View Filing Data

Document and Entity Information - shares	3 Months Ended
Document and Entity Information - shares	Mar. 31, 2012	May 03, 2012
Document and Entity Information
Entity Registrant Name	PLAINS ALL AMERICAN PIPELINE LP
Entity Central Index Key	0001070423
Document Type	10-Q
Document Period End Date	Mar. 31, 2012
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		161,318,749
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2012	Dec. 31, 2011
CURRENT ASSETS
Cash and cash equivalents	$ 14	$ 26
Trade accounts receivable and other receivables, net	2,902	3,190
Inventory	1,079	978
Other current assets	171	157
Total current assets	4,166	4,351
PROPERTY AND EQUIPMENT	9,312	9,029
Accumulated depreciation	(1,337)	(1,289)
Property and equipment, net	7,975	7,740
OTHER ASSETS
Goodwill	1,879	1,854
Restricted cash (Note 4)	1,632
Linefill and base gas	577	564
Long-term inventory	146	135
Investments in unconsolidated entities	192	191
Other, net	514	546
Total assets	17,081	15,381
CURRENT LIABILITIES
Accounts payable and accrued liabilities	3,489	3,599
Short-term debt	757	679
Other current liabilities	196	233
Total current liabilities	4,442	4,511
LONG-TERM LIABILITIES
Senior notes, net of unamortized discount of $15 and $13, respectively	5,510	4,262
Long-term debt under credit facilities and other	284	258
Other long-term liabilities and deferred credits	332	376
Total long-term liabilities	6,126	4,896
COMMITMENTS AND CONTINGENCIES (NOTE 12)
PARTNERS' CAPITAL
Common unitholders (161,318,749 and 155,376,937 units outstanding, respectively)	5,779	5,249
General partner	218	201
Total partners' capital excluding noncontrolling interests	5,997	5,450
Noncontrolling interests	516	524
Total partners' capital	6,513	5,974
Total liabilities and partners' capital	$ 17,081	$ 15,381

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2012	Dec. 31, 2011
CONDENSED CONSOLIDATED BALANCE SHEETS
Senior notes, unamortized discount (in dollars)	$ 15	$ 13
Common unitholders, units outstanding (in units)	161,318,749	155,376,937

- 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.

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+ Details

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2012 USD ($) $ / shares shares	Mar. 31, 2011 USD ($) $ / shares shares
REVENUES
Supply and Logistics segment revenues	$ 8,877	$ 7,435
Transportation segment revenues	150	141
Facilities segment revenues	191	118
Total revenues	9,218	7,694
COSTS AND EXPENSES
Purchases and related costs	8,502	7,079
Field operating costs	249	197
General and administrative expenses	94	70
Depreciation and amortization	60	63
Total costs and expenses	8,905	7,409
OPERATING INCOME	313	285
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	7
Interest expense (net of capitalized interest of $9 and $5, respectively)	(65)	(65)
Other income/(expense), net	2	(22)
INCOME BEFORE TAX	257	198
Current income tax expense	(17)	(11)
Deferred income tax expense	(3)	(2)
NET INCOME	237	185
Net income attributable to noncontrolling interests	(7)	(3)
NET INCOME ATTRIBUTABLE TO PLAINS	230	182
NET INCOME ATTRIBUTABLE TO PLAINS:
LIMITED PARTNERS	162	129
GENERAL PARTNER	$ 68	$ 53
BASIC NET INCOME PER LIMITED PARTNER UNIT (in dollars per unit) \| $ / shares	1.03	0.90
DILUTED NET INCOME PER LIMITED PARTNER UNIT (in dollars per unit) \| $ / shares	1.02	0.90
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING (in units) \| shares	157	143
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING (in units) \| shares	158	144

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Interest expense, capitalized interest	$ 9	$ 5

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Net income	$ 237	$ 185
Other comprehensive income/(loss)	59	(29)
Comprehensive income	296	156
Less: Comprehensive income attributable to noncontrolling interests	(3)	(3)
Comprehensive income attributable to Plains	$ 293	$ 153

- 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

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- 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.

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- Definition

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

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+ Details

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME $ in Millions	3 Months Ended
	Mar. 31, 2012 USD ($)
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period	$ 54
Reclassification adjustments	(52)
Deferred gain on cash flow hedges, net of tax	76
Currency translation adjustment	35
Total period activity	59
Balance at end of period	113
Derivative Instruments
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period	(102)
Reclassification adjustments	(52)
Deferred gain on cash flow hedges, net of tax	76
Total period activity	24
Balance at end of period	(78)
Translation Adjustments
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period	156
Currency translation adjustment	35
Total period activity	35
Balance at end of period	$ 191

- Definition

Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge.

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- Definition

Adjustment that results from the process of translating subsidiary financial statements and foreign equity investments into the reporting currency of the reporting entity, net of tax.

+ References

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Net of tax effect of the reclassification adjustment for accumulated gains and losses from derivative instrument designated and qualifying as the effective portion of cash flow hedges included in accumulated comprehensive income that was realized in net income during the period.

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- Definition

Change in accumulated gains and losses from derivative instrument designated and qualifying as the effective portion of cash flow hedges, net of tax effect. The after tax effect change includes an entity's share of an equity investee's Increase or Decrease in deferred hedging gains or losses.

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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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 237	$ 185
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	60	63
Equity compensation expense	39	20
Gain on sales of linefill and base gas	(12)	(13)
Net cash received/(paid) for terminated interest rate or foreign currency hedging instruments	(23)	12
Other	(4)	3
Changes in assets and liabilities, net of acquisitions	20	384
Net cash provided by operating activities	317	654
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	(21)	(756)
Change in restricted cash	(1,632)	18
Additions to property and equipment	(263)	(121)
Proceeds from sales of assets	13
Net cash received for sales and purchases of linefill and base gas	13	19
Other investing activities		(2)
Net cash used in investing activities	(1,890)	(842)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) on PAA's revolving credit facility	184	(654)
Net repayments on PAA's hedged inventory facility	(75)	(200)
Net repayments on PNG's credit agreements	(5)	(52)
Proceeds from the issuance of senior notes	1,247	597
Repayments of senior notes		(200)
Net proceeds from the issuance of common units (Note 9)	455	503
Cash received for sale of noncontrolling interest in a subsidiary		370
Distributions paid to common unitholders (Note 9)	(159)	(135)
Distributions paid to general partner (Note 9)	(66)	(49)
Distributions to noncontrolling interests	(12)	(5)
Other financing activities	(9)	(4)
Net cash provided by financing activities	1,560	171
Effect of translation adjustment on cash	1
Net decrease in cash and cash equivalents	(12)	(17)
Cash and cash equivalents, beginning of period	26	36
Cash and cash equivalents, end of period	14	19
Cash paid for interest, net of amounts capitalized	78	$ 71
Cash paid for income taxes, net of amounts refunded	$ 28

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL - 3 months ended Mar. 31, 2012 - USD ($) $ in Millions	Total	Common Units	General Partner	Partners' Capital Excluding Noncontrolling Interests	Noncontrolling Interests
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
Increase (Decrease) in Partners' Capital
Net income	$ 237	$ 162	68	230	7
Distributions	(237)	(159)	(66)	(225)	(12)
Issuance of common units	$ 455	$ 446	9	455
Issuance of common units (in units)	5,750,000	6,000,000
Issuance of common units under LTIP	$ 16	$ 16		16
Equity compensation expense	9	3	5	8	1
Other comprehensive income/(loss)	59	62	1	63	(4)
Balance at Mar. 31, 2012	$ 6,513	$ 5,779	$ 218	$ 5,997	$ 516
Balance (in units) at Mar. 31, 2012	161,318,749	161,000,000

Organization and Basis of Presentation

3 Months Ended

Mar. 31, 2012

Organization and Basis of Presentation

Organization and Basis of Presentation

Note 1—Organization and Basis of Presentation

Organization

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”). When used in this document, NGL refers to all NGL products including LPG. 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.

As used in this Form 10-Q and unless the context indicates otherwise, the terms “Partnership,” “Plains,” “PAA,” “we,” “us,” “our,” “ours” and similar terms refer to Plains All American Pipeline, L.P. and its subsidiaries. Also, 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.

Definitions

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

AOCI	=	Accumulated other comprehensive income
Bcf	=	Billion cubic feet
Btu	=	British thermal unit
CAD	=	Canadian dollar
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
ICE	=	IntercontinentalExchange
LIBOR	=	London Interbank Offered Rate
LLS	=	Light Louisiana Sweet
LTIP	=	Long-term incentive plan
Mcf	=	Thousand cubic feet
MLP	=	Master limited partnership
MQD	=	Minimum quarterly distribution
NGL	=	Natural gas liquids including ethane, natural gasoline products, propane and butane
NPNS	=	Normal purchases and normal sales
NYMEX	=	New York Mercantile Exchange
NYSE	=	New York Stock Exchange
PLA	=	Pipeline loss allowance
PNG	=	PAA Natural Gas Storage, L.P.
SEC	=	Securities and Exchange Commission
USD	=	United States dollar
WTI	=	West Texas Intermediate
WTS	=	West Texas Sour

Basis of Consolidation and Presentation

The accompanying unaudited condensed consolidated interim financial statements and notes thereto should be read in conjunction with our 2011 Annual Report on Form 10-K. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated in consolidation. As discussed further below, certain reclassifications have been made to information from previous years to conform to the current presentation. The condensed balance sheet data as of December 31, 2011 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three months ended March 31, 2012 should not be taken as indicative of results to be expected for the entire year.

