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Document and Entity Information - USD ($) $ in Billions	12 Months Ended
Document and Entity Information - USD ($) $ in Billions	Dec. 31, 2014	Feb. 18, 2015	Jun. 30, 2014
Document and Entity Information
Entity Registrant Name	PLAINS ALL AMERICAN PIPELINE LP
Entity Central Index Key	0001070423
Document Type	10-K
Document Period End Date	Dec. 31, 2014
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 21.8
Entity Common Stock, Shares Outstanding		376,241,697
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
CURRENT ASSETS
Cash and cash equivalents	$ 403	$ 41
Trade accounts receivable and other receivables, net	2,615	3,638
Inventory	891	1,065
Other current assets	270	220
Total current assets	4,179	4,964
PROPERTY AND EQUIPMENT	14,178	12,473
Accumulated depreciation	(1,906)	(1,654)
Property and equipment, net	12,272	10,819
OTHER ASSETS
Goodwill	2,465	2,503
Investments in unconsolidated entities	1,735	485
Linefill and base gas	930	798
Long-term inventory	186	251
Other, net	489	540
Total assets	22,256	20,360
CURRENT LIABILITIES
Accounts payable and accrued liabilities	2,986	3,983
Short-term debt	1,287	1,113
Other current liabilities	482	315
Total current liabilities	4,755	5,411
LONG-TERM LIABILITIES
Senior notes, net of unamortized discount of $18 and $15, respectively	8,757	6,710
Other long-term debt	5	5
Other long-term liabilities and deferred credits	548	531
Total long-term liabilities	9,310	7,246
COMMITMENTS AND CONTINGENCIES (NOTE 17)
PARTNERS' CAPITAL
Common unitholders (375,107,793 and 359,133,200 units outstanding, respectively)	7,793	7,349
General partner	340	295
Total partners' capital excluding noncontrolling interests	8,133	7,644
Noncontrolling interests	58	59
Total partners' capital	8,191	7,703
Total liabilities and partners' capital	$ 22,256	$ 20,360

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
CONSOLIDATED BALANCE SHEETS
Senior notes, unamortized discount	$ 18	$ 15
Common unitholders, units outstanding (in units)	375,107,793	359,133,200

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES
Supply and Logistics segment revenues	$ 42,114	$ 40,692	$ 36,438
Transportation segment revenues	774	701	623
Facilities segment revenues	576	856	736
Total revenues	43,464	42,249	37,797
COSTS AND EXPENSES
Purchases and related costs	39,500	38,465	34,368
Field operating costs	1,456	1,322	1,180
General and administrative expenses	325	359	342
Depreciation and amortization	392	375	482
Total costs and expenses	41,673	40,521	36,372
OPERATING INCOME	1,791	1,728	1,425
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	108	64	38
Interest expense (net of capitalized interest of $48, $38 and $36, respectively)	(340)	(303)	(288)
Other income/(expense), net	(2)	1	6
INCOME BEFORE TAX	1,557	1,490	1,181
Current income tax expense	(71)	(100)	(53)
Deferred income tax benefit/(expense)	(100)	1	(1)
NET INCOME	1,386	1,391	1,127
Net income attributable to noncontrolling interests	(2)	(30)	(33)
NET INCOME ATTRIBUTABLE TO PAA	1,384	1,361	1,094
NET INCOME ATTRIBUTABLE TO PAA:
LIMITED PARTNERS	884	967	789
GENERAL PARTNER	$ 500	$ 394	$ 305
BASIC NET INCOME PER LIMITED PARTNER UNIT (in dollars per unit)	$ 2.39	$ 2.82	$ 2.41
DILUTED NET INCOME PER LIMITED PARTNER UNIT (in dollars per unit)	$ 2.38	$ 2.80	$ 2.40
BASIC WEIGHTED AVERAGE LIMITED PARTNER UNITS OUTSTANDING (in units)	367	341	325
DILUTED WEIGHTED AVERAGE LIMITED PARTNER UNITS OUTSTANDING (in units)	369	343	328

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CONSOLIDATED STATEMENTS OF OPERATIONS
Interest expense, Capitalized interest	$ 48	$ 38	$ 36

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income	$ 1,386	$ 1,391	$ 1,127
Other comprehensive income/(loss)	(370)	(177)	26
Comprehensive income	1,016	1,214	1,153
Comprehensive income attributable to noncontrolling interests	(2)	(30)	(30)
Comprehensive income attributable to PAA	$ 1,014	$ 1,184	$ 1,123

CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME / (LOSS) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period	$ (97)	$ 80	$ 54
Reclassification adjustments	4	(66)	(62)
Deferred gain (loss) on cash flow hedges, net of tax	(86)	109	44
Currency translation adjustments	(288)	(220)	44
Total period activity	(370)	(177)	26
Balance at end of period	(467)	(97)	80
Derivative Instruments
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period	(77)	(120)	(102)
Reclassification adjustments	4	(66)	(62)
Deferred gain (loss) on cash flow hedges, net of tax	(86)	109	44
Total period activity	(82)	43	(18)
Balance at end of period	(159)	(77)	(120)
Translation Adjustments
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance at beginning of period	(20)	200	156
Currency translation adjustments	(288)	(220)	44
Total period activity	(288)	(220)	44
Balance at end of period	$ (308)	$ (20)	$ 200

- 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.

+ References + Details

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 1,386	$ 1,391	$ 1,127
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	392	375	482
Equity-indexed compensation expense	98	116	101
Inventory valuation adjustments	289	7	128
Deferred income tax (benefit)/expense	100	(1)	1
Gain on sales of linefill and base gas	(8)	(7)	(19)
(Gain)/loss on foreign currency revaluation	13	(1)	2
Settlement of terminated interest rate hedging instruments	(7)	8	(112)
Equity earnings in unconsolidated entities	(108)	(64)	(38)
Distributions from unconsolidated entities	105	54	40
Other	11	2	(6)
Changes in assets and liabilities, net of acquisitions
Trade accounts receivable and other	1,177	(186)	218
Inventory	(129)	134	(180)
Accounts payable and other current liabilities	(1,315)	126	(504)
Net cash provided by operating activities	2,004	1,954	1,240
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired (Note 3)	(10)	(28)	(2,156)
Additions to property, equipment and other	(1,932)	(1,613)	(1,204)
Cash received for sales of linefill and base gas	24	40	65
Cash paid for purchases of linefill and base gas	(161)	(122)	(109)
Investment in unconsolidated entities (Note 8)	(1,246)	(133)	(76)
Proceeds from sales of assets	28	200	22
Cash received upon formation of equity-method investment			59
Other investing activities	1	3	7
Net cash used in investing activities	(3,296)	(1,653)	(3,392)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) under PAA senior secured hedged inventory facility (Note 10)		(660)	591
Net borrowings/(repayments) under PAA senior unsecured revolving credit facility (Note 10)		(92)	59
Net borrowings/(repayments) under PNG credit agreement		(382)	61
Net borrowings/(repayments) under PAA commercial paper program (Note 10)	(366)	1,110
Proceeds from the issuance of PAA senior notes (Note 10)	2,595	699	1,996
Repayments of PAA senior notes (Note 10)		(250)	(500)
Net proceeds from the issuance of common units (Note 11)	848	465	959
Contributions from general partner	18	25	20
Net proceeds from the issuance of PNG common units		40
Distributions paid to common unitholders (Note 11)	(934)	(791)	(684)
Distributions paid to general partner (Note 11)	(473)	(369)	(285)
Distributions paid to noncontrolling interests	(3)	(49)	(48)
Other financing activities	(28)	(27)	(18)
Net cash provided by/(used in) financing activities	1,657	(281)	2,151
Effect of translation adjustment on cash	(3)	(3)	(1)
Net increase/(decrease) in cash and cash equivalents	362	17	(2)
Cash and cash equivalents, beginning of period	41	24	26
Cash and cash equivalents, end of period	403	41	24
Cash paid for:
Interest, net of amounts capitalized	334	305	295
Income taxes, net of amounts refunded	$ 159	$ 37	$ 71

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions	Common Units	General Partner	Partners' Capital Excluding Noncontrolling Interests	Noncontrolling Interests	Total
Balance, beginning of period at Dec. 31, 2011	$ 5,249	$ 201	$ 5,450	$ 524	$ 5,974
Balance, beginning of period (in units) at Dec. 31, 2011	310,800,000
Increase (Decrease) in Partners' Capital
Net income	$ 789	305	1,094	33	1,127
Distributions	(684)	(285)	(969)	(48)	(1,017)
Issuance of common units	$ 959	20	979		$ 979
Issuance of common units (in units)	23,500,000				23,563,707
Issuance of common units under LTIP, net of units tendered by employees to satisfy tax withholding obligations	$ 33	1	34		$ 34
Issuance of common units under LTIP, net of units tendered by employees to satisfy tax withholding obligations (in units)	1,000,000
Equity-indexed compensation expense	$ 18	6	24	4	28
Distribution equivalent right payments	(4)		(4)	(1)	(5)
Other comprehensive income/(loss)	28	1	29	(3)	26
Balance, end of period at Dec. 31, 2012	$ 6,388	249	6,637	509	7,146
Balance, end of period (in units) at Dec. 31, 2012	335,300,000
Increase (Decrease) in Partners' Capital
Net income	$ 967	394	1,361	30	1,391
Distributions	(791)	(369)	(1,160)	(49)	(1,209)
Issuance of common units	$ 468	9	477		477
Issuance of common units (in units)	8,600,000
Issuance of common units under LTIP, net of units tendered by employees to satisfy tax withholding obligations	$ (11)	1	(10)		(10)
Issuance of common units under LTIP, net of units tendered by employees to satisfy tax withholding obligations (in units)	500,000
Equity-indexed compensation expense	$ 33	5	38	1	39
Distribution equivalent right payments	(5)		(5)	(1)	(6)
Other comprehensive income/(loss)	(173)	(4)	(177)		(177)
Issuance of PNG common units	8		8	32	40
PNG Merger (Note 11)	$ 465	10	475	(463)	12
PNG Merger (Note 11) (in units)	14,700,000
Balance, end of period at Dec. 31, 2013	$ 7,349	295	7,644	59	$ 7,703
Balance, end of period (in units) at Dec. 31, 2013	359,100,000				359,133,200
Increase (Decrease) in Partners' Capital
Net income	$ 884	500	1,384	2	$ 1,386
Distributions	(934)	(473)	(1,407)	(3)	(1,410)
Issuance of common units	$ 848	18	866		866
Issuance of common units (in units)	15,400,000
Issuance of common units under LTIP, net of units tendered by employees to satisfy tax withholding obligations	$ (17)	1	(16)		(16)
Issuance of common units under LTIP, net of units tendered by employees to satisfy tax withholding obligations (in units)	600,000
Equity-indexed compensation expense	$ 32	7	39		39
Distribution equivalent right payments	(6)		(6)		(6)
Other comprehensive income/(loss)	(362)	(8)	(370)		(370)
Other	(1)		(1)		(1)
Balance, end of period at Dec. 31, 2014	$ 7,793	$ 340	$ 8,133	$ 58	$ 8,191
Balance, end of period (in units) at Dec. 31, 2014	375,100,000				375,107,793

Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2014

Organization and Basis of Presentation

Organization and Basis of Presentation

Note 1—Organization and Basis of Presentation

Organization

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

We own and operate midstream energy infrastructure and provide logistics services for crude oil, natural gas liquids (“NGL”), natural gas and refined products. The term NGL includes ethane and natural gasoline products as well as products commonly referred to as liquefied petroleum gas (“LPG”), such as propane and butane. When used in this Form 10-K, NGL refers to all NGL products including LPG. We own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. Our business activities are conducted through three operating segments: Transportation, Facilities and Supply and Logistics. See Note 19 for further discussion of our operating segments.

Our 2% general partner interest is held by PAA GP LLC, a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP LLC, AAP also owns all of our incentive distribution rights (“IDRs”). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole member of GP LLC, and at December 31, 2014, owned an approximate 34.1% limited partner interest in AAP.

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

Definitions

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

AOCI	=	Accumulated other comprehensive income / (loss)
Bcf	=	Billion cubic feet
Btu	=	British thermal unit
CAD	=	Canadian dollar
CERCLA	=	Federal Comprehensive Environmental Response, Compensation and Liability Act, as amended
DERs	=	Distribution equivalent rights
EBITDA	=	Earnings before interest, taxes, depreciation and amortization
FASB	=	Financial Accounting Standards Board
GAAP	=	Generally accepted accounting principles in the United States
ICE	=	Intercontinental Exchange
IPO	=	Initial public offering
LIBOR	=	London Interbank Offered Rate
LTIP	=	Long-term incentive plan
Mcf	=	Thousand cubic feet
MLP	=	Master limited partnership
MQD	=	Minimum quarterly distribution
NYMEX	=	New York Mercantile Exchange
NYSE	=	New York Stock Exchange
Oxy	=	Occidental Petroleum Corporation or its subsidiaries
PLA	=	Pipeline loss allowance
PNG	=	PAA Natural Gas Storage, L.P.
RCRA	=	Federal Resource Conservation and Recovery Act, as amended
USD	=	United States dollar
WTI	=	West Texas Intermediate

Basis of Consolidation and Presentation

The accompanying financial statements and related notes present and discuss our consolidated financial position as of December 31, 2014 and 2013, and the consolidated results of our operations, cash flows, changes in partners’ capital, comprehensive income and changes in accumulated other comprehensive income / (loss) for the years ended December 31, 2014, 2013 and 2012. All significant intercompany transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications do not affect net income attributable to PAA. The accompanying consolidated financial statements include PAA and all of its wholly owned subsidiaries.

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

PNG Merger

On December 31, 2013, with the approval of PNG’s common unitholders, PNG became our wholly-owned subsidiary through a unit-for-unit exchange (referred to herein as the “PNG Merger”). See Note 11 for further discussion. Since we historically consolidated PNG for financial reporting purposes, the PNG Merger did not change the basis of consolidation of our historical financial statements.

Two-for-One Unit Split

A two-for-one split of our common units was completed on October 1, 2012. The effect of the two-for-one split has been retroactively applied to all unit and per-unit data presented in this Form 10-K. In addition, our partnership agreement was amended to modify certain definitions related to target distribution amounts and minimum distribution amounts to reflect the unit split.

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2014
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies	Note 2—Summary of Significant Accounting Policies Use of Estimates The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We make significant estimates with respect to (i) purchases and sales accruals, (ii) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (iii) mark-to-market gains and losses on derivative instruments (pursuant to guidance issued by the FASB regarding fair value measurements), (iv) accruals and contingent liabilities, (v) equity-indexed compensation plan accruals, (vi) property and equipment and depreciation expense, (vii) allowance for doubtful accounts and (viii) inventory valuations. Although we believe these estimates are reasonable, actual results could differ from these estimates. Revenue Recognition Supply and Logistics Segment Revenues. Revenues from sales of crude oil, NGL and natural gas are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. Sales of crude oil and NGL consist of outright sales contracts. Inventory purchases and sales under buy/sell transactions are treated as inventory exchanges. The sales under these exchanges are netted to zero in Supply and Logistics segment revenues in our Consolidated Statements of Operations. Additionally, we may utilize derivatives in connection with the transactions described above. For commodity derivatives that are designated as cash flow hedges, derivative gains and losses are deferred in AOCI and recognized in revenues in the periods during which the underlying physical hedged transaction impacts earnings. Also, the ineffective portion of the change in fair value of cash flow hedges is recognized in revenues each period along with the change in fair value of derivatives that do not qualify for or are not designated for hedge accounting. Transportation Segment Revenues. Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems, trucks and barges. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil and NGL at a published tariff, as well as revenues associated with agreements for committed space on various assets. Tariff revenues are recognized either at the point of delivery or at the point of receipt pursuant to specifications outlined in the regulated and non-regulated tariffs. Revenues associated with fees are recognized in the month to which the fee applies. The majority of our pipeline tariff and fee revenues are based on actual volumes and rates. As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to offset losses due to evaporation, measurement and other losses in transit. We value the variance of allowance volumes to actual losses at the estimated net realizable value (including the impact of gains and losses from derivative related activities) at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues. In addition, we have certain agreements that require counterparties to ship a minimum volume over an agreed upon period. Revenue is recognized at the latter of when the volume is shipped (pursuant to specifications outlined in the tariffs) or when the counterparty’s ability to make up the minimum volume has expired. Facilities Segment Revenues. Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. Revenues generated in this segment include (i) fees that are generated from storage capacity agreements, (ii) terminal throughput fees that are generated when we receive crude oil, refined products or NGL from one connecting source and deliver the applicable product to another connecting carrier, (iii) loading and unloading fees at our rail terminals, (iv) fees from NGL fractionation and isomerization, (v) fees from natural gas and condensate processing services and (vi) fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services. We generate revenue through a combination of month-to-month and multi-year agreements and processing arrangements. Storage fees resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized. Terminal fees (including throughput and rail fees) are recognized as the crude oil, NGL or refined product enters or exits the terminal and is received from or delivered to the connecting carrier or third-party terminal, as applicable. Hub service fees are recognized in the period the natural gas moves across our header system. Fees from NGL fractionation, isomerization services and gas processing services are recognized in the period when the services are performed. In addition, we have certain agreements that require counterparties to throughput a minimum volume over an agreed upon period. Revenue is recognized at the latter of when the volume exits the terminal or when the counterparty’s ability to make up the minimum volume has expired. Purchases and Related Costs Purchases and related costs include (i) the cost of crude oil, NGL and natural gas obtained in outright purchases, (ii) fees incurred for third-party storage and transportation, whether by pipeline, truck, rail, ship or barge, (iii) interest cost attributable to borrowings for inventory stored in a contango market and (iv) performance-related bonus costs. These costs are recognized when incurred except in the case of products purchased, which are recognized at the time title transfers to us. Purchases that are part of exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Consolidated Statements of Operations. Field Operating Costs and General and Administrative Expenses Field operating costs consist of various field operating expenses, including fuel and power costs, telecommunications, payroll and benefit costs (including equity-indexed compensation expense) for truck drivers and field and other operations personnel, third-party trucking transportation costs for our U.S. crude oil operations, maintenance and integrity management costs, regulatory compliance, environmental remediation, insurance, vehicle leases, and property taxes. General and administrative expenses consist primarily of payroll and benefit costs (including equity-indexed compensation expense), certain information systems and legal costs, office rent, contract and consultant costs and audit and tax fees. Foreign Currency Transactions/Translation Certain of our subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of subsidiaries with a Canadian dollar functional currency are translated at period-end rates of exchange, and revenues and expenses are translated at average exchange rates prevailing for each month. The resulting translation adjustments are made directly to a separate component of other comprehensive income, which is reflected in Partners’ Capital on our Consolidated Balance Sheet. Certain of our subsidiaries also enter into transactions and have monetary assets and liabilities that are denominated in a currency other than the entities’ respective functional currencies. Gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities are included in the Consolidated Statements of Operations. The revaluation of foreign currency transactions and monetary assets and liabilities resulted in a loss of $13 million for the year ended December 31, 2014, a gain of $1 million for the year ended December 31, 2013 and a loss of $2 million for the year ended December 31, 2012. Cash and Cash Equivalents Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. We used the cash on hand at December 31, 2014 to repay $400 million of commercial paper borrowings during the first week of January 2015. In accordance with our policy, outstanding checks are classified as accounts payable rather than negative cash. As of December 31, 2014 and 2013, accounts payable included $94 million and $70 million, respectively, of outstanding checks that were reclassified from cash and cash equivalents. Accounts Receivable Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas storage. These purchasers include, but are not limited to, refiners, producers, marketing and trading companies and financial institutions that are active in the physical and financial commodity markets. The majority of our accounts receivable relate to our crude oil supply and logistics activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes. During late 2014 and early 2015, commodity prices dropped significantly. This volatility has caused liquidity issues impacting many energy companies, which in turn has increased the potential credit risks associated with certain counterparties with which we do business. To mitigate credit risk related to our accounts receivable, we have in place a rigorous credit review process. We closely monitor market conditions to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit or parental guarantees. As of December 31, 2014 and 2013, we had received $180 million and $117 million, respectively, of advance cash payments from third parties to mitigate credit risk. Furthermore, as of December 31, 2014 and 2013, we had received $198 million and $426 million, respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. In addition, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Further, we enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet) for a majority of such arrangements. We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At December 31, 2014 and 2013, substantially all of our accounts receivable (net of allowance for doubtful accounts) were less than 30 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled $4 million and $5 million at December 31, 2014 and 2013, respectively. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts. Noncontrolling Interests We account for noncontrolling interests in subsidiaries in accordance with FASB guidance, which requires all entities to report noncontrolling interests in subsidiaries as a component of equity in the consolidated financial statements. Noncontrolling interest represents the portion of assets and liabilities in a consolidated subsidiary that is owned by a third-party. See Note 11 for additional discussion regarding our noncontrolling interests. Asset Retirement Obligations FASB guidance establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including estimates related to (i) the time of the liability recognition, (ii) initial measurement of the liability, (iii) allocation of asset retirement cost to expense, (iv) subsequent measurement of the liability and (v) financial statement disclosures. FASB guidance also requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Some of our assets, primarily related to our Transportation and Facilities segments, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. These assets have been in existence for many years and with regular maintenance will continue to be in service for many years to come. It is not possible to predict when demand for these transportation or storage services will cease, and we do not believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations. We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonably determine the settlement dates. A small portion of our contractual or regulatory obligations is related to assets that are inactive or that we plan to take out of service and, although the ultimate timing and costs to settle these obligations are not known with certainty, we have recorded a reasonable estimate of these obligations. We have estimated that the fair value of these obligations was $36 million and $34 million, respectively, at December 31, 2014 and 2013. Fair Value Measurements 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. The determination of the fair values 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. See Note 12 for further discussion. Other Significant Accounting Policies See the respective footnotes for our accounting policies regarding (i) acquisitions, (ii) net income per limited partner unit, (iii) inventory, linefill and base gas and long-term inventory, (iv) property and equipment, (v) goodwill, (vi) investments in unconsolidated entities, (vii) other assets, net, (viii) derivatives and risk management activities, (ix) income taxes, (x) equity-indexed compensation and (xi) legal and environmental matters. Recent Accounting Pronouncements In January 2015, as part of its initiative to reduce complexity in accounting standards, the FASB issued guidance to eliminate the concept of extraordinary items from GAAP. This guidance will become effective for interim and annual periods beginning after December 15, 2015. We expect to adopt this guidance on January 1, 2016. We do not believe our adoption will have a material impact on our financial position, results of operations or cash flows. In May 2014, the FASB issued guidance regarding the recognition of revenue from contracts with customers with the underlying principle that an entity will recognize revenue to reflect amounts expected to be received in exchange for the provision of goods and services to customers upon the transfer of those goods or services. The guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. This guidance becomes effective for interim and annual periods beginning after December 15, 2016 and can be adopted either with a full retrospective approach or a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. We are currently evaluating which transition approach to apply and the effect that adopting this guidance will have on our financial position, results of operations and cash flows. In April 2014, the FASB issued guidance that modifies the criteria under which assets to be disposed of are evaluated to determine if such assets qualify as a discontinued operation and requires new disclosures for both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. This guidance is effective prospectively for annual and interim reporting periods beginning after December 15, 2014. Early adoption is permitted but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issue. We adopted this guidance on January 1, 2015. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In March 2013, the FASB issued guidance regarding the release of cumulative translation adjustments into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a business within a foreign entity. This guidance became effective beginning after December 15, 2013. We adopted this guidance on January 1, 2014. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

Acquisitions and Dispositions

12 Months Ended

Dec. 31, 2014

Acquisitions and Dispositions

Acquisitions and Dispositions

Note 3—Acquisitions and Dispositions

2014 Acquisitions

Acquisition of Interest in BridgeTex Pipeline Company, LLC

On November 14, 2014, we acquired a 50% interest in BridgeTex Pipeline Company, LLC (“BridgeTex”) from Oxy. We account for this investment under the equity method of accounting. See Note 8 for additional discussion.

The following acquisitions were accounted for using the acquisition method of accounting and the determination of the fair value of the assets and liabilities acquired has been estimated in accordance with the applicable accounting guidance.

Other 2014 Acquisitions

During the year ended December 31, 2014, we completed two additional acquisitions for aggregate consideration of $11 million. The assets acquired primarily included a crude oil terminal and a propane terminal included in our Facilities segment. We recognized goodwill of $1 million related to these acquisitions.

2013 Acquisitions

During the year ended December 31, 2013, we completed an acquisition for aggregate consideration of $19 million. The assets acquired included a trucking business included in our Transportation segment. We recognized goodwill of $6 million related to this acquisition.

2012 Acquisitions

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. from Amoco Canada International Holdings B.V. Total consideration for this acquisition (referred to herein as the “BP NGL Acquisition”), which was based on an October 1, 2011 effective date, was approximately $1.68 billion in cash, including $17 million of imputed interest.

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

				Average
				Depreciable
Description	Amount			Life (in years)
Working capital	$	241		N/A
Property and equipment	1,081			5 - 70
Linefill	85			N/A
Long-term inventory	165			N/A
Intangible assets (contract)	130			13
Goodwill	236			N/A
Deferred tax liability	(236		)	N/A
Environmental liability	(14		)	N/A
Other long-term liabilities	(5		)	N/A
Total	$	1,683

The purchase price was equal to the fair value of the net tangible and intangible assets acquired, excluding the resulting deferred tax liability and goodwill. The deferred tax liability is determined by the difference between the fair value of the acquired assets and liabilities and the tax basis for those assets and liabilities. The resulting liability gives rise to an equal and offsetting goodwill balance for this transaction.

