk rate hedging included in AOCI \| $	$ 10
Foreign exchange forward contract at the rate CAD 1.01 to USD 1.00 maturing in 2012
Currency Exchange Rate Risk Hedging:
Notional amount of outstanding foreign currency forward exchange contracts	$ 15	$ 15
Average exchange rate for outstanding foreign currency forward exchange contracts	1.01	1.01
Foreign exchange forward contract at the rate CAD 1.00 to USD 1.00 maturing in 2013
Currency Exchange Rate Risk Hedging:
Notional amount of outstanding foreign currency forward exchange contracts	$ 9	$ 9
Average exchange rate for outstanding foreign currency forward exchange contracts	1.00	1.00

Derivatives and Hedging Instruments (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Impact of derivative activities recognized in earnings
Total	$ (36)	$ 23
Reclassification from AOCI to earnings during the period to offset a LCM adjustment relating to carrying value of PNG's inventory	6
Commodity \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	(62)	16
Derivatives in Cash Flow Hedging Relationships - Ineffective Portion	(8)	(1)
Commodity \| Transportation segment revenues
Impact of derivative activities recognized in earnings
Total		2
Commodity \| Purchases and related costs
Impact of derivative activities recognized in earnings
Total	6	(4)
Commodity \| Field Operating costs
Impact of derivative activities recognized in earnings
Total	1	3
Commodity \| Facilities segment revenues
Impact of derivative activities recognized in earnings
Total	11
Interest Rate Contracts \| Interest expense
Impact of derivative activities recognized in earnings
Total	1	3
Net gain associated with interest rate swaps designated as fair value hedges	2	1
Foreign exchange contracts \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	1	2
Foreign exchange contracts \| Purchases and related costs
Impact of derivative activities recognized in earnings
Total		2
Foreign exchange contracts \| Other income/(expense), net
Impact of derivative activities recognized in earnings
Total	6	(1)
Derivatives designated as hedging instruments
Impact of derivative activities recognized in earnings
Total	(137)	25
Derivatives designated as hedging instruments \| Commodity \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	(161)	14
Derivatives designated as hedging instruments \| Commodity \| Transportation segment revenues
Impact of derivative activities recognized in earnings
Total		2
Derivatives designated as hedging instruments \| Commodity \| Purchases and related costs
Impact of derivative activities recognized in earnings
Total	6	8
Derivatives designated as hedging instruments \| Commodity \| Facilities segment revenues
Impact of derivative activities recognized in earnings
Total	11
Derivatives designated as hedging instruments \| Interest Rate Contracts \| Interest expense
Impact of derivative activities recognized in earnings
Total	1	1
Derivatives designated as hedging instruments \| Foreign exchange contracts \| Other income/(expense), net
Impact of derivative activities recognized in earnings
Total	6
Derivatives not designated as hedging instruments
Impact of derivative activities recognized in earnings
Total	101	(2)
Derivatives not designated as hedging instruments \| Commodity \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	99	2
Derivatives not designated as hedging instruments \| Commodity \| Purchases and related costs
Impact of derivative activities recognized in earnings
Total		(12)
Derivatives not designated as hedging instruments \| Commodity \| Field Operating costs
Impact of derivative activities recognized in earnings
Total	1	3
Derivatives not designated as hedging instruments \| Interest Rate Contracts \| Interest expense
Impact of derivative activities recognized in earnings
Total		2
Derivatives not designated as hedging instruments \| Foreign exchange contracts \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	$ 1	2
Derivatives not designated as hedging instruments \| Foreign exchange contracts \| Purchases and related costs
Impact of derivative activities recognized in earnings
Total		2
Derivatives not designated as hedging instruments \| Foreign exchange contracts \| Other income/(expense), net
Impact of derivative activities recognized in earnings
Total		$ (1)