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

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, 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, total partners’ capital or cash flows. 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 condensed consolidated statement of operations, which resulted in the following changes (in millions):

Three Months Ended March 31, 2011	As Previously Reported		As Revised
Net Income Attributable to Plains:
Limited Partners	$	133	$	129
General Partner	49		53
	$	182	$	182

- 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)
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-Number 46R
-Paragraph 4, 14, 15
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Recent Accounting Pronouncements

3 Months Ended

Mar. 31, 2012

Recent Accounting Pronouncements

Recent Accounting Pronouncements

Note 2—Recent Accounting Pronouncements

Other than as discussed below and in our 2011 Annual Report on Form 10-K, no new accounting pronouncements have become effective during the three months ended March 31, 2012 that are of significance or potential significance to us.

In September 2011, the FASB issued guidance with the purpose of simplifying 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 became effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We adopted this guidance on January 1, 2012. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

In June 2011, the FASB issued guidance regarding the presentation of other comprehensive income, which was later amended in December 2011, with the purpose of increasing the prominence of other comprehensive income in financial statements. This guidance, as amended, requires entities to present comprehensive income in either (i) a single continuous statement of comprehensive income or (ii) two separate but consecutive statements. This guidance became effective for interim and annual periods beginning after December 15, 2011. We adopted the guidance, as amended, on January 1, 2012. Since this guidance only impacts the presentation of comprehensive income and does not change the composition or calculation of such financial information, adoption did not have a material impact on our financial position, results of operations or cash flows.

In May 2011, the FASB issued guidance to amend certain fair value measurement and disclosure requirements in an effort to improve consistency with international reporting standards. The amendments generally clarify that the concepts of highest and best use and valuation premise in fair value measurement are relevant only when measuring the fair value of non-financial assets and are not relevant when measuring the fair value of financial assets or of liabilities. In addition, the guidance expanded disclosure requirements associated with (i) unobservable inputs for Level 3 fair value measurements and (ii) items that are not measured at fair value in the financial statements, but for which fair value is required to be disclosed. This guidance became effective prospectively for interim and annual reporting periods beginning after December 15, 2011. We adopted this guidance on January 1, 2012. Other than requiring additional disclosure, which is included in Note 7, our adoption did not have a material impact on our financial position, results of operations or cash flows.

- Definition

The entire disclosure for reporting accounting changes and error corrections. It includes the conveyance of information necessary for a user of the Company's financial information to understand all aspects and required disclosure information concerning all changes and error corrections reported in the Company's financial statements for the period.

+ References + Details

Accounts Receivable

3 Months Ended

Mar. 31, 2012

Accounts Receivable

Accounts Receivable

Note 3—Accounts Receivable

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At March 31, 2012 and December 31, 2011, 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 March 31, 2012 and December 31, 2011. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

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 March 31, 2012 and December 31, 2011, we had received approximately $177 million and $186 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 portion of our transactions and also serve to mitigate credit risk.

- Definition

The entire disclosure for claims held for amounts due a company. Examples include trade accounts receivables, notes receivables, loans receivables.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 3, 4
-Article 5

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Position (SOP)
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Acquisitions

3 Months Ended

Mar. 31, 2012

Acquisitions

Acquisitions

Note 4—Acquisitions

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

Acquisition Closed Subsequent to March 31, 2012

BP NGL Acquisition. On April 1, 2012, we acquired all of the 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 was based on an October 1, 2011 effective date, was 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 was paid in cash upon closing. As of March 31, 2012, we had approximately $1.63 billion in restricted cash held by an escrow agent in contemplation of closing this acquisition.

Upon completion of this acquisition, we became 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 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 8 million barrels upon closing. 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. 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 acquired as a result of the acquisition.

Other Acquisitions

During the three months ended March 31, 2012 we completed two acquisitions for an aggregate consideration of approximately $21 million. The assets acquired primarily included trailers that are utilized in our transportation segment, and terminal facilities included in our facilities segment. We recognized goodwill of approximately $10 million related to these acquisitions.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Emerging Issues Task Force (EITF)
-Number 88-16
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+ Details

Inventory, Linefill, Base Gas and Long-term Inventory

3 Months Ended

Mar. 31, 2012

Inventory, Linefill, Base Gas and Long-term Inventory

Inventory, Linefill, Base Gas and Long-term Inventory

Note 5—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):

	March 31, 2012						December 31, 2011
		Unit of	Total		Price/			Unit of	Total		Price/
	Volumes	Measure	Value		Unit (1)		Volumes	Measure	Value		Unit (1)
Inventory
Crude oil	8,464	barrels	$	821	$	97.00	5,361	barrels	$	483	$	90.10
NGL	3,829	barrels	216		$	56.41	6,885	barrels	438		$	63.62
Natural gas (2)	14,453	Mcf	33		$	2.28	16,170	Mcf	51		$	3.15
Other	N/A		9		N/A		N/A		6		N/A
Inventory subtotal			1,079						978

Linefill and base gas
Crude oil	9,410	barrels	526		$	55.90	9,366	barrels	514		$	54.88
Natural gas (2)	14,105	Mcf	49		$	3.47	14,105	Mcf	48		$	3.40
NGL	31	barrels	2		$	64.52	31	barrels	2		$	64.52
Linefill and base gas subtotal			577						564

Long-term inventory
Crude oil	1,848	barrels	138		$	74.68	1,714	barrels	127		$	74.10
NGL	150	barrels	8		$	53.33	150	barrels	8		$	53.33
Long-term inventory subtotal			146						135

Total			$	1,802					$	1,677

(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.

Goodwill

3 Months Ended

Mar. 31, 2012

Goodwill

Goodwill

Note 6 — Goodwill

The table below reflects our changes in goodwill for the period indicated (in millions):

	Transportation		Facilities		Supply & Logistics		Total (1)
Balance, December 31, 2011	$	818	$	609	$	427	$	1,854
2012 Goodwill Related Activity:
Acquisitions (2)	10		—		—		10
Foreign currency translation adjustments	4		—		1		5
Purchase price accounting adjustments and other (2)	10		—		—		10
Balance, March 31, 2012	$	842	$	609	$	428	$	1,879

(1) As of March 31, 2012, 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 determination. This preliminary goodwill balance may be adjusted when the purchase price determination is finalized.

Debt

3 Months Ended

Mar. 31, 2012

Debt

Debt

Note 7—Debt

Debt consisted of the following (in millions):

	March 31,			December 31,
	2012			2011
SHORT-TERM DEBT
Credit Facilities:
Senior secured hedged inventory facility bearing a weighted-average interest rate of 1.5% at December 31, 2011	$	—		$	75
PAA senior unsecured revolving credit facility, bearing a weighted-average interest rate of 1.5% and 1.6% at March 31, 2012 and December 31, 2011, respectively (1)	217			32
PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.1% at both March 31, 2012 and December 31, 2011 (2)	37			68
4.25% senior notes due September 2012 (3)	500			500
Other	3			4
Total short-term debt	757			679

LONG-TERM DEBT
Senior Notes:
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			600
3.65% senior notes due June 2022 (4)	750			—
6.70% senior notes due May 2036	250			250
6.65% senior notes due January 2037	600			600
5.15% senior notes due June 2042 (4)	500			—
Unamortized discounts	(15		)	(13		)
Senior notes, net of unamortized discounts	5,510			4,262
Credit Facilities and Other:
PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.1% at both March 31, 2012 and December 31, 2011 (2)	79			54
PNG GO Zone term loans, bearing a weighted-average interest rate of 1.5% at both March 31, 2012 and December 31, 2011	200			200
Other	5			4
Total long-term debt	5,794			4,520
Total debt (1) (2) (5)	$	6,551		$	5,199

(1) 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 NGL and crude oil inventory and NYMEX and ICE margin deposits.

(2) 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.

(3) Our $500 million 4.25% senior notes will mature in September 2012. The proceeds from these notes are being used to supplement capital available from our hedged inventory facility, to fund working capital needs associated with base levels of waterborne cargos and for seasonal NGL inventory requirements. After these notes mature, we intend to use our credit facilities to finance hedged inventory. Concurrent with the issuance of these senior notes in July 2009, we entered into interest rate swaps. See Note 6 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for further discussion of our interest rate swaps.

(4) In March 2012, we completed the issuance of $750 million, 3.65% senior notes due 2022 and $500 million, 5.15% senior notes due 2042. The senior notes were sold at 99.823% and 99.755% of face value, respectively. Interest payments are due on June 1 and December 1 each year, beginning on December 1, 2012. We used the net proceeds from these offerings to fund a portion of the consideration for the BP NGL Acquisition and for general partnership purposes. See Note 4 for more information regarding this acquisition.

(5) Our fixed-rate senior notes had a face value of approximately $6.0 billion and $4.8 billion as of March 31, 2012 and December 31, 2011, respectively. We estimated the aggregate fair value of these notes as of March 31, 2012 and December 31, 2011 to be approximately $6.7 billion and $5.4 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near quarter end. We estimate that the carrying value of outstanding borrowings under our credit facilities approximates fair value as interest rates reflect current market rates. The fair value estimates for both our senior notes and credit facilities are based upon observable market data and are classified within Level 2 of the fair value hierarchy.

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. Pursuant to its terms, we had the option to activate the facility at any time over a six-month period. In March 2012, we elected to terminate this 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. At March 31, 2012 and December 31, 2011, we had outstanding letters of credit of approximately $42 million and $33 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

Net Income Per Limited Partner Unit

3 Months Ended

Mar. 31, 2012

Net Income Per Limited Partner Unit

Net Income Per Limited Partner Unit

Note 8—Net Income Per Limited Partner Unit

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three months ended March 31, 2012 and 2011 (amounts in millions, except per unit data):

	Three Months Ended March 31,
	2012			2011
Numerator for basic and diluted earnings per limited partner unit (1):
Net income attributable to Plains	$	230		$	182
Less: General partner’s incentive distribution	(65		)	(50		)
Less: General partner 2% ownership	(3		)	(3		)
Net income available to limited partners in accordance with the application of the two-class method for MLPs	$	162		$	129

Denominator:
Basic weighted average number of limited partner units outstanding	157			143
Effect of dilutive securities:
Weighted average LTIP units (2)	1			1
Diluted weighted average number of limited partner units outstanding	158			144

Basic net income per limited partner unit	$	1.03		$	0.90

Diluted net income per limited partner unit	$	1.02		$	0.90

(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 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. See Note 10 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for a complete discussion of our LTIP awards.