The BP NGL Acquisition was pre-funded through various means, including the issuance of common units and senior notes in March 2012 for net proceeds of approximately $1.69 billion. During the year ended December 31, 2012, we incurred $13 million of acquisition-related costs associated with the BP NGL Acquisition. Such costs are reflected as a component of “General and administrative expenses” in our Consolidated Statement of Operations.

USD Rail Terminal Acquisition

On December 12, 2012, we completed a transaction with U.S. Development Group (referred to herein as the “USD Rail Terminal Acquisition”) for an aggregate consideration of $503 million, paid in cash. Through the USD Rail Terminal Acquisition, we acquired four operating crude oil rail terminals and one terminal under development. The determination of the fair value of the assets and liabilities acquired was $1 million of working capital, $76 million of property and equipment and $426 million of goodwill. The goodwill arising from the USD Rail Terminal Acquisition represents anticipated opportunities to generate future cash flows from the rail facilities by utilizing them to reduce capacity constraints in certain geographic market areas.

Other 2012 Acquisitions

During the year ended December 31, 2012, we completed several additional acquisitions for an aggregate consideration of $150 million. The assets acquired primarily included crude oil and condensate gathering pipelines, a truck unloading terminal and trailers that are utilized in our Transportation segment, and terminal facilities included in our Facilities segment. We recognized goodwill of $10 million related to these acquisitions.

Pro Forma Results

Disclosure of the revenues and earnings from the BP NGL Acquisition, USD Rail Terminal Acquisition and our other 2012 acquisitions in our results for the year ended December 31, 2012 is not practicable as they were not operated as standalone subsidiaries. Selected unaudited pro forma results of operations for the year ended December 31, 2012, assuming our 2012 acquisitions had occurred on January 1, 2012, are presented below (in millions, except per unit data):

	Year Ended
	December 31, 2012
Total revenues	$	38,729
Net income attributable to PAA	$	1,149
Limited partner interest in net income attributable to PAA	$	846
Net income per limited partner unit:
Basic	$	2.57
Diluted	$	2.55

Dispositions

During 2014, 2013 and 2012, we sold various property and equipment for proceeds totaling $28 million, $200 million and $22 million, respectively. Gains of $1 million, less than $1 million and $6 million were recognized in 2014, 2013 and 2012, respectively, related to these sales.

Our 2013 dispositions primarily included the sale of certain refined products pipeline systems and related assets included in our Transportation segment. We closed a portion of the transaction in July 2013 and the balance in November 2013.

- 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
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1497-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1490-128463

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1392-128463

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7008-128479

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1486-128463

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6927-128479

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=39739317&loc=d3e4845-128472

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1500-128463

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1524-128463

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7000-128479

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=39739317&loc=d3e4922-128472

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=39739317&loc=d3e4934-128472

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=39739317&loc=d3e4926-128472

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1383-128463

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
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-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6996-128479

+ Details

Net Income Per Limited Partner Unit

12 Months Ended

Dec. 31, 2014

Net Income Per Limited Partner Unit

Net Income Per Limited Partner Unit

Note 4—Net Income Per Limited Partner Unit

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

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

Diluted net income per limited partner unit is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period using the two-class method. Our LTIP awards that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 16 for a complete discussion of our LTIP awards including specific discussion regarding DERs.

The following table sets forth the computation of basic and diluted net income per limited partner unit for the years ended December 31, 2014, 2013 and 2012 (in millions, except per unit data):

	Year Ended December 31,
	2014			2013			2012
Basic Net Income per Limited Partner Unit
Net income attributable to PAA	$	1,384		$	1,361		$	1,094
Less: General partner’s incentive distribution (1)	(482		)	(375		)	(289		)
Less: General partner 2% ownership (1)	(18		)	(19		)	(16		)
Net income available to limited partners	884			967			789
Less: Undistributed earnings allocated and distributions to participating securities (1)	(6		)	(7		)	(5		)
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	878		$	960		$	784

Basic weighted average limited partner units outstanding	367			341			325

Basic net income per limited partner unit	$	2.39		$	2.82		$	2.41

Diluted Net Income per Limited Partner Unit
Net income attributable to PAA	$	1,384		$	1,361		$	1,094
Less: General partner’s incentive distribution (1)	(482		)	(375		)	(289		)
Less: General partner 2% ownership (1)	(18		)	(19		)	(16		)
Net income available to limited partners	884			967			789
Less: Undistributed earnings allocated and distributions to participating securities (1)	(6		)	(6		)	(4		)
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	878		$	961		$	785

Basic weighted average limited partner units outstanding	367			341			325
Effect of dilutive securities: Weighted average LTIP units	2			2			3
Diluted weighted average limited partner units outstanding	369			343			328

Diluted net income per limited partner unit	$	2.38		$	2.80		$	2.40

(1)

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

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

	Year Ended December 31,
	2014		2013			2012
Basic net income per limited partner unit impact	$	—	$	(0.20	)	$	(0.11	)

Diluted net income per limited partner unit impact	$	—	$	(0.20	)	$	(0.11	)

Inventory, Linefill and Base Gas and Long-term Inventory

12 Months Ended

Dec. 31, 2014

Inventory, Linefill and Base Gas and Long-term Inventory

Inventory, Linefill and Base Gas and Long-term Inventory

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

Inventory primarily consists of crude oil, NGL and natural gas in pipelines, storage facilities and railcars that are valued at the lower of cost or market, with cost determined using an average cost method within specific inventory pools. At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Consolidated Statements of Operations. During the years ended December 31, 2014, 2013 and 2012, we recorded charges of $289 million, $7 million and $128 million, respectively, related to the writedown of our crude oil, NGL and natural gas inventory due to declines in prices. The year ended December 31, 2014 included the writedown of our natural gas inventory that was purchased in conjunction with managing natural gas storage deliverability requirements during the extended period of severe cold weather in the first quarter of 2014. A portion of these adjustments were offset by the recognition of gains on derivative instruments being utilized to hedge the future sales of our crude oil and NGL inventory. Substantially all of such gains were recorded to “Supply and Logistics segment revenues” in our accompanying Consolidated Statement of Operations. In 2014, we recognized $160 million of such gains. A majority of the inventory subject to writedown in the 2013 and 2012 periods had been liquidated and the applicable derivative instruments had been settled by the end of each year. See Note 12 for discussion of our derivative and risk management activities.

Linefill and base gas and minimum working inventory requirements in assets we own are recorded at historical cost and consist of crude oil, NGL and natural gas. We classify as linefill or base gas (i) our proportionate share of barrels used to fill a pipeline that we own such that when an incremental barrel is pumped into or enters a pipeline it forces product out at another location, (ii) barrels that represent the minimum working requirements in tanks and caverns that we own and (iii) natural gas required to maintain the minimum operating pressure of natural gas storage facilities we own. Linefill and base gas carrying amounts are reviewed for impairment in accordance with FASB guidance with respect to accounting for the impairment or disposal of long-lived assets. Carrying amounts that are not expected to be recoverable through future cash flows are written down to estimated fair value. See Note 6 for further discussion regarding impairment of long-lived assets. During 2014, 2013 and 2012, we did not recognize any impairments of linefill and base gas, but we did recognize gains of $8 million, $7 million and $19 million, respectively, on the sale of linefill and base gas for proceeds of $24 million, $40 million and $65 million, respectively.

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

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

	December 31, 2014							December 31, 2013
	Volumes	Unit of Measure		Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure		Carrying Value		Price/ Unit (1)
Inventory
Crude oil	6,465		barrels	$	304	$	47.02	6,951		barrels	$	540	$	77.69
NGL	13,553		barrels	454		$	33.50	8,061		barrels	352		$	43.67
Natural gas	32,317		Mcf	102		$	3.16	40,505		Mcf	150		$	3.70
Other	N/A			31		N/A		N/A			23		N/A
Inventory subtotal				891							1,065

Linefill and base gas
Crude oil	11,810		barrels	744		$	63.00	10,966		barrels	679		$	61.92
NGL	1,212		barrels	52		$	42.90	1,341		barrels	62		$	46.23
Natural gas	28,612		Mcf	134		$	4.68	16,615		Mcf	57		$	3.43
Linefill and base gas subtotal				930							798

Long-term inventory
Crude oil	2,582		barrels	136		$	52.67	2,498		barrels	202		$	80.86
NGL	1,681		barrels	50		$	29.74	1,161		barrels	49		$	42.20
Long-term inventory subtotal				186							251

Total				$	2,007						$	2,114

(1)

Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products.

Property and Equipment

12 Months Ended

Dec. 31, 2014

Property and Equipment

Property and Equipment

Note 6—Property and Equipment

In accordance with our capitalization policy, expenditures made to expand the existing operating and/or earnings capacity of our assets are capitalized. We also capitalize certain costs directly related to the construction of such assets, including related internal labor costs, engineering costs and interest costs. For the years ended December 31, 2014, 2013 and 2012, capitalized interest was $48 million, $38 million and $36 million, respectively. We also capitalize expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are expensed as incurred.

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

	Estimated Useful	December 31,
	Lives (Years)	2014			2013
Pipelines and related facilities	10 - 70	$	7,003		$	6,113
Storage, terminal and rail facilities	30 - 70	4,853			4,704
Trucking equipment and other	3 - 15	198			150
Construction in progress	-	1,545			1,008
Office property and equipment	2 - 50	156			125
Land and other	N/A	423			373
		14,178			12,473
Accumulated depreciation		(1,906		)	(1,654		)
Property and equipment, net		$	12,272		$	10,819

We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets. Depreciation expense for the years ended December 31, 2014, 2013 and 2012 was $319 million, $259 million and $222 million, respectively. We also classify gains and losses on sales of assets and asset impairments as a component of “Depreciation and amortization” in our Consolidated Statements of Operations. See Note 3 for additional information regarding dispositions. See “Impairment of Long-Lived Assets” below for a discussion of our policy for the recognition of asset impairments.

Impairment of Long-Lived Assets

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

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

whether there is an indication of impairment;

the grouping of assets;

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

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

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

During the years ended December 31, 2014 and 2013 we recognized impairments of $10 million and $20 million, respectively, related predominantly to assets taken out of service.

During the year ended December 31, 2012, we recognized losses on impairments of long-lived assets of $168 million, primarily related to our Pier 400 terminal project, which is reflected in “Depreciation and amortization” on our Consolidated Statement of Operations. This project, which we acquired in late 2006 by virtue of our merger with Pacific Energy Partners, L.P., was to develop a deepwater petroleum import terminal at Pier 400 and Terminal Island in the Port of Los Angeles to handle marine receipts of crude oil and refinery feedstock. During the third quarter of 2012, we decided not to proceed with the development of this project. A number of factors contributed to the uncertainties with respect to financial returns and the determination not to proceed with the project, including project delays, the economic downturn, regulatory and permitting hurdles, a challenging refining environment in California and an industry shift in the outlook for availability of domestic crude oil. We assessed the recoverability of these long-lived assets and, where necessary, performed further analysis based on a projected discounted cash flow methodology. As a result of this impairment review, we wrote off a substantial portion of the carrying amount of these long-lived assets, except for the portion that we anticipate we will recover. These project assets were included in our Facilities segment.

Also in 2012, we recognized a loss on impairment as a result of our decision to sell certain refined products pipeline systems and related assets included in the Transportation segment. In accordance with GAAP, we wrote their book value down to their expected sales price. In 2013, we sold these systems and related assets.

Goodwill

12 Months Ended

Dec. 31, 2014

Goodwill

Goodwill

Note 7—Goodwill

Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized.

In accordance with FASB guidance, we test goodwill at least annually (as of June 30) and on an interim basis if a triggering event occurs, such as an adverse change in business climate, to determine whether impairment has occurred. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. A reporting unit is an operating segment or one level below an operating segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are our operating segments. FASB guidance requires a two-step, quantitative approach to testing goodwill for impairment; however, we may first assess certain qualitative factors to determine whether it is necessary to perform the two-step goodwill impairment test. We did not elect to apply this qualitative assessment during our 2014 annual goodwill impairment test, but proceeded directly to the two-step, quantitative test. In Step 1, we compare the fair value of the reporting unit with the respective book values, including goodwill, by using an income approach based on a discounted cash flow analysis. This approach requires us to make long-term forecasts of future revenues, expenses and other expenditures. Those forecasts require the use of various assumptions and estimates, the most significant of which are net revenues (total revenues less purchases and related costs), operating expenses, general and administrative expenses and the weighted average cost of capital. Fair value of the reporting units is determined using significant unobservable inputs, or Level 3 inputs in the fair value hierarchy. When the fair value is greater than book value, then the reporting unit’s goodwill is not considered impaired. If the book value is greater than fair value, then we proceed to Step 2. In Step 2, we compare the implied fair value of the reporting unit’s goodwill with the book value. A goodwill impairment loss is recognized if the carrying amount exceeds its fair value.

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

The following table reflects our goodwill by segment and changes in goodwill during the years ended December 31, 2014 and 2013 (in millions):

	Transportation			Facilities			Supply and Logistics			Total
Balance at December 31, 2012	$	897		$	1,171		$	467		$	2,535
Acquisitions	6			—			—			6
Foreign currency translation adjustments	(20		)	(9		)	(4		)	(33		)
Purchase price accounting adjustments and other	(5		)	—			—			(5		)
Balance at December 31, 2013	$	878		$	1,162		$	463		$	2,503
Acquisitions (1)	—			1			—			1
Foreign currency translation adjustments	(24		)	(11		)	(4		)	(39		)
Balance at December 31, 2014	$	854		$	1,152		$	459		$	2,465

(1)

Goodwill is recorded at the acquisition date based on a preliminary fair value determination. This preliminary goodwill balance may be adjusted when the fair value determination is finalized. See Note 3 for additional discussion of our acquisitions.

Investments in Unconsolidated Entities

12 Months Ended

Dec. 31, 2014

Investments in Unconsolidated Entities

Investments in Unconsolidated Entities

Note 8—Investments in Unconsolidated Entities

Investments in entities over which we have significant influence but not control are accounted for by the equity method. We do not consolidate any part of the assets or liabilities of our equity investees. Our share of net income or loss is reflected as one line item on our Consolidated Statements of Operations entitled “Equity earnings in unconsolidated entities” and will increase or decrease, as applicable, the carrying value of our investments in unconsolidated entities on the balance sheet. In addition, as applicable, we include a proportionate share of our equity method investees’ unrealized gains and losses in other comprehensive income on our Consolidated Balance Sheet. We also adjust our investment balances in these investees by the like amount. We evaluate our equity investments for impairment in accordance with FASB guidance with respect to the equity method of accounting for investments in common stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature.

We consider distributions received from unconsolidated entities as returns on investment in those entities to the extent of cumulative net operating cash flows, and therefore classify these distributions as cash flows from operating activities in our Consolidated Statement of Cash Flows. We define cumulative net operating cash flows as cumulative net income adjusted for certain non-cash items such as depreciation and amortization expense. Other distributions received from unconsolidated entities would be considered a return of the investment and classified as cash flows from investing activities on the Consolidated Statement of Cash Flows. Our contributions to these entities will increase the carrying value of our investments and are reflected in our Consolidated Statements of Cash Flows in investing activities. During the years ended December 31, 2014, 2013 and 2012, we made cash contributions to Eagle Ford Pipeline LLC and White Cliffs Pipeline, LLC to support construction and expansion activities of such entities.

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

Entity	Type of Operation	Our Ownership Interest
Settoon Towing, LLC	Barge Transportation Services	50	%
BridgeTex Pipeline Company, LLC	Crude Oil Pipeline	50	%
Eagle Ford Pipeline LLC	Crude Oil Pipeline	50	%
White Cliffs Pipeline, LLC	Crude Oil Pipeline	36	%
Butte Pipe Line Company	Crude Oil Pipeline	22	%
Frontier Pipeline Company	Crude Oil Pipeline	22	%

In August 2012, we formed Eagle Ford Pipeline LLC with Enterprise Products Partners L.P. (“Enterprise”) for the purpose of developing a crude oil pipeline system in the Eagle Ford Area of South Texas. In conjunction with the formation, we and Enterprise contributed fixed assets with estimated book values of $134 million and $15 million, respectively. In addition, Enterprise contributed cash of $59 million, which we received from Eagle Ford Pipeline LLC.

On November 14, 2014, we acquired a 50% interest in BridgeTex from Oxy. BridgeTex owns a 300,000 barrel-per-day crude oil pipeline that extends from Colorado City in West Texas to a crude oil terminal in East Houston, which we believe is complementary to our existing West Texas assets. We paid cash of $1.088 billion, including working capital adjustments of $13 million, for our interest in BridgeTex.

Our investments in unconsolidated entities exceeded our share of the underlying equity in the net assets of such entities by $763 million and $78 million at December 31, 2014 and 2013, respectively. Such basis differences are included in the carrying values of our investments on our Consolidated Balance Sheets. The portion of the basis differences attributable to depreciable or amortizable assets is amortized on a straight-line basis over the estimated useful life of the related assets, which reduces “Equity earnings in unconsolidated entities” on our Consolidated Statements of Operations. The portion of the basis differences attributable to goodwill is not amortized. The increase in basis differences in 2014 was primarily due to our acquisition of an interest in BridgeTex.

Summarized Financial Information of Unconsolidated Entities

Combined summarized financial information for all of our unconsolidated entities is shown in the tables below (in millions):

	December 31,
	2014		2013
Current assets	$	184	$	177
Noncurrent assets	$	2,303	$	1,067
Current liabilities	$	142	$	57
Noncurrent liabilities	$	222	$	211

	Year Ended December 31,
	2014		2013		2012
Revenues	$	531	$	344	$	257
Operating income	$	301	$	181	$	132
Net income	$	285	$	172	$	118

Other Assets, Net

12 Months Ended

Dec. 31, 2014

Other Assets, Net

Other Assets, Net

Note 9—Other Assets, Net

Other assets, net of accumulated amortization, consisted of the following as of the dates indicated (in millions):

	December 31,
	2014			2013
Intangible assets	$	676		$	674
Debt issue costs	92			70
Fair value of derivative instruments	27			30
Other	19			37
	814			811
Accumulated amortization	(325		)	(271		)
	$	489		$	540

Costs incurred in connection with the issuance of long-term debt and amendments to our credit facilities are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization. Fully amortized debt issue costs and the related accumulated amortization are written off in conjunction with the refinancing or termination of the applicable debt arrangement. We capitalized debt issue costs of $24 million and $9 million in 2014 and 2013, respectively. Gross debt issue costs of $2 million and $8 million were removed from our Consolidated Balance Sheet during 2014 and 2013, respectively.

Amortization expense related to other assets (including finite-lived intangible assets) for the three years ended December 31, 2014, 2013 and 2012 was $64 million, $96 million and $99 million, respectively. Amortization expense for finite-lived intangible assets for the years ended December 31, 2014, 2013 and 2012 was $57 million, $85 million and $90 million, respectively.

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

		December 31, 2014							December 31, 2013
	Estimated Useful			Accumulated							Accumulated
	Lives (Years)	Cost		Amortization			Net		Cost		Amortization			Net
Customer contracts and relationships	1 - 20	$	593	$	(288	)	$	305	$	591	$	(237	)	$	354
Property tax abatement	7 - 13	38		(18		)	20		38		(14		)	24
Other agreements	25 - 70	37		(4		)	33		37		(3		)	34
Emission reduction credits (1)	N/A	8		—			8		8		—			8
		$	676	$	(310	)	$	366	$	674	$	(254	)	$	420

(1)

Emission reduction credits, once surrendered in exchange for environmental permits, are finite-lived.

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

2015	$	52
2016	$	44
2017	$	41
2018	$	36
2019	$	33

Debt

12 Months Ended

Dec. 31, 2014

Debt

Debt

Note 10—Debt

Debt consisted of the following as of the dates indicated (in millions):

	December 31,			December 31,
	2014			2013
SHORT-TERM DEBT
PAA commercial paper notes, bearing a weighted-average interest rate of 0.46% and 0.33%, respectively (1)	$	734		$	1,109
PAA senior notes:
5.25% senior notes due June 2015	150			—
3.95% senior notes due September 2015	400			—
Other	3			4
Total short-term debt	1,287			1,113

LONG-TERM DEBT
PAA senior notes:
5.25% senior notes due June 2015	—			150
3.95% senior notes due September 2015	—			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
2.60% senior notes due December 2019	500			—
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	750			750
2.85% senior notes due January 2023	400			400
3.85% senior notes due October 2023	700			700
3.60% senior notes due November 2024	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	500			500
4.30% senior notes due January 2043	350			350
4.70% senior notes due June 2044	700			—
4.90% senior notes due February 2045	650			—
Unamortized discounts	(18		)	(15		)
PAA senior notes, net of unamortized discounts	8,757			6,710
Other	5			5
Total long-term debt	8,762			6,715
Total debt (2)	$	10,049		$	7,828

(1)

At December 31, 2014 and 2013, we classified all of the borrowings under our commercial paper program as short-term as 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)

Our fixed-rate senior notes (including current maturities) had a face value of approximately $9.3 billion and $6.7 billion as of December 31, 2014 and 2013, respectively. We estimated the aggregate fair value of these notes as of December 31, 2014 and 2013 to be approximately $9.9 billion and $7.2 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 year end. We estimate that the carrying value of outstanding borrowings under our credit facilities and commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, credit facilities and commercial paper program are based upon observable market data and are classified within Level 2 of the fair value hierarchy.

Commercial Paper Program

In August 2013, we established a commercial paper program under which we may issue, from time to time, privately placed, unsecured commercial paper notes. Such notes are backstopped by the PAA senior unsecured revolving credit facility and the PAA senior secured hedged inventory facility; as such, any borrowings under our commercial paper program reduce the available capacity under these facilities. In October 2014, the maximum aggregate borrowing capacity was increased from $1.5 billion to $3.0 billion.

Credit Facilities

PAA senior secured hedged inventory facility. The PAA senior secured hedged inventory facility has a committed borrowing capacity of $1.4 billion, of which $400 million is available for the issuance of letters of credit. Subject to obtaining additional or increased lender commitments, the committed amount of the facility may be increased to $1.9 billion. Proceeds from the facility are primarily used to finance purchased or stored hedged inventory, including NYMEX and ICE margin deposits. Such obligations under the committed facility are secured by the financed inventory and the associated accounts receivable and are repaid from the proceeds of the sale of the financed inventory. Borrowings accrue interest based, at our election, on either the Eurocurrency Rate or the Base Rate, in each case plus a margin based on our credit rating at the applicable time. The agreement also provides for one or more one-year extensions, subject to applicable approval. In August 2014, we extended the maturity date of the facility by one year to August 2017 through the exercise of the option included in the current credit agreement.

PAA senior unsecured revolving credit facility. The PAA senior unsecured revolving credit facility has a committed borrowing capacity of $1.6 billion and contains an accordion feature that enables us to increase the committed capacity to $2.1 billion, subject to obtaining additional or increased lender commitments. The credit agreement also provides for the issuance of letters of credit. Borrowings accrue interest based, at our election, on the Eurocurrency Rate, the Base Rate or the Canadian Prime Rate, in each case plus a margin based on our credit rating at the applicable time. The agreement also provides for one or more one-year extensions, subject to applicable approval. In August 2014, we extended the maturity date of the facility by one year to August 2019 through the exercise of the option included in the current credit agreement.

PAA senior unsecured 364-day revolving credit facility. In January 2015, we entered into a 364-day senior unsecured credit agreement with a borrowing capacity of $1.0 billion. Borrowings will accrue interest based, at our election, on either the Eurocurrency Rate or the Base Rate, in each case plus a margin based on our credit rating at the applicable time. The covenants, restrictions and events of default in the credit agreement are substantially the same as those in the PAA senior unsecured revolving credit facility agreement. See “-Covenants and Compliance” below.

Senior Notes

Our senior notes are co-issued, jointly and severally, by Plains All American Pipeline, L.P. and a 100%-owned consolidated finance subsidiary (neither of which have independent assets or operations) and are unsecured senior obligations of such entities and rank equally in right of payment with existing and future senior indebtedness of the issuers. We may, at our option, redeem any series of senior notes at any time in whole or from time to time in part, prior to maturity, at the redemption prices described in the indentures governing the senior notes. Our senior notes are not guaranteed by any of our subsidiaries.

Senior Notes Issuances

The table below summarizes our issuances of senior unsecured notes during 2014, 2013 and 2012 (in millions):

Year	Description	Maturity	Face Value		Interest Payment Dates
2014	2.60% Senior Notes issued at 99.813% of face value	December 2019	$	500	June 15 and December 15
2014	4.90% Senior Notes issued at 99.876% of face value	February 2045	$	650	February 15 and August 15
2014	3.60% Senior Notes issued at 99.842% of face value	November 2024	$	750	May 1 and November 1
2014	4.70% Senior Notes issued at 99.734% of face value	June 2044	$	700	June 15 and December 15

2013	3.85% Senior Notes issued at 99.792% of face value	October 2023	$	700	April 15 and October 15

2012	2.85% Senior Notes issued at 99.752% of face value	January 2023	$	400	January 31 and July 31
2012	4.30% Senior Notes issued at 99.925% of face value	January 2043	$	350	January 31 and July 31
2012	3.65% Senior Notes issued at 99.823% of face value	June 2022	$	750	June 1 and December 1
2012	5.15% Senior Notes issued at 99.755% of face value	June 2042	$	500	June 1 and December 1

Senior Note Repayments

On December 13, 2013, we repaid our $250 million, 5.63% senior notes. We utilized cash on hand and available capacity under our commercial paper program to repay these notes.

On September 4, 2012, we repaid our $500 million, 4.25% senior notes. We utilized cash on hand and available capacity under our credit facilities to repay these notes.

Maturities

The weighted average life of our senior notes outstanding at December 31, 2014 was approximately 13 years and the aggregate maturities for the next five years and thereafter are as follows (in millions):

Calendar Year	Payment
2015	$	550
2016	175
2017	400
2018	600
2019	850
Thereafter	6,750
Total (1)	$		9,325

(1)

Excludes aggregate unamortized net discount of $18 million.