Derivatives and Hedging Instruments (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Derivatives disclosures
Asset Derivatives Fair Value	$ 187	$ 120
Liability Derivatives Fair Value	(230)	(150)
Net loss deferred in AOCI	(99)
Net gain expected to be reclassified to earnings in next 12 months	21
Gain expected to be reclassified to earnings prior to 2015	9
Net deferred gain/(loss) recognized in AOCI on derivatives (effective portion)	(151)	(76)
Gain (loss) expected to be reclassified to earnings through 2045	(129)
Gain (loss) on discontinued cash flow hedge reclassified to earnings during the year	2
Broker receivable		99
Broker payable	7
Initial margin	52	56
Variation margin returned/(posted)	(59)	43
Commodity
Derivatives disclosures
Net deferred gain/(loss) recognized in AOCI on derivatives (effective portion)	(15)	(82)
Interest Rate Contracts
Derivatives disclosures
Net deferred gain/(loss) recognized in AOCI on derivatives (effective portion)	(136)	8
Foreign exchange contracts
Derivatives disclosures
Net deferred gain/(loss) recognized in AOCI on derivatives (effective portion)		(2)
Derivatives designated as hedging instruments
Derivatives disclosures
Asset Derivatives Fair Value	94	81
Liability Derivatives Fair Value	(187)	(72)
Derivatives designated as hedging instruments \| Commodity \| Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	72	71
Liability Derivatives Fair Value	(47)	(70)
Derivatives designated as hedging instruments \| Commodity \| Other long-term assets
Derivatives disclosures
Asset Derivatives Fair Value	20
Liability Derivatives Fair Value	(2)	(1)
Derivatives designated as hedging instruments \| Commodity \| Other current liabilities
Derivatives disclosures
Liability Derivatives Fair Value		(1)
Derivatives designated as hedging instruments \| Interest Rate Contracts \| Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	1	10
Derivatives designated as hedging instruments \| Interest Rate Contracts \| Other current liabilities
Derivatives disclosures
Liability Derivatives Fair Value	(24)
Derivatives designated as hedging instruments \| Interest Rate Contracts \| Other long-term liabilities
Derivatives disclosures
Liability Derivatives Fair Value	(114)
Derivatives designated as hedging instruments \| Foreign exchange contracts \| Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	1
Derivatives not designated as hedging instruments
Derivatives disclosures
Asset Derivatives Fair Value	93	39
Liability Derivatives Fair Value	(43)	(78)
Derivatives not designated as hedging instruments \| Commodity \| Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	87	11
Liability Derivatives Fair Value	(39)	(68)
Derivatives not designated as hedging instruments \| Commodity \| Other long-term assets
Derivatives disclosures
Asset Derivatives Fair Value	6	20
Liability Derivatives Fair Value	(3)
Derivatives not designated as hedging instruments \| Commodity \| Other current liabilities
Derivatives disclosures
Asset Derivatives Fair Value		2
Liability Derivatives Fair Value	$ (1)	(10)
Derivatives not designated as hedging instruments \| Interest Rate Contracts \| Other current assets
Derivatives disclosures
Asset Derivatives Fair Value		4
Derivatives not designated as hedging instruments \| Interest Rate Contracts \| Other long-term assets
Derivatives disclosures
Asset Derivatives Fair Value		1
Derivatives not designated as hedging instruments \| Foreign exchange contracts \| Other current assets
Derivatives disclosures
Asset Derivatives Fair Value		$ 1

Derivatives and Hedging Instruments (Details 6) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2011	Dec. 31, 2011	Dec. 31, 2010
Level 3
Roll forward of Level 3 Net Liability
Beginning Balance	$ (14)	$ (14)	$ (28)
Unrealized gains/(losses):
Included in earnings		17	(22)
Included in other comprehensive income		2	3
Settlements		21	42
Derivatives entered into during the period		3	(9)
Transfers out of Level 3		(17)
Ending Balance		12	(14)
Change in unrealized gains/(losses) included in earnings relating to level 3 derivatives still held at the end of the periods		22	(27)
Transfers from level 3 to Level 2	$ 17
Recurring Fair Value Measures \| Level 1
Recurring Fair Value Measures
Net asset/(liability) at fair value		80	(16)
Recurring Fair Value Measures \| Level 1 \| Commodity
Recurring Fair Value Measures
Net asset/(liability) at fair value		80	(16)
Recurring Fair Value Measures \| Level 2
Recurring Fair Value Measures
Net asset/(liability) at fair value		(135)
Recurring Fair Value Measures \| Level 2 \| Commodity
Recurring Fair Value Measures
Net asset/(liability) at fair value		1
Recurring Fair Value Measures \| Level 2 \| Interest Rate Contracts
Recurring Fair Value Measures
Net asset/(liability) at fair value		(137)
Recurring Fair Value Measures \| Level 2 \| Foreign exchange contracts
Recurring Fair Value Measures
Net asset/(liability) at fair value		1
Recurring Fair Value Measures \| Level 3
Recurring Fair Value Measures
Net asset/(liability) at fair value		12	(14)
Recurring Fair Value Measures \| Level 3 \| Commodity
Recurring Fair Value Measures
Net asset/(liability) at fair value		12	(30)
Recurring Fair Value Measures \| Level 3 \| Interest Rate Contracts
Recurring Fair Value Measures
Net asset/(liability) at fair value			15
Recurring Fair Value Measures \| Level 3 \| Foreign exchange contracts
Recurring Fair Value Measures
Net asset/(liability) at fair value			1
Recurring Fair Value Measures \| Total
Recurring Fair Value Measures
Net asset/(liability) at fair value		(43)	(30)
Recurring Fair Value Measures \| Total \| Commodity
Recurring Fair Value Measures
Net asset/(liability) at fair value		93	(46)
Recurring Fair Value Measures \| Total \| Interest Rate Contracts
Recurring Fair Value Measures
Net asset/(liability) at fair value		(137)	15
Recurring Fair Value Measures \| Total \| Foreign exchange contracts
Recurring Fair Value Measures
Net asset/(liability) at fair value		$ 1	$ 1

Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Current tax (benefit)/expense:
State income tax	$ 2	$ 1	$ 2
Canadian federal and provincial income tax	36	(2)	13
Total current tax (benefit)/expense	38	(1)	15
Deferred tax (benefit)/expense:
State income tax, deferred	(2)	1
Canadian federal and provincial income tax, deferred	9	(1)	(9)
Total deferred tax (benefit)/expense	7		(9)
Total income tax (benefit)/expense	$ 45	$ (1)	$ 6

- Definition

The component of income tax expense for the period representing amounts of income taxes paid or payable (or refundable) for the period for all income tax obligations as determined by applying the provisions of relevant enacted tax laws to relevant amounts of taxable Income or Loss from continuing operations.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 45
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Current Tax Expense (or Benefit)
-URI http://asc.fasb.org/extlink&oid=6509736

Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

+ Details

- Definition

The component of income tax expense for the period representing amounts paid or payable (or refundable) as determined by applying the provisions of enacted state and local tax law to relevant amounts of taxable Income or Loss from continuing operations.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 45
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

+ Details

- Definition

The component of total income tax expense for the period comprised of the increase (decrease) in the entity's net foreign deferred tax assets and liabilities attributable to continuing operations as determined by applying the provisions of applicable enacted tax laws of countries other than the country of domicile.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 45
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-URI http://asc.fasb.org/extlink&oid=6510177

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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

+ Details

- Definition

The component of income tax expense for the period representing the increase (decrease) in the entity's deferred tax assets and liabilities pertaining to continuing operations.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 95
-Paragraph 28
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
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-Name Statement of Financial Accounting Standard (FAS)
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-Name Accounting Standards Codification
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

+ Details

- Definition

The component of total income tax expense for the period comprised of the increase (decrease) in the entity's state and local deferred tax assets and liabilities attributable to continuing operations as determined by applying the provisions of the applicable enacted tax laws.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 45
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.7)
-URI http://asc.fasb.org/extlink&oid=6889476&loc=d3e330036-122817

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Deferred Tax Expense (or Benefit)
-URI http://asc.fasb.org/extlink&oid=6510177

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 8, 16, 17, 289
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Income Taxes (Details 2) - USD ($) $ in Millions	12 Months Ended
Income Taxes (Details 2) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Taxes
Income before tax	$ 1,039	$ 513	$ 586
Partnership earnings not subject to current Canadian tax	(909)	(509)	(585)
Partnership earnings subject to current Canadian tax	$ 130	$ 4	$ 1
Canadian federal and provincial corporate tax rate (as a percent)	27.00%	28.00%	29.00%
Income tax at statutory rate	$ 35	$ 1
Current tax (benefit)/expense:
Canadian withholding tax	12
Canadian period tax as a result of book versus tax differences	(9)		$ 4
Canadian permanent differences between book and tax	(2)	(3)	9
State income tax	2	1	2
Total current tax (benefit)/expense	38	(1)	15
Deferred tax (benefit)/expense:
State income tax, deferred	(2)	1
Canadian deferred tax (benefit)/expense as a result of book versus tax differences	9	(1)	(9)
Total deferred tax (benefit)/expense	7		(9)
Total income tax (benefit)/expense	45	(1)	$ 6
Deferred tax assets:
Book accruals in excess of current tax deductions	18	4
Total deferred tax assets	18	4
Deferred tax liabilities:
Property, plant and equipment in excess of tax values	(147)	(128)
Total deferred tax liabilities	(147)	(128)
Net deferred tax liabilities	$ (129)	$ (124)