Partners' Capital and Distributions

3 Months Ended

Mar. 31, 2012

Partners' Capital and Distributions

Partners' Capital and Distributions

Note 9—Partners’ Capital and Distributions

PAA Distributions

The following table details the distributions paid during or pertaining to the first three months of 2012, net of reductions to the general partner’s incentive distributions (in millions, except per unit amounts):

		Distributions Paid								Distributions
		Common		General Partner						per limited
Date Declared	Date Paid or To Be Paid	Units		Incentive		2%		Total		partner unit
April 10, 2012	May 15, 2012 (1)	$	169	$	65	$	3	$	237	$	1.0450
January 10, 2012	February 14, 2012	$	159	$	63	$	3	$	225	$	1.0250

(1) Payable to unitholders of record at the close of business on May 4, 2012, for the period January 1, 2012 through March 31, 2012.

In order to enhance our distribution coverage ratio and liquidity following a significant acquisition, our general partner has, from time to time, agreed to reduce the amounts due to it as incentive distributions. As such, beginning with the first distribution declared and paid after closing the BP NGL Acquisition, which occurred on April 1, 2012, our general partner agreed to reduce the amount of its incentive distributions by $15 million per year for two years and $10 million per year thereafter. The first incentive distribution reduction related to this acquisition of approximately $4 million will be applied to the May 2012 distribution. See Note 4 for further discussion of the BP NGL Acquisition.

PAA Equity Offerings

During the three months ended March 31, 2012, we completed an equity offering of our common units as shown in the table below (in millions, except unit and per unit data):

		Gross		Proceeds		General Partner					Net
Date	Units Issued	Unit Price		from Sale		Contribution		Costs			Proceeds
March 2012 (1)	5,750,000	$	80.03	$	460	$	9	$	(14	)	$	455

(1) This offering of common units was an underwritten transaction that required us to pay a gross spread. The net proceeds from this offering were used to fund a portion of the BP NGL acquisition, to reduce outstanding borrowings under our credit facilities and for general partnership purposes.

LTIP Vesting

In connection with the settlement of vested LTIP awards, we issued 191,812 common units during the three months ended March 31, 2012 with a fair value of approximately $16 million.

Noncontrolling Interests in Subsidiaries

As of March 31, 2012, noncontrolling interests in subsidiaries consisted of the following: (i) an approximate 36 % interest in PNG and (ii) a 25% interest in SLC Pipeline LLC.

Modification of Conversion of PNG Subordinated Units

In February 2012, PNG modified the terms of the first three tranches of the PNG Series B subordinated units held by PAA. The Series B subordinated units do not participate in quarterly distributions. Instead, the Series B subordinated units convert into Series A subordinated units or common units in five 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 modification increased the quarterly distribution benchmark for Tranche 1, 2 and 3 from annualized levels of $1.44 per unit, $1.53 per unit and $1.63 per unit, respectively, to an annualized level of $1.71 per unit. The following table presents the operational and financial benchmarks, as modified, 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 (1)
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

(1) For satisfaction of this benchmark, PNG must, for two consecutive quarters, (i) maintain distributable cash flow 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 (ii) distribute available cash of at least the annualized distribution benchmark 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. See Note 5 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for a complete discussion of our Series B subordinated units.

Noncontrolling Interests Rollforward

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

	For the Three Months Ended
	March 31,
	2012			2011
Beginning balance	$	524		$	231
Sale of noncontrolling interests in a subsidiary	—			306
Net income attributable to noncontrolling interests	7			3
Distributions to noncontrolling interests	(12		)	(5		)
Equity compensation expense	1			1
Other comprehensive income/(loss):
Reclassification adjustments	(6		)	—
Deferred gain/(loss) on cash flow hedges, net	2			—
Ending Balance	$	516		$	536

- 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

Equity Compensation Plans

3 Months Ended

Mar. 31, 2012

Equity Compensation Plans

Equity Compensation Plans

Note 10—Equity Compensation Plans

For a complete discussion of our equity compensation awards, see Note 10 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K.

PNG Long-term Incentive Plan Award Modification. In February 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 (iii) 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 in 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.

Other Equity Compensation Information. 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)(4)
	Units		Weighted Average Grant Date Fair Value per Unit		Units	Weighted Average Grant Date Fair Value per Unit
Outstanding, December 31, 2011	4.0		$	43.53	0.8	$	20.55
Granted	0.7		$	65.63	0.1	$	15.05
Vested (5)	(0.8	)	$	37.85	—	$	—
Outstanding, March 31, 2012	3.9		$	48.65	0.9	$	17.97

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

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

(3) Amounts include PNG Transaction Grants.

(4) Weighted average grant date fair value per unit for PNG Units outstanding at March 31, 2012, is impacted by the modification of PNG awards during the first quarter of 2012 as discussed above.

(5) Approximately 0.2 million PAA units were issued, net of approximately 0.1 million units withheld for taxes, during the three months ended March 31, 2012. The remaining 0.5 million units that vested were settled in cash.

Class B Units of Plains AAP, L.P. At March 31, 2012 and December 31, 2011, 183,500 AAP LP Class B units were outstanding. As of March 31, 2012, approximately 104,313 of the Class B units outstanding had been earned, 24,250 of which became earned during the three months ended March 31, 2012. A total of 16,500 AAP LP Class B units are reserved for future issuances.

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):

	Three Months Ended
	March 31,
	2012		2011
Equity compensation expense	$	39	$	20
LTIP unit-settled vestings	$	24	$	—
LTIP cash-settled vestings	$	36	$	—
DER cash payments	$	2	$	1

- 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

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-SubTopic 50
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+ Details

Derivatives and Risk Management Activities

3 Months Ended

Mar. 31, 2012

Derivatives and Risk Management Activities

Derivatives and Risk Management Activities

Note 11—Derivatives and Risk Management Activities

We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on hydrocarbon commodity (referred to herein as “commodity”) price changes. We use various derivative instruments to (i) manage our exposure to commodity price risk as well as to optimize our profits, (ii) manage our exposure to interest rate risk and (iii) manage our exposure to currency exchange rate risk. Our commodity risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring 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 inventory 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 March 31, 2012, net derivative positions related to these activities included:

· An approximate 217,100 barrels per day net long position (total of 6.5 million barrels) associated with our crude oil purchases, which was unwound ratably during April 2012 to match monthly average pricing.

· A net short spread position averaging approximately 21,400 barrels per day (total of 19.6 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through November 2014. 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 9,000 barrels per day on average (total of 5.8 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 10,500 barrels per day on average (total of 2.6 million barrels) of LLS/WTI crude oil basis swaps from May 2012 through December 2012, which hedge anticipated sales of crude oil. 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.

· An average of 16,200 barrels per day (total of 1.5 million barrels) of butane/WTI spread positions, which hedge specific butane sales contracts that are based on a percentage of WTI through June 2012.

· A short swap position of approximately 21.9 Bcf through December 2012 related to anticipated sales of natural gas.

Inventory Storage — We own approximately 78 million barrels of crude oil, NGL 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. From time to time, we elect to purchase and store crude oil, NGL 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 March 31, 2012, we had a net short open derivative volume of approximately 7.5 million barrels hedging our inventory or anticipated inventory storage. 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 March 31, 2012, 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 2.1 million barrels) through December 2015, (ii) a long put option position of approximately 0.2 million barrels through December 2012 and (iii) a long call option position of approximately 0.6 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 March 31, 2012, we had a long swap position of approximately 3.5 Bcf through August 2014 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 March 31, 2012, AOCI includes deferred losses of approximately $82 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.

We have 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 as of March 31, 2012 (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	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 March 2012 senior note issuances, we terminated four ten-year forward starting interest rate swaps. These swaps had an aggregate notional amount of $200 million and an average fixed rate of 3.46%. We paid out cash of approximately $24 million associated with the termination of the swaps.

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 approximately $12 million associated with the termination of these swaps.

During July 2009, concurrent with our senior notes issuance, 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 March 31, 2012, AOCI includes net deferred gains of approximately $9 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 March 31, 2012, 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	$	11	$	11	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 condensed consolidated statements of cash flows.

A summary of the impact of our derivative activities recognized in earnings for the three months ended March 31, 2012 and 2011 is as follows (in millions):

	Three Months Ended March 31, 2012									Three Months Ended March 31, 2011
				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	$	34		$	(38	)	$	(4	)	$	(75	)	$	4	$	(71	)

Transportation segment revenues	—			—			—			—			—		—

Facilities segment revenues	12			—			12			(1		)	—		(1		)

Purchases and related costs	4			1			5			—			—		—

Field operating costs	—			2			2			—			1		1

Interest Rate Derivatives

Interest expense	(1		)	—			(1		)	1			—		1

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			1			1			—			3		3

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

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	50		$	(34	)	$	16		$	(74	)	$	8	$	(66	)

(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 $3 million and approximately $8 million for the three months ended March 31, 2012 and 2011, respectively, that represent the ineffective portion of our cash flow hedges. These amounts relate to commodity and interest rate derivatives.