Covenants and Compliance

Our credit agreements (which impact our ability to access our commercial paper program because they provide the backstop that supports our short-term credit ratings) and the indentures governing our senior notes contain cross-default provisions. Our credit agreements prohibit declaration or payments of distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting our ability to, among other things:

grant liens on certain property;

incur indebtedness, including capital leases;

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

engage in certain transactions with affiliates; and

enter into certain burdensome agreements.

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

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

A default under our credit facilities would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with our credit agreements, our ability to make distributions of available cash is not restricted. As of December 31, 2014, we were in compliance with the covenants contained in our credit agreements and indentures.

Borrowings and Repayments

Total borrowings under our credit agreements and commercial paper program for the years ended December 31, 2014, 2013 and 2012 were approximately $70.9 billion, $31.0 billion and $12.9 billion, respectively. Total repayments under our credit agreements and commercial paper program were approximately $71.3 billion, $31.0 billion and $12.2 billion for the years ended December 31, 2014, 2013 and 2012, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.

Letters of Credit

In connection with our supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil, NGL and natural gas. These letters of credit are issued under the PAA senior unsecured revolving credit facility and the PAA senior secured hedged inventory facility, and our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil, NGL or natural gas is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. Additionally, we issue letters of credit to support insurance programs and construction activities. At December 31, 2014 and 2013, we had outstanding letters of credit of $87 million and $41 million, respectively.

Partners' Capital and Distributions

12 Months Ended

Dec. 31, 2014

Partners' Capital and Distributions

Partners' Capital and Distributions

Note 11—Partners’ Capital and Distributions

Units Outstanding

Partners’ capital at December 31, 2014 consisted of 375,107,793 common units outstanding, representing a 98% effective aggregate ownership interest in the Partnership and its subsidiaries after giving effect to the 2% general partner interest.

Distributions

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

General Partner Distributions. Our general partner is entitled to receive (i) distributions representing its 2% general partner interest and (ii) incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly distribution provisions, the general partner is entitled, without duplication, to 2% of amounts we distribute up to $0.2250 per unit, referred to as our MQD, 15% of amounts we distribute in excess of $0.2250 per unit, 25% of the amounts we distribute in excess of $0.2475 per unit and 50% of amounts we distribute in excess of $0.3375 per unit.

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

	Year
	2014				2013				2012
			Excess				Excess				Excess
	Distribution (1)		over MQD		Distribution (1)		over MQD		Distribution (1)		over MQD
First Quarter	$	0.6150	$	0.3900	$	0.5625	$	0.3375	$	0.5125	$	0.2875
Second Quarter	$	0.6300	$	0.4050	$	0.5750	$	0.3500	$	0.5225	$	0.2975
Third Quarter	$	0.6450	$	0.4200	$	0.5875	$	0.3625	$	0.5325	$	0.3075
Fourth Quarter	$	0.6600	$	0.4350	$	0.6000	$	0.3750	$	0.5425	$	0.3175

(1)

Distributions represent those declared and paid in the applicable period shown.

During the years ended December 31, 2014, 2013 and 2012, our general partner’s incentive distributions were reduced by approximately $23 million, $15 million and $11 million, respectively. These reductions were agreed to in connection with the BP NGL Acquisition and the PNG Merger. In addition, our general partner has agreed to reduce the amount of its incentive distribution by $5.5 million per quarter during 2015, $5.0 million per quarter in 2016 and $3.75 million per quarter thereafter. See Note 3 for further discussion of the BP NGL Acquisition.

Total cash distributions, net of reductions in our general partner’s incentive distributions, paid during the years ended December 31, 2014, 2013 and 2012 were as follows (in millions, except per unit data):

	Distributions Paid								Distributions
	Common		General Partner						per limited
Year	Units		2%		Incentive		Total		partner unit
2014	$	934	$	19	$	454	$	1,407	$	2.55
2013	$	791	$	16	$	353	$	1,160	$	2.33
2012	$	684	$	14	$	271	$	969	$	2.11

On January 8, 2015, we declared a cash distribution of $0.6750 per unit on our outstanding common units. The distribution was paid on February 13, 2015 to unitholders of record on January 30, 2015, for the period October 1, 2014 through December 31, 2014. The total distribution paid was $390 million, with $254 million paid to our common unitholders and $5 million and $131 million paid to our general partner for its 2% general partner and incentive distribution interests, respectively.

PAA Equity Offerings

During 2014, 2013 and 2012, we entered into several equity distribution agreements under our Continuous Offering Program, pursuant to which we may offer and sell, through sales agents, common units representing limited partner interests having aggregate offering prices ranging from $300 million to up to $900 million. Sales of such common units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed upon by our sales agent and us. In addition to our Continuous Offering Program, we may sell common units through overnight or marketed offerings.

The following table summarizes our issuance of common units in connection with marketed offerings and our Continuous Offering Program during the three years ended December 31, 2014 (net proceeds in millions):

Year	Type of Offering	Units Issued	Net Proceeds (1) (2)

2014 Total	Continuous Offering Program	15,375,810	$	866	(3)

2013 Total	Continuous Offering Program	8,644,807	$	477	(3)

2012	Continuous Offering Program	12,063,707	$	524	(3)
2012	Marketed Offering	11,500,000	455		(4)
2012 Total		23,563,707	$	979

(1)

Amounts are net of costs associated with the offerings.

(2)

Amounts include our general partner’s proportionate capital contributions of $18 million, $9 million and $20 million during 2014, 2013 and 2012, respectively.

(3)

We pay commissions to our sales agents in connection with common unit issuances under our Continuous Offering Program. We paid $9 million, $5 million and $6 million of such commissions during 2014, 2013 and 2012, respectively.

(4)

Offering was an underwritten transaction that required us to pay a gross spread. The net proceeds from such offering were used to fund a portion of the BP NGL Acquisition.

Noncontrolling Interests in Subsidiaries

As of December 31, 2014, noncontrolling interests in our subsidiaries consisted of a 25% interest in SLC Pipeline LLC.

PNG Merger

Prior to the PNG Merger, which was completed on December 31, 2013, we owned 100% of the outstanding subordinated units of PNG and approximately 46% of the 61.2 million outstanding common units of PNG. Under the terms of the PNG Merger Agreement, we issued 0.445 PAA common units for each outstanding PNG common unit (the “Merger Exchange Ratio”) held by unitholders other than us, plus cash in lieu of any fractional PAA common units otherwise issuable in the PNG Merger. Also in conjunction with the PNG Merger, our general partner agreed to reduce the amount of its incentive distributions. See the subsection “Distributions” above.

As a result of the PNG Merger, we purchased the noncontrolling interests in PNG for consideration of approximately 14.7 million PAA common units valued at $760 million. Such purchase resulted in an equity-classified loss of $290 million, which we recorded as a decrease to our partners’ capital. In addition, in conjunction with the PNG Merger, our general partner made a proportional contribution of $16 million associated with our issuance of PAA common units and we incurred transaction costs of $4 million resulting in a net increase in partners’ capital associated with the PNG Merger of $12 million.

Issuance of PNG Common Units

PNG issued approximately 1.9 million common units during the year ended December 31, 2013. As a result of PNG’s common unit issuances, we recorded an increase in noncontrolling interest of $32 million and an increase to our partners’ capital of $8 million in 2013. These increases represent the portion of the proceeds attributable to the respective ownership interests in PNG, adjusted for the impact of the dilution of our ownership interest. PNG did not issue any common units during the year ended December 31, 2012.

The following table as required by GAAP sets forth the impact on net income attributable to PAA giving effect to the changes in our ownership interest in PNG during 2013 discussed above, which was recognized in partners’ capital (in millions):

	Year Ended
	December 31, 2013
Net income attributable to PAA	$	1,361
Transfers to/from noncontrolling interests:
Increase in capital from sale of PNG common units	8
Decrease in capital from purchase of PNG common units in conjunction with the PNG Merger	(290		)
Net transfers to/from noncontrolling interests	(282		)
Change from net income attributable to PAA and transfers to/from noncontrolling interests	$	1,079

Derivatives and Risk Management Activities

12 Months Ended

Dec. 31, 2014

Derivatives and Risk Management Activities

Derivatives and Risk Management Activities

Note 12—Derivatives and Risk Management Activities

We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on hydrocarbon commodity (referred to herein as “commodity”) price changes. We use various derivative instruments to (i) manage our exposure to commodity price risk, as well as to optimize our profits, (ii) manage our exposure to interest rate risk and (iii) manage our exposure to currency exchange rate risk. Our commodity risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in a transaction are highly effective in offsetting changes in cash flows or the fair value of hedged items.

Commodity Price Risk Hedging

Our core business activities involve certain commodity price-related risks that we manage in various ways, including through the use of derivative instruments. Our policy is to (i) only purchase inventory for which we have a market, (ii) structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold physical inventory or derivatives for the purpose of speculating on commodity price changes. The material commodity-related risks inherent in our business activities can be divided into the following general categories:

Commodity Purchases and Sales — In the normal course of our operations, we purchase and sell commodities. We use derivatives to manage the associated risks and to optimize profits. As of December 31, 2014, net derivative positions related to these activities included:

An average of 269,400 barrels per day net long position (total of 8.4 million barrels) associated with our crude oil purchases, which was unwound ratably during January 2015 to match monthly average pricing.

A net short time spread position averaging approximately 20,500 barrels per day (total of 10.0 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through June 2016.

An average of 33,600 barrels per day (total of 11.2 million barrels) of crude oil grade spread positions through December 2015. These derivatives allow us to lock in grade basis differentials.

A net short position of approximately 28.1 Bcf through April 2016 related to anticipated sales of natural gas inventory and base gas requirements.

A net short position of approximately 9.3 million barrels through March 2017 related to the anticipated sales of our crude oil, NGL and refined products inventory.

A long position of 32,400 barrels per day (total of 1.0 million barrels) through February 2015 related to anticipated crude oil linefill requirements.

Pipeline Loss Allowance Oil — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to offset losses due to evaporation, measurement and other losses in transit. We utilize derivative instruments to hedge a portion of the anticipated sales of the allowance oil that is to be collected under our tariffs. As of December 31, 2014, our PLA hedges included a net short position for an average of approximately 1,300 barrels per day (total of 0.4 million barrels) through December 2015 and a long call position of approximately 0.8 million barrels through December 2016.

Natural Gas Processing/NGL Fractionation — We purchase natural gas for processing and operational needs. Additionally, we purchase NGL mix for fractionation and sell the resulting individual specification products (including ethane, propane, butane and condensate). In conjunction with these activities, we hedge the price risk associated with the purchase of the natural gas and the subsequent sale of the individual specification products. As of December 31, 2014, we had a long natural gas position of approximately 26.1 Bcf through December 2016, a short propane position of approximately 4.1 million barrels through December 2016, a short butane position of approximately 1.2 million barrels through December 2016 and a short WTI position of approximately 0.4 million barrels through December 2016. In addition, we had a long power position of 0.4 million megawatt hours which hedges a portion of our power supply requirements at our natural gas processing and fractionation plants through December 2016.

To the extent they qualify and we decide to make the election, all of our commodity derivatives for which we elect hedge accounting are designated as cash flow hedges. Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchases and normal sales scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings.We have determined that substantially all of our physical purchase and sale agreements qualify for the normal purchases and normal sales scope exception.

Interest Rate Risk Hedging

We use interest rate derivatives to hedge interest rate risk associated with anticipated debt issuances and outstanding debt instruments. The derivative instruments we use to manage this risk consist primarily of interest rate swaps and treasury locks. As of December 31, 2014, AOCI includes deferred losses of $161 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 loss related to these instruments is being amortized to interest expense over the terms of the hedged debt instruments.

We have entered into forward starting interest rate swaps to hedge the underlying benchmark interest rate related to forecasted debt issuances through 2018. The following table summarizes the terms of our forward starting interest rate swaps as of December 31, 2014 (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

10 forward starting swaps (30-year)

250

6/15/2015

3.60%

Cash flow hedge

Anticipated debt offering

8 forward starting swaps (30-year)

200

6/15/2016

3.06%

Cash flow hedge

Anticipated debt offering

8 forward starting swaps (30-year)

200

6/15/2017

3.14%

Cash flow hedge

Anticipated debt offering

8 forward starting swaps (30-year)

200

6/15/2018

3.20%

Cash flow hedge

Additionally, we entered into eight forward starting interest rate swaps in January 2015 with an aggregate notional amount of $200 million, locking in a weighted average interest rate of 2.83% for an anticipated debt offering. The expected termination date on these swaps is June 14, 2019.

The following table summarizes activity related to terminated interest rate derivatives (all of which were designated as cash flow hedges) for the years ended December 31, 2014, 2013 and 2012 (notional amounts and cash received/(paid) in millions):

Hedged Transaction	Number and Types of Derivatives Terminated	Notional Amount		Cash Received/(Paid)			Average Rate Locked
April 2014 senior note issuance	5 treasury lock agreements	$	250	$	(7	)	3.62%
August 2013 senior note issuance (1)	5 forward starting swaps (30-year)	$	125	$	11		3.39%
December 2012 senior note issuance	6 forward starting swaps (30-year)	$	250	$	(89	)	4.24%
March 2012 senior note issuance (2)	4 forward starting swaps (10-year)	$	200	$	(24	)	3.46%

(1)

A gain of approximately $3 million was immediately recognized in interest expense attributable to the ineffective portion of these swaps upon termination.

(2)

A loss of approximately $1 million was immediately recognized in interest expense attributable to the ineffective portion of these swaps upon termination.

Currency Exchange Rate Risk Hedging

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

As of December 31, 2014, our outstanding foreign currency derivatives include derivatives we use to (i) hedge currency exchange risk associated with USD-denominated commodity purchases and sales in Canada and (ii) hedge currency exchange risk created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales.

The following table summarizes our open forward exchange contracts as of December 31, 2014 (in millions):

		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2015	$	460	$	535	$1.00 - $1.16

Forward exchange contracts that exchange USD for CAD:
	2015	$	345	$	387	$1.00 - $1.12

Summary of Financial Impact

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

A summary of the impact of our derivative activities recognized in earnings for the years ended December 31, 2014, 2013 and 2012 is as follows (in millions):

	Year Ended December 31, 2014
	Derivatives in Hedging Relationships
Location of gain/(loss)	Gain/(loss) reclassified from AOCI into income (1) (2)			Other gain/(loss) recognized in income		Derivatives Not Designated as a Hedge			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	(1	)	$	—	$	206		$	205

Field operating costs	—			—		(21		)	(21		)

Interest Rate Derivatives

Interest expense	(5		)	—		—			(5		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			—		(28		)	(28		)

Other income/(expense), net	2			—		—			2

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(4	)	$	—	$	157		$	153

	Year Ended December 31, 2013
	Derivatives in Hedging Relationships
Location of gain/(loss)	Gain/(loss) reclassified from AOCI into income (1)			Other gain/(loss) recognized in income			Derivatives Not Designated as a Hedge			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	78		$	(1	)	$	(116	)	$	(39	)

Facilities segment revenues	(10		)	(1		)	—			(11		)

Field operating costs	—			—			8			8

Interest Rate Derivatives

Interest expense	(7		)	3			—			(4		)

Foreign Currency Derivatives

Other income/(expense), net	5			—			—			5

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	66		$	1		$	(108	)	$	(41	)

	Year Ended December 31, 2012
	Derivatives in Hedging Relationships
Location of gain/(loss)	Gain/(loss) reclassified from AOCI into income (1)			Other gain/(loss) recognized in income			Derivatives Not Designated as a Hedge			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	12		$	—		$	60		$	72

Facilities segment revenues	3			(1		)	1			3

Purchases and related costs	45			—			1			46

Field operating costs	—			—			1			1

Interest Rate Derivatives

Interest expense	(4		)	1			—			(3		)

Foreign Currency Derivatives

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

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

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	62		$	—		$	62		$	124

(1)

During the years ended December 31, 2014 and 2012, all of our hedged transactions were probable of occurring. During the year ended December 31, 2013, we reclassified gains of $3 million and losses of $1 million from AOCI to Supply and Logistics segment revenues and Facilities segment revenues, respectively, as a result of anticipated hedged transactions that were probable of not occurring.

(2)

During the year ended December 31, 2014 we reclassified gains of $7 million from AOCI to Supply and Logistics segment revenues associated with inventory valuation adjustments on the related hedged inventory.

The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2014 (in millions):

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	23	Other current assets	$	(12	)
	Other long-term assets	8		Other long-term assets	(1		)
Interest rate derivatives				Other current liabilities	(44		)
				Other long-term liabilities	(26		)
Total derivatives designated as hedging instruments		$	31		$	(83	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	439	Other current assets	$	(246	)
	Other long-term assets	23		Other long-term assets	(3		)
				Other current liabilities	(35		)
				Other long-term liabilities	(5		)
Foreign currency derivatives				Other current liabilities	(12		)
Total derivatives not designated as hedging instruments		$	462		$	(301	)

Total derivatives		$	493		$	(384	)

The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2013 (in millions):

	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	36	Other current assets	$	(24	)
	Other long-term assets	5
Interest rate derivatives	Other long-term assets	26
Total derivatives designated as hedging instruments		$	67		$	(24	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	60	Other current assets	$	(117	)
	Other long-term assets	5		Other long-term assets	(6		)
	Other current liabilities	1		Other current liabilities	(5		)
				Other long-term liabilities	(1		)
Foreign currency derivatives				Other current liabilities	(4		)
Total derivatives not designated as hedging instruments		$	66		$	(133	)

Total derivatives		$	133		$	(157	)

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

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through clearing brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of December 31, 2014, we had a net broker payable of $133 million (consisting of initial margin of $126 million reduced by $259 million of variation margin that had been returned to us). As of December 31, 2013, we had a net broker receivable of $161 million (consisting of initial margin of $85 million increased by $76 million of variation margin that had been posted by us).

The following tables present information about derivatives and financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements as of the dates indicated (in millions):

	December 31, 2014						December 31, 2013
	Derivative			Derivative			Derivative			Derivative
	Asset Positions			Liability Positions			Asset Positions			Liability Positions
Netting Adjustments:
Gross position - asset/(liability)	$	493		$	(384	)	$	133		$	(157	)
Netting adjustment	(262		)	262			(148		)	148
Cash collateral paid/(received)	(133		)	—			161			—
Net position - asset/(liability)	$	98		$	(122	)	$	146		$	(9	)

Balance Sheet Location After Netting Adjustments:
Other current assets	$	71		$	—		$	116		$	—
Other long-term assets	27			—			30			—
Other current liabilities	—			(91		)	—			(8		)
Other long-term liabilities	—			(31		)	—			(1		)
	$	98		$	(122	)	$	146		$	(9	)

As of December 31, 2014, there was a net loss of $159 million deferred in AOCI including tax effects. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the earnings recognition of the underlying hedged commodity transaction or (ii) interest expense accruals associated with underlying debt instruments. Of the total net loss deferred in AOCI at December 31, 2014, we expect to reclassify a net gain of $14 million to earnings in the next twelve months. The remaining deferred loss of $173 million is expected to be reclassified to earnings through 2048. A portion of these amounts are based on market prices as of December 31, 2014; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

The net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives for the three years ended December 31, 2014 are as follows (in millions):

	Year Ended December 31,
	2014			2013		2012
Commodity derivatives, net	$	15		$	37	$	56
Interest rate derivatives, net	(103		)	72		(12		)
Foreign currency derivatives, net	2			—		—
Total	$	(86	)	$	109	$	44

At December 31, 2014 and December 31, 2013, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our cleared derivatives as described above, we do not require our non-cleared derivative counterparties to post collateral with us.

Recurring Fair Value Measurements

Derivative Financial Assets and Liabilities

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and December 31, 2013 (in millions):

	Fair Value as of December 31, 2014											Fair Value as of December 31, 2013
Recurring Fair Value Measures (1)	Level 1			Level 2			Level 3		Total			Level 1		Level 2			Level 3			Total
Commodity derivatives	$	(85	)	$	261		$	15	$	191		$	16	$	(59	)	$	(3	)	$	(46	)
Interest rate derivatives	—			(70		)	—		(70		)	—		26			—			26
Foreign currency derivatives	—			(12		)	—		(12		)	—		(4		)	—			(4		)
Total net derivative asset/(liability)	$	(85	)	$	179		$	15	$	109		$	16	$	(37	)	$	(3	)	$	(24	)

(1)

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

Level 1

Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives such as futures and options. The fair value of exchange-traded commodity derivatives is based on unadjusted quoted prices in active markets.

Level 2

Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives and over-the-counter commodity, interest rate and foreign currency derivatives that are traded in active markets. In addition, it includes certain physical commodity contracts. The fair value of these derivatives is based on broker price quotations which are corroborated with market observable inputs.

Level 3

Level 3 of the fair value hierarchy includes certain physical commodity contracts. The fair value of our Level 3 physical commodity contracts is based on a valuation model utilizing broker-quoted forward commodity prices, and timing estimates, which involve management judgment. The significant unobservable inputs used in the fair value measurement of our Level 3 derivatives are forward prices obtained from brokers. A significant increase or decrease in these forward prices could result in a material change in fair value to our Level 3 derivatives.

Rollforward of Level 3 Net Asset/(Liability)

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

	Year Ended December 31,
	2014			2013
Beginning Balance	$	(3	)	$	4
Total gains/(losses) for the period:
Included in earnings (1)	—			(1		)
Included in other comprehensive income	—			—
Settlements	3			(3		)
Derivatives entered into during the period	15			(3		)
Transfers out of Level 3	—			—
Ending Balance	$	15		$	(3	)

Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the periods	$	15		$	(4	)

(1)

We reported unrealized gains and losses associated with Level 3 commodity derivatives in our Consolidated Statements of Operations as Supply and Logistics segment revenues.

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Income Taxes

12 Months Ended

Dec. 31, 2014

Income Taxes

Income Taxes

Note 13—Income Taxes

Income tax expense is estimated using the tax rate in effect or to be in effect during the relevant periods in the jurisdictions in which we operate. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes and are stated at enacted tax rates expected to be in effect when taxes are actually paid or recovered. To the extent we do not consider it more likely than not that a deferred tax asset will be recovered, a valuation allowance is established. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. We review contingent tax liabilities for estimated exposures on a more likely than not standard related to our current tax positions.

Pursuant to FASB guidance related to accounting for uncertainty in income taxes, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and precedents of the taxing authority. As of December 31, 2014 and 2013, we had not recognized any material amounts in connection with uncertainty in income taxes.

U.S. Federal and State Taxes

As an MLP, we are not subject to U.S. federal income taxes; rather the tax effect of our operations is passed through to our unitholders. Although we are subject to state income taxes in some states, the impact to the years ended December 31, 2014, 2013, and 2012 was immaterial.

Canadian Federal and Provincial Taxes

All of our Canadian operations are conducted within entities that are treated as corporations for Canadian tax purposes (flow through for U.S. tax purposes) and that are subject to Canadian federal and provincial taxes. Additionally, payments of interest and dividends from our Canadian entities to other Plains entities are subject to Canadian withholding tax that is treated as income tax expense.

Tax Components

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

	Year Ended December 31,
	2014		2013			2012
Current tax expense:
State income tax	$	1	$	1		$	2
Canadian federal and provincial income tax	70		99			51
Total current tax expense	$	71	$	100		$	53

Deferred tax (benefit)/expense:
Canadian federal and provincial income tax	$	100	$	(1	)	$	1
Total deferred tax (benefit)/expense	$	100	$	(1	)	$	1
Total income tax expense	$	171	$	99		$	54

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

	Year Ended December 31,
	2014			2013			2012
Income before tax	$	1,557		$	1,490		$	1,181
Partnership earnings not subject to current Canadian tax	(976		)	(1,187		)	(1,046		)
	$	581		$	303		$	135
Canadian federal and provincial corporate tax rate	25		%	25		%	25		%
Income tax at statutory rate	$	145		$	76		$	34

Canadian withholding tax	$	16		$	19		$	18
Canadian permanent differences and rate changes	9			3			—
State income tax	1			1			2
Total income tax expense	$	171		$	99		$	54

Deferred tax assets and liabilities are aggregated by the applicable tax paying entity and jurisdiction and result from the following (in millions):

	December 31,
	2014			2013
Deferred tax assets:
Book accruals in excess of current tax deductions	$	29		$	41
Net operating losses	2			—
Derivative instruments	—			15
Total deferred tax assets	31			56

Deferred tax liabilities:
Derivative instruments	(71		)	—
Property and equipment in excess of tax values	(322		)	(332		)
Other	(49		)	(66		)
Total deferred tax liabilities	(442		)	(398		)
Net deferred tax assets / (liabilities)	$	(411	)	$	(342	)

Balance sheet classification of deferred tax assets / (liabilities):
Other, net	$	2		$	—
Other current liabilities	(64		)	—
Other long-term liabilities and deferred credits	(349		)	(342		)
	$	(411	)	$	(342	)

As of December 31, 2014, we had foreign net operating loss carryforwards of $8 million, which will expire in 2034.

Generally, tax returns for our Canadian entities are open to audit from 2008 through 2014. Our U.S. and state tax years are generally open to examination from 2011 to 2014.