Major Customers and Concentration of Credit Risk (Details) - Revenues	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Minimum
Major Customers and Concentration of Credit Risk
Percentage required for qualification as major customer (as a percent)	10.00%	10.00%	10.00%
Marathon Petroleum Corporation \| Consolidated revenue
Major Customers and Concentration of Credit Risk
Percentage of major customer revenue (as a percent)	16.00%	14.00%	14.00%
ConocoPhillips Company \| Consolidated revenue
Major Customers and Concentration of Credit Risk
Percentage of major customer revenue (as a percent)	10.00%	10.00%	12.00%

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Related party transaction
Costs reimbursed to general partner	$ 419	$ 374	$ 328
Oxy
Related party transaction
Related party ownership of general partner interest (as a percent)	35.00%
Revenues	$ 2,568	2,189	181
Purchases and related cost	361	221	164
Trade accounts receivable and other receivables, gross	132	379
Accounts payable, gross	155	$ 124
Vulcan Energy Corporation
Related party transaction
Ownership interest in general partner of entity that was sold by a related party (as a percent)		50.10%
Other
Related party transaction
Purchases and related cost	33	$ 36	$ 34
Accounts payable, gross	$ 5	$ 3

Equity Compensation Plans (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended			12 Months Ended
	Feb. 29, 2012	Feb. 28, 2012	Sep. 30, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Feb. 02, 2012	Dec. 31, 2008
Share-based Compensation Arrangement, by Share-based Payment Award
Accrued liability related to all outstanding LTIP awards and DERs				$ 138	$ 102
PAA Long-term Incentive Plans
Share-based Compensation Arrangement, by Share-based Payment Award
Units Outstanding (in units)				4,000,000	4,400,000	3,900,000		3,900,000
Estimated unit vesting in 2012 (in units)				1,500,000
Estimated unit vesting in 2013 (in units)				1,100,000
Estimated unit vesting in 2014 (in units)				700,000
Estimated unit vesting in 2015 (in units)				700,000
PNG annualized distribution probable of occurring				$ 4.35	$ 4.00
Units outstanding that include DERs (in units)				2,200,000
DERs currently vested (in units)				1,700,000
Units vested (in units)				700,000	1,100,000	600,000
PAA Long-term Incentive Plans \| Range of annualized vesting distribution amount from $3.75 to $4.45
Share-based Compensation Arrangement, by Share-based Payment Award
Units Outstanding (in units)				2,600,000
Estimated unit vesting in 2012 (in units)				900,000
Estimated unit vesting in 2013 (in units)				600,000
Estimated unit vesting in 2014 (in units)				500,000
Estimated unit vesting in 2015 (in units)				600,000
Annualized distribution, low end of range (in dollars per unit)				$ 3.75
Annualized distribution, high end of range (in dollars per unit)				$ 4.45
PAA Long-term Incentive Plans \| Range of annualized vesting distribution amount from $3.80 to $4.25
Share-based Compensation Arrangement, by Share-based Payment Award
Units Outstanding (in units)				1,400,000
Estimated unit vesting in 2012 (in units)				600,000
Estimated unit vesting in 2013 (in units)				500,000
Estimated unit vesting in 2014 (in units)				200,000
Estimated unit vesting in 2015 (in units)				100,000
Annualized distribution, low end of range (in dollars per unit)				$ 3.80
Annualized distribution, high end of range (in dollars per unit)				$ 4.25
Award vesting rights (as a percent)				fifty percent
Employees and Directors LTIP
Share-based Compensation Arrangement, by Share-based Payment Award
Authorized grants (in units)				5,400,000
Non-officer Employee Long-term Incentive Tracking Unit Plan
Share-based Compensation Arrangement, by Share-based Payment Award
Authorized grants (in units)				2,100,000
PNG Long Term Incentive Plan Awards
Share-based Compensation Arrangement, by Share-based Payment Award
Authorized grants (in units)				3,000,000
Units Outstanding (in units)				500,000
Estimated unit vesting in 2013 (in units)				100,000
Estimated unit vesting in 2014 (in units)				100,000
Estimated unit vesting in 2015 (in units)				100,000
Estimated unit vesting thereafter (in units)				200,000
PNG annualized distribution probable of occurring				$ 1.45	$ 1.45
Award vesting rights (as a percent)		fifty percent
Units outstanding that include DERs (in units)				300,000
Phantom common units granted (in units)		232,500
Phantom common units granted associated with the conversion of Series A and Series B subordinated units (in units)		232,500
PNG Long Term Incentive Plan Awards \| Range of annualized vesting distribution amount from $1.55 to $1.90
Share-based Compensation Arrangement, by Share-based Payment Award
Units Outstanding (in units)				300,000
Estimated unit vesting in 2015 (in units)				100,000
Estimated unit vesting thereafter (in units)				200,000
Annualized distribution, low end of range (in dollars per unit)				$ 1.55
Annualized distribution, high end of range (in dollars per unit)				$ 1.90
PNG Long Term Incentive Plan Awards \| Other ranges of annualized vesting distribution
Share-based Compensation Arrangement, by Share-based Payment Award
Units Outstanding (in units)				200,000
Estimated unit vesting in 2013 (in units)				100,000
Estimated unit vesting in 2014 (in units)				100,000
Awards associated with DERs that begin payment in February 2012
Share-based Compensation Arrangement, by Share-based Payment Award
Units Outstanding (in units)							70,000
Annualized distribution threshold of units with associated DERs (in dollars per share)							$ 1.45
Awards associated with DERs that begin payment in May 2013
Share-based Compensation Arrangement, by Share-based Payment Award
Units Outstanding (in units)							70,000
Annualized distribution threshold of units with associated DERs (in dollars per share)							$ 1.50
Awards associated with DERs that begin payment in May 2014
Share-based Compensation Arrangement, by Share-based Payment Award
Units Outstanding (in units)	the remainder
Annualized distribution threshold of units with associated DERs (in dollars per share)							$ 1.55
PNG Transaction Grants
Share-based Compensation Arrangement, by Share-based Payment Award
Phantom common units granted (in units)			375,000
Units vested (in units)				62,500