(3) Interest expense includes a net gain of approximately $1 million for both the three months ended March 31, 2012 and 2011, 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 $4 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 condensed consolidated balance sheet on a gross basis as of March 31, 2012 (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	$	87	Other current assets	$	(54	)
	Other long-term assets	7		Other long-term assets	(1		)
	Other long-term liabilities	3		Other long-term liabilities	(3		)
Interest rate derivatives	Other current assets	1		Other current liabilities	(1		)
	Other long-term assets	2		Other long-term liabilities	(65		)
Foreign currency derivatives	Other current assets	1

Total derivatives designated as hedging instruments		$	101		$	(124	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	44	Other current assets	$	(39	)
	Other long-term liabilities	1		Other long-term assets	(6		)

Total derivatives not designated as hedging instruments		$	45		$	(45	)

Total derivatives		$	146		$	(169	)

The following table summarizes the derivative assets and liabilities on our condensed 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	)

As of March 31, 2012, there was a net loss of approximately $78 million deferred in AOCI including 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 March 31, 2012, we expect to reclassify a net gain of approximately $2 million to earnings in the next twelve months. Of the remaining deferred loss in AOCI, a net gain of approximately $4 million is expected to be reclassified to earnings prior to 2015 with the remaining deferred loss of $84 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 three months ended March 31, 2012 and March 31, 2011, all of our hedged transactions were probable of occurring. The net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives during the three months ended March 31, 2012 and 2011 are as follows (in millions):

	Three Months Ended
	March 31,
	2012		2011
Commodity derivatives, net	$	25	$	(145	)
Foreign currency derivatives, net	—		(1		)
Interest rate derivatives, net	51		2
Total	$	76	$	(144	)

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 March 31, 2012, we had a net broker receivable of approximately $49 million (consisting of initial margin of $74 million reduced by $25 million of variation margin that had been returned to us). 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). At March 31, 2012 and December 31, 2011, 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 March 31, 2012 and December 31, 2011. 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 March 31, 2012 (in millions)										Fair Value as of December 31, 2011 (in millions)
Recurring Fair Value Measures (1)	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Commodity derivatives	$	37	$	—		$	2	$	39		$	80	$	1		$	12	$	93
Interest rate derivatives	—		(63		)	—		(63		)	—		(137		)	—		(137		)
Foreign currency derivatives	—		1			—		1			—		1			—		1
Total	$	37	$	(62	)	$	2	$	(23	)	$	80	$	(135	)	$	12	$	(43	)

(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

Level 1 of the fair value hierarchy includes 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.

Level 2

Level 2 of the fair value hierarchy includes 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

Level 3 of the fair value hierarchy includes 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 forward commodity prices, which are market observable inputs, and timing estimates, which involve management judgment.

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):

	Three Months Ended
	March 31,
	2012			2011
Beginning Balance	$	12		$	(14	)
Unrealized gains/(losses):
Included in earnings (1)	(4		)	6
Included in other comprehensive income	3			(2		)
Settlements	(12		)	32
Derivatives entered into during the period	3			(10		)
Transfers out of level 3	—			(17		)
Ending Balance	$	2		$	(5	)

Change in unrealized gains/(losses) included in earnings relating to level 3 derivatives still held at the end of the period	$	(1	)	$	(3	)

(1) We reported unrealized gains and losses associated with level 3 commodity derivatives in our condensed consolidated statements of operations as Supply and Logistics segment revenues.

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.

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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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+ Details

Commitments and Contingencies

3 Months Ended

Mar. 31, 2012

Commitments and Contingencies

Commitments and Contingencies

Note 12—Commitments and Contingencies

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 New Jersey Department of Environmental Protection (“NJDEP”) brought suit in the Superior Court of New Jersey against GATX Corporation (“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 responsibility for prior remediation costs.

Pemex Exploración y Producción v. Big Star Gathering Ltd L.L.P. et al. In two cases filed in the Texas Southern District Court in May 2011 and April 2012, 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 March 31, 2012, our estimated undiscounted reserve for environmental liabilities totaled approximately $74 million, of which approximately $10 million was classified as short-term and $64 million was classified as long-term. At December 31, 2011, our reserve for environmental liabilities totaled approximately $74 million, of which approximately $12 million was classified as short-term and $62 million was classified as long-term. At March 31, 2012 and December 31, 2011, we had recorded receivables totaling approximately $15 million and $47 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.

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. In the future, we may not be able to maintain insurance at levels that we consider adequate for 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.

In 2011, we elected not to renew our hurricane insurance, and, 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
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+ Details

Operating Segments

3 Months Ended

Mar. 31, 2012

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. The following table reflects certain financial data for each segment for the periods indicated (in millions):

	Transportation		Facilities		Supply and Logistics		Total
Three Months Ended March 31, 2012
Revenues:
External Customers	$	150	$	191	$	8,877	$	9,218
Intersegment (1)	167		45		—		212
Total revenues of reportable segments	$	317	$	236	$	8,877	$	9,430
Equity earnings in unconsolidated entities	$	7	$	—	$	—	$	7
Segment profit (2) (3)	$	162	$	90	$	128	$	380
Maintenance capital	$	24	$	7	$	4	$	35

Three Months Ended March 31, 2011
Revenues:
External Customers	$	141	$	118	$	7,435	$	7,694
Intersegment (1)	134		43		—		177
Total revenues of reportable segments	$	275	$	161	$	7,435	$	7,871
Segment profit (2) (3)	$	137	$	78	$	133	$	348
Maintenance capital	$	18	$	3	$	3	$	24

(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. For further discussion, see “Analysis of Operating Segments” under Item 7 of our 2011 Annual Report on Form 10-K.

(2) Supply and logistics segment profit includes interest expense (related to hedged inventory purchases) of approximately $2 million and $5 million for the three months ended March 31, 2012 and 2011, respectively.

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

	For the Three Months
	Ended March 31,
	2012			2011
Segment profit	$	380		$	348
Depreciation and amortization	(60		)	(63		)
Interest expense	(65		)	(65		)
Other income/(expense), net	2			(22		)
Income tax expense	(20		)	(13		)
Net income	237			185
Less: Net income attributable to noncontrolling interests	(7		)	(3		)
Net income attributable to Plains	$	230		$	182

- 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.

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-Name Statement of Financial Accounting Standard (FAS)
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+ Details

Related Party Transactions

3 Months Ended

Mar. 31, 2012

Related Party Transactions

Related Party Transactions

Note 14—Related Party Transactions

See Note 9 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for a complete discussion of our related party transactions.

Occidental Petroleum Corporation

As of March 31, 2012, 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 months ended March 31, 2012 and 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):

	Three Months Ended
	March 31,
	2012		2011
Revenues	$	455	$	702

Purchases and related costs	$	148	$	74

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

	March 31,		December 31,
	2012		2011
Trade accounts receivable and other receivables	$	147	$	132

Accounts payable	$	171	$	155

- 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

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-Publisher SEC
-Name Regulation S-X (SX)
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-Article 4
-Section 08
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-Number 210
-Article 3A
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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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+ Details

Organization and Basis of Presentation (Tables)

3 Months Ended

Mar. 31, 2012

Organization and Basis of Presentation

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

Three Months Ended March 31, 2011	As Previously Reported		As Revised
Net Income Attributable to Plains:
Limited Partners	$	133	$	129
General Partner	49		53
	$	182	$	182

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

3 Months Ended

Mar. 31, 2012

Inventory, Linefill, Base Gas and Long-term Inventory

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

	March 31, 2012						December 31, 2011
		Unit of	Total		Price/			Unit of	Total		Price/
	Volumes	Measure	Value		Unit (1)		Volumes	Measure	Value		Unit (1)
Inventory
Crude oil	8,464	barrels	$	821	$	97.00	5,361	barrels	$	483	$	90.10
NGL	3,829	barrels	216		$	56.41	6,885	barrels	438		$	63.62
Natural gas (2)	14,453	Mcf	33		$	2.28	16,170	Mcf	51		$	3.15
Other	N/A		9		N/A		N/A		6		N/A
Inventory subtotal			1,079						978

Linefill and base gas
Crude oil	9,410	barrels	526		$	55.90	9,366	barrels	514		$	54.88
Natural gas (2)	14,105	Mcf	49		$	3.47	14,105	Mcf	48		$	3.40
NGL	31	barrels	2		$	64.52	31	barrels	2		$	64.52
Linefill and base gas subtotal			577						564

Long-term inventory
Crude oil	1,848	barrels	138		$	74.68	1,714	barrels	127		$	74.10
NGL	150	barrels	8		$	53.33	150	barrels	8		$	53.33
Long-term inventory subtotal			146						135

Total			$	1,802					$	1,677

(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.

Goodwill (Tables)

3 Months Ended

Mar. 31, 2012

Goodwill

Changes in goodwill

	Transportation		Facilities		Supply & Logistics		Total (1)
Balance, December 31, 2011	$	818	$	609	$	427	$	1,854
2012 Goodwill Related Activity:
Acquisitions (2)	10		—		—		10
Foreign currency translation adjustments	4		—		1		5
Purchase price accounting adjustments and other (2)	10		—		—		10
Balance, March 31, 2012	$	842	$	609	$	428	$	1,879

(1) As of March 31, 2012, the total carrying amount of goodwill is net of approximately $3 million of accumulated impairment losses.