Major Customers and Concentration of Credit Risk	12 Months Ended
Major Customers and Concentration of Credit Risk	Dec. 31, 2014
Major Customers and Concentration of Credit Risk
Major Customers and Concentration of Credit Risk	Note 14—Major Customers and Concentration of Credit Risk Marathon Petroleum Corporation and its subsidiaries accounted for approximately 17%, 15% and 16% of our revenues for the years ended December 31, 2014, 2013 and 2012, respectively. ExxonMobil Corporation and its subsidiaries accounted for approximately 15% of our revenues for the year ended December 31, 2014 and approximately 13% of our revenues for each of the years ended December 31, 2013 and 2012. Phillips 66 and its subsidiaries accounted for approximately 11% of our revenues for the year ended December 31, 2013. No other customers accounted for 10% or more of our revenues during any of the three years ended December 31, 2014. The majority of revenues from these customers pertain to our supply and logistics operations. The sales to these customers occur at multiple locations and we believe that the loss of these customers would have only a short-term impact on our operating results. There is risk, however, that we would not be able to identify and access a replacement market at comparable margins. Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas storage. This industry concentration has the potential to impact our overall exposure to credit risk in that the customers may be similarly affected by changes in economic, industry or other conditions. We review credit exposure and financial information of our counterparties and generally require letters of credit for receivables from customers that are not considered creditworthy, unless the credit risk can otherwise be reduced. See Note 2 for additional discussion of our accounts receivable and our review of credit exposure.

Related Party Transactions

12 Months Ended

Dec. 31, 2014

Related Party Transactions

Related Party Transactions

Note 15—Related Party Transactions

Reimbursement of Expenses of Our General Partner and its Affiliates

We do not pay our general partner a management fee, but we do reimburse our general partner for all direct and indirect costs of services provided to us or incurred on our behalf, including the costs of employee, officer and director compensation and benefits allocable to us as well as all other expenses necessary or appropriate to the conduct of our business (other than expenses related to grants of AAP Management Units). We record these costs on the accrual basis in the period in which our general partner incurs them. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Total costs reimbursed by us to our general partner for the years ended December 31, 2014, 2013 and 2012 were $598 million, $567 million and $535 million, respectively.

Transactions with Oxy

On November 14, 2014, we purchased Oxy’s 50% interest in BridgeTex. See Note 8 for further discussion. Also on November 14, 2014, Oxy exchanged a portion of its interest in our general partner for Class A shares of PAGP and immediately sold such shares through a secondary public offering completed by PAGP. As of December 31, 2014, Oxy owned approximately 13.2% of the limited partner interests in our general partner and had a representative on the board of directors of GP LLC.

During the three years ended December 31, 2014, we recognized sales and transportation revenues and purchased petroleum products from Oxy. These transactions were conducted at posted tariff rates or prices that we believe approximate market. See detail below (in millions):

	Year Ended December 31,
	2014		2013		2012
Revenues	$	1,212	$	1,309	$	1,636

Purchases and related costs	$	925	$	863	$	557

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

	December 31,
	2014		2013
Trade accounts receivable and other receivables	$	489	$	133

Accounts payable	$	441	$	181

Transactions with Equity Method Investees

We also have transactions with companies in which we hold an investment accounted for under the equity method of accounting (see Note 8 for information related to these investments). We recorded revenues of $3 million, $33 million and $18 million during the years ended December 31, 2014, 2013 and 2012, respectively. The revenues for the years ended December 31, 2013 and 2012 were primarily associated with sales of crude oil to Eagle Ford Pipeline LLC for its linefill requirements. These sales did not result in any gain for us. During the three years ended December 31, 2014, we utilized transportation services and purchased petroleum products provided by these companies. Costs related to these services totaled $75 million, $79 million and $42 million for the years ended December 31, 2014, 2013 and 2012, respectively. These transactions were conducted at posted tariff rates or contracted rates or prices that we believe approximate market. Receivables from our equity method investees totaled less than $1 million at December 31, 2014 and $2 million at December 31, 2013. Accounts payable to our equity method investees were $6 million at both December 31, 2014 and December 31, 2013.

In 2014, we sold land to Eagle Ford Pipeline LLC for proceeds of $25 million. Such proceeds are included in “Proceeds from sales of assets” on our Consolidated Statement of Cash Flows. We did not recognize any gain in connection with this transaction.

- Definition

The entire disclosure for related party transactions. 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 + Details

Equity-Indexed Compensation Plans

12 Months Ended

Dec. 31, 2014

Equity-Indexed Compensation Plans

Equity-Indexed Compensation Plans

Note 16—Equity-Indexed Compensation Plans

PAA Long-Term Incentive Plan Awards

Plains All American 2013 Long-Term Incentive Plan. In November 2013, our common unitholders approved the Plains All American 2013 Long-Term Incentive Plan (the “PAA 2013 LTIP”), which consolidated our three previous long-term incentive plans (the Plains All American GP LLC 1998 Long-Term Incentive Plan, as amended, the Plains All American 2005 Long-Term Incentive Plan, as amended, and the Plains All American PPX Successor Long-Term Incentive Plan, as amended) into a single plan. The PAA 2013 LTIP authorizes the issuance of an aggregate of approximately 13.1 million PAA common units deliverable upon vesting. Although other types of awards are contemplated under the PAA 2013 LTIP, currently outstanding awards are limited to “phantom units,” which mature into the right to receive common units of PAA (or cash equivalent) upon vesting. Some awards also include DERs, which, subject to applicable vesting criteria, entitle the grantee to a cash payment equal to the cash distribution paid on an outstanding PAA common unit.

Plains All American PNG Successor Long-Term Incentive Plan. In conjunction with the PNG Merger on December 31, 2013, our general partner adopted and assumed the PAA Natural Gas Storage, L.P. 2010 Long-Term Incentive Plan (the “PNG 2010 LTIP”) and changed the plan name to the Plains All American PNG Successor Long-Term Incentive Plan (the “PNG Successor LTIP”). Additionally, as a result of the PNG Merger, outstanding awards of PNG phantom units issued under the PNG 2010 LTIP were converted into comparable awards of phantom units representing the right to receive PAA common units by applying the Merger Exchange Ratio to each outstanding phantom unit and rounding down to the nearest PAA phantom unit for any fractions. See Note 10 for further discussion of the PNG Merger. The PNG Successor LTIP authorizes the issuance of an aggregate of 1.3 million PAA common units deliverable upon vesting. Although other types of awards are contemplated under the PNG Successor LTIP, currently outstanding awards are limited to “phantom units,” which mature into the right to receive common units of PAA (or cash equivalent) upon vesting. Some awards also include DERs, which, subject to applicable vesting criteria, entitle the grantee to a cash payment equal to the cash distribution paid on an outstanding PAA common unit.

Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan. Our general partner has adopted the Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan (the “2006 Plan”) for non-officer employees. The 2006 Plan authorizes the grant of approximately 4.2 million “tracking units” which, upon vesting, represent the right to receive a cash payment in an amount based upon the market value of a PAA common unit at the time of vesting.

Our general partner is entitled to reimbursement by us for any costs incurred in settling obligations under the PAA 2013 LTIP, the PNG Successor LTIP or the 2006 Plan.

At December 31, 2014, the following LTIP awards, denominated in PAA units, were outstanding (units in millions):

PAA LTIP Units	PAA Distribution	Estimated Unit Vesting Date
Outstanding (1) (2)	Required (3)	2015	2016	2017	2018	Thereafter
7.3	$2.075-$3.200	2.1	2.1	1.8	1.2	0.1

(1)

Approximately 3.5 million of the 7.3 million outstanding PAA LTIP awards also include DERs, of which 3.2 million had vested as of December 31, 2014.

(2)

LTIP units outstanding do not include AAP Management Units.

(3)

These LTIP awards have performance conditions requiring the attainment of an annualized PAA distribution of between $2.075 and $3.20 and vest upon the later of a certain date or the attainment of such levels. If the performance conditions are not attained while the grantee remains employed by us, or the grantee does not meet employment requirements, these awards will be forfeited. For purposes of this disclosure, vesting dates are based on an estimate of future distribution levels and assume that all grantees remain employed by us through the vesting date.

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

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

Our accrued liability at December 31, 2014 related to all outstanding liability-classified LTIP awards and DERs was $101 million, of which $57 million was classified as short-term and $44 million was classified as long-term. These short- and long-term accrued LTIP liabilities are reflected in “Accounts payable and accrued liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Consolidated Balance Sheet. These liabilities include accruals associated with our assessments that an annualized distribution of $2.90 was probable of occurring. At December 31, 2013, the accrued liability was $98 million, of which $43 million was classified as short-term and $55 million was classified as long-term.

Activity for LTIP awards under our equity-indexed compensation plans denominated in PAA and PNG units is summarized in the following table (units in millions):

	PAA Units (1) (3)				PNG Units (2) (4)
			Weighted Average				Weighted Average
			Grant Date				Grant Date
	Units		Fair Value per Unit		Units		Fair Value per Unit
Outstanding at December 31, 2011	8.0		$	21.77	0.8		$	20.55
Granted	1.5		$	33.90	0.1		$	15.33
Vested	(3.2	)	$	19.82	—		$	23.64
Cancelled or forfeited	(0.3	)	$	29.36	—		$	—
Outstanding at December 31, 2012	6.0		$	25.55	0.9		$	17.49
Granted	4.1		$	47.60	0.4		$	17.51
Vested	(1.8	)	$	24.79	—		$	18.88
Cancelled or forfeited (5)	(0.3	)	$	36.70	(0.3	)	$	21.62
Conversion of PNG unit-denominated awards into PAA unit-denominated awards (6)	0.4		$	40.54	(1.0	)	$	16.41
Outstanding at December 31, 2013	8.4		$	36.97	—		$	—
Granted	1.2		$	47.68
Vested	(1.9	)	$	25.49
Cancelled or forfeited	(0.4	)	$	40.14
Outstanding at December 31, 2014	7.3		$	41.21

(1)

Amounts do not include AAP Management Units.

(2)

Amounts include PNG Transaction Grants, which are discussed further below.

(3)

Approximately 0.6 million, 0.5 million and 1.0 million PAA common units were issued net of tax withholding of approximately 0.3 million, 0.3 million and 0.5 million units in 2014, 2013 and 2012, respectively, in connection with the settlement of vested awards. The remaining PAA awards (approximately 1.0 million, 1.0 million and 1.7 million units) that vested during 2014, 2013 and 2012, respectively, were settled in cash.

(4)

Less than 0.1 million PNG units vested during each of the years ended December 31, 2013 and 2012.

(5)

As a result of the PNG Merger on December 31, 2013, approximately 0.3 million outstanding PNG Transaction Grants were cancelled.

(6)

As a result of the PNG Merger on December 31, 2013, outstanding awards of PNG phantom units were converted into comparable awards of PAA phantom units representing the right to receive PAA common units by applying the Merger Exchange Ratio to each outstanding PNG phantom unit and rounding down to the nearest PAA phantom unit for any fractions.

PNG Transaction Grants

In connection with the IPO of PNG in 2010, we created a plan based on PNG equity. In September 2010, we entered into agreements with certain of our officers, pursuant to which these officers acquired, in equal proportion, phantom common units, phantom series A subordinated units, and phantom series B subordinated units representing a portion of the limited partner interest of PNG issued to us in connection with PNG’s IPO. The phantom common units vested in equal one-half increments in May 2011 and May 2012. The unvested portion of these grants were surrendered on December 31, 2013 in connection with the closing of the PNG Merger.

AAP Management Units

In August 2007, the owners of our general partner authorized the issuance of AAP Management Units in order to provide additional performance incentives and encourage retention for certain members of our senior management. AAP Management Units become earned in various increments upon the achievement of annualized PAA distribution levels of between $1.75 and $3.10 (or in some cases, within 180 days thereafter). As of December 31, 2014, 1.3 million AAP Management Units had not yet become earned; however, these unearned AAP Management Units will become earned in various increments 180 days after the achievement of annualized PAA distribution levels of between $2.55 and $3.10. When earned, the AAP Management Units are entitled to participate in distributions paid by our general partner in excess of $11 million (as adjusted for debt service costs and excluding special distributions funded by debt) per quarter. Up to approximately 52.1 million AAP Management Units are authorized for issuance. Assuming all 52.1 million AAP Management Units were granted and earned, the maximum participation would be approximately 8% of our general partner’s distribution in excess of $11 million (as adjusted) each quarter.

The following is a summary of activity of AAP Management Units for the periods indicated (in millions):

	Reserved for Future Grants		Outstanding	Outstanding Units Earned	Grant Date Fair Value of Outstanding AAP Management Units (1)
Balance as of December 31, 2012	4.7		47.4	34.0	$	44
Granted	(1.2	)	1.2	—	7
Earned	N/A		N/A	13.0	N/A
Balance as of December 31, 2013	3.5		48.6	47.0	$	51
Granted	(0.5	)	0.5	—	13
Earned	N/A		N/A	0.8	N/A
Balance as of December 31, 2014	3.0		49.1	47.8	$	64

(1)

Of the $64 million grant date fair value, $55 million had been recognized through December 31, 2014 on a cumulative basis. Of this amount, $7 million, $5 million and $6 million was recognized as expense during the years ended December 31, 2014, 2013 and 2012, respectively.

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

Other Consolidated Equity-Indexed Compensation Plan Information

We refer to all of the LTIPs and AAP Management Units collectively as the “Equity-indexed compensation plans.” The table below summarizes the expense recognized and the value of vested LTIPs (settled both in common units and cash) under our equity-indexed compensation plans and includes both liability-classified and equity-classified awards (in millions):

	Year Ended December 31,
	2014		2013		2012
Equity-indexed compensation expense	$	98	$	116	$	101
LTIP unit-settled vestings (1)	$	53	$	48	$	62
LTIP cash-settled vestings	$	53	$	61	$	66
DER cash payments	$	8	$	8	$	7

(1)

For the years ended December 31, 2013 and 2012, less than $1 million and $1 million, respectively, relates to unit vestings which were settled with PNG common units.

Based on the December 31, 2014 fair value measurement and probability assessment regarding future distributions, we expect to recognize $144 million of additional expense over the life of our outstanding awards related to the remaining unrecognized fair value. Actual amounts may differ materially as a result of a change in the market price of our units and/or probability assessments regarding future distributions. We estimate that the remaining fair value will be recognized in expense as shown below (in millions):

Year	Equity-Indexed Compensation Plan Fair Value Amortization (1) (2)
2015	$	70
2016	46
2017	21
2018	6
2019	1
Thereafter	—
Total	$	144

(1)

Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at December 31, 2014.

(2)

Includes unamortized fair value associated with AAP Management Units.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies.

Commitments and Contingencies

Note 17—Commitments and Contingencies

Commitments

Lease expense for 2014, 2013 and 2012 was $145 million, $132 million and $102 million, respectively. We have commitments, some of which are leases, related to real property, equipment and operating facilities. We also incur costs associated with leased land, rights-of-way, permits and regulatory fees. Future non-cancelable commitments related to these items at December 31, 2014, are summarized below (in millions):

	2015		2016		2017		2018		2019		Thereafter		Total
Leases (1)	$	162	$	151	$	127	$	102	$	78	$	373	$	993
Other commitments (2)	62		62		49		38		27		90		328
Total	$	224	$	213	$	176	$	140	$	105	$	463	$	1,321

(1)

Includes capital and operating leases as defined by FASB guidance.

(2)

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

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 material adverse effect on our financial condition, results of operations or cash flows. Although we believe that our operations are presently in material compliance with applicable requirements, as we acquire and incorporate additional assets it is possible that the EPA or other governmental entities may seek to impose fines, penalties or performance obligations on us (or on a portion of our operations) as a result of any past noncompliance whether such noncompliance initially developed before or after our acquisition.

Environmental

General. Although we believe that our efforts to enhance our leak prevention and detection capabilities have produced positive results, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail and storage operations. These releases can result from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. Whether current or past, damages and liabilities associated with any such releases from our assets may substantially affect our business.

We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. We record receivables for amounts recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery.

Environmental expenditures that pertain to current operations or to future revenues are expensed or capitalized consistent with our capitalization policy for property and equipment. Expenditures that result from the remediation of an existing condition caused by past operations and that do not contribute to current or future profitability are expensed.

At December 31, 2014, our estimated undiscounted reserve for environmental liabilities totaled $82 million, of which $13 million was classified as short-term and $69 million was classified as long-term. At December 31, 2013, our estimated undiscounted reserve for environmental liabilities totaled $93 million, of which $11 million was classified as short-term and $82 million was classified as long-term. The short- and long-term environmental liabilities referenced above are reflected in “Accounts payable and accrued liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Consolidated Balance Sheets. At December 31, 2014 and 2013, we had recorded receivables totaling $8 million and $10 million, respectively, for amounts probable of recovery under insurance and from third parties under indemnification agreements, which are predominantly reflected in “Trade accounts receivable and other receivables, net” on our Consolidated Balance Sheets.

In some cases, the actual cash expenditures may not occur for three years or longer. Our estimates used in these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing legal claims giving rise to additional liabilities. Therefore, although we believe that the reserve is adequate, costs incurred may be in excess of the reserve and may potentially have a material adverse effect on our financial condition, results of operations or cash flows.

Bay Springs Pipeline Release. During February 2013, we experienced a crude oil release of approximately 120 barrels on a portion of one of our pipelines near Bay Springs, Mississippi. Most of the released crude oil was contained within our pipeline right of way, but some of the released crude oil entered a nearby waterway where it was contained with booms. The EPA has issued an administrative order requiring us to take various actions in response to the release, including remediation, reporting and other actions. We have satisfied the requirements of the administrative order; however, we may be subjected to a civil penalty. The aggregate cost to clean up and remediate the site was approximately $6 million.

Kemp River Pipeline Releases. During May and June 2013, two separate releases were discovered on our Kemp River pipeline in Northern Alberta, Canada that, in the aggregate, resulted in the release of approximately 700 barrels of condensate and light crude oil. Clean-up and remediation activities are being conducted in cooperation with the applicable regulatory agencies. Final investigation by the Alberta Energy Regulator is not complete. To date, no charges, fines or penalties have been assessed against PMC with respect to these releases; however, it is possible that fines or penalties may be assessed against PMC in the future. We estimate that the aggregate clean-up and remediation costs associated with these releases will be approximately $15 million. Through December 31, 2014, we spent approximately $9 million in connection with clean-up and remediation activities.

National Energy Board Audit. In the third quarter of 2014, the National Energy Board (“NEB”) of Canada notified PMC that various corrective actions from a 2010 audit had not been completed to the satisfaction of the NEB. The NEB initiated a process to assess PMC’s approach to compliance with the NEB’s Onshore Pipeline Regulations, which process resulted in the issuance by the NEB of an order on January 15, 2015 that imposed six conditions on PMC designed to enhance PMC’s ability to operate its pipelines in a manner that protects the public and the environment. The conditions include the filing of certain safety critical tasks, controls and programs with the NEB, external audits of certain PMC programs and systems, and periodic update meetings with NEB staff regarding the status and progress of corrective actions. In early February 2015, the NEB imposed a penalty on PMC of $76,000 CAD related to these issues. It is possible that additional fines and penalties may be assessed against PMC in the future related to this matter.

Environmental Remediation

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

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

Assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified. We have in the past experienced and in the future likely will experience releases of crude oil into the environment from our pipeline and storage operations. We also may discover environmental impacts from past releases that were previously unidentified.

Insurance

A pipeline, terminal or other facility may experience damage as a result of an accident, natural disaster or terrorist activity. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain various types of insurance 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 third-party liability and property damage 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, costs have increased substantially and deductibles have increased as well.

Our assessment of the current availability of coverage and associated rates for hurricane insurance has led us to the decision to 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 maintained at our historic coverage 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.

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Data (Unaudited)

Quarterly Financial Data (Unaudited)

Note 18—Quarterly Financial Data (Unaudited)

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total (1)
	(in millions, except per unit data)
2014
Revenues	$	11,684	$	11,195	$	11,127	$	9,459	$	43,464
Gross margin (2)	$	582	$	455	$	482	$	597	$	2,116
Operating income	$	493	$	365	$	404	$	530	$	1,791
Net income	$	385	$	288	$	324	$	390	$	1,386
Net income attributable to PAA	$	384	$	287	$	323	$	389	$	1,384
Basic net income per limited partner unit	$	0.74	$	0.45	$	0.52	$	0.67	$	2.39
Diluted net income per limited partner unit	$	0.73	$	0.45	$	0.52	$	0.67	$	2.38
Cash distributions per common unit (3)	$	0.6150	$	0.6300	$	0.6450	$	0.6600	$	2.5500

2013
Revenues	$	10,620	$	10,295	$	10,703	$	10,631	$	42,249
Gross margin (2)	$	761	$	474	$	375	$	478	$	2,087
Operating income	$	655	$	383	$	296	$	394	$	1,728
Net income	$	536	$	300	$	237	$	318	$	1,391
Net income attributable to PAA	$	528	$	292	$	231	$	309	$	1,361
Basic net income per limited partner unit	$	1.28	$	0.58	$	0.38	$	0.59	$	2.82
Diluted net income per limited partner unit	$	1.27	$	0.57	$	0.38	$	0.58	$	2.80
Cash distributions per common unit (3)	$	0.5625	$	0.5750	$	0.5875	$	0.6000	$	2.3250

(1)

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

(2)

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

(3)

Represents cash distributions declared and paid in the period presented.

Operating Segments

12 Months Ended

Dec. 31, 2014

Operating Segments

Operating Segments

Note 19—Operating Segments

We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. See “Revenue Recognition” in Note 2 for a summary of the types of products and services from which each segment derives its revenues. Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates segment performance based on measures including segment profit and maintenance capital investment. We define segment profit as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses. Each of the items above excludes depreciation and amortization.

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

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

	Transportation		Facilities		Supply and Logistics		Total
Year Ended December 31, 2014
Revenues (1):
External Customers	$	774	$	576	$	42,114	$	43,464
Intersegment (2)	881		551		36		1,468
Total revenues of reportable segments	$	1,655	$	1,127	$	42,150	$	44,932
Equity earnings in unconsolidated entities	$	108	$	—	$	—	$	108
Segment profit (3) (4)	$	925	$	584	$	782	$	2,291
Capital expenditures (5)	$	2,483	$	582	$	60	$	3,125
Maintenance capital	$	165	$	52	$	7	$	224

As of December 31, 2014
Total assets	$	9,637	$	6,843	$	5,776	$	22,256
Investments in unconsolidated entities	$	1,735	$	—	$	—	$	1,735

	Transportation		Facilities		Supply and Logistics		Total
Year Ended December 31, 2013
Revenues:
External Customers	$	701	$	856	$	40,692	$	42,249
Intersegment (2)	797		521		4		1,322
Total revenues of reportable segments	$	1,498	$	1,377	$	40,696	$	43,571
Equity earnings in unconsolidated entities	$	64	$	—	$	—	$	64
Segment profit (3) (4)	$	729	$	616	$	822	$	2,167
Capital expenditures (5)	$	1,046	$	549	$	46	$	1,641
Maintenance capital	$	123	$	38	$	15	$	176

As of December 31, 2013
Total assets	$	7,221	$	6,555	$	6,584	$	20,360
Investments in unconsolidated entities	$	485	$	—	$	—	$	485

	Transportation		Facilities		Supply and Logistics		Total
Year Ended December 31, 2012
Revenues:
External Customers	$	623	$	736	$	36,438	$	37,797
Intersegment (2)	793		362		2		1,157
Total revenues of reportable segments	$	1,416	$	1,098	$	36,440	$	38,954
Equity earnings in unconsolidated entities	$	38	$	—	$	—	$	38
Segment profit (3) (4)	$	710	$	482	$	753	$	1,945
Capital expenditures (5)	$	1,244	$	1,724	$	503	$	3,471
Maintenance capital	$	108	$	49	$	13	$	170

As of December 31, 2012
Total assets	$	6,423	$	6,134	$	6,678	$	19,235
Investments in unconsolidated entities	$	343	$	—	$	—	$	343

(1)

Effective January 1, 2014, our natural gas sales and costs, primarily attributable to the activities performed by our natural gas storage commercial optimization group, are reported in the Supply and Logistics segment. Such items were previously reported in the Facilities segment.

(2)

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.

(3)

Supply and Logistics segment profit includes interest expense (related to hedged inventory purchases) of $12 million, $30 million and $12 million for the years ended December 31, 2014, 2013 and 2012, respectively.

(4)

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

	Year Ended December 31,
	2014			2013			2012
Segment profit	$	2,291		$	2,167		$	1,945
Depreciation and amortization	(392		)	(375		)	(482		)
Interest expense, net	(340		)	(303		)	(288		)
Other income/(expense), net	(2		)	1			6
Income before tax	1,557			1,490			1,181
Income tax expense	(171		)	(99		)	(54		)
Net income	1,386			1,391			1,127
Net income attributable to noncontrolling interests	(2		)	(30		)	(33		)
Net income attributable to PAA	$	1,384		$	1,361		$	1,094

(5)

Expenditures for acquisition capital and expansion capital, including investments in unconsolidated entities.

Geographic Data

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

	Year Ended December 31,
Revenues (1)	2014		2013		2012
United States	$	34,860	$	32,924	$	29,978
Canada	8,604		9,325		7,819
	$	43,464	$	42,249	$	37,797

(1)

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

	December 31,
Long-Lived Assets (1)	2014		2013
United States	$	14,400	$	11,743
Canada	3,650		3,623
	$	18,050	$	15,366

(1)

Excludes long-term derivative assets.

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Publisher FASB
-Name Accounting Standards Codification
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-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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Reference 12: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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+ Details

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Summary of Significant Accounting Policies

Basis of Consolidation and Presentation

All significant intercompany transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications do not affect net income attributable to PAA. The accompanying consolidated financial statements include PAA and all of its wholly owned subsidiaries.

Use of Estimates

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

Revenue Recognition

Supply and Logistics Segment Revenues. Revenues from sales of crude oil, NGL and natural gas are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. Sales of crude oil and NGL consist of outright sales contracts. Inventory purchases and sales under buy/sell transactions are treated as inventory exchanges. The sales under these exchanges are netted to zero in Supply and Logistics segment revenues in our Consolidated Statements of Operations.