Equity Compensation Plans (Details 2) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement, by Share-based Payment Award
Equity compensation expense	$ 110	$ 98	$ 68
Other Consolidated Equity Compensation Information
LTIP unit settled vestings	24	26	19
LTIP cash settled vestings	19	36	8
DER cash payments	4	$ 4	$ 4
Unit vestings which were settled with PNG units	$ 2
Units issued in connection with the settlement of vested awards, net of tax withholding (in units)	0.2	0.3	0.3
Units issued in connection with tax withholding on units vested (in units)	0.1	0.2	0.2
Vested awards settled in cash (in units)	0.4	0.6	0.1
Additional expense expected to be recognized over life of outstanding awards related to remaining unrecognized fair value	$ 90
Equity Compensation Plan Fair Value Amortization
2012	50
2013	26
2014	11
2015	3
Total	$ 90
PAA Long-term Incentive Plans
Outstanding (in units)
Outstanding at beginning of period (in units)	4.4	3.9	3.9
Granted (in units)	0.5	2.0	0.6
Vested (in units)	(0.7)	(1.1)	(0.6)
Cancelled or forfeited (in units)	(0.2)	(0.4)	(0.1)
Acquired (in units)			0.1
Outstanding at end of period (in units)	4.0	4.4	3.9
Weighted Average Grant Date Fair Value per unit
Outstanding at beginning of period (in dollars per unit)	$ 41.69	$ 36.40	$ 36.44
Granted (in dollars per unit)	55.05	45.66	32.20
Vested (in dollars per unit)	40.68	32.20	34.55
Cancelled or forfeited (in dollars per unit)	41.97	35.62	37.82
Acquired (in dollars per unit)			26.24
Outstanding at end of period (in dollars per unit)	$ 43.53	$ 41.69	$ 36.40
PNG LTIP Awards Including Transaction Grants
Outstanding (in units)
Outstanding at beginning of period (in units)	1.0		0.0
Granted (in units)		1.1
Vested (in units)	(0.1)
Cancelled or forfeited (in units)	(0.1)	(0.1)
Outstanding at end of period (in units)	0.8	1.0
Weighted Average Grant Date Fair Value per unit
Outstanding at beginning of period (in dollars per unit)	$ 20.55		$ 0
Granted (in dollars per unit)		$ 20.49
Vested (in dollars per unit)	23.62
Cancelled or forfeited (in dollars per unit)	19.20	19.22
Outstanding at end of period (in dollars per unit)	$ 20.55	$ 20.55
PNG LTIP Awards Including Transaction Grants \| Maximum
Other Consolidated Equity Compensation Information
Equity compensation expense		$ 1
AAP LP Class B Units
Share-based Compensation Arrangement, by Share-based Payment Award
Equity compensation expense	$ 9	$ 9