- 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

Debt (Tables)

3 Months Ended

Mar. 31, 2012

Debt

Components of debt

	March 31,			December 31,
	2012			2011
SHORT-TERM DEBT
Credit Facilities:
Senior secured hedged inventory facility bearing a weighted-average interest rate of 1.5% at December 31, 2011	$	—		$	75
PAA senior unsecured revolving credit facility, bearing a weighted-average interest rate of 1.5% and 1.6% at March 31, 2012 and December 31, 2011, respectively (1)	217			32
PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.1% at both March 31, 2012 and December 31, 2011 (2)	37			68
4.25% senior notes due September 2012 (3)	500			500
Other	3			4
Total short-term debt	757			679

LONG-TERM DEBT
Senior Notes:
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			600
3.65% senior notes due June 2022 (4)	750			—
6.70% senior notes due May 2036	250			250
6.65% senior notes due January 2037	600			600
5.15% senior notes due June 2042 (4)	500			—
Unamortized discounts	(15		)	(13		)
Senior notes, net of unamortized discounts	5,510			4,262
Credit Facilities and Other:
PNG senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.1% at both March 31, 2012 and December 31, 2011 (2)	79			54
PNG GO Zone term loans, bearing a weighted-average interest rate of 1.5% at both March 31, 2012 and December 31, 2011	200			200
Other	5			4
Total long-term debt	5,794			4,520
Total debt (1) (2) (5)	$	6,551		$	5,199

Net Income Per Limited Partner Unit (Tables)

3 Months Ended

Mar. 31, 2012

Net Income Per Limited Partner Unit

Computation of basic and diluted earnings per limited partner unit

	Three Months Ended March 31,
	2012			2011
Numerator for basic and diluted earnings per limited partner unit (1):
Net income attributable to Plains	$	230		$	182
Less: General partner’s incentive distribution	(65		)	(50		)
Less: General partner 2% ownership	(3		)	(3		)
Net income available to limited partners in accordance with the application of the two-class method for MLPs	$	162		$	129

Denominator:
Basic weighted average number of limited partner units outstanding	157			143
Effect of dilutive securities:
Weighted average LTIP units (2)	1			1
Diluted weighted average number of limited partner units outstanding	158			144

Basic net income per limited partner unit	$	1.03		$	0.90

Diluted net income per limited partner unit	$	1.02		$	0.90

Partners' Capital and Distributions (Tables)

3 Months Ended

Mar. 31, 2012

Partners' Capital and Distributions

Total cash distributions paid or to be paid

		Distributions Paid								Distributions
		Common		General Partner						per limited
Date Declared	Date Paid or To Be Paid	Units		Incentive		2%		Total		partner unit
April 10, 2012	May 15, 2012 (1)	$	169	$	65	$	3	$	237	$	1.0450
January 10, 2012	February 14, 2012	$	159	$	63	$	3	$	225	$	1.0250

(1) Payable to unitholders of record at the close of business on May 4, 2012, for the period January 1, 2012 through March 31, 2012.

Equity offerings of common units

		Gross		Proceeds		General Partner					Net
Date	Units Issued	Unit Price		from Sale		Contribution		Costs			Proceeds
March 2012 (1)	5,750,000	$	80.03	$	460	$	9	$	(14	)	$	455

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 (1)
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

Schedule of changes in noncontrolling interests in partners' capital

	For the Three Months Ended
	March 31,
	2012			2011
Beginning balance	$	524		$	231
Sale of noncontrolling interests in a subsidiary	—			306
Net income attributable to noncontrolling interests	7			3
Distributions to noncontrolling interests	(12		)	(5		)
Equity compensation expense	1			1
Other comprehensive income/(loss):
Reclassification adjustments	(6		)	—
Deferred gain/(loss) on cash flow hedges, net	2			—
Ending Balance	$	516		$	536

Equity Compensation Plans (Tables)

3 Months Ended

Mar. 31, 2012

Equity Compensation Plans

Summary of equity compensation activity

	PAA Units (1)				PNG Units (2)(3)(4)
	Units		Weighted Average Grant Date Fair Value per Unit		Units	Weighted Average Grant Date Fair Value per Unit
Outstanding, December 31, 2011	4.0		$	43.53	0.8	$	20.55
Granted	0.7		$	65.63	0.1	$	15.05
Vested (5)	(0.8	)	$	37.85	—	$	—
Outstanding, March 31, 2012	3.9		$	48.65	0.9	$	17.97

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

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

(3) Amounts include PNG Transaction Grants.

(4) Weighted average grant date fair value per unit for PNG Units outstanding at March 31, 2012, is impacted by the modification of PNG awards during the first quarter of 2012 as discussed above.

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

	Three Months Ended
	March 31,
	2012		2011
Equity compensation expense	$	39	$	20
LTIP unit-settled vestings	$	24	$	—
LTIP cash-settled vestings	$	36	$	—
DER cash payments	$	2	$	1

Derivatives and Risk Management Activities (Tables)

3 Months Ended

Mar. 31, 2012

Derivatives and Risk Management Activities

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	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	$	11	$	11	CAD $1.01 to USD $1.00
2013	$	9	$	9	CAD $1.00 to USD $1.00

Impact of derivative activities recognized in earnings

	Three Months Ended March 31, 2012									Three Months Ended March 31, 2011
				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	$	34		$	(38	)	$	(4	)	$	(75	)	$	4	$	(71	)

Transportation segment revenues	—			—			—			—			—		—

Facilities segment revenues	12			—			12			(1		)	—		(1		)

Purchases and related costs	4			1			5			—			—		—

Field operating costs	—			2			2			—			1		1

Interest Rate Derivatives

Interest expense	(1		)	—			(1		)	1			—		1

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			1			1			—			3		3

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

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	50		$	(34	)	$	16		$	(74	)	$	8	$	(66	)

(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.

(4) Includes realized and unrealized gains or losses for derivatives not designated for hedge accounting during the period.

Summary of derivative assets and liabilities on consolidated balance sheet

The following table summarizes the derivative assets and liabilities on our condensed consolidated balance sheet on a gross basis as of March 31, 2012 (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	$	87	Other current assets	$	(54	)
	Other long-term assets	7		Other long-term assets	(1		)
	Other long-term liabilities	3		Other long-term liabilities	(3		)
Interest rate derivatives	Other current assets	1		Other current liabilities	(1		)
	Other long-term assets	2		Other long-term liabilities	(65		)
Foreign currency derivatives	Other current assets	1

Total derivatives designated as hedging instruments		$	101		$	(124	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	44	Other current assets	$	(39	)
	Other long-term liabilities	1		Other long-term assets	(6		)

Total derivatives not designated as hedging instruments		$	45		$	(45	)

Total derivatives		$	146		$	(169	)

The following table summarizes the derivative assets and liabilities on our condensed 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	)

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

	Three Months Ended
	March 31,
	2012		2011
Commodity derivatives, net	$	25	$	(145	)
Foreign currency derivatives, net	—		(1		)
Interest rate derivatives, net	51		2
Total	$	76	$	(144	)

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

	Fair Value as of March 31, 2012 (in millions)										Fair Value as of December 31, 2011 (in millions)
Recurring Fair Value Measures (1)	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Commodity derivatives	$	37	$	—		$	2	$	39		$	80	$	1		$	12	$	93
Interest rate derivatives	—		(63		)	—		(63		)	—		(137		)	—		(137		)
Foreign currency derivatives	—		1			—		1			—		1			—		1
Total	$	37	$	(62	)	$	2	$	(23	)	$	80	$	(135	)	$	12	$	(43	)

(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

	Three Months Ended
	March 31,
	2012			2011
Beginning Balance	$	12		$	(14	)
Unrealized gains/(losses):
Included in earnings (1)	(4		)	6
Included in other comprehensive income	3			(2		)
Settlements	(12		)	32
Derivatives entered into during the period	3			(10		)
Transfers out of level 3	—			(17		)
Ending Balance	$	2		$	(5	)

Change in unrealized gains/(losses) included in earnings relating to level 3 derivatives still held at the end of the period	$	(1	)	$	(3	)

(1) We reported unrealized gains and losses associated with level 3 commodity derivatives in our condensed consolidated statements of operations as Supply and Logistics segment revenues.

- 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
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-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
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-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
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-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
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-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

Operating Segments (Tables)

3 Months Ended

Mar. 31, 2012

Operating Segments

Segment financial data

	Transportation		Facilities		Supply and Logistics		Total
Three Months Ended March 31, 2012
Revenues:
External Customers	$	150	$	191	$	8,877	$	9,218
Intersegment (1)	167		45		—		212
Total revenues of reportable segments	$	317	$	236	$	8,877	$	9,430
Equity earnings in unconsolidated entities	$	7	$	—	$	—	$	7
Segment profit (2) (3)	$	162	$	90	$	128	$	380
Maintenance capital	$	24	$	7	$	4	$	35

Three Months Ended March 31, 2011
Revenues:
External Customers	$	141	$	118	$	7,435	$	7,694
Intersegment (1)	134		43		—		177
Total revenues of reportable segments	$	275	$	161	$	7,435	$	7,871
Segment profit (2) (3)	$	137	$	78	$	133	$	348
Maintenance capital	$	18	$	3	$	3	$	24

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

	For the Three Months
	Ended March 31,
	2012			2011
Segment profit	$	380		$	348
Depreciation and amortization	(60		)	(63		)
Interest expense	(65		)	(65		)
Other income/(expense), net	2			(22		)
Income tax expense	(20		)	(13		)
Net income	237			185
Less: Net income attributable to noncontrolling interests	(7		)	(3		)
Net income attributable to Plains	$	230		$	182

Reconciliation of segment profit to net income attributable to Plains

	For the Three Months
	Ended March 31,
	2012			2011
Segment profit	$	380		$	348
Depreciation and amortization	(60		)	(63		)
Interest expense	(65		)	(65		)
Other income/(expense), net	2			(22		)
Income tax expense	(20		)	(13		)
Net income	237			185
Less: Net income attributable to noncontrolling interests	(7		)	(3		)
Net income attributable to Plains	$	230		$	182

- 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

Related Party Transactions (Tables) - Oxy

3 Months Ended

Mar. 31, 2012

Related party transaction

Revenues and purchases related to transactions with related parties

	Three Months Ended
	March 31,
	2012		2011
Revenues	$	455	$	702

Purchases and related costs	$	148	$	74

Receivable and payable amounts with related parties

	March 31,		December 31,
	2012		2011
Trade accounts receivable and other receivables	$	147	$	132

Accounts payable	$	171	$	155

Organization and Basis of Presentation (Details) $ in Millions	3 Months Ended
	Mar. 31, 2012 USD ($) segment	Mar. 31, 2011 USD ($)
Organization and Basis of Presentation
Operating segments number \| segment	3
Partner Income Allocation
General partner ownership interest (as a percent)	2.00%
Net Income Attributable to Plains	$ 230	$ 182
Limited Partner
Partner Income Allocation
Limited partner ownership interest (as a percent)	98.00%
Net Income Attributable to Plains		129
General Partner
Partner Income Allocation
General partner ownership interest (as a percent)	2.00%
Net Income Attributable to Plains		53
Total Net Income Attributable to Plains
Partner Income Allocation
Net Income Attributable to Plains		182
Amounts Previously Reported \| Limited Partner
Partner Income Allocation
Net Income Attributable to Plains		133
Amounts Previously Reported \| General Partner
Partner Income Allocation
Net Income Attributable to Plains		$ 49