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

Transportation Segment Revenues. Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems, trucks and barges. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil and NGL at a published tariff, as well as revenues associated with agreements for committed space on various assets. Tariff revenues are recognized either at the point of delivery or at the point of receipt pursuant to specifications outlined in the regulated and non-regulated tariffs. Revenues associated with fees are recognized in the month to which the fee applies. The majority of our pipeline tariff and fee revenues are based on actual volumes and rates. As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to offset losses due to evaporation, measurement and other losses in transit. We value the variance of allowance volumes to actual losses at the estimated net realizable value (including the impact of gains and losses from derivative related activities) at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues. In addition, we have certain agreements that require counterparties to ship a minimum volume over an agreed upon period. Revenue is recognized at the latter of when the volume is shipped (pursuant to specifications outlined in the tariffs) or when the counterparty’s ability to make up the minimum volume has expired.

Facilities Segment Revenues. Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. Revenues generated in this segment include (i) fees that are generated from storage capacity agreements, (ii) terminal throughput fees that are generated when we receive crude oil, refined products or NGL from one connecting source and deliver the applicable product to another connecting carrier, (iii) loading and unloading fees at our rail terminals, (iv) fees from NGL fractionation and isomerization, (v) fees from natural gas and condensate processing services and (vi) fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services.

We generate revenue through a combination of month-to-month and multi-year agreements and processing arrangements. Storage fees resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized. Terminal fees (including throughput and rail fees) are recognized as the crude oil, NGL or refined product enters or exits the terminal and is received from or delivered to the connecting carrier or third-party terminal, as applicable. Hub service fees are recognized in the period the natural gas moves across our header system. Fees from NGL fractionation, isomerization services and gas processing services are recognized in the period when the services are performed. In addition, we have certain agreements that require counterparties to throughput a minimum volume over an agreed upon period. Revenue is recognized at the latter of when the volume exits the terminal or when the counterparty’s ability to make up the minimum volume has expired.

Purchases and Related Costs

Purchases and related costs include (i) the cost of crude oil, NGL and natural gas obtained in outright purchases, (ii) fees incurred for third-party storage and transportation, whether by pipeline, truck, rail, ship or barge, (iii) interest cost attributable to borrowings for inventory stored in a contango market and (iv) performance-related bonus costs. These costs are recognized when incurred except in the case of products purchased, which are recognized at the time title transfers to us. Purchases that are part of exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Consolidated Statements of Operations.

Field Operating Costs and General and Administrative Expenses

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

Foreign Currency Transactions/Translation

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

Certain of our subsidiaries also enter into transactions and have monetary assets and liabilities that are denominated in a currency other than the entities’ respective functional currencies. Gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities are included in the Consolidated Statements of Operations. The revaluation of foreign currency transactions and monetary assets and liabilities resulted in a loss of $13 million for the year ended December 31, 2014, a gain of $1 million for the year ended December 31, 2013 and a loss of $2 million for the year ended December 31, 2012.

Cash and Cash Equivalents

Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. We used the cash on hand at December 31, 2014 to repay $400 million of commercial paper borrowings during the first week of January 2015.

In accordance with our policy, outstanding checks are classified as accounts payable rather than negative cash. As of December 31, 2014 and 2013, accounts payable included $94 million and $70 million, respectively, of outstanding checks that were reclassified from cash and cash equivalents.

Accounts Receivable

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas storage. These purchasers include, but are not limited to, refiners, producers, marketing and trading companies and financial institutions that are active in the physical and financial commodity markets. The majority of our accounts receivable relate to our crude oil supply and logistics activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes.

During late 2014 and early 2015, commodity prices dropped significantly. This volatility has caused liquidity issues impacting many energy companies, which in turn has increased the potential credit risks associated with certain counterparties with which we do business. To mitigate credit risk related to our accounts receivable, we have in place a rigorous credit review process. We closely monitor market conditions to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit or parental guarantees. As of December 31, 2014 and 2013, we had received $180 million and $117 million, respectively, of advance cash payments from third parties to mitigate credit risk. Furthermore, as of December 31, 2014 and 2013, we had received $198 million and $426 million, respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. In addition, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Further, we enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet) for a majority of such arrangements.

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At December 31, 2014 and 2013, substantially all of our accounts receivable (net of allowance for doubtful accounts) were less than 30 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled $4 million and $5 million at December 31, 2014 and 2013, respectively. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

Noncontrolling Interests

We account for noncontrolling interests in subsidiaries in accordance with FASB guidance, which requires all entities to report noncontrolling interests in subsidiaries as a component of equity in the consolidated financial statements. Noncontrolling interest represents the portion of assets and liabilities in a consolidated subsidiary that is owned by a third-party. See Note 11 for additional discussion regarding our noncontrolling interests.

Asset Retirement Obligations

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

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

A small portion of our contractual or regulatory obligations is related to assets that are inactive or that we plan to take out of service and, although the ultimate timing and costs to settle these obligations are not known with certainty, we have recorded a reasonable estimate of these obligations. We have estimated that the fair value of these obligations was $36 million and $34 million, respectively, at December 31, 2014 and 2013.

Fair Value Measurements

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. The determination of the fair values 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. See Note 12 for further discussion.

Recent Accounting Pronouncements

In January 2015, as part of its initiative to reduce complexity in accounting standards, the FASB issued guidance to eliminate the concept of extraordinary items from GAAP. This guidance will become effective for interim and annual periods beginning after December 15, 2015. We expect to adopt this guidance on January 1, 2016. We do not believe our adoption will have a material impact on our financial position, results of operations or cash flows.

In May 2014, the FASB issued guidance regarding the recognition of revenue from contracts with customers with the underlying principle that an entity will recognize revenue to reflect amounts expected to be received in exchange for the provision of goods and services to customers upon the transfer of those goods or services. The guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. This guidance becomes effective for interim and annual periods beginning after December 15, 2016 and can be adopted either with a full retrospective approach or a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. We are currently evaluating which transition approach to apply and the effect that adopting this guidance will have on our financial position, results of operations and cash flows.

In April 2014, the FASB issued guidance that modifies the criteria under which assets to be disposed of are evaluated to determine if such assets qualify as a discontinued operation and requires new disclosures for both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. This guidance is effective prospectively for annual and interim reporting periods beginning after December 15, 2014. Early adoption is permitted but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issue. We adopted this guidance on January 1, 2015. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

In March 2013, the FASB issued guidance regarding the release of cumulative translation adjustments into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a business within a foreign entity. This guidance became effective beginning after December 15, 2013. We adopted this guidance on January 1, 2014. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

Acquisitions

Net Income Per Limited Partner Unit

The following table sets forth the computation of basic and diluted net income per limited partner unit for the years ended December 31, 2014, 2013 and 2012 (in millions, except per unit data):

	Year Ended December 31,
	2014			2013			2012
Basic Net Income per Limited Partner Unit
Net income attributable to PAA	$	1,384		$	1,361		$	1,094
Less: General partner’s incentive distribution (1)	(482		)	(375		)	(289		)
Less: General partner 2% ownership (1)	(18		)	(19		)	(16		)
Net income available to limited partners	884			967			789
Less: Undistributed earnings allocated and distributions to participating securities (1)	(6		)	(7		)	(5		)
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	878		$	960		$	784

Basic weighted average limited partner units outstanding	367			341			325

Basic net income per limited partner unit	$	2.39		$	2.82		$	2.41

Diluted Net Income per Limited Partner Unit
Net income attributable to PAA	$	1,384		$	1,361		$	1,094
Less: General partner’s incentive distribution (1)	(482		)	(375		)	(289		)
Less: General partner 2% ownership (1)	(18		)	(19		)	(16		)
Net income available to limited partners	884			967			789
Less: Undistributed earnings allocated and distributions to participating securities (1)	(6		)	(6		)	(4		)
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	878		$	961		$	785

Basic weighted average limited partner units outstanding	367			341			325
Effect of dilutive securities: Weighted average LTIP units	2			2			3
Diluted weighted average limited partner units outstanding	369			343			328

Diluted net income per limited partner unit	$	2.38		$	2.80		$	2.40

(1)

Inventory, Linefill and Base Gas and Long-term Inventory

Property and Equipment

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

	Estimated Useful	December 31,
	Lives (Years)	2014			2013
Pipelines and related facilities	10 - 70	$	7,003		$	6,113
Storage, terminal and rail facilities	30 - 70	4,853			4,704
Trucking equipment and other	3 - 15	198			150
Construction in progress	-	1,545			1,008
Office property and equipment	2 - 50	156			125
Land and other	N/A	423			373
		14,178			12,473
Accumulated depreciation		(1,906		)	(1,654		)
Property and equipment, net		$	12,272		$	10,819

Impairment of Long-Lived Assets

whether there is an indication of impairment;

the grouping of assets;

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

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

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

Goodwill

Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized.

The following table reflects our goodwill by segment and changes in goodwill during the years ended December 31, 2014 and 2013 (in millions):

	Transportation			Facilities			Supply and Logistics			Total
Balance at December 31, 2012	$	897		$	1,171		$	467		$	2,535
Acquisitions	6			—			—			6
Foreign currency translation adjustments	(20		)	(9		)	(4		)	(33		)
Purchase price accounting adjustments and other	(5		)	—			—			(5		)
Balance at December 31, 2013	$	878		$	1,162		$	463		$	2,503
Acquisitions (1)	—			1			—			1
Foreign currency translation adjustments	(24		)	(11		)	(4		)	(39		)
Balance at December 31, 2014	$	854		$	1,152		$	459		$	2,465

(1)

Investments in Unconsolidated Entities

Debt

Intangible Assets

Intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable.

Derivatives

Derivatives That Qualify for Hedge Accounting

For derivatives that qualify as cash flow hedges, changes in fair value of the effective portion of the hedges are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions are recognized in earnings.

Derivatives That Do Not Qualify for Hedge Accounting

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 Derivative Activities

Cash settlements associated with our derivative activities are reflected as cash flows from operating activities in our Consolidated Statements of Cash Flows.

Offsetting Derivative Assets and Liabilities

Income Taxes

Concentration of Credit Risk

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

Reimbursement of Expenses of Our General Partner and its Affiliates

Equity Compensation

AAP Management Units

Legal Contingencies

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.

Environmental Matters

Operating Segments

Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates segment performance based on measures including segment profit and maintenance capital investment. We define segment profit as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses. Each of the items above excludes depreciation and amortization.

Acquisitions and Dispositions (Tables)

12 Months Ended

Dec. 31, 2014

Business acquisition

Summary of selected unaudited pro forma results of operations

	Year Ended
	December 31, 2012
Total revenues	$	38,729
Net income attributable to PAA	$	1,149
Limited partner interest in net income attributable to PAA	$	846
Net income per limited partner unit:
Basic	$	2.57
Diluted	$	2.55

BP NGL Acquisition

Business acquisition

Business acquisition fair value determination

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

				Average
				Depreciable
Description	Amount			Life (in years)
Working capital	$	241		N/A
Property and equipment	1,081			5 - 70
Linefill	85			N/A
Long-term inventory	165			N/A
Intangible assets (contract)	130			13
Goodwill	236			N/A
Deferred tax liability	(236		)	N/A
Environmental liability	(14		)	N/A
Other long-term liabilities	(5		)	N/A
Total	$	1,683

Net Income Per Limited Partner Unit (Tables)

12 Months Ended

Dec. 31, 2014

Net Income Per Limited Partner Unit

Computation of basic and diluted net income per limited partner unit

	Year Ended December 31,
	2014			2013			2012
Basic Net Income per Limited Partner Unit
Net income attributable to PAA	$	1,384		$	1,361		$	1,094
Less: General partner’s incentive distribution (1)	(482		)	(375		)	(289		)
Less: General partner 2% ownership (1)	(18		)	(19		)	(16		)
Net income available to limited partners	884			967			789
Less: Undistributed earnings allocated and distributions to participating securities (1)	(6		)	(7		)	(5		)
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	878		$	960		$	784

Basic weighted average limited partner units outstanding	367			341			325

Basic net income per limited partner unit	$	2.39		$	2.82		$	2.41

Diluted Net Income per Limited Partner Unit
Net income attributable to PAA	$	1,384		$	1,361		$	1,094
Less: General partner’s incentive distribution (1)	(482		)	(375		)	(289		)
Less: General partner 2% ownership (1)	(18		)	(19		)	(16		)
Net income available to limited partners	884			967			789
Less: Undistributed earnings allocated and distributions to participating securities (1)	(6		)	(6		)	(4		)
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	878		$	961		$	785

Basic weighted average limited partner units outstanding	367			341			325
Effect of dilutive securities: Weighted average LTIP units	2			2			3
Diluted weighted average limited partner units outstanding	369			343			328

Diluted net income per limited partner unit	$	2.38		$	2.80		$	2.40

(1)

Undistributed earnings allocation to IDRs impact on basic and diluted net income per limited partner unit

	Year Ended December 31,
	2014		2013			2012
Basic net income per limited partner unit impact	$	—	$	(0.20	)	$	(0.11	)

Diluted net income per limited partner unit impact	$	—	$	(0.20	)	$	(0.11	)

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

12 Months Ended

Dec. 31, 2014

Inventory, Linefill and Base Gas and Long-term Inventory

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

	December 31, 2014							December 31, 2013
	Volumes	Unit of Measure		Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure		Carrying Value		Price/ Unit (1)
Inventory
Crude oil	6,465		barrels	$	304	$	47.02	6,951		barrels	$	540	$	77.69
NGL	13,553		barrels	454		$	33.50	8,061		barrels	352		$	43.67
Natural gas	32,317		Mcf	102		$	3.16	40,505		Mcf	150		$	3.70
Other	N/A			31		N/A		N/A			23		N/A
Inventory subtotal				891							1,065

Linefill and base gas
Crude oil	11,810		barrels	744		$	63.00	10,966		barrels	679		$	61.92
NGL	1,212		barrels	52		$	42.90	1,341		barrels	62		$	46.23
Natural gas	28,612		Mcf	134		$	4.68	16,615		Mcf	57		$	3.43
Linefill and base gas subtotal				930							798

Long-term inventory
Crude oil	2,582		barrels	136		$	52.67	2,498		barrels	202		$	80.86
NGL	1,681		barrels	50		$	29.74	1,161		barrels	49		$	42.20
Long-term inventory subtotal				186							251

Total				$	2,007						$	2,114

(1)

Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2014

Property and Equipment

Components of property and equipment, net

	Estimated Useful	December 31,
	Lives (Years)	2014			2013
Pipelines and related facilities	10 - 70	$	7,003		$	6,113
Storage, terminal and rail facilities	30 - 70	4,853			4,704
Trucking equipment and other	3 - 15	198			150
Construction in progress	-	1,545			1,008
Office property and equipment	2 - 50	156			125
Land and other	N/A	423			373
		14,178			12,473
Accumulated depreciation		(1,906		)	(1,654		)
Property and equipment, net		$	12,272		$	10,819

Goodwill (Tables)

12 Months Ended

Dec. 31, 2014

Goodwill

Schedule of goodwill by segment and changes during the period

	Transportation			Facilities			Supply and Logistics			Total
Balance at December 31, 2012	$	897		$	1,171		$	467		$	2,535
Acquisitions	6			—			—			6
Foreign currency translation adjustments	(20		)	(9		)	(4		)	(33		)
Purchase price accounting adjustments and other	(5		)	—			—			(5		)
Balance at December 31, 2013	$	878		$	1,162		$	463		$	2,503
Acquisitions (1)	—			1			—			1
Foreign currency translation adjustments	(24		)	(11		)	(4		)	(39		)
Balance at December 31, 2014	$	854		$	1,152		$	459		$	2,465

(1)

Investments in Unconsolidated Entities (Tables)

12 Months Ended

Dec. 31, 2014

Investments in Unconsolidated Entities

Investments in entities accounted for under the equity method of accounting

Entity	Type of Operation	Our Ownership Interest
Settoon Towing, LLC	Barge Transportation Services	50	%
BridgeTex Pipeline Company, LLC	Crude Oil Pipeline	50	%
Eagle Ford Pipeline LLC	Crude Oil Pipeline	50	%
White Cliffs Pipeline, LLC	Crude Oil Pipeline	36	%
Butte Pipe Line Company	Crude Oil Pipeline	22	%
Frontier Pipeline Company	Crude Oil Pipeline	22	%

Summarized financial information for unconsolidated entities

	December 31,
	2014		2013
Current assets	$	184	$	177
Noncurrent assets	$	2,303	$	1,067
Current liabilities	$	142	$	57
Noncurrent liabilities	$	222	$	211

	Year Ended December 31,
	2014		2013		2012
Revenues	$	531	$	344	$	257
Operating income	$	301	$	181	$	132
Net income	$	285	$	172	$	118

Other Assets, Net (Tables)

12 Months Ended

Dec. 31, 2014

Other Assets, Net

Components of other assets, net of accumulated amortization

	December 31,
	2014			2013
Intangible assets	$	676		$	674
Debt issue costs	92			70
Fair value of derivative instruments	27			30
Other	19			37
	814			811
Accumulated amortization	(325		)	(271		)
	$	489		$	540

Components of intangible assets that have finite lives

		December 31, 2014							December 31, 2013
	Estimated Useful			Accumulated							Accumulated
	Lives (Years)	Cost		Amortization			Net		Cost		Amortization			Net
Customer contracts and relationships	1 - 20	$	593	$	(288	)	$	305	$	591	$	(237	)	$	354
Property tax abatement	7 - 13	38		(18		)	20		38		(14		)	24
Other agreements	25 - 70	37		(4		)	33		37		(3		)	34
Emission reduction credits (1)	N/A	8		—			8		8		—			8
		$	676	$	(310	)	$	366	$	674	$	(254	)	$	420

(1)

Emission reduction credits, once surrendered in exchange for environmental permits, are finite-lived.

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

2015	$	52
2016	$	44
2017	$	41
2018	$	36
2019	$	33

Debt (Tables)

12 Months Ended

Dec. 31, 2014

Debt

Components of debt

	December 31,			December 31,
	2014			2013
SHORT-TERM DEBT
PAA commercial paper notes, bearing a weighted-average interest rate of 0.46% and 0.33%, respectively (1)	$	734		$	1,109
PAA senior notes:
5.25% senior notes due June 2015	150			—
3.95% senior notes due September 2015	400			—
Other	3			4
Total short-term debt	1,287			1,113

LONG-TERM DEBT
PAA senior notes:
5.25% senior notes due June 2015	—			150
3.95% senior notes due September 2015	—			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
2.60% senior notes due December 2019	500			—
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	750			750
2.85% senior notes due January 2023	400			400
3.85% senior notes due October 2023	700			700
3.60% senior notes due November 2024	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	500			500
4.30% senior notes due January 2043	350			350
4.70% senior notes due June 2044	700			—
4.90% senior notes due February 2045	650			—
Unamortized discounts	(18		)	(15		)
PAA senior notes, net of unamortized discounts	8,757			6,710
Other	5			5
Total long-term debt	8,762			6,715
Total debt (2)	$	10,049		$	7,828

(1)

(2)

Issuances of senior unsecured notes

Year	Description	Maturity	Face Value		Interest Payment Dates
2014	2.60% Senior Notes issued at 99.813% of face value	December 2019	$	500	June 15 and December 15
2014	4.90% Senior Notes issued at 99.876% of face value	February 2045	$	650	February 15 and August 15
2014	3.60% Senior Notes issued at 99.842% of face value	November 2024	$	750	May 1 and November 1
2014	4.70% Senior Notes issued at 99.734% of face value	June 2044	$	700	June 15 and December 15

2013	3.85% Senior Notes issued at 99.792% of face value	October 2023	$	700	April 15 and October 15

2012	2.85% Senior Notes issued at 99.752% of face value	January 2023	$	400	January 31 and July 31
2012	4.30% Senior Notes issued at 99.925% of face value	January 2043	$	350	January 31 and July 31
2012	3.65% Senior Notes issued at 99.823% of face value	June 2022	$	750	June 1 and December 1
2012	5.15% Senior Notes issued at 99.755% of face value	June 2042	$	500	June 1 and December 1

Long-term debt maturities

Calendar Year	Payment
2015	$	550
2016	175
2017	400
2018	600
2019	850
Thereafter	6,750
Total (1)	$		9,325

(1)

Excludes aggregate unamortized net discount of $18 million.

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

Reference 4: 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.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=34725769&loc=d3e28878-108400

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

+ Details

Partners' Capital and Distributions (Tables)

12 Months Ended

Dec. 31, 2014

Partners' Capital and Distributions

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

	Year
	2014				2013				2012
			Excess				Excess				Excess
	Distribution (1)		over MQD		Distribution (1)		over MQD		Distribution (1)		over MQD
First Quarter	$	0.6150	$	0.3900	$	0.5625	$	0.3375	$	0.5125	$	0.2875
Second Quarter	$	0.6300	$	0.4050	$	0.5750	$	0.3500	$	0.5225	$	0.2975
Third Quarter	$	0.6450	$	0.4200	$	0.5875	$	0.3625	$	0.5325	$	0.3075
Fourth Quarter	$	0.6600	$	0.4350	$	0.6000	$	0.3750	$	0.5425	$	0.3175

(1)

Distributions represent those declared and paid in the applicable period shown.

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

	Distributions Paid								Distributions
	Common		General Partner						per limited
Year	Units		2%		Incentive		Total		partner unit
2014	$	934	$	19	$	454	$	1,407	$	2.55
2013	$	791	$	16	$	353	$	1,160	$	2.33
2012	$	684	$	14	$	271	$	969	$	2.11

Issuance of common units

Year	Type of Offering	Units Issued	Net Proceeds (1) (2)

2014 Total	Continuous Offering Program	15,375,810	$	866	(3)

2013 Total	Continuous Offering Program	8,644,807	$	477	(3)

2012	Continuous Offering Program	12,063,707	$	524	(3)
2012	Marketed Offering	11,500,000	455		(4)
2012 Total		23,563,707	$	979

(1)

Amounts are net of costs associated with the offerings.

(2)

Amounts include our general partner’s proportionate capital contributions of $18 million, $9 million and $20 million during 2014, 2013 and 2012, respectively.

(3)

(4)

Offering was an underwritten transaction that required us to pay a gross spread. The net proceeds from such offering were used to fund a portion of the BP NGL Acquisition.

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

	Year Ended
	December 31, 2013
Net income attributable to PAA	$	1,361
Transfers to/from noncontrolling interests:
Increase in capital from sale of PNG common units	8
Decrease in capital from purchase of PNG common units in conjunction with the PNG Merger	(290		)
Net transfers to/from noncontrolling interests	(282		)
Change from net income attributable to PAA and transfers to/from noncontrolling interests	$	1,079

Derivatives and Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2014

Derivative disclosures

Impact of derivative activities recognized in earnings

	Year Ended December 31, 2014
	Derivatives in Hedging Relationships
Location of gain/(loss)	Gain/(loss) reclassified from AOCI into income (1) (2)			Other gain/(loss) recognized in income		Derivatives Not Designated as a Hedge			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	(1	)	$	—	$	206		$	205

Field operating costs	—			—		(21		)	(21		)

Interest Rate Derivatives

Interest expense	(5		)	—		—			(5		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			—		(28		)	(28		)

Other income/(expense), net	2			—		—			2

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(4	)	$	—	$	157		$	153

	Year Ended December 31, 2013
	Derivatives in Hedging Relationships
Location of gain/(loss)	Gain/(loss) reclassified from AOCI into income (1)			Other gain/(loss) recognized in income			Derivatives Not Designated as a Hedge			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	78		$	(1	)	$	(116	)	$	(39	)

Facilities segment revenues	(10		)	(1		)	—			(11		)

Field operating costs	—			—			8			8

Interest Rate Derivatives

Interest expense	(7		)	3			—			(4		)

Foreign Currency Derivatives

Other income/(expense), net	5			—			—			5

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	66		$	1		$	(108	)	$	(41	)

	Year Ended December 31, 2012
	Derivatives in Hedging Relationships
Location of gain/(loss)	Gain/(loss) reclassified from AOCI into income (1)			Other gain/(loss) recognized in income			Derivatives Not Designated as a Hedge			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	12		$	—		$	60		$	72

Facilities segment revenues	3			(1		)	1			3

Purchases and related costs	45			—			1			46

Field operating costs	—			—			1			1

Interest Rate Derivatives

Interest expense	(4		)	1			—			(3		)

Foreign Currency Derivatives

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

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

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	62		$	—		$	62		$	124

(1)

(2)

Summary of derivative assets and liabilities on consolidated balance sheet on a gross basis

The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2014 (in millions):

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	23	Other current assets	$	(12	)
	Other long-term assets	8		Other long-term assets	(1		)
Interest rate derivatives				Other current liabilities	(44		)
				Other long-term liabilities	(26		)
Total derivatives designated as hedging instruments		$	31		$	(83	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	439	Other current assets	$	(246	)
	Other long-term assets	23		Other long-term assets	(3		)
				Other current liabilities	(35		)
				Other long-term liabilities	(5		)
Foreign currency derivatives				Other current liabilities	(12		)
Total derivatives not designated as hedging instruments		$	462		$	(301	)

Total derivatives		$	493		$	(384	)

The following table summarizes the derivative assets and liabilities on our Consolidated Balance Sheet on a gross basis as of December 31, 2013 (in millions):

	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	36	Other current assets	$	(24	)
	Other long-term assets	5
Interest rate derivatives	Other long-term assets	26
Total derivatives designated as hedging instruments		$	67		$	(24	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	60	Other current assets	$	(117	)
	Other long-term assets	5		Other long-term assets	(6		)
	Other current liabilities	1		Other current liabilities	(5		)
				Other long-term liabilities	(1		)
Foreign currency derivatives				Other current liabilities	(4		)
Total derivatives not designated as hedging instruments		$	66		$	(133	)

Total derivatives		$	133		$	(157	)

Schedule of derivatives assets and liabilities that are subject to offsetting, including enforceable master netting arrangements

	December 31, 2014						December 31, 2013
	Derivative			Derivative			Derivative			Derivative
	Asset Positions			Liability Positions			Asset Positions			Liability Positions
Netting Adjustments:
Gross position - asset/(liability)	$	493		$	(384	)	$	133		$	(157	)
Netting adjustment	(262		)	262			(148		)	148
Cash collateral paid/(received)	(133		)	—			161			—
Net position - asset/(liability)	$	98		$	(122	)	$	146		$	(9	)

Balance Sheet Location After Netting Adjustments:
Other current assets	$	71		$	—		$	116		$	—
Other long-term assets	27			—			30			—
Other current liabilities	—			(91		)	—			(8		)
Other long-term liabilities	—			(31		)	—			(1		)
	$	98		$	(122	)	$	146		$	(9	)

Net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives

	Year Ended December 31,
	2014			2013		2012
Commodity derivatives, net	$	15		$	37	$	56
Interest rate derivatives, net	(103		)	72		(12		)
Foreign currency derivatives, net	2			—		—
Total	$	(86	)	$	109	$	44

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

	Fair Value as of December 31, 2014											Fair Value as of December 31, 2013
Recurring Fair Value Measures (1)	Level 1			Level 2			Level 3		Total			Level 1		Level 2			Level 3			Total
Commodity derivatives	$	(85	)	$	261		$	15	$	191		$	16	$	(59	)	$	(3	)	$	(46	)
Interest rate derivatives	—			(70		)	—		(70		)	—		26			—			26
Foreign currency derivatives	—			(12		)	—		(12		)	—		(4		)	—			(4		)
Total net derivative asset/(liability)	$	(85	)	$	179		$	15	$	109		$	16	$	(37	)	$	(3	)	$	(24	)

(1)

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

Reconciliation of changes in fair value of derivatives classified as Level 3

	Year Ended December 31,
	2014			2013
Beginning Balance	$	(3	)	$	4
Total gains/(losses) for the period:
Included in earnings (1)	—			(1		)
Included in other comprehensive income	—			—
Settlements	3			(3		)
Derivatives entered into during the period	15			(3		)
Transfers out of Level 3	—			—
Ending Balance	$	15		$	(3	)

Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the periods	$	15		$	(4	)

(1)

We reported unrealized gains and losses associated with Level 3 commodity derivatives in our Consolidated Statements of Operations as Supply and Logistics segment revenues.