Equity Compensation Plans (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Grant Date Fair Value of Outstanding Class B Units:
Expense recognized	$ 110	$ 98	$ 68
AAP LP Class B Units
Reserved for Future Grants
Reserved for future grants outstanding, beginning balance (in units)	24,500
Unit issuance (in units)	(8,000)
Reserved for future grants outstanding, ending balance (in units)	16,500	24,500
Outstanding
Outstanding at beginning of period (in units)	175,500
Unit issuance (in units)	8,000
Outstanding at end of period (in units)	183,500	175,500
Outstanding Units Earned
Outstanding Units Earned, beginning balance (in units)	80,063
Outstanding at end of period (in units)	80,063	80,063
Grant Date Fair Value of Outstanding Class B Units:
Grant Date Fair Value of Outstanding Class B Units, beginning balance	$ 40
Units issued	4
Grant Date Fair Value of Outstanding Class B Units, ending balance	44	$ 40
Expense recognized	$ 9	$ 9

Equity Compensation Plans (Details 4) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		12 Months Ended
	Jul. 31, 2010	Aug. 31, 2007	Dec. 31, 2011	Dec. 31, 2010
AAP LP Class B Units
Share-based Compensation Arrangement, by Share-based Payment Award
Authorized grants (in units)		200,000
Reserved for Future Grants, outstanding			16,500	24,500
Annualized distribution, low end of range (in dollars per unit)		$ 3.50
Annualized distribution, high end of range (in dollars per unit)		$ 4.80
Number of days required for vesting, in some cases		180 days
Threshold on distributions paid for participation in award		$ 11.0
Maximum participation in excess of distribution (as a percent)		8.00%
Class B Units of PNGS GP LLC
Share-based Compensation Arrangement, by Share-based Payment Award
Authorized grants (in units)	165,000
Unit forfeitures (in units)			16,500
Units Outstanding (in units)			74,250
Reserved for Future Grants, outstanding			90,750
Increments (as a percent)	25.00%
Increment period (in days)	180 days
Annualized distribution level one (in dollars per unit)	$ 2.00
Annualized distribution level two (in dollars per unit)	2.30
Annualized distribution level three (in dollars per unit)	2.50
Annualized distribution level four (in dollars per unit)	$ 2.70
Award vesting rights (as a percent)	50.00%
Award vesting rights on the fifth anniversary of the date of grant (as a percent)	50.00%
Award vesting rights after the fifth anniversary of the date of grant (as a percent)	100.00%
Threshold on distributions paid for participation in award	$ 2.5
Maximum participation in excess of distribution (as a percent)	6.00%

Commitments and Contingencies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Future non-cancelable commitments related to various operating and capital leases
2012	$ 71
2013	55
2014	47
2015	41
2016	33
Thereafter	292
Total	539
Expenditures related to leases	60	$ 52	$ 55
Other commitments
2012	34
2013	21
2014	19
2015	15
2016	11
Thereafter	47
Total	147
Leases and other commitments
2012	105
2013	76
2014	66
2015	56
2016	44
Thereafter	339
Total	$ 686

Commitments and Contingencies (Details 2) - USD ($)	1 Months Ended
Commitments and Contingencies (Details 2) - USD ($)	Dec. 31, 2011	Nov. 30, 2011
Plains Products Terminals LLC
Loss Contingencies
Natural resources contamination - allocated and paid		$ 550,000
Bay Area Air Quality Management District Notices for Alleged Violations
Loss Contingencies
Penalty paid	$ 116,000

Commitments and Contingencies (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Environmental
Estimated environmental reserve	$ 74	$ 66
Reserve for environmental liabilities, short-term	12	10
Reserve for environmental liabilities, long-term	62	56
Probable recoveries from insurers and third parties recorded as a receivable	$ 47	$ 5
Actual cash expenditures for environmental liabilities, period paid, low end of range (in years)	3 years
Actual cash expenditures for environmental liabilities, period paid, high end of range (in years)	5 years

- Definition

Carrying value of the obligation (known or estimated) arising from requirements to perform activities to remediate one or more sites, payable in twelve months or in the next operating cycle if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 9
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 20
-Article 5

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Statement of Position (SOP)
-Number 96-1
-Paragraph 161, 163
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14326-108349

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 30
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6393242&loc=d3e13207-110859

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.20)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section 45
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6361293&loc=d3e6911-107765

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 30
-Section 50
-Paragraph 10
-Subparagraph (d)(1)
-URI http://asc.fasb.org/extlink&oid=6393242&loc=d3e13237-110859