Accounts Receivable (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
Accounts Receivable (Details) - USD ($) $ in Millions	Mar. 31, 2012	Dec. 31, 2011
Accounts Receivable
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
Advance cash payments received from third parties to mitigate credit risk	$ 177	$ 186

Acquisitions (Details) barrel in Millions, $ in Millions	1 Months Ended		3 Months Ended
Acquisitions (Details) barrel in Millions, $ in Millions	Apr. 30, 2012 Y	Oct. 31, 2011 USD ($)	Mar. 31, 2012 USD ($) entity	Apr. 02, 2012 USD ($) mi barrel barrelperday bcfperday plant railcar
Business acquisition
Restricted cash (Note 4)			$ 1,632
BP NGL Acquisition
Business acquisition
Purchase price				$ 1,670
Purchase price: Cash deposit		$ 50
Interest paid at closing (as a percent)				2.00%
Restricted cash (Note 4)			1,630
Contractual rights related to NGL pipelines acquired (in miles) \| mi				2,600
NGL storage capacity acquired (in barrels) \| barrel				20
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				8
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
Other Acquisitions
Business acquisition
Purchase price			$ 21
Number of additional acquisitions completed (in entities) \| entity			2
Goodwill			$ 10

Inventory, Linefill, Base Gas and Long-term Inventory (Details) barrel in Thousands, cubicfeet in Millions, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2012 USD ($) denominator numerator USDperBarrel USDperthousandcubicfeet barrel cubicfeet	Dec. 31, 2011 USD ($) denominator numerator USDperBarrel USDperthousandcubicfeet barrel cubicfeet
Inventory by category
Inventory	$ 1,079	$ 978
Linefill and base gas	577	564
Long-term inventory	146	135
Total	$ 1,802	$ 1,677
Inventory-related disclosures
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
Crude oil
Inventory by category
Inventory	$ 821	$ 483
Linefill and base gas	526	514
Long-term inventory	$ 138	$ 127
Inventory, Volumes (in barrels or cubic feet) \| barrel	8,464	5,361
Linefill and base gas, Volumes (in barrels or cubic feet) \| barrel	9,410	9,366
Long-term inventory, Volumes (in barrels or cubic feet) \| barrel	1,848	1,714
Inventory, Price/Unit of measure (in dollars per unit) \| USDperBarrel	97.00	90.10
Linefill and base gas, Price/Unit of measure (in dollars per unit) \| USDperBarrel	55.90	54.88
Long-term inventory, Price/Unit of measure (in dollars per unit) \| USDperBarrel	74.68	74.10
NGL
Inventory by category
Inventory	$ 216	$ 438
Linefill and base gas	2	2
Long-term inventory	$ 8	$ 8
Inventory, Volumes (in barrels or cubic feet) \| barrel	3,829	6,885
Linefill and base gas, Volumes (in barrels or cubic feet) \| barrel	31	31
Long-term inventory, Volumes (in barrels or cubic feet) \| barrel	150	150
Inventory, Price/Unit of measure (in dollars per unit) \| USDperBarrel	56.41	63.62
Linefill and base gas, Price/Unit of measure (in dollars per unit) \| USDperBarrel	64.52	64.52
Long-term inventory, Price/Unit of measure (in dollars per unit) \| USDperBarrel	53.33	53.33
Natural gas
Inventory by category
Inventory	$ 33	$ 51
Linefill and base gas	$ 49	$ 48
Inventory, Volumes (in barrels or cubic feet) \| cubicfeet	14,453	16,170
Linefill and base gas, Volumes (in barrels or cubic feet) \| cubicfeet	14,105	14,105
Inventory, Price/Unit of measure (in dollars per unit) \| USDperthousandcubicfeet	2.28	3.15
Linefill and base gas, Price/Unit of measure (in dollars per unit) \| USDperthousandcubicfeet	3.47	3.40
Inventory-related disclosures
Number used to divide into natural gas volumes to convert to barrels \| denominator	6
Other
Inventory by category
Inventory	$ 9	$ 6

Goodwill (Details) $ in Millions	3 Months Ended
Goodwill (Details) $ in Millions	Mar. 31, 2012 USD ($)
Changes in goodwill
Balance at beginning of period	$ 1,854
Acquisitions	10
Foreign currency translation adjustments	5
Purchase price accounting adjustments and other	10
Balance at end of period	1,879
Accumulated impairment losses	3
Transportation
Changes in goodwill
Balance at beginning of period	818
Acquisitions	10
Foreign currency translation adjustments	4
Purchase price accounting adjustments and other	10
Balance at end of period	842
Facilities
Changes in goodwill
Balance at beginning of period	609
Balance at end of period	609
Supply and Logistics
Changes in goodwill
Balance at beginning of period	427
Foreign currency translation adjustments	1
Balance at end of period	$ 428

- Definition

Carrying amount as of the balance sheet date, which is the cumulative amount paid and (if applicable) the fair value of any noncontrolling interest in the acquiree, adjusted for any amortization recognized prior to the adoption of any changes in generally accepted accounting principles (as applicable) and for any impairment charges, in excess of the fair value of net assets acquired in one or more business combination transactions.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-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 142
-Paragraph 43
-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 141R
-Paragraph 68
-Subparagraph l
-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 350
-SubTopic 20
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6388280&loc=d3e13770-109266

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6905597&loc=d3e13816-109267

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 72
-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 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 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.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 34
-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

Debt (Details) - USD ($) $ in Millions	3 Months Ended
Debt (Details) - USD ($) $ in Millions	Mar. 31, 2012	Dec. 31, 2011
Short-term debt:
Total short-term debt	$ 757	$ 679
Other short-term debt	3	4
Long-term debt:
Senior notes, net of unamortized discounts	5,510	4,262
Unamortized discount	(15)	(13)
Long-term debt, other	5	4
Total long-term debt	5,794	4,520
Total debt	$ 6,551	$ 5,199
Senior secured hedged inventory facility maturing in August 2013
Debt
Credit facility, interest rate (as a percent)		1.50%
Short-term debt:
Credit Facility, Current		$ 75
PAA senior unsecured revolving credit facility maturing in August 2016
Debt
Credit facility, interest rate (as a percent)	1.50%	1.60%
Short-term debt:
Credit Facility, Current	$ 217	$ 32
Repayment period (in years)	1 year
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%	5.00%
Long-term debt:
Senior notes	$ 600	$ 600
3.65% senior notes due June 2022
Debt
Debt instrument, interest rate (as a percent)	3.65%
Long-term debt:
Senior notes	$ 750
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
5.15% senior notes due June 2042
Debt
Debt instrument, interest rate (as a percent)	5.15%
Long-term debt:
Senior notes	$ 500
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	$ 500
PNG senior unsecured credit facility
Debt
Credit facility, interest rate (as a percent)	2.10%	2.10%
Short-term debt:
Credit Facility, Current	$ 37	$ 68
Repayment period (in years)	1 year
Long-term debt:
Long-term debt under credit facilities	$ 79	$ 54
PNG GO Zone term loans
Debt
Term Loans, interest rate (as a percent)	1.50%	1.50%
Long-term debt:
Term Loans, amounts oustanding	$ 200	$ 200

Debt (Details 2) - Terminated PAA senior unsecured 364-day revolving credit agreement $ in Billions	12 Months Ended
	Dec. 31, 2011 USD ($)
Debt
Borrowing capacity	$ 1.2
Period for activation of credit facility (in months)	6 months
Tenure of credit facility	364 days

Debt (Details 3) - USD ($) $ in Millions	Mar. 31, 2012	Dec. 31, 2011
Fixed rate senior notes
Debt
Debt instrument face value	$ 6,000	$ 4,800
Debt instrument fair value	6,700	5,400
4.25% senior notes due September 2012
Debt
Senior Notes, Current	$ 500	$ 500
Debt instrument, interest rate (as a percent)	4.25%	4.25%
3.65% senior notes due June 2022
Debt
Senior notes	$ 750
Debt instrument, interest rate (as a percent)	3.65%
Percentage of face value at which senior notes are sold	99.823%
5.15% senior notes due June 2042
Debt
Senior notes	$ 500
Debt instrument, interest rate (as a percent)	5.15%
Percentage of face value at which senior notes are sold	99.755%

Debt (Details 4) - USD ($) $ in Millions	Mar. 31, 2012	Dec. 31, 2011
Debt
Outstanding letters of credit	$ 42	$ 33

Net Income Per Limited Partner Unit (Details) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2012 USD ($) $ / shares shares	Mar. 31, 2011 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	$ 230	$ 182
Less: General partner's incentive distribution paid	(65)	(50)
Less: General partner 2% ownership	(3)	(3)
Net income available to limited partners in accordance with the application of the two-class method for MLPs	$ 162	$ 129
Denominator:
Basic weighted average number of limited partner units outstanding (in units) \| shares	157	143
Effect of dilutive securities:
Weighted average LTIP units (in units) \| shares	1	1
Diluted weighted average number of limited partner units outstanding (in units) \| shares	158	144
Basic net income per limited partner unit (in dollars per unit) \| $ / shares	1.03	0.90
Diluted net income per limited partner unit (in dollars per unit) \| $ / shares	1.02	0.90