Interest Rate Derivatives

Derivative disclosures

Schedule of 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

10 forward starting swaps (30-year)

250

6/15/2015

3.60%

Cash flow hedge

Anticipated debt offering

8 forward starting swaps (30-year)

200

6/15/2016

3.06%

Cash flow hedge

Anticipated debt offering

8 forward starting swaps (30-year)

200

6/15/2017

3.14%

Cash flow hedge

Anticipated debt offering

8 forward starting swaps (30-year)

200

6/15/2018

3.20%

Cash flow hedge

Summary of activity related to terminated interest rate derivatives

Hedged Transaction	Number and Types of Derivatives Terminated	Notional Amount		Cash Received/(Paid)			Average Rate Locked
April 2014 senior note issuance	5 treasury lock agreements	$	250	$	(7	)	3.62%
August 2013 senior note issuance (1)	5 forward starting swaps (30-year)	$	125	$	11		3.39%
December 2012 senior note issuance	6 forward starting swaps (30-year)	$	250	$	(89	)	4.24%
March 2012 senior note issuance (2)	4 forward starting swaps (10-year)	$	200	$	(24	)	3.46%

(1)

A gain of approximately $3 million was immediately recognized in interest expense attributable to the ineffective portion of these swaps upon termination.

(2)

A loss of approximately $1 million was immediately recognized in interest expense attributable to the ineffective portion of these swaps upon termination.

Foreign Currency Derivatives

Derivative disclosures

Open forward exchange contracts

The following table summarizes our open forward exchange contracts as of December 31, 2014 (in millions):

		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2015	$	460	$	535	$1.00 - $1.16

Forward exchange contracts that exchange USD for CAD:
	2015	$	345	$	387	$1.00 - $1.12

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2014

Income Taxes

Components of income tax expense

	Year Ended December 31,
	2014		2013			2012
Current tax expense:
State income tax	$	1	$	1		$	2
Canadian federal and provincial income tax	70		99			51
Total current tax expense	$	71	$	100		$	53

Deferred tax (benefit)/expense:
Canadian federal and provincial income tax	$	100	$	(1	)	$	1
Total deferred tax (benefit)/expense	$	100	$	(1	)	$	1
Total income tax expense	$	171	$	99		$	54

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

	Year Ended December 31,
	2014			2013			2012
Income before tax	$	1,557		$	1,490		$	1,181
Partnership earnings not subject to current Canadian tax	(976		)	(1,187		)	(1,046		)
	$	581		$	303		$	135
Canadian federal and provincial corporate tax rate	25		%	25		%	25		%
Income tax at statutory rate	$	145		$	76		$	34

Canadian withholding tax	$	16		$	19		$	18
Canadian permanent differences and rate changes	9			3			—
State income tax	1			1			2
Total income tax expense	$	171		$	99		$	54

Deferred tax assets and liabilities

	December 31,
	2014			2013
Deferred tax assets:
Book accruals in excess of current tax deductions	$	29		$	41
Net operating losses	2			—
Derivative instruments	—			15
Total deferred tax assets	31			56

Deferred tax liabilities:
Derivative instruments	(71		)	—
Property and equipment in excess of tax values	(322		)	(332		)
Other	(49		)	(66		)
Total deferred tax liabilities	(442		)	(398		)
Net deferred tax assets / (liabilities)	$	(411	)	$	(342	)

Balance sheet classification of deferred tax assets / (liabilities):
Other, net	$	2		$	—
Other current liabilities	(64		)	—
Other long-term liabilities and deferred credits	(349		)	(342		)
	$	(411	)	$	(342	)

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2014

Oxy

Related party transaction

	Year Ended December 31,
	2014		2013		2012
Revenues	$	1,212	$	1,309	$	1,636

Purchases and related costs	$	925	$	863	$	557

	December 31,
	2014		2013
Trade accounts receivable and other receivables	$	489	$	133

Accounts payable	$	441	$	181

Equity-Indexed Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2014

Equity-Indexed Compensation Plans

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

PAA LTIP Units	PAA Distribution	Estimated Unit Vesting Date
Outstanding (1) (2)	Required (3)	2015	2016	2017	2018	Thereafter
7.3	$2.075-$3.200	2.1	2.1	1.8	1.2	0.1

(1)

Approximately 3.5 million of the 7.3 million outstanding PAA LTIP awards also include DERs, of which 3.2 million had vested as of December 31, 2014.

(2)

LTIP units outstanding do not include AAP Management Units.

(3)

Summary of activity for LTIP awards under equity-indexed compensation plans denominated in PAA and PNG units

	PAA Units (1) (3)				PNG Units (2) (4)
			Weighted Average				Weighted Average
			Grant Date				Grant Date
	Units		Fair Value per Unit		Units		Fair Value per Unit
Outstanding at December 31, 2011	8.0		$	21.77	0.8		$	20.55
Granted	1.5		$	33.90	0.1		$	15.33
Vested	(3.2	)	$	19.82	—		$	23.64
Cancelled or forfeited	(0.3	)	$	29.36	—		$	—
Outstanding at December 31, 2012	6.0		$	25.55	0.9		$	17.49
Granted	4.1		$	47.60	0.4		$	17.51
Vested	(1.8	)	$	24.79	—		$	18.88
Cancelled or forfeited (5)	(0.3	)	$	36.70	(0.3	)	$	21.62
Conversion of PNG unit-denominated awards into PAA unit-denominated awards (6)	0.4		$	40.54	(1.0	)	$	16.41
Outstanding at December 31, 2013	8.4		$	36.97	—		$	—
Granted	1.2		$	47.68
Vested	(1.9	)	$	25.49
Cancelled or forfeited	(0.4	)	$	40.14
Outstanding at December 31, 2014	7.3		$	41.21

(1)

Amounts do not include AAP Management Units.

(2)

Amounts include PNG Transaction Grants, which are discussed further below.

(3)

(4)

Less than 0.1 million PNG units vested during each of the years ended December 31, 2013 and 2012.

(5)

As a result of the PNG Merger on December 31, 2013, approximately 0.3 million outstanding PNG Transaction Grants were cancelled.

(6)

Summary of activity of AAP Management Units

	Reserved for Future Grants		Outstanding	Outstanding Units Earned	Grant Date Fair Value of Outstanding AAP Management Units (1)
Balance as of December 31, 2012	4.7		47.4	34.0	$	44
Granted	(1.2	)	1.2	—	7
Earned	N/A		N/A	13.0	N/A
Balance as of December 31, 2013	3.5		48.6	47.0	$	51
Granted	(0.5	)	0.5	—	13
Earned	N/A		N/A	0.8	N/A
Balance as of December 31, 2014	3.0		49.1	47.8	$	64

(1)

Summary of expense recognized and the value of vested LTIP awards under equity-indexed compensation plans

	Year Ended December 31,
	2014		2013		2012
Equity-indexed compensation expense	$	98	$	116	$	101
LTIP unit-settled vestings (1)	$	53	$	48	$	62
LTIP cash-settled vestings	$	53	$	61	$	66
DER cash payments	$	8	$	8	$	7

(1)

For the years ended December 31, 2013 and 2012, less than $1 million and $1 million, respectively, relates to unit vestings which were settled with PNG common units.

Estimated equity-indexed compensation plan fair value amortization

Year	Equity-Indexed Compensation Plan Fair Value Amortization (1) (2)
2015	$	70
2016	46
2017	21
2018	6
2019	1
Thereafter	—
Total	$	144

(1)

Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at December 31, 2014.

(2)

Includes unamortized fair value associated with AAP Management Units.

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies.

Schedule of future non-cancelable commitments

	2015		2016		2017		2018		2019		Thereafter		Total
Leases (1)	$	162	$	151	$	127	$	102	$	78	$	373	$	993
Other commitments (2)	62		62		49		38		27		90		328
Total	$	224	$	213	$	176	$	140	$	105	$	463	$	1,321

(1)

Includes capital and operating leases as defined by FASB guidance.

(2)

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

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Data (Unaudited)

Quarterly Financial Data (Unaudited)

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total (1)
	(in millions, except per unit data)
2014
Revenues	$	11,684	$	11,195	$	11,127	$	9,459	$	43,464
Gross margin (2)	$	582	$	455	$	482	$	597	$	2,116
Operating income	$	493	$	365	$	404	$	530	$	1,791
Net income	$	385	$	288	$	324	$	390	$	1,386
Net income attributable to PAA	$	384	$	287	$	323	$	389	$	1,384
Basic net income per limited partner unit	$	0.74	$	0.45	$	0.52	$	0.67	$	2.39
Diluted net income per limited partner unit	$	0.73	$	0.45	$	0.52	$	0.67	$	2.38
Cash distributions per common unit (3)	$	0.6150	$	0.6300	$	0.6450	$	0.6600	$	2.5500

2013
Revenues	$	10,620	$	10,295	$	10,703	$	10,631	$	42,249
Gross margin (2)	$	761	$	474	$	375	$	478	$	2,087
Operating income	$	655	$	383	$	296	$	394	$	1,728
Net income	$	536	$	300	$	237	$	318	$	1,391
Net income attributable to PAA	$	528	$	292	$	231	$	309	$	1,361
Basic net income per limited partner unit	$	1.28	$	0.58	$	0.38	$	0.59	$	2.82
Diluted net income per limited partner unit	$	1.27	$	0.57	$	0.38	$	0.58	$	2.80
Cash distributions per common unit (3)	$	0.5625	$	0.5750	$	0.5875	$	0.6000	$	2.3250

(1)

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

(2)

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

(3)

Represents cash distributions declared and paid in the period presented.

Operating Segments (Tables)

12 Months Ended

Dec. 31, 2014

Operating Segments

Segment financial data

	Transportation		Facilities		Supply and Logistics		Total
Year Ended December 31, 2014
Revenues (1):
External Customers	$	774	$	576	$	42,114	$	43,464
Intersegment (2)	881		551		36		1,468
Total revenues of reportable segments	$	1,655	$	1,127	$	42,150	$	44,932
Equity earnings in unconsolidated entities	$	108	$	—	$	—	$	108
Segment profit (3) (4)	$	925	$	584	$	782	$	2,291
Capital expenditures (5)	$	2,483	$	582	$	60	$	3,125
Maintenance capital	$	165	$	52	$	7	$	224

As of December 31, 2014
Total assets	$	9,637	$	6,843	$	5,776	$	22,256
Investments in unconsolidated entities	$	1,735	$	—	$	—	$	1,735

	Transportation		Facilities		Supply and Logistics		Total
Year Ended December 31, 2013
Revenues:
External Customers	$	701	$	856	$	40,692	$	42,249
Intersegment (2)	797		521		4		1,322
Total revenues of reportable segments	$	1,498	$	1,377	$	40,696	$	43,571
Equity earnings in unconsolidated entities	$	64	$	—	$	—	$	64
Segment profit (3) (4)	$	729	$	616	$	822	$	2,167
Capital expenditures (5)	$	1,046	$	549	$	46	$	1,641
Maintenance capital	$	123	$	38	$	15	$	176

As of December 31, 2013
Total assets	$	7,221	$	6,555	$	6,584	$	20,360
Investments in unconsolidated entities	$	485	$	—	$	—	$	485

	Transportation		Facilities		Supply and Logistics		Total
Year Ended December 31, 2012
Revenues:
External Customers	$	623	$	736	$	36,438	$	37,797
Intersegment (2)	793		362		2		1,157
Total revenues of reportable segments	$	1,416	$	1,098	$	36,440	$	38,954
Equity earnings in unconsolidated entities	$	38	$	—	$	—	$	38
Segment profit (3) (4)	$	710	$	482	$	753	$	1,945
Capital expenditures (5)	$	1,244	$	1,724	$	503	$	3,471
Maintenance capital	$	108	$	49	$	13	$	170

As of December 31, 2012
Total assets	$	6,423	$	6,134	$	6,678	$	19,235
Investments in unconsolidated entities	$	343	$	—	$	—	$	343

(1)

(2)

(3)

(4)

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

	Year Ended December 31,
	2014			2013			2012
Segment profit	$	2,291		$	2,167		$	1,945
Depreciation and amortization	(392		)	(375		)	(482		)
Interest expense, net	(340		)	(303		)	(288		)
Other income/(expense), net	(2		)	1			6
Income before tax	1,557			1,490			1,181
Income tax expense	(171		)	(99		)	(54		)
Net income	1,386			1,391			1,127
Net income attributable to noncontrolling interests	(2		)	(30		)	(33		)
Net income attributable to PAA	$	1,384		$	1,361		$	1,094

(5)

Expenditures for acquisition capital and expansion capital, including investments in unconsolidated entities.

Reconciliation of segment profit to net income attributable to PAA

	Year Ended December 31,
	2014			2013			2012
Segment profit	$	2,291		$	2,167		$	1,945
Depreciation and amortization	(392		)	(375		)	(482		)
Interest expense, net	(340		)	(303		)	(288		)
Other income/(expense), net	(2		)	1			6
Income before tax	1,557			1,490			1,181
Income tax expense	(171		)	(99		)	(54		)
Net income	1,386			1,391			1,127
Net income attributable to noncontrolling interests	(2		)	(30		)	(33		)
Net income attributable to PAA	$	1,384		$	1,361		$	1,094

Revenues attributable to geographical areas

	Year Ended December 31,
Revenues (1)	2014		2013		2012
United States	$	34,860	$	32,924	$	29,978
Canada	8,604		9,325		7,819
	$	43,464	$	42,249	$	37,797

(1)

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

Long-lived assets attributable to geographical areas

	December 31,
Long-Lived Assets (1)	2014		2013
United States	$	14,400	$	11,743
Canada	3,650		3,623
	$	18,050	$	15,366

(1)

Excludes long-term derivative assets.

Organization and Basis of Presentation (Details)		12 Months Ended
Organization and Basis of Presentation (Details)	Oct. 01, 2012	Dec. 31, 2014 segment
Organization
Operating segments number		3
General partner ownership interest (as a percent)		2.00%
PAGP limited partner interest in AAP (as a percent)		98.00%
Two-for-One Unit Split
Unit split conversion ratio	2
PAGP \| AAP
Organization
PAGP limited partner interest in AAP (as a percent)		34.10%

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions		12 Months Ended
	Jan. 07, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Foreign Currency Transactions
Gain (loss) on revaluation of foreign currency transactions and monetary assets and liabilities		$ (13)	$ 1	$ (2)
Cash and Cash Equivalents
Repayment of commercial paper notes		(366)	1,110
Outstanding checks included in accounts payable that were reclassified from cash and cash equivalents		94	70
Accounts Receivable
Advance cash payments received from third parties to mitigate credit risk		180	117
Standby letters of credit		$ 198	$ 426
Substantially all accounts receivable, net, maximum age of balances past their scheduled invoice date		30 days	30 days
Allowance for doubtful accounts receivable		$ 4	$ 5
Asset Retirement Obligation [Abstract]
Fair value of asset retirement obligations		$ 36	$ 34
Subsequent Event
Cash and Cash Equivalents
Repayment of commercial paper notes	$ (400)

Acquisitions and Dispositions (Detail) $ / shares in Units, $ in Millions			1 Months Ended	12 Months Ended
	Dec. 12, 2012 USD ($) item	Apr. 01, 2012 USD ($)	Mar. 31, 2012 USD ($)	Dec. 31, 2014 USD ($) entity	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($) $ / shares	Nov. 14, 2014
Business acquisition, allocation of fair value of assets and liabilities
Goodwill				$ 2,465	$ 2,503	$ 2,535
Selected unaudited pro forma results of operations:
Pro Forma, Total revenues						38,729
Pro forma, Net income attributable to PAA						1,149
Pro forma, limited partner interest in net income attributable to PAA						$ 846
Pro forma, Basic net income per limited partner unit (in dollars per unit) \| $ / shares						$ 2.57
Pro forma, Diluted net income per limited partner unit (in dollars per unit) \| $ / shares						$ 2.55
BridgeTex Pipeline Company, LLC
Business acquisition
Interest acquired (as a percent)				50.00%			50.00%
Other 2014 Acquisitions
Business acquisition
Number of additional acquisitions completed (in entities) \| entity				2
Consideration				$ 11
Business acquisition, allocation of fair value of assets and liabilities
Goodwill				$ 1
2013 Acquisitions
Business acquisition
Consideration					19
Business acquisition, allocation of fair value of assets and liabilities
Goodwill					$ 6
BP NGL Acquisition
Business acquisition
Consideration		$ 1,680
Imputed interest		$ 17
Business acquisition, allocation of fair value of assets and liabilities
Working capital						$ 241
Property and equipment						1,081
Linefill						85
Long-term inventory						165
Intangible assets (contract)						130
Goodwill						236
Deferred tax liability						(236)
Environmental liability						(14)
Other long-term liabilities						(5)
Total net assets acquired						1,683
Net proceeds from issuance of common units and senior notes			$ 1,690
Acquisition-related costs						$ 13
Finite Lived Intangible assets
Average Depreciable Life						13 years
BP NGL Acquisition \| Minimum
Property and equipment, useful life
Average Depreciable Life						5 years
BP NGL Acquisition \| Maximum
Property and equipment, useful life
Average Depreciable Life						70 years
USD Rail Terminal Acquisition
Business acquisition
Consideration	$ 503
Number of operating crude oil rail terminals acquired \| item	4
Number of terminals under development acquired \| item	1
Business acquisition, allocation of fair value of assets and liabilities
Working capital						$ 1
Property and equipment						76
Goodwill						426
Other 2012 Acquisitions
Business acquisition
Consideration						150
Business acquisition, allocation of fair value of assets and liabilities
Goodwill						$ 10

Acquisitions and Dispositions (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Dispositions
Proceeds from sale of various property and equipment	$ 28	$ 200	$ 22
Gain (loss) on sale of various property and equipment	$ 1		$ 6
Maximum
Dispositions
Gain (loss) on sale of various property and equipment		$ 1

Net Income Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net Income Per Limited Partner Unit
General partner ownership interest (as a percent)									2.00%
Basic Net Income per Limited Partner Unit
Net income attributable to PAA	$ 389	$ 323	$ 287	$ 384	$ 309	$ 231	$ 292	$ 528	$ 1,384	$ 1,361	$ 1,094
Less: General partner's incentive distribution									(482)	(375)	(289)
Less: General partner 2% ownership									(18)	(19)	(16)
Net income available to limited partners									884	967	789
Less: Undistributed earnings allocated and distributions to participating securities									(6)	(7)	(5)
Net income available to limited partners in accordance with application of the two-class method for MLPs									$ 878	$ 960	$ 784
Basic weighted average limited partner units outstanding (in units)									367	341	325
Basic net income per limited partner unit (in dollars per unit)	$ 0.67	$ 0.52	$ 0.45	$ 0.74	$ 0.59	$ 0.38	$ 0.58	$ 1.28	$ 2.39	$ 2.82	$ 2.41
Diluted Net Income per Limited Partner Unit
Net income attributable to PAA	$ 389	$ 323	$ 287	$ 384	$ 309	$ 231	$ 292	$ 528	$ 1,384	$ 1,361	$ 1,094
Less: General partner's incentive distribution									(482)	(375)	(289)
Less: General partner 2% ownership									(18)	(19)	(16)
Net income available to limited partners									884	967	789
Less: Undistributed earnings allocated and distributions to participating securities									(6)	(6)	(4)
Net income available to limited partners in accordance with application of the two-class method for MLPs									$ 878	$ 961	$ 785
Basic weighted average limited partner units outstanding (in units)									367	341	325
Effect of dilutive securities:
Weighted average LTIP units (in units)									2	2	3
Diluted weighted average limited partner units outstanding (in units)									369	343	328
Diluted net income per limited partner unit (in dollars per unit)	$ 0.67	$ 0.52	$ 0.45	$ 0.73	$ 0.58	$ 0.38	$ 0.57	$ 1.27	$ 2.38	$ 2.80	$ 2.40

Net Income Per Limited Partner Unit (Details 2) - $ / shares	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Basic and Diluted Net Income per Limited Partner Unit
Basic net income per limited partner unit impact (in dollars per unit)	$ (0.20)	$ (0.11)
Diluted net income per limited partner unit impact (in dollars per unit)	$ (0.20)	$ (0.11)

Inventory, Linefill and Base Gas and Long-term Inventory (Details) bbl in Thousands, Mcf in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2014 USD ($) $ / bbl $ / Mcf Mcf bbl	Dec. 31, 2013 USD ($) $ / bbl $ / Mcf Mcf bbl	Dec. 31, 2012 USD ($)
Inventory-related disclosures
Charge related to the write-down of inventory	$ 289	$ 7	$ 128
Gains on derivative instruments	160
Gain on sales of linefill and base gas	8	7	19
Cash received for sales of linefill and base gas	24	40	$ 65
Inventory by category
Inventory	891	1,065
Linefill and base gas	930	798
Long-term inventory	186	251
Total	2,007	2,114
Crude oil
Inventory by category
Inventory	304	540
Linefill and base gas	744	679
Long-term inventory	$ 136	$ 202
Inventory, Volumes (in barrels or in Mcf) \| bbl	6,465	6,951
Linefill and base gas, Volumes (in barrels or in Mcf) \| bbl	11,810	10,966
Long-term inventory, Volumes (in barrels or in Mcf) \| bbl	2,582	2,498
Inventory, Price/Unit of measure (in dollars per unit) \| $ / bbl	47.02	77.69
Linefill and base gas, Price/Unit of measure (in dollars per unit) \| $ / bbl	63.00	61.92
Long-term inventory, Price/Unit of measure (in dollars per unit) \| $ / bbl	52.67	80.86
NGL
Inventory by category
Inventory	$ 454	$ 352
Linefill and base gas	52	62
Long-term inventory	$ 50	$ 49
Inventory, Volumes (in barrels or in Mcf) \| bbl	13,553	8,061
Linefill and base gas, Volumes (in barrels or in Mcf) \| bbl	1,212	1,341
Long-term inventory, Volumes (in barrels or in Mcf) \| bbl	1,681	1,161
Inventory, Price/Unit of measure (in dollars per unit) \| $ / bbl	33.50	43.67
Linefill and base gas, Price/Unit of measure (in dollars per unit) \| $ / bbl	42.90	46.23
Long-term inventory, Price/Unit of measure (in dollars per unit) \| $ / bbl	29.74	42.20
Natural gas
Inventory by category
Inventory	$ 102	$ 150
Linefill and base gas	$ 134	$ 57
Inventory, Volumes (in barrels or in Mcf) \| Mcf	32,317	40,505
Linefill and base gas, Volumes (in barrels or in Mcf) \| Mcf	28,612	16,615
Inventory, Price/Unit of measure (in dollars per unit) \| $ / Mcf	3.16	3.70
Linefill and base gas, Price/Unit of measure (in dollars per unit) \| $ / Mcf	4.68	3.43
Other
Inventory by category
Inventory	$ 31	$ 23