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 43
-Chapter 3
-Section A
-Paragraph 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Commitments and Contingencies (Details 4) $ in Millions	12 Months Ended
Commitments and Contingencies (Details 4) $ in Millions	Dec. 31, 2011 USD ($) mi	Dec. 31, 2010 USD ($)
Loss Contingencies
Probable recoveries from insurers, net of deductibles	$ 47	$ 5
Rainbow pipeline
Loss Contingencies
Length of Pipeline Isolated and Depressurized (in miles) \| mi	45
Total estimated cost to clean-up and remediate the site, before insurance recoveries	$ 70
Recognized remaining undiscounted gross environmental remediation liability	2
Probable recoveries from insurers, net of deductibles	$ 41

Commitments and Contingencies (Details 5) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2004
Insurance
Premiums and deductibles as a percentage of coverage limit (as a percent)	20.00%
Number of years over which hurricane limit insurance was purchased	2 years
Hurricane property and business interruption insurance limit	$ 10
Texas New Mexico pipeline assets purchased from Link
Environmental remediation disclosures
Environmental reserve recognized			$ 20
Amount of first costs for environmental remediation costs to be born by reporting entity per acquisition agreement			$ 11
Description of first costs for environmental remediation costs to be born by reporting entity per acquisition agreement			we agreed in an arrangement with TNM to bear the first $11 million in costs of pre-May 1999 environmental issues
Amount of environmental remediation costs above which the costs the selling entity agreed to pay all costs			$ 20
Remediation costs incurred since acquisition of a business		$ 22
Environmental remediation costs borne by the seller of a business acquired by the reporting entity		$ 11

Quarterly Financial Data (Unaudited) (Details) $ / shares in Units, $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2011 USD ($) $ / shares	Sep. 30, 2011 USD ($) $ / shares	Jun. 30, 2011 USD ($) $ / shares	Mar. 31, 2011 USD ($) $ / shares	Dec. 31, 2010 USD ($) $ / shares	Sep. 30, 2010 USD ($) $ / shares	Jun. 30, 2010 USD ($) $ / shares	Mar. 31, 2010 USD ($) $ / shares	Dec. 31, 2009 $ / shares	Sep. 30, 2009 $ / shares	Jun. 30, 2009 $ / shares	Mar. 31, 2009 $ / shares	Dec. 31, 2011 USD ($) $ / shares	Dec. 31, 2010 USD ($) $ / shares	Dec. 31, 2009 USD ($) $ / shares
Quarterly Financial Data (Unaudited)
Revenues	$ 8,884	$ 8,837	$ 8,859	$ 7,694	$ 7,231	$ 6,414	$ 6,124	$ 6,125					$ 34,275	$ 25,893	$ 18,520
Gross margin	453	413	371	355	300	206	248	273					1,592	1,027
Operating income	359	357	298	285	213	150	192	211					1,298	767	779
Net income	288	288	233	185	146	84	133	151					994	514	580
Net income attributable to Plains	$ 278	$ 281	$ 225	$ 182	$ 142	$ 81	$ 131	$ 151					$ 966	$ 505	$ 579
Basic net income per limited partner unit (in dollars per unit) \| $ / shares	1.38	1.48	1.14	0.90	0.68	0.28	0.65	0.80					4.91	2.41	3.34
Diluted net income per limited partner unit (in dollars per unit) \| $ / shares	1.37	1.47	1.13	0.90	0.67	0.28	0.65	0.80					4.88	2.40	3.32
Cash distributions per common unit (in dollars per unit) \| $ / shares	$ 0.9950	$ 0.9825	$ 0.9700	$ 0.9575	$ 0.9500	$ 0.9425	$ 0.9350	$ 0.9275	$ 0.9200	$ 0.9050	$ 0.9050	$ 0.8925	$ 3.91	$ 3.76	$ 3.62

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 87-21
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 10, 15
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 95
-Paragraph 28, 29, 30
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Article 5
-Section 03
-Paragraph 19

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Paragraph 20
-Article 9

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Net Income
-URI http://asc.fasb.org/extlink&oid=6518256

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Other Comprehensive Income
-URI http://asc.fasb.org/extlink&oid=6519514

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 225
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03.18)
-URI http://asc.fasb.org/extlink&oid=6880815&loc=d3e20235-122688

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 225
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04.19)
-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6920043&loc=d3e565-108580

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 225
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04.22)
-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph A7
-Appendix A