Partners' Capital and Distributions (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		3 Months Ended
	May 31, 2012	Feb. 29, 2012	Mar. 31, 2012
Partners' Capital and Distributions
Cash distributions paid to common unit holders	$ 169	$ 159
Cash distribution paid to General Partner - Incentive	65	63
Reduction of Incentive Distribution	4
Cash distributions paid to General Partner - 2%	3	3
Total distributions paid during the period	$ 237	$ 225
Cash distributions per limited partner unit (in dollars per unit)	$ 1.0450	$ 1.0250
General partner ownership interest (as a percent)			2.00%
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

Partners' Capital and Distributions (Details 2) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2012 USD ($) $ / shares shares
Partners Capital and Distribution
Units Issued \| shares	5,750,000
Gross Unit Price (in dollars per unit) \| $ / shares	$ 80.03
Proceeds from Sale	$ 460
General Partner Contribution	9
Costs	(14)
Net Proceeds	$ 455

Partners' Capital and Distributions (Details 3)	Mar. 31, 2012
PNG
Partners Capital and Distribution
Noncontrolling interests, ownership percentage of noncontrolling owners	36.00%
SLC Pipeline
Partners Capital and Distribution
Noncontrolling interests, ownership percentage of noncontrolling owners	25.00%

Partners' Capital and Distributions (Details 4) shares in Millions	1 Months Ended	3 Months Ended
	Feb. 29, 2012 $ / shares	Mar. 31, 2012 Bcf tranche $ / shares shares
PNG
Performance Thresholds
General partner ownership interest (as a percent)		2.00%
Series B Subordinated Units
Performance Thresholds
Number of distinct tranches \| tranche		5
Series B Subordinated Units \| Tranche 1 \| PNG
Performance Thresholds
Previous annualized distribution benchmark	$ 1.44
Annualized distribution level (in dollars per unit)		$ 1.71
Working gas storage capacity (in Bcf) \| Bcf		29.6
Series B subordinated units that will convert into Series A subordinated units \| shares		2.6
Series B Subordinated Units \| Tranche 2 \| PNG
Performance Thresholds
Previous annualized distribution benchmark	1.53
Annualized distribution level (in dollars per unit)		$ 1.71
Working gas storage capacity (in Bcf) \| Bcf		35.6
Series B subordinated units that will convert into Series A subordinated units \| shares		2.8
Series B Subordinated Units \| Tranche 3 \| PNG
Performance Thresholds
Previous annualized distribution benchmark	$ 1.63
Annualized distribution level (in dollars per unit)		$ 1.71
Working gas storage capacity (in Bcf) \| Bcf		41.6
Series B subordinated units that will convert into Series A subordinated units \| shares		2.1
Series B Subordinated Units \| Tranche 4 \| PNG
Performance Thresholds
Annualized distribution level (in dollars per unit)		$ 1.71
Working gas storage capacity (in Bcf) \| Bcf		48.0
Series B subordinated units that will convert into Series A subordinated units \| shares		3.0
Series B Subordinated Units \| Tranche 5 \| PNG
Performance Thresholds
Annualized distribution level (in dollars per unit)		$ 1.80
Working gas storage capacity (in Bcf) \| Bcf		48.0
Series B subordinated units that will convert into Series A subordinated units \| shares		3.0

Partners' Capital and Distributions (Details 5) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
LTIP Vesting
LTIP unit vestings, fair value	$ 24
Changes in the noncontrolling interests in partners' capital
Beginning balance	524
Net income attributable to noncontrolling interests	7	$ 3
Equity compensation expense	9
Other comprehensive income/(loss):
Ending Balance	516
Noncontrolling Interests
Changes in the noncontrolling interests in partners' capital
Beginning balance	524	231
Sale of noncontrolling interest in a subsidiary		306
Net income attributable to noncontrolling interests	7	3
Distribution to noncontrolling interest	(12)	(5)
Equity compensation expense	1	1
Other comprehensive income/(loss):
Reclassification adjustments	(6)
Deferred gain/(loss) on cash flow hedges, net	2
Ending Balance	$ 516	$ 536
PNG Long Term Incentive Plan Awards
LTIP Vesting
LTIP awards, issued (in units)	191,812
LTIP unit vestings, fair value	$ 16

Equity Compensation Plans (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended
	Feb. 29, 2012	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Other Consolidated Equity Compensation Information
Equity compensation expense		$ 39	$ 20
LTIP unit settled vestings		24
LTIP cash settled vestings		36
DER cash payments		$ 2	$ 1
PNG Long Term Incentive Plan Awards
Share-based Compensation Arrangement, by Share-based Payment Award
Award vesting rights (as a percent)	fifty percent
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
Awards associated with DERs that begin payment in February 2012
Share-based Compensation Arrangement, by Share-based Payment Award
Annualized distribution threshold of units with associated DERs (in dollars per share)	$ 1.45
Outstanding (in units)
Outstanding at end of period (in units)	70,000
Awards associated with DERs that begin payment in May 2013
Share-based Compensation Arrangement, by Share-based Payment Award
Annualized distribution threshold of units with associated DERs (in dollars per share)	$ 1.50
Outstanding (in units)
Outstanding at end of period (in units)	70,000
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
PAA Long-term Incentive Plans
Outstanding (in units)
Outstanding at beginning of period (in units)		4,000,000
Granted (in units)		700,000
Vested (in units)		(800,000)
Outstanding at end of period (in units)		3,900,000
Weighted Average Grant Date Fair Value per unit
Outstanding at beginning of period (in dollars per unit)		$ 43.53
Granted (in dollars per unit)		65.63
Vested (in dollars per unit)		37.85
Outstanding at end of period (in dollars per unit)		$ 48.65
Units issued in connection with the settlement of vested awards, net of tax withholding (in units)		200,000
Units issued in connection with tax withholding on units vested (in units)		100,000
Vested awards settled in cash (in units)		500,000
PNG LTIP Awards Including Transaction Grants
Outstanding (in units)
Outstanding at beginning of period (in units)		800,000
Granted (in units)		100,000
Outstanding at end of period (in units)		900,000
Weighted Average Grant Date Fair Value per unit
Outstanding at beginning of period (in dollars per unit)		$ 20.55
Granted (in dollars per unit)		15.05
Outstanding at end of period (in dollars per unit)		$ 17.97
AAP LP Class B Units
Outstanding (in units)
Earned (in units)		(24,250)
Weighted Average Grant Date Fair Value per unit
Units Outstanding (in units)		183,500		183,500
Outstanding Units Earned (in units)		104,313
Reserved for future issuances		16,500

Derivatives and Risk Management Activities (Details) barrel in Millions	Mar. 31, 2012 Bcf barrel barrelsperday
Commodity Price Risk Hedging:
Storage capacity owned but not used in entity's transportation operations (in barrels)	78.0
Crude oil, LPG and refined products inventory hedged (in barrels)	7.5
Net long crude oil derivative position
Commodity Price Risk Hedging:
Net derivative positions per day (in barrels) \| barrelsperday	217,100
Crude oil, LPG and refined products inventory hedged (in barrels)	6.5
Net short spread position hedging anticipated crude oil lease gathering purchases
Commodity Price Risk Hedging:
Net derivative positions per day (in barrels) \| barrelsperday	21,400
Crude oil, LPG and refined products inventory hedged (in barrels)	19.6
WTS/WTI crude oil basis swaps
Commodity Price Risk Hedging:
Net derivative positions per day (in barrels) \| barrelsperday	9,000
Crude oil, LPG and refined products inventory hedged (in barrels)	5.8
LLS/WTI crude oil basis swaps
Commodity Price Risk Hedging:
Net derivative positions per day (in barrels) \| barrelsperday	10,500
Crude oil, LPG and refined products inventory hedged (in barrels)	2.6
Average butane/WTI spread positions
Commodity Price Risk Hedging:
Net derivative positions per day (in barrels) \| barrelsperday	16,200
Crude oil, LPG and refined products inventory hedged (in barrels)	1.5
Crude oil net short position
Commodity Price Risk Hedging:
Net derivative positions per day (in barrels) \| barrelsperday	1,500
Crude oil, LPG and refined products inventory hedged (in barrels)	2.1
Crude oil long put option position
Commodity Price Risk Hedging:
Crude oil, LPG and refined products inventory hedged (in barrels)	0.2
Crude oil long call option position
Commodity Price Risk Hedging:
Crude oil, LPG and refined products inventory hedged (in barrels)	0.6
Long natural gas swaps position for anticipated base gas purchases
Commodity Price Risk Hedging:
Crude oil, LPG and refined products inventory hedged (in barrels) \| Bcf	3.5
Short natural gas swap position related to anticipated natural gas sales
Commodity Price Risk Hedging:
Crude oil, LPG and refined products inventory hedged (in barrels) \| Bcf	21.9