Property and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
Property and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property and Equipment
Interest expense, Capitalized interest	$ 48	$ 38	$ 36
Property and equipment, gross	14,178	12,473
Accumulated depreciation	(1,906)	(1,654)
Property and equipment, net	12,272	10,819
Depreciation expense	319	259	222
Impairments of long-lived assets	10	20	$ 168
Pipelines and related facilities
Property and Equipment
Property and equipment, gross	$ 7,003	6,113
Pipelines and related facilities \| Minimum
Property and Equipment
Estimated Useful Lives	10 years
Pipelines and related facilities \| Maximum
Property and Equipment
Estimated Useful Lives	70 years
Storage, terminal and rail facilities
Property and Equipment
Property and equipment, gross	$ 4,853	4,704
Storage, terminal and rail facilities \| Minimum
Property and Equipment
Estimated Useful Lives	30 years
Storage, terminal and rail facilities \| Maximum
Property and Equipment
Estimated Useful Lives	70 years
Trucking equipment and other
Property and Equipment
Property and equipment, gross	$ 198	150
Trucking equipment and other \| Minimum
Property and Equipment
Estimated Useful Lives	3 years
Trucking equipment and other \| Maximum
Property and Equipment
Estimated Useful Lives	15 years
Construction in progress
Property and Equipment
Property and equipment, gross	$ 1,545	1,008
Office property and equipment
Property and Equipment
Property and equipment, gross	$ 156	125
Office property and equipment \| Minimum
Property and Equipment
Estimated Useful Lives	2 years
Office property and equipment \| Maximum
Property and Equipment
Estimated Useful Lives	50 years
Land and other
Property and Equipment
Property and equipment, gross	$ 423	$ 373

Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
Goodwill (Details) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
Changes in goodwill
Balance at beginning of period	$ 2,503	$ 2,535
Acquisitions	1	6
Foreign currency translation adjustments	(39)	(33)
Purchase price accounting adjustments and other		(5)
Balance at end of period	2,465	2,503
Transportation
Changes in goodwill
Balance at beginning of period	878	897
Acquisitions		6
Foreign currency translation adjustments	(24)	(20)
Purchase price accounting adjustments and other		(5)
Balance at end of period	854	878
Facilities
Changes in goodwill
Balance at beginning of period	1,162	1,171
Acquisitions	1
Foreign currency translation adjustments	(11)	(9)
Balance at end of period	1,152	1,162
Supply and Logistics
Changes in goodwill
Balance at beginning of period	463	467
Foreign currency translation adjustments	(4)	(4)
Balance at end of period	$ 459	$ 463

Investments in Unconsolidated Entities (Details) $ in Millions		1 Months Ended	12 Months Ended
	Nov. 14, 2014 USD ($) bbl / d	Aug. 31, 2012 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)
Equity Method of Accounting
Payments to acquire or subsequent contributions to unconsolidated entities			$ 1,246	$ 133	$ 76
Amount by which investments in unconsolidated entities exceed our share of the underlying equity in the net assets			$ 763	$ 78
Cash received upon formation of equity-method investment					$ 59
Settoon Towing, LLC
Equity Method of Accounting
Ownership interest (as a percent)			50.00%
BridgeTex Pipeline Company, LLC
Equity Method of Accounting
Ownership interest (as a percent)	50.00%		50.00%
Capacity of crude oil pipeline (in barrels per day) \| bbl / d	300,000
Payments to acquire or subsequent contributions to unconsolidated entities	$ 1,088
Working capital adjustments	$ 13
Eagle Ford Pipeline LLC
Equity Method of Accounting
Ownership interest (as a percent)			50.00%
Estimated book value of fixed assets contributed		$ 134
Cash received upon formation of equity-method investment		59
Eagle Ford Pipeline LLC \| Enterprise Products Partners
Equity Method of Accounting
Estimated book value of fixed assets contributed		$ 15
White Cliffs Pipeline, LLC
Equity Method of Accounting
Ownership interest (as a percent)			36.00%
Butte Pipe Line Company
Equity Method of Accounting
Ownership interest (as a percent)			22.00%
Frontier Pipeline Company
Equity Method of Accounting
Ownership interest (as a percent)			22.00%

Investments in Unconsolidated Entities (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Combined summarized financial information for unconsolidated entities
Current assets	$ 184	$ 177
Noncurrent assets	2,303	1,067
Current liabilities	142	57
Noncurrent liabilities	222	211
Revenues	531	344	$ 257
Operating income	301	181	132
Net income	$ 285	$ 172	$ 118

Other Assets, Net (Detail) - USD ($) $ in Millions	12 Months Ended
Other Assets, Net (Detail) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Assets, Net
Intangible assets	$ 676	$ 674
Debt issue costs	92	70
Fair value of derivative instruments	27	30
Other	19	37
Other assets, gross	814	811
Accumulated amortization	(325)	(271)
Other assets, net	489	540
Debt issue costs capitalized during the period	24	9
Gross debt issue costs removed from balance sheet	2	8
Amortization expense related to other assets (including finite-lived intangible assets)	64	96	$ 99
Amortization expense for finite-lived intangible assets	$ 57	$ 85	$ 90

Other Assets, Net (Detail 2) - USD ($) $ in Millions	12 Months Ended
Other Assets, Net (Detail 2) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets
Cost	$ 676	$ 674
Accumulated amortization	(310)	(254)
Net	366	420
Estimated amortization expense related to finite-lived intangible assets for the next five years
2015	52
2016	44
2017	41
2018	36
2019	33
Customer contracts and relationships
Finite-Lived Intangible Assets
Cost	593	591
Accumulated amortization	(288)	(237)
Net	$ 305	354
Customer contracts and relationships \| Minimum
Finite-Lived Intangible Assets
Estimated Useful Lives	1 year
Customer contracts and relationships \| Maximum
Finite-Lived Intangible Assets
Estimated Useful Lives	20 years
Property tax abatement
Finite-Lived Intangible Assets
Cost	$ 38	38
Accumulated amortization	(18)	(14)
Net	$ 20	24
Property tax abatement \| Minimum
Finite-Lived Intangible Assets
Estimated Useful Lives	7 years
Property tax abatement \| Maximum
Finite-Lived Intangible Assets
Estimated Useful Lives	13 years
Other agreements
Finite-Lived Intangible Assets
Cost	$ 37	37
Accumulated amortization	(4)	(3)
Net	$ 33	34
Other agreements \| Minimum
Finite-Lived Intangible Assets
Estimated Useful Lives	25 years
Other agreements \| Maximum
Finite-Lived Intangible Assets
Estimated Useful Lives	70 years
Emission reduction credits
Finite-Lived Intangible Assets
Cost	$ 8	8
Net	$ 8	$ 8

Debt (Details) - USD ($) $ in Millions	12 Months Ended
Debt (Details) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Short-term debt:
Other short-term debt	$ 3	$ 4
Total short-term debt	1,287	1,113
Long-term debt:
Unamortized discounts	(18)	(15)
PAA senior notes, net of unamortized discounts	8,757	6,710
Long-term debt, other	5	5
Total long-term debt	8,762	6,715
Total debt	10,049	7,828
5.25% senior notes due June 2015
Short-term debt:
Senior Notes, Current	$ 150
Long-term debt:
Senior Notes, Noncurrent		$ 150
Debt instrument, interest rate (as a percent)	5.25%	5.25%
3.95% senior notes due September 2015
Short-term debt:
Senior Notes, Current	$ 400
Long-term debt:
Senior Notes, Noncurrent		$ 400
Debt instrument, interest rate (as a percent)	3.95%	3.95%
5.88% senior notes due August 2016
Long-term debt:
Senior Notes, Noncurrent	$ 175	$ 175
Debt instrument, interest rate (as a percent)	5.88%	5.88%
6.13% senior notes due January 2017
Long-term debt:
Senior Notes, Noncurrent	$ 400	$ 400
Debt instrument, interest rate (as a percent)	6.13%	6.13%
6.50% senior notes due May 2018
Long-term debt:
Senior Notes, Noncurrent	$ 600	$ 600
Debt instrument, interest rate (as a percent)	6.50%	6.50%
8.75% senior notes due May 2019
Long-term debt:
Senior Notes, Noncurrent	$ 350	$ 350
Debt instrument, interest rate (as a percent)	8.75%	8.75%
2.60% senior notes due December 2019
Long-term debt:
Senior Notes, Noncurrent	$ 500
Debt instrument, interest rate (as a percent)	2.60%
5.75% senior notes due January 2020
Long-term debt:
Senior Notes, Noncurrent	$ 500	$ 500
Debt instrument, interest rate (as a percent)	5.75%	5.75%
5.00% senior notes due February 2021
Long-term debt:
Senior Notes, Noncurrent	$ 600	$ 600
Debt instrument, interest rate (as a percent)	5.00%	5.00%
3.65% senior notes due June 2022
Long-term debt:
Senior Notes, Noncurrent	$ 750	$ 750
Debt instrument, interest rate (as a percent)	3.65%	3.65%	3.65%
2.85% senior notes due January 2023
Long-term debt:
Senior Notes, Noncurrent	$ 400	$ 400
Debt instrument, interest rate (as a percent)	2.85%	2.85%	2.85%
3.85% senior notes due October 2023
Long-term debt:
Senior Notes, Noncurrent	$ 700	$ 700
Debt instrument, interest rate (as a percent)	3.85%	3.85%
3.60% senior notes due November 2024
Long-term debt:
Senior Notes, Noncurrent	$ 750
Debt instrument, interest rate (as a percent)	3.60%
6.70% senior notes due May 2036
Long-term debt:
Senior Notes, Noncurrent	$ 250	$ 250
Debt instrument, interest rate (as a percent)	6.70%	6.70%
6.65% senior notes due January 2037
Long-term debt:
Senior Notes, Noncurrent	$ 600	$ 600
Debt instrument, interest rate (as a percent)	6.65%	6.65%
5.15% senior notes due June 2042
Long-term debt:
Senior Notes, Noncurrent	$ 500	$ 500
Debt instrument, interest rate (as a percent)	5.15%	5.15%	5.15%
4.30% senior notes due January 2043
Long-term debt:
Senior Notes, Noncurrent	$ 350	$ 350
Debt instrument, interest rate (as a percent)	4.30%	4.30%	4.30%
4.70% senior notes due June 2044
Long-term debt:
Senior Notes, Noncurrent	$ 700
Debt instrument, interest rate (as a percent)	4.70%
4.90% senior notes due February 2045
Long-term debt:
Senior Notes, Noncurrent	$ 650
Debt instrument, interest rate (as a percent)	4.90%
Commercial paper program
Short-term debt:
PAA commercial paper notes, bearing a weighted-average interest rate of 0.46% and 0.33%, respectively	$ 734	$ 1,109
Repayment period	1 year
Weighted average interest rate, short-term (as a percent)	0.46%	0.33%

Debt (Details 2) $ in Millions			1 Months Ended		12 Months Ended
Debt (Details 2) $ in Millions	Dec. 13, 2013 USD ($)	Sep. 04, 2012 USD ($)	Jan. 31, 2015 USD ($)	Aug. 31, 2014	Dec. 31, 2014 USD ($) item	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Oct. 31, 2014 USD ($)	Sep. 30, 2014 USD ($)
Debt
Consolidated subsidiary, ownership interest held by the parent (as a percent)					100.00%
Repayments of senior notes						$ 250	$ 500
Commercial paper program
Debt
Maximum aggregate borrowing capacity					$ 3,000			$ 3,000	$ 1,500
Letters of credit
Debt
Outstanding letters of credit					$ 87	41
Letters of credit \| Maximum
Debt
Periods for which letters of credit are issued					70 days
PAA senior secured hedged inventory facility
Debt
Borrowing capacity					$ 1,400
Maximum aggregate borrowing capacity					$ 1,900
Basis Variable interest rate used					Eurocurrency Rate or the Base Rate
Number of years by which maturity date of credit facility may be extended					1 year
Number of years by which maturity date of credit facility was extended during the period.				1 year
PAA senior secured hedged inventory facility \| Minimum
Debt
Credit facility extensions available \| item					1
PAA senior secured hedged inventory facility \| Letters of credit
Debt
Borrowing capacity					$ 400
PAA senior unsecured revolving credit facility
Debt
Borrowing capacity					1,600
Maximum aggregate borrowing capacity					$ 2,100
Basis Variable interest rate used					Eurocurrency Rate, the Base Rate or the Canadian Prime Rate
Number of years by which maturity date of credit facility may be extended					1 year
Number of years by which maturity date of credit facility was extended during the period.				1 year
PAA senior unsecured revolving credit facility \| Minimum
Debt
Credit facility extensions available \| item					1
PAA senior unsecured 364-day revolving credit facility \| Subsequent Event
Debt
Expiration period for credit facility			364 days
Borrowing capacity			$ 1,000
Basis Variable interest rate used					Eurocurrency Rate or the Base Rate
Credit agreements and commercial paper program
Debt
Total borrowings					$ 70,900	31,000	12,900
Total repayments					71,300	31,000	$ 12,200
PAA senior notes
Debt
Debt instrument face value					9,300	6,700
PAA senior notes \| Level 2
Debt
Debt instrument fair value					$ 9,900	$ 7,200
2.60% senior notes due December 2019
Debt
Debt instrument, interest rate (as a percent)					2.60%
Percentage of face value at which senior notes are sold					99.813%
Debt instrument face value					$ 500
4.90% senior notes due February 2045
Debt
Debt instrument, interest rate (as a percent)					4.90%
Percentage of face value at which senior notes are sold					99.876%
Debt instrument face value					$ 650
3.60% senior notes due November 2024
Debt
Debt instrument, interest rate (as a percent)					3.60%
Percentage of face value at which senior notes are sold					99.842%
Debt instrument face value					$ 750
4.70% senior notes due June 2044
Debt
Debt instrument, interest rate (as a percent)					4.70%
Percentage of face value at which senior notes are sold					99.734%
Debt instrument face value					$ 700
3.85% senior notes due October 2023
Debt
Debt instrument, interest rate (as a percent)					3.85%	3.85%
Percentage of face value at which senior notes are sold						99.792%
Debt instrument face value						$ 700
2.85% senior notes due January 2023
Debt
Debt instrument, interest rate (as a percent)					2.85%	2.85%	2.85%
Percentage of face value at which senior notes are sold							99.752%
Debt instrument face value							$ 400
4.30% senior notes due January 2043
Debt
Debt instrument, interest rate (as a percent)					4.30%	4.30%	4.30%
Percentage of face value at which senior notes are sold							99.925%
Debt instrument face value							$ 350
3.65% senior notes due June 2022
Debt
Debt instrument, interest rate (as a percent)					3.65%	3.65%	3.65%
Percentage of face value at which senior notes are sold							99.823%
Debt instrument face value							$ 750
5.15% senior notes due June 2042
Debt
Debt instrument, interest rate (as a percent)					5.15%	5.15%	5.15%
Percentage of face value at which senior notes are sold							99.755%
Debt instrument face value							$ 500
5.63% senior notes
Debt
Debt instrument, interest rate (as a percent)	5.63%
Repayments of senior notes	$ 250
4.25% senior notes
Debt
Debt instrument, interest rate (as a percent)		4.25%
Repayments of senior notes		$ 500

Debt (Detail 3) $ in Millions	12 Months Ended
Debt (Detail 3) $ in Millions	Dec. 31, 2014 USD ($)
Debt
Weighted-average life of senior notes outstanding	13 years
Maturities
2015	$ 550
2016	175
2017	400
2018	600
2019	850
Thereafter	6,750
Total	9,325
Aggregate unamortized net discount excluded from debt maturities	$ 18
PAA senior notes
Debt
Debt Covenant Compliance	As of December 31, 2014, we were in compliance with the covenants contained in our credit agreements and indentures.
PAA senior secured hedged inventory facility
Debt
Coverage ratio of debt-to-EBITDA, maximum	5.00
Ratio of debt-to-EBITDA during acquisition period, maximum	5.50
Acquisition period	9 months
Threshold for acquisition period qualification	$ 150
Debt Covenant Compliance	As of December 31, 2014, we were in compliance with the covenants contained in our credit agreements and indentures.
PAA senior unsecured revolving credit facility
Debt
Coverage ratio of debt-to-EBITDA, maximum	5.00
Ratio of debt-to-EBITDA during acquisition period, maximum	5.50
Acquisition period	9 months
Threshold for acquisition period qualification	$ 150
Debt Covenant Compliance	As of December 31, 2014, we were in compliance with the covenants contained in our credit agreements and indentures.

Partners' Capital and Distributions (Details) - $ / shares	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Partners' Capital and Distributions
Common unitholders, units outstanding (in units)	375,107,793	359,133,200
Ownership interest (as a percent)	98.00%
General partner ownership interest (as a percent)	2.00%
Percentage of available cash distributed (as a percent)	100.00%
Number of days after end of quarter within which distributions must be paid to unitholders	45 days
Partners Capital and Distribution
Percent of distribution amount to the general partner before incentive distributions	2.00%
General Partner Distribution - Level One
Partners Capital and Distribution
Percent of distribution amount to the general partner before incentive distributions	2.00%
General Partner Distribution - Level Two
Partners Capital and Distribution
Percent of distribution amount to the general partner above threshold	15.00%
Quarterly incentive distribution threshold amount (in dollars per unit)	$ 0.2250
General Partner Distribution - Level Three
Partners Capital and Distribution
Percent of distribution amount to the general partner above threshold	25.00%
Quarterly incentive distribution threshold amount (in dollars per unit)	$ 0.2475
General Partner Distribution - Level Four
Partners Capital and Distribution
Percent of distribution amount to the general partner above threshold	50.00%
Quarterly incentive distribution threshold amount (in dollars per unit)	$ 0.3375

Partners' Capital and Distributions (Details 2) - $ / shares	3 Months Ended												12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Partners' Capital and Distributions
Cash distributions per limited partner unit (in dollars per unit)	$ 0.6600	$ 0.6450	$ 0.6300	$ 0.6150	$ 0.6000	$ 0.5875	$ 0.5750	$ 0.5625	$ 0.5425	$ 0.5325	$ 0.5225	$ 0.5125	$ 2.5500	$ 2.3250	$ 2.11
Cash distributions per limited partner unit in excess over MQD (in dollars per unit)	$ 0.4350	$ 0.4200	$ 0.4050	$ 0.3900	$ 0.3750	$ 0.3625	$ 0.3500	$ 0.3375	$ 0.3175	$ 0.3075	$ 0.2975	$ 0.2875

Partners' Capital and Distributions (Details 3) - General Partner - BP NGL Acquisition - PNG Merger - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reduction in incentive distributions
Reduction in incentive distributions	$ 23,000	$ 15,000	$ 11,000
Reduction in incentive distributions per quarter in 2015 (in dollars per quarter)	5,500
Reduction in incentive distributions per quarter in 2016 (in dollars per quarter)	5,000
Reduction in incentive distributions per quarter after 2016 (in dollars per quarter)	$ 3,750

Partners' Capital and Distributions (Details 4) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended												12 Months Ended
	Feb. 13, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Partners Capital and Distribution
Distributions paid to common unit holders														$ 934	$ 791	$ 684
Distributions paid to General Partner - 2%														19	16	14
Distributions paid to General Partner - Incentive														454	353	271
Total distributions paid during the period														$ 1,410	$ 1,209	$ 1,017
Cash distributions per limited partner unit (in dollars per unit)		$ 0.6600	$ 0.6450	$ 0.6300	$ 0.6150	$ 0.6000	$ 0.5875	$ 0.5750	$ 0.5625	$ 0.5425	$ 0.5325	$ 0.5225	$ 0.5125	$ 2.5500	$ 2.3250	$ 2.11
General Partner Interest Distribution Percentage														2.00%
Subsequent Event \| Fourth Quarter Distribution
Partners Capital and Distribution
Distributions paid to common unit holders	$ 254
Distributions paid to General Partner - 2%	5
Distributions paid to General Partner - Incentive	131
Total distributions paid during the period	$ 390
Cash distributions per limited partner unit (in dollars per unit)	$ 0.6750
Distribution declared, date														Jan. 08, 2015
Unitholders of record, date														Jan. 30, 2015
Distribution Date														Feb. 13, 2015
General Partner Interest Distribution Percentage	2.00%
Partners' Capital Excluding Noncontrolling Interests
Partners Capital and Distribution
Total distributions paid during the period														$ 1,407	$ 1,160	$ 969

Partners' Capital and Distributions (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Partners Capital and Distribution
Units Issued			23,563,707
Net proceeds from sale	$ 866	$ 477	$ 979
Contribution from general partner	$ 18	$ 9	$ 20
Continuous Offering Program
Partners Capital and Distribution
Units Issued	15,375,810	8,644,807	12,063,707
Net proceeds from sale	$ 866	$ 477	$ 524
Commissions paid	9	$ 5	6
Continuous Offering Program \| Minimum
Partners Capital and Distribution
Aggregate offer price of common stock			$ 300
Continuous Offering Program \| Maximum
Partners Capital and Distribution
Aggregate offer price of common stock	$ 900
Marketed Offering
Partners Capital and Distribution
Units Issued			11,500,000
Net proceeds from sale			$ 455

Partners' Capital and Distributions (Details 6) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
	Dec. 30, 2013	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Partners Capital and Distribution
Ownership interest (as a percent)			98.00%
Contribution from general partner		$ 9	$ 18	$ 9	$ 20
Net impact of PNG Merger on total partners' capital				$ 12
PNG \| Subordinated units
Partners Capital and Distribution
Ownership interest (as a percent)	100.00%
Common Units \| PNG
Partners Capital and Distribution
Ownership interest (as a percent)	46.00%
Outstanding units (in units)	61,200,000
PNG Merger
Partners Capital and Distribution
Number of PAA common units issued for each outstanding common unit of PNG (in units)		0.445		0.445
PAA common units issued in exchange for outstanding PNG common units (in units)		14,700,000
Value of PAA common units issued in exchange for outstanding PNG common units		$ 760
Equity-classified loss from purchase of PNG common units		290
Contribution from general partner		16		$ 16
Transaction costs		4
Net impact of PNG Merger on total partners' capital		$ 12
SLC Pipeline LLC
Partners Capital and Distribution
Noncontrolling interests in subsidiaries (as a percent)			25.00%

Partners' Capital and Distributions (Details 7) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Partners Capital and Distribution
Issuance of PNG common units (in units)		23,563,707
Increase in capital from PNG common unit issuances	$ 40
PNG Common Unit Issuance
Partners Capital and Distribution
Issuance of PNG common units (in units)	1,900,000
Increase in noncontrolling interest from PNG common unit issuances	$ 32
PNG Common Unit Issuance \| Partners' Capital Excluding Noncontrolling Interests
Partners Capital and Distribution
Increase in capital from PNG common unit issuances	$ 8

Partners' Capital and Distributions (Detail 8) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net Income attributable to PAA
Net income attributable to PAA	$ 389	$ 323	$ 287	$ 384	$ 309	$ 231	$ 292	$ 528	$ 1,384	$ 1,361	$ 1,094
Transfers to/from noncontrolling interests:
Increase in capital from sale of PNG common units										40
Net transfers to/from noncontrolling interests										12
Partners' Capital Excluding Noncontrolling Interests
Transfers to/from noncontrolling interests:
Increase in capital from sale of PNG common units										8
Net transfers to/from noncontrolling interests										475
Partners' Capital Excluding Noncontrolling Interests \| PNG
Net Income attributable to PAA
Net income attributable to PAA										1,361
Transfers to/from noncontrolling interests:
Increase in capital from sale of PNG common units										8
Decrease in capital from purchase of PNG common units in conjunction with the PNG Merger										(290)
Net transfers to/from noncontrolling interests										(282)
Change from net income attributable to PAA and net transfers to/from noncontrolling interests										$ 1,079

- Definition

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

+ References + Details

Derivatives and Risk Management Activities (Details) bbl in Millions, Mcf in Millions, MWh in Millions	12 Months Ended
	Dec. 31, 2014 bbl / d MWh Mcf bbl
Net long position associated with crude oil purchases
Commodity Price Risk Hedging:
Average derivative positions notional amount per day (in barrels) \| bbl / d	269,400
Derivative position notional amount (in barrels or Mcf)	8.4
Net short time spread position hedging anticipated crude oil lease gathering purchases
Commodity Price Risk Hedging:
Average derivative positions notional amount per day (in barrels) \| bbl / d	20,500
Derivative position notional amount (in barrels or Mcf)	10.0
Crude oil grade spread positions
Commodity Price Risk Hedging:
Average derivative positions notional amount per day (in barrels) \| bbl / d	33,600
Derivative position notional amount (in barrels or Mcf)	11.2
Net short natural gas position related to anticipated natural gas sales
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf) \| Mcf	28.1
Net short position related to anticipated sales of crude oil, NGL and refined products inventory
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	9.3
Long position related to anticipated crude oil linefill requirements
Commodity Price Risk Hedging:
Average derivative positions notional amount per day (in barrels) \| bbl / d	32,400
Derivative position notional amount (in barrels or Mcf)	1.0
PLA crude oil net short position
Commodity Price Risk Hedging:
Average derivative positions notional amount per day (in barrels) \| bbl / d	1,300
Derivative position notional amount (in barrels or Mcf)	0.4
PLA crude oil long call position
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	0.8
Long natural gas position for natural gas purchases
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf) \| Mcf	26.1
Short propane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	4.1
Short butane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	1.2
Short WTI position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	0.4
Long power position for power supply requirements
Commodity Price Risk Hedging:
Derivative position notional amount (in megawatt hours) \| MWh	0.4