+ Details

- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

+ References

+ Details

Operating Segments (Details) $ in Millions	1 Months Ended	3 Months Ended								12 Months Ended
Operating Segments (Details) $ in Millions	Oct. 31, 2011 USD ($)	Dec. 31, 2011 USD ($) segment	Sep. 30, 2011 USD ($)	Jun. 30, 2011 USD ($)	Mar. 31, 2011 USD ($)	Dec. 31, 2010 USD ($) segment	Sep. 30, 2010 USD ($)	Jun. 30, 2010 USD ($)	Mar. 31, 2010 USD ($)	Dec. 31, 2011 USD ($) segment	Dec. 31, 2010 USD ($) segment	Dec. 31, 2009 USD ($) segment
Operating Segments
Operating segments number \| segment		3				3				3	3	3
Revenues:
External Customers		$ 8,884	$ 8,837	$ 8,859	$ 7,694	$ 7,231	$ 6,414	$ 6,124	$ 6,125	$ 34,275	$ 25,893	$ 18,520
Intersegment										754	632	562
Total revenues of reportable segments										35,029	26,525	19,082
Equity earnings in unconsolidated entities										13	3	15
Segment profit										1,560	1,026	1,030
Capital expenditures										1,935	762	757
Total assets		15,381				13,703				15,381	13,703	12,358
Maintenance capital										120	93	81
BP NGL Acquisition
Revenues:
Cash deposit related to pending acquisition included in capital expenditures	$ 50
Transportation
Revenues:
External Customers										572	565	536
Intersegment										593	480	425
Total revenues of reportable segments										1,165	1,045	961
Equity earnings in unconsolidated entities										13	3	7
Segment profit										555	516	477
Capital expenditures										600	329	183
Total assets		5,156				4,701				5,156	4,701	4,468
Maintenance capital										86	67	57
Facilities
Revenues:
External Customers										638	339	227
Intersegment										158	151	135
Total revenues of reportable segments										796	490	362
Equity earnings in unconsolidated entities												8
Segment profit										358	270	208
Capital expenditures										1,317	270	564
Total assets		4,506				3,303				4,506	3,303	3,097
Maintenance capital										22	17	16
Facilities \| BP NGL Acquisition
Revenues:
Cash deposit related to pending acquisition included in capital expenditures										50
Supply and Logistics
Revenues:
External Customers										33,065	24,989	17,757
Intersegment										3	1	2
Total revenues of reportable segments										33,068	24,990	17,759
Segment profit										647	240	345
Capital expenditures										18	163	10
Total assets		$ 5,719				$ 5,699				5,719	5,699	4,793
Maintenance capital										12	9	8
Interest expense related to hedged inventory purchases										$ 20	$ 17	$ 11

Operating Segments (Details 2) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
Operating Segments (Details 2) - USD ($) $ in Millions	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Reconciliation of segment profit to net income attributable to Plains
Segment profit									$ 1,560	$ 1,026	$ 1,030
Depreciation and amortization									(249)	(256)	(236)
Interest expense									(253)	(248)	(224)
Other income/(expense), net									(19)	(9)	16
Income tax benefit/(expense)									(45)	1	(6)
NET INCOME	$ 288	$ 288	$ 233	$ 185	$ 146	$ 84	$ 133	$ 151	994	514	580
Less: Net income attributable to noncontrolling interests									(28)	(9)	(1)
NET INCOME ATTRIBUTABLE TO PLAINS	$ 278	$ 281	$ 225	$ 182	$ 142	$ 81	$ 131	$ 151	$ 966	$ 505	$ 579

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References

+ Details

- Definition

The portion of net Income or Loss attributable to the noncontrolling interest (if any) deducted in order to derive the portion attributable to the parent.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph A1, A4, A5
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 55
-Paragraph 4K
-URI http://asc.fasb.org/extlink&oid=6922042&loc=SL4591552-111686

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6921930&loc=SL4573702-111684

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 55
-Paragraph 4J
-URI http://asc.fasb.org/extlink&oid=6922042&loc=SL4591551-111686

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-Subparagraph c(1)
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

+ References

+ Details

Operating Segments (Details 3) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
Operating Segments (Details 3) - USD ($) $ in Millions	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues and long lived assets attributable to geographic areas
Revenues	$ 8,884	$ 8,837	$ 8,859	$ 7,694	$ 7,231	$ 6,414	$ 6,124	$ 6,125	$ 34,275	$ 25,893	$ 18,520
Long-Lived Assets	11,010				9,302				11,010	9,302
United States
Revenues and long lived assets attributable to geographic areas
Revenues									28,181	21,471	15,439
Long-Lived Assets	9,127				7,502				9,127	7,502
Canada
Revenues and long lived assets attributable to geographic areas
Revenues									6,094	4,422	$ 3,081
Long-Lived Assets	$ 1,883				$ 1,800				$ 1,883	$ 1,800