Derivatives and Risk Management Activities (Details 2) $ in Millions	1 Months Ended	3 Months Ended
	Jul. 31, 2009 USD ($) contract	Mar. 31, 2012 USD ($) contract
Interest Rate Risk Hedging
Net deferred losses from interest rate risk hedging included in AOCI \| $		$ (82)
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 payment for (proceeds from) termination of interest rate swaps \| $		$ (12)
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
4 forward starting swaps (10-year)
Interest Rate Risk Hedging
Number of terminated 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
Cash payment for (proceeds from) termination of interest rate swaps \| $		$ 24
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 Risk Management Activities (Details 3) $ in Millions, $ in Millions	Mar. 31, 2012 USD ($) rate	Mar. 31, 2012 CAD ($) rate
Currency Exchange Rate Risk Hedging:
Net deferred gains from currency risk rate hedging included in AOCI \| $	$ 9
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	$ 11	$ 11
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 Risk Management Activities (Details 4) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Impact of derivative activities recognized in earnings
Total	$ 16	$ (66)
Unrealized gains reclassified from AOCI to earnings to offset lower of cost or market adjustment relating to carrying value of inventory	4
Commodity \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	(4)	(71)
Derivatives in Cash Flow Hedging Relationships - Ineffective Portion	(3)	(8)
Commodity \| Facilities segment revenues
Impact of derivative activities recognized in earnings
Total	12	(1)
Commodity \| Purchases and related costs
Impact of derivative activities recognized in earnings
Total	5
Commodity \| Field Operating costs
Impact of derivative activities recognized in earnings
Total	2	1
Interest Rate Contracts \| Interest expense
Impact of derivative activities recognized in earnings
Total	(1)	1
Net gain associated with interest rate swaps designated as fair value hedges	1	1
Foreign exchange contracts \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	1	3
Foreign exchange contracts \| Other income/(expense), net
Impact of derivative activities recognized in earnings
Total	1	1
Derivatives designated as hedging instruments
Impact of derivative activities recognized in earnings
Total	50	(74)
Derivatives designated as hedging instruments \| Commodity \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	34	(75)
Derivatives designated as hedging instruments \| Commodity \| Facilities segment revenues
Impact of derivative activities recognized in earnings
Total	12	(1)
Derivatives designated as hedging instruments \| Commodity \| Purchases and related costs
Impact of derivative activities recognized in earnings
Total	4
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	1	1
Derivatives not designated as hedging instruments
Impact of derivative activities recognized in earnings
Total	(34)	8
Derivatives not designated as hedging instruments \| Commodity \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	(38)	4
Derivatives not designated as hedging instruments \| Commodity \| Purchases and related costs
Impact of derivative activities recognized in earnings
Total	1
Derivatives not designated as hedging instruments \| Commodity \| Field Operating costs
Impact of derivative activities recognized in earnings
Total	2	1
Derivatives not designated as hedging instruments \| Foreign exchange contracts \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	$ 1	$ 3

Derivatives and Risk Management Activities (Details 5) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Derivatives disclosures
Asset Derivatives Fair Value	$ 146		$ 187
Liability Derivatives Fair Value	(169)		(230)
Net loss deferred in AOCI	(78)
Net gain expected to be reclassified to earnings in next 12 months	2
Gain expected to be reclassified to earnings prior to 2015	4
Net deferred gain/(loss) recognized in AOCI on derivatives (effective portion)	76	$ (144)
Gain (loss) expected to be reclassified to earnings through 2045	(84)
Broker receivable	49
Broker payable			7
Initial margin	74		52
Variation margin returned/(posted)	25		59
Commodity
Derivatives disclosures
Net deferred gain/(loss) recognized in AOCI on derivatives (effective portion)	25	(145)
Foreign exchange contracts
Derivatives disclosures
Net deferred gain/(loss) recognized in AOCI on derivatives (effective portion)		(1)
Interest Rate Contracts
Derivatives disclosures
Net deferred gain/(loss) recognized in AOCI on derivatives (effective portion)	51	$ 2
Derivatives designated as hedging instruments
Derivatives disclosures
Asset Derivatives Fair Value	101		94
Liability Derivatives Fair Value	(124)		(187)
Derivatives designated as hedging instruments \| Commodity \| Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	87		72
Liability Derivatives Fair Value	(54)		(47)
Derivatives designated as hedging instruments \| Commodity \| Other long-term assets
Derivatives disclosures
Asset Derivatives Fair Value	7		20
Liability Derivatives Fair Value	(1)		(2)
Derivatives designated as hedging instruments \| Commodity \| Other long-term liabilities
Derivatives disclosures
Asset Derivatives Fair Value	3
Liability Derivatives Fair Value	(3)
Derivatives designated as hedging instruments \| Foreign exchange contracts \| Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	1		1
Derivatives designated as hedging instruments \| Interest Rate Contracts \| Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	1		1
Derivatives designated as hedging instruments \| Interest Rate Contracts \| Other long-term assets
Derivatives disclosures
Asset Derivatives Fair Value	2
Derivatives designated as hedging instruments \| Interest Rate Contracts \| Other current liabilities
Derivatives disclosures
Liability Derivatives Fair Value	(1)		(24)
Derivatives designated as hedging instruments \| Interest Rate Contracts \| Other long-term liabilities
Derivatives disclosures
Liability Derivatives Fair Value	(65)		(114)
Derivatives not designated as hedging instruments
Derivatives disclosures
Asset Derivatives Fair Value	45		93
Liability Derivatives Fair Value	(45)		(43)
Derivatives not designated as hedging instruments \| Commodity \| Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	44		87
Liability Derivatives Fair Value	(39)		(39)
Derivatives not designated as hedging instruments \| Commodity \| Other long-term assets
Derivatives disclosures
Asset Derivatives Fair Value			6
Liability Derivatives Fair Value	(6)		(3)
Derivatives not designated as hedging instruments \| Commodity \| Other current liabilities
Derivatives disclosures
Liability Derivatives Fair Value			$ (1)
Derivatives not designated as hedging instruments \| Commodity \| Other long-term liabilities
Derivatives disclosures
Asset Derivatives Fair Value	$ 1

Derivatives and Risk Management Activities (Details 6) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Level 3
Roll forward of Level 3 Net Liability
Beginning Balance	$ 12	$ (14)
Unrealized gains/(losses):
Included in earnings	(4)	6
Included in other comprehensive income	3	(2)
Settlements	(12)	32
Derivatives entered into during the period	3	(10)
Transfers out of Level 3		(17)
Ending Balance	2	(5)
Change in unrealized gains/(losses) included in earnings relating to level 3 derivatives still held at the end of the periods	(1)	$ (3)
Recurring Fair Value Measures \| Level 1
Recurring Fair Value Measures
Net asset/(liability) at fair value	37		$ 80
Recurring Fair Value Measures \| Level 1 \| Commodity
Recurring Fair Value Measures
Net asset/(liability) at fair value	37		80
Recurring Fair Value Measures \| Level 2
Recurring Fair Value Measures
Net asset/(liability) at fair value	(62)		(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	(63)		(137)
Recurring Fair Value Measures \| Level 2 \| Foreign exchange contracts
Recurring Fair Value Measures
Net asset/(liability) at fair value	1		1
Recurring Fair Value Measures \| Level 3
Recurring Fair Value Measures
Net asset/(liability) at fair value	2		12
Recurring Fair Value Measures \| Level 3 \| Commodity
Recurring Fair Value Measures
Net asset/(liability) at fair value	2		12
Recurring Fair Value Measures \| Total
Recurring Fair Value Measures
Net asset/(liability) at fair value	(23)		(43)
Recurring Fair Value Measures \| Total \| Commodity
Recurring Fair Value Measures
Net asset/(liability) at fair value	39		93
Recurring Fair Value Measures \| Total \| Interest Rate Contracts
Recurring Fair Value Measures
Net asset/(liability) at fair value	(63)		(137)
Recurring Fair Value Measures \| Total \| Foreign exchange contracts
Recurring Fair Value Measures
Net asset/(liability) at fair value	$ 1		$ 1

Commitments and Contingencies (Details)	Apr. 30, 2012 case	Sep. 30, 2011 USD ($)
Plains Products Terminals LLC
Loss Contingencies
Natural resources contamination - allocated and paid \| $		$ 550,000
Pemex Exploracion y Produccion (PEP)
Loss Contingencies
Number of cases filed \| case	2

Commitments and Contingencies (Details 2) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011
Environmental
Estimated environmental reserve	$ 74	$ 74
Reserve for environmental liabilities, short-term	10	12
Reserve for environmental liabilities, long-term	64	62
Probable recoveries from insurers and third parties recorded as a receivable	$ 15	$ 47
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

Operating Segments (Details) $ in Millions	3 Months Ended
Operating Segments (Details) $ in Millions	Mar. 31, 2012 USD ($) segment	Mar. 31, 2011 USD ($)
Operating Segments
Number of Operating Segments \| segment	3
Revenues:
External Customers	$ 9,218	$ 7,694
Intersegment	212	177
Total revenues of reportable segments	9,430	7,871
Equity earnings in unconsolidated entities	7
Segment profit	380	348
Maintenance capital	35	24
Transportation
Revenues:
External Customers	150	141
Intersegment	167	134
Total revenues of reportable segments	317	275
Equity earnings in unconsolidated entities	7
Segment profit	162	137
Maintenance capital	24	18
Facilities
Revenues:
External Customers	191	118
Intersegment	45	43
Total revenues of reportable segments	236	161
Segment profit	90	78
Maintenance capital	7	3
Supply and Logistics
Revenues:
External Customers	8,877	7,435
Total revenues of reportable segments	8,877	7,435
Segment profit	128	133
Maintenance capital	4	3
Interest expense related to hedged inventory purchases	$ 2	$ 5

Operating Segments (Details 2) - USD ($) $ in Millions	3 Months Ended
Operating Segments (Details 2) - USD ($) $ in Millions	Mar. 31, 2012	Mar. 31, 2011
Reconciliation of segment profit to net income attributable to Plains
Segment profit	$ 380	$ 348
Depreciation and amortization	(60)	(63)
Interest expense	(65)	(65)
Other income/(expense), net	2	(22)
Income tax expense	(20)	(13)
NET INCOME	237	185
Net income attributable to noncontrolling interests	(7)	(3)
NET INCOME ATTRIBUTABLE TO PLAINS	$ 230	$ 182

- 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
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
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-Publisher AICPA
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Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph A7
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+ 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
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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

+ Details

Related Party Transactions (Details) - Oxy - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Related party transaction
Related party ownership of general partner interest (as a percent)	35.00%
Revenues	$ 455	$ 702
Purchases and related cost	148	$ 74
Trade accounts receivable and other receivables, gross	147		$ 132
Accounts payable, gross	$ 171		$ 155

- Definition

The aggregate amount of receivables to be collected from related parties where one party can exercise control or significant influence over another party; including affiliates, owners or officers and their immediate families, pension trusts, and so forth, at the financial statement date. which are usually due within one year (or one business cycle).

+ References + Details

- Definition

Carrying amount as of the balance sheet date of obligations due all related parties. For classified balance sheets, represents the current portion of such liabilities (due within one year or within the normal operating cycle if longer).

+ References + Details