Derivatives and Risk Management Activities (Details 2) $ in Millions	1 Months Ended
	Apr. 30, 2014 USD ($) contract	Aug. 31, 2013 USD ($) contract	Dec. 31, 2012 USD ($) contract	Mar. 31, 2012 USD ($) contract	Jan. 31, 2015 USD ($) contract	Dec. 31, 2014 USD ($) contract	Dec. 31, 2013 USD ($)	Dec. 31, 2011 USD ($)
Interest Rate Risk Hedging
Net deferred gains (losses) from interest rate risk hedging included in AOCI			$ 80			$ (467)	$ (97)	$ 54
Interest Rate Derivatives
Interest Rate Risk Hedging
Net deferred gains (losses) from interest rate risk hedging included in AOCI						$ (161)
10 forward starting interest rate swaps (30-year) \| Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives (in contracts) \| contract						10
Notional amount of derivatives						$ 250
Rate of fixed interest to be received on interest rate swap (as a percent)						3.60%
8 forward starting interest rate swaps (30-year), one \| Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives (in contracts) \| contract						8
Notional amount of derivatives						$ 200
Rate of fixed interest to be received on interest rate swap (as a percent)						3.06%
8 forward starting interest rate swaps (30-year), two \| Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives (in contracts) \| contract						8
Notional amount of derivatives						$ 200
Rate of fixed interest to be received on interest rate swap (as a percent)						3.14%
8 forward starting interest rate swaps (30-year), three \| Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives (in contracts) \| contract						8
Notional amount of derivatives						$ 200
Rate of fixed interest to be received on interest rate swap (as a percent)						3.20%
8 forward starting interest rate swaps \| Subsequent Event
Interest Rate Risk Hedging
Number of interest rate derivatives (in contracts) \| contract					8
Notional amount of derivatives					$ 200
Rate of fixed interest to be received on interest rate swap (as a percent)					2.83%
Treasury lock agreements entered into in anticipation of April 2014 issuance of senior notes \| Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives terminated (in contracts) \| contract	5
Notional amount of derivatives	$ 250
Cash received (paid) in connection with termination of interest rate derivatives	$ (7)
Rate of fixed interest to be received on interest rate swap (as a percent)	3.62%
5 forward starting interest rate swaps (30-year) \| Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives terminated (in contracts) \| contract		5
Notional amount of derivatives		$ 125
Cash received (paid) in connection with termination of interest rate derivatives		$ 11
Rate of fixed interest to be received on interest rate swap (as a percent)		3.39%
5 forward starting interest rate swaps (30-year) \| Interest expense \| Cash flow hedge
Interest Rate Risk Hedging
Gain / (loss) on derivative instruments recognized in interest expense attributable to the ineffective portion of the swaps		$ 3
6 forward starting interest rate swaps (30-year) \| Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives terminated (in contracts) \| contract			6
Notional amount of derivatives			$ 250
Cash received (paid) in connection with termination of interest rate derivatives			$ (89)
Rate of fixed interest to be received on interest rate swap (as a percent)			4.24%
4 forward starting interest rate swaps (10-year) \| Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives terminated (in contracts) \| contract				4
Notional amount of derivatives				$ 200
Cash received (paid) in connection with termination of interest rate derivatives				$ (24)
Rate of fixed interest to be received on interest rate swap (as a percent)				3.46%
4 forward starting interest rate swaps (10-year) \| Interest expense \| Cash flow hedge
Interest Rate Risk Hedging
Gain / (loss) on derivative instruments recognized in interest expense attributable to the ineffective portion of the swaps				$ (1)

Derivatives and Risk Management Activities (Details 3) $ in Millions, $ in Millions	Dec. 31, 2014 CAD ($) $ / $	Dec. 31, 2014 USD ($) $ / $
Forward exchange contracts that exchange CAD for USD at the rate USD 1.00 to CAD 1.16 maturing in 2015
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 535	$ 460
Average exchange rate	1.16	1.16
Forward exchange contracts that exchange USD for CAD at the rate USD 1.00 to CAD 1.12 maturing in 2015
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 387	$ 345
Average exchange rate	1.12	1.12

Derivatives and Risk Management Activities (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Impact of derivative activities recognized in earnings
Total	$ 153	$ (41)	$ 124
Commodity Derivatives \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	205	(39)	72
Commodity Derivatives \| Facilities segment revenues
Impact of derivative activities recognized in earnings
Total		(11)	3
Commodity Derivatives \| Purchases and related costs
Impact of derivative activities recognized in earnings
Total			46
Commodity Derivatives \| Field Operating costs
Impact of derivative activities recognized in earnings
Total	(21)	8	1
Interest Rate Derivatives \| Interest expense
Impact of derivative activities recognized in earnings
Total	(5)	(4)	(3)
Foreign Currency Derivatives \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	(28)		(1)
Foreign Currency Derivatives \| Other income/(expense), net
Impact of derivative activities recognized in earnings
Total	2	5	6
Derivatives in Hedging Relationships
Impact of derivative activities recognized in earnings
Gain/(loss) reclassified from AOCI into income	(4)	66	62
Other gain/(loss) recognized in income		1
Derivatives in Hedging Relationships \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Gain/(loss) reclassified from AOCI into income	7
Derivatives in Hedging Relationships \| Commodity Derivatives \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Gain/(loss) reclassified from AOCI into income	(1)	78	12
Other gain/(loss) recognized in income		(1)
Derivatives in Hedging Relationships \| Commodity Derivatives \| Facilities segment revenues
Impact of derivative activities recognized in earnings
Gain/(loss) reclassified from AOCI into income		(10)	3
Other gain/(loss) recognized in income		(1)	(1)
Derivatives in Hedging Relationships \| Commodity Derivatives \| Purchases and related costs
Impact of derivative activities recognized in earnings
Gain/(loss) reclassified from AOCI into income			45
Derivatives in Hedging Relationships \| Interest Rate Derivatives \| Interest expense
Impact of derivative activities recognized in earnings
Gain/(loss) reclassified from AOCI into income	(5)	(7)	(4)
Other gain/(loss) recognized in income		3	1
Derivatives in Hedging Relationships \| Foreign Currency Derivatives \| Other income/(expense), net
Impact of derivative activities recognized in earnings
Gain/(loss) reclassified from AOCI into income	2	5	6
Derivatives in Hedging Relationships \| Hedged Transactions probable of not occurring \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Gain/(loss) reclassified from AOCI into income		3
Derivatives in Hedging Relationships \| Hedged Transactions probable of not occurring \| Facilities segment revenues
Impact of derivative activities recognized in earnings
Gain/(loss) reclassified from AOCI into income		(1)
Derivatives Not Designated as a Hedge
Impact of derivative activities recognized in earnings
Total	157	(108)	62
Derivatives Not Designated as a Hedge \| Commodity Derivatives \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	206	(116)	60
Derivatives Not Designated as a Hedge \| Commodity Derivatives \| Facilities segment revenues
Impact of derivative activities recognized in earnings
Total			1
Derivatives Not Designated as a Hedge \| Commodity Derivatives \| Purchases and related costs
Impact of derivative activities recognized in earnings
Total			1
Derivatives Not Designated as a Hedge \| Commodity Derivatives \| Field Operating costs
Impact of derivative activities recognized in earnings
Total	(21)	$ 8	1
Derivatives Not Designated as a Hedge \| Foreign Currency Derivatives \| Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	$ (28)		$ (1)

Derivatives and Risk Management Activities (Details 5) $ in Millions	12 Months Ended
	Dec. 31, 2014 USD ($) contract	Dec. 31, 2013 USD ($) contract	Dec. 31, 2012 USD ($)
Derivatives disclosures
Asset Derivatives Fair Value	$ 493	$ 133
Liability Derivatives Fair Value	(384)	(157)
Net gain (loss) deferred in AOCI	(159)
Net gain (loss) expected to be reclassified to earnings in next 12 months	14
Gain (loss) expected to be reclassified to earnings through 2048	(173)
Net deferred gain/(loss) recognized in AOCI on derivatives (effective portion)	(86)	109	$ 44
Broker payable	133
Broker receivable		161
Initial margin	126	85
Variation margin posted/(returned)	$ (259)	$ 76
Number of outstanding derivatives containing credit-risk related contingent features \| contract	0	0
Derivative credit-risk related contingent features	none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings
Commodity Derivatives
Derivatives disclosures
Net deferred gain/(loss) recognized in AOCI on derivatives (effective portion)	$ 15	$ 37	56
Interest Rate Derivatives
Derivatives disclosures
Net deferred gain/(loss) recognized in AOCI on derivatives (effective portion)	(103)	72	$ (12)
Foreign Currency Derivatives
Derivatives disclosures
Net deferred gain/(loss) recognized in AOCI on derivatives (effective portion)	2
Derivatives in Hedging Relationships
Derivatives disclosures
Asset Derivatives Fair Value	31	67
Liability Derivatives Fair Value	(83)	(24)
Derivatives in Hedging Relationships \| Commodity Derivatives \| Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	23	36
Liability Derivatives Fair Value	(12)	(24)
Derivatives in Hedging Relationships \| Commodity Derivatives \| Other long-term assets
Derivatives disclosures
Asset Derivatives Fair Value	8	5
Liability Derivatives Fair Value	(1)
Derivatives in Hedging Relationships \| Interest Rate Derivatives \| Other long-term assets
Derivatives disclosures
Asset Derivatives Fair Value		26
Derivatives in Hedging Relationships \| Interest Rate Derivatives \| Other current liabilities
Derivatives disclosures
Liability Derivatives Fair Value	(44)
Derivatives in Hedging Relationships \| Interest Rate Derivatives \| Other long-term liabilities
Derivatives disclosures
Liability Derivatives Fair Value	(26)
Derivatives Not Designated as a Hedge
Derivatives disclosures
Asset Derivatives Fair Value	462	66
Liability Derivatives Fair Value	(301)	(133)
Derivatives Not Designated as a Hedge \| Commodity Derivatives \| Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	439	60
Liability Derivatives Fair Value	(246)	(117)
Derivatives Not Designated as a Hedge \| Commodity Derivatives \| Other long-term assets
Derivatives disclosures
Asset Derivatives Fair Value	23	5
Liability Derivatives Fair Value	(3)	(6)
Derivatives Not Designated as a Hedge \| Commodity Derivatives \| Other current liabilities
Derivatives disclosures
Asset Derivatives Fair Value		1
Liability Derivatives Fair Value	(35)	(5)
Derivatives Not Designated as a Hedge \| Commodity Derivatives \| Other long-term liabilities
Derivatives disclosures
Liability Derivatives Fair Value	(5)	(1)
Derivatives Not Designated as a Hedge \| Foreign Currency Derivatives \| Other current liabilities
Derivatives disclosures
Liability Derivatives Fair Value	$ (12)	$ (4)

Derivatives and Risk Management Activities (Details 6) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
Derivative Asset Positions
Gross Position - Asset	$ 493	$ 133
Netting Adjustment	(262)	(148)
Cash collateral received	(133)
Cash collateral paid		161
Net Position - Asset	98	146
Derivative Liability Positions
Gross Position - Liability	(384)	(157)
Netting Adjustment	262	148
Net Position - Liability	(122)	(9)
Other current assets
Derivative Asset Positions
Net Position - Asset	71	116
Other long-term assets
Derivative Asset Positions
Net Position - Asset	27	30
Other current liabilities
Derivative Liability Positions
Net Position - Liability	(91)	(8)
Other long-term liabilities
Derivative Liability Positions
Net Position - Liability	$ (31)	$ (1)

Derivatives and Risk Management Activities (Details 7) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Level 3
Rollforward of Level 3 Net Asset/(Liability)
Beginning Balance	$ (3)	$ 4
Total gains/(losses) for the period:
Included in earnings		(1)
Settlements	3	(3)
Derivatives entered into during the period	15	(3)
Ending Balance	15	(3)
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the periods	15	(4)
Recurring Fair Value Measures
Recurring Fair Value Measures
Net derivative asset/(liability)	109	(24)
Recurring Fair Value Measures \| Commodity Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	191	(46)
Recurring Fair Value Measures \| Interest Rate Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	(70)	26
Recurring Fair Value Measures \| Foreign Currency Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	(12)	(4)
Recurring Fair Value Measures \| Level 1
Recurring Fair Value Measures
Net derivative asset/(liability)	(85)	16
Recurring Fair Value Measures \| Level 1 \| Commodity Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	(85)	16
Recurring Fair Value Measures \| Level 2
Recurring Fair Value Measures
Net derivative asset/(liability)	179	(37)
Recurring Fair Value Measures \| Level 2 \| Commodity Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	261	(59)
Recurring Fair Value Measures \| Level 2 \| Interest Rate Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	(70)	26
Recurring Fair Value Measures \| Level 2 \| Foreign Currency Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	(12)	(4)
Recurring Fair Value Measures \| Level 3
Recurring Fair Value Measures
Net derivative asset/(liability)	15	(3)
Recurring Fair Value Measures \| Level 3 \| Commodity Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	$ 15	$ (3)

Income Taxes (Detail) - USD ($) $ in Millions	12 Months Ended
Income Taxes (Detail) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current tax expense:
State income tax	$ 1	$ 1	$ 2
Canadian federal and provincial income tax	70	99	51
Total current tax expense	71	100	53
Deferred tax (benefit)/expense:
Canadian federal and provincial income tax	100	(1)	1
Total deferred tax (benefit)/expense	100	(1)	1
Total income tax expense	$ 171	$ 99	$ 54

Income Taxes (Detail 2) - USD ($) $ in Millions	12 Months Ended
Income Taxes (Detail 2) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income before tax	$ 1,557	$ 1,490	$ 1,181
Partnership earnings not subject to current Canadian tax	(976)	(1,187)	(1,046)
Partnership earnings subject to current Canadian tax	$ 581	$ 303	$ 135
Canadian federal and provincial corporate tax rate (as a percent)	25.00%	25.00%	25.00%
Income tax at statutory rate	$ 145	$ 76	$ 34
Canadian withholding tax	16	19	18
Canadian permanent differences and rate changes	9	3
State income tax	1	1	2
Total income tax expense	171	99	$ 54
Deferred tax assets:
Book accruals in excess of current tax deductions	29	41
Net operating losses	2
Derivative instruments		15
Total deferred tax assets	31	56
Deferred tax liabilities:
Derivative instruments	(71)
Property and equipment in excess of tax values	(322)	(332)
Other	(49)	(66)
Total deferred tax liabilities	(442)	(398)
Net deferred tax assets/(liabilities)	(411)	(342)
Foreign
Deferred tax liabilities:
Operating loss carryforwards	8
Other long-term assets
Deferred tax assets:
Net deferred tax assets/(liabilities)	2
Other current liabilities
Deferred tax liabilities:
Net deferred tax assets/(liabilities)	(64)
Other long-term liabilities
Deferred tax liabilities:
Net deferred tax assets/(liabilities)	$ (349)	$ (342)

Major Customers and Concentration of Credit Risk (Details) - Revenues - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Marathon Petroleum Corporation
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue	17.00%	15.00%	16.00%
ExxonMobil Corporation
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue	15.00%	13.00%	13.00%
Phillips 66
Major Customers and Concentration of Credit Risk
Major customer percentage of total revenue		11.00%

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Nov. 14, 2014
Related party transaction
Costs reimbursed to general partner	$ 598	$ 567	$ 535
Proceeds from sales of assets	$ 28	200	22
BridgeTex Pipeline Company, LLC
Related party transaction
Interest acquired (as a percent)	50.00%			50.00%
Oxy
Related party transaction
Related party ownership of general partner interest (as a percent)	13.20%
Revenues	$ 1,212	1,309	1,636
Purchases and related costs	925	863	557
Trade accounts receivable and other receivables, gross	489	133
Accounts payable, gross	441	181
Oxy \| BridgeTex Pipeline Company, LLC
Related party transaction
Interest acquired (as a percent)				50.00%
Equity Method Investees
Related party transaction
Revenues	3	33	18
Purchases and related costs	75	79	$ 42
Trade accounts receivable and other receivables, gross		2
Accounts payable, gross	6	$ 6
Equity Method Investees \| Maximum
Related party transaction
Trade accounts receivable and other receivables, gross	1
Eagle Ford Pipeline LLC
Related party transaction
Proceeds from sales of assets	$ 25

Equity-Indexed Compensation Plans (Details) shares in Millions	1 Months Ended	12 Months Ended
	Nov. 30, 2013 plan	Dec. 31, 2014 $ / shares shares	Dec. 31, 2013 shares	Dec. 31, 2012 shares	Dec. 31, 2011 shares
Long-Term Incentive Plan Awards
Equity-Indexed Compensation Plans
Units outstanding (in units)		7.3	8.4	6.0	8.0
Units outstanding that include DERs (in units)		3.5
DERs currently vested (in units)		3.2
Long-Term Incentive Plan Awards \| Range of annualized vesting distribution amount from $2.075 to $3.200
Equity-Indexed Compensation Plans
Units outstanding (in units)		7.3
Estimated unit vesting in 2015 (in units)		2.1
Estimated unit vesting in 2016 (in units)		2.1
Estimated unit vesting in 2017 (in units)		1.8
Estimated unit vesting in 2018 (in units)		1.2
Estimated unit vesting thereafter (in units)		0.1
Annualized distribution, low end of range (in dollars per unit) \| $ / shares		$ 2.075
Annualized distribution, high end of range (in dollars per unit) \| $ / shares		$ 3.200
PAA 2013 LTIP
Equity-Indexed Compensation Plans
Number of long-term incentive plans that are consolidated into single plan \| plan	3
Authorized grants (in units)		13.1
PNG Successor LTIP
Equity-Indexed Compensation Plans
Authorized grants (in units)		1.3
2006 Plan
Equity-Indexed Compensation Plans
Authorized grants (in units)		4.2

Equity-Indexed Compensation Plans (Details 2) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	1 Months Ended		12 Months Ended
	May 31, 2012	May 31, 2011	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Long-Term Incentive Plan Awards
Outstanding (in units)
Outstanding at beginning of period (in units)			8.4	6.0	8.0
Granted (in units)			1.2	4.1	1.5
Vested (in units)			(1.9)	(1.8)	(3.2)
Cancelled or forfeited (in units)			(0.4)	(0.3)	(0.3)
Conversion of PNG unit-denominated awards into PAA unit-denominated awards (in units)				0.4
Outstanding at end of period (in units)			7.3	8.4	6.0
Weighted Average Grant Date Fair Value per Unit
Outstanding at beginning of period (in dollars per unit)			$ 36.97	$ 25.55	$ 21.77
Granted (in dollars per unit)			47.68	47.60	33.90
Vested (in dollars per unit)			25.49	24.79	19.82
Cancelled or forfeited (in dollars per unit)			40.14	36.70	29.36
Conversion of PNG unit-denominated awards into PAA unit-denominated awards (in dollars per unit)				40.54
Outstanding at end of period (in dollars per unit)			$ 41.21	$ 36.97	$ 25.55
Units issued in connection with the settlement of vested awards, net of tax withholding (in units)			0.6	0.5	1.0
Units withheld for taxes (in units)			0.3	0.3	0.5
Vested awards settled in cash (in units)			1.0	1.0	1.7
Long-Term Incentive Plan Awards \| Liability Awards
Weighted Average Grant Date Fair Value per Unit
Accrued liability related to all outstanding LTIP awards and DERs			$ 101	$ 98
Short-term accrued liability related to all outstanding LTIP awards and DERs			57	43
Long-term accrued liability related to all outstanding LTIP awards and DERs			$ 44	$ 55
Annualized distribution probable of occurring (in dollars per share)			$ 2.90
PNG LTIP
Outstanding (in units)
Outstanding at beginning of period (in units)				0.9	0.8
Granted (in units)				0.4	0.1
Cancelled or forfeited (in units)				(0.3)
Conversion of PNG unit-denominated awards into PAA unit-denominated awards (in units)				(1.0)
Outstanding at end of period (in units)					0.9
Weighted Average Grant Date Fair Value per Unit
Outstanding at beginning of period (in dollars per unit)				$ 17.49	$ 20.55
Granted (in dollars per unit)				17.51	15.33
Vested (in dollars per unit)				18.88	23.64
Cancelled or forfeited (in dollars per unit)				21.62
Conversion of PNG unit-denominated awards into PAA unit-denominated awards (in dollars per unit)				$ 16.41
Outstanding at end of period (in dollars per unit)					$ 17.49
PNG LTIP \| Maximum
Outstanding (in units)
Vested (in units)				(0.1)	(0.1)
PNG Transaction Grants
Outstanding (in units)
Cancelled or forfeited (in units)				(0.3)
PNG Transaction Grants \| Vested Awards
Equity-indexed Compensation Plans, Additional Disclosures
Phantom common units which vested in increment (in percent)	50.00%	50.00%

Equity-Indexed Compensation Plans (Details 3) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended			89 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014
Grant Date Fair Value of Outstanding AAP Management Units
Equity-indexed compensation expense	$ 98	$ 116	$ 101
AAP Management Units
Equity-Indexed Compensation Plans
Authorized grants (in units)	52.1			52.1
Maximum participation in excess of distribution (as a percent)	8.00%
Threshold for participation in distributions	$ 11
Reserved for Future Grants
Reserved for future grants, beginning balance (in units)	3.5	4.7
Granted (in units)	(0.5)	(1.2)
Reserved for future grants, ending balance (in units)	3.0	3.5	4.7	3.0
Outstanding
Outstanding, beginning balance (in units)	48.6	47.4
Granted (in units)	0.5	1.2
Outstanding, ending balance (in units)	49.1	48.6	47.4	49.1
Outstanding Units Earned
Outstanding Units Earned, beginning balance (in units)	47.0	34.0
Earned (in units)	0.8	13.0
Outstanding Units Earned, ending balance (in units)	47.8	47.0	34.0	47.8
Grant Date Fair Value of Outstanding AAP Management Units
Grant Date Fair Value of Outstanding AAP Management Units, beginning balance	$ 51	$ 44
Granted	13	7
Grant Date Fair Value of Outstanding AAP Management Units, ending balance	64	51	$ 44	$ 64
Equity-indexed compensation expense	$ 7	$ 5	$ 6	$ 55
AAP Management Units \| Range of annualized vesting distribution amount for all units outstanding
Equity-Indexed Compensation Plans
Annualized distribution, low end of range (in dollars per unit)	$ 1.75
Annualized distribution, high end of range (in dollars per unit)	$ 3.10
Number of days after achievement of distribution that units will become earned, in some cases	180 days
AAP Management Units \| Range of annualized vesting distribution amount for units that yet to become earned
Equity-Indexed Compensation Plans
Units outstanding (in units)	1.3			1.3
Annualized distribution, low end of range (in dollars per unit)	$ 2.55
Annualized distribution, high end of range (in dollars per unit)	$ 3.10
Number of days after achievement of distribution that units will become earned, in some cases	180 days

Equity-Indexed Compensation Plans (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Consolidated Equity-Indexed Compensation Plan Information
Equity-indexed compensation expense	$ 98	$ 116	$ 101
LTIP unit-settled vestings	53	48	62
LTIP cash-settled vestings	53	61	66
DER cash payments	8	8	7
Equity-Indexed Compensation Plan Fair Value Amortization
2015	70
2016	46
2017	21
2018	6
2019	1
Total	$ 144
PNG
Other Consolidated Equity-Indexed Compensation Plan Information
LTIP unit-settled vestings			$ 1
PNG \| Maximum
Other Consolidated Equity-Indexed Compensation Plan Information
LTIP unit-settled vestings		$ 1

Commitments and Contingencies (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Leases
Lease expense	$ 145	$ 132	$ 102
2015	162
2016	151
2017	127
2018	102
2019	78
Thereafter	373
Total	993
Other commitments
2015	62
2016	62
2017	49
2018	38
2019	27
Thereafter	90
Total	328
Total
2015	224
2016	213
2017	176
2018	140
2019	105
Thereafter	463
Total	$ 1,321

Commitments and Contingencies (Details 2) $ in Millions		1 Months Ended	2 Months Ended	12 Months Ended	20 Months Ended	23 Months Ended
Commitments and Contingencies (Details 2) $ in Millions	Jan. 15, 2015 item	Feb. 28, 2013 bbl	Jun. 30, 2013 item bbl	Dec. 31, 2014 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2014 USD ($)	Feb. 28, 2015 CAD ($)	Dec. 31, 2013 USD ($)
Environmental
Estimated undiscounted reserve for environmental liabilities				$ 82	$ 82	$ 82		$ 93
Estimated undiscounted reserve for environmental liabilities, short-term				13	13	13		11
Estimated undiscounted reserve for environmental liabilities, long-term				69	69	69		82
Amounts probable of recovery under insurance and from third parties under indemnification agreements				$ 8	8	8		$ 10
Minimum
Environmental
Actual cash expenditures for environmental liabilities, period paid				3 years
Bay Springs Pipeline Release
Environmental
Estimated size of release (in barrels) \| bbl		120
Total cost to clean up and remediate the site						6
Kemp River Pipeline Release
Environmental
Number of events occurred \| item			2
Estimated size of release (in barrels) \| bbl			700
Total estimated cost to clean up and remediate the site				$ 15	15	15
Cost incurred, to date, to clean up and remediate the site					9
PMC \| National Energy Board Audit \| Subsequent Event
Environmental
Number of conditions imposed related to regulatory compliance \| item	6
Charges, fines or penalties assessed							$ 76,000
PMC \| Kemp River Pipeline Release
Environmental
Charges, fines or penalties assessed				$ 0	$ 0	$ 0

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Data (Unaudited)
Revenues	$ 9,459	$ 11,127	$ 11,195	$ 11,684	$ 10,631	$ 10,703	$ 10,295	$ 10,620					$ 43,464	$ 42,249	$ 37,797
Gross margin	597	482	455	582	478	375	474	761					2,116	2,087
Operating income	530	404	365	493	394	296	383	655					1,791	1,728	1,425
Net income	390	324	288	385	318	237	300	536					1,386	1,391	1,127
Net income attributable to PAA	$ 389	$ 323	$ 287	$ 384	$ 309	$ 231	$ 292	$ 528					$ 1,384	$ 1,361	$ 1,094
Basic net income per limited partner unit (in dollars per unit)	$ 0.67	$ 0.52	$ 0.45	$ 0.74	$ 0.59	$ 0.38	$ 0.58	$ 1.28					$ 2.39	$ 2.82	$ 2.41
Diluted net income per limited partner unit (in dollars per unit)	0.67	0.52	0.45	0.73	0.58	0.38	0.57	1.27					2.38	2.80	2.40
Cash distributions per common unit (in dollars per unit)	$ 0.6600	$ 0.6450	$ 0.6300	$ 0.6150	$ 0.6000	$ 0.5875	$ 0.5750	$ 0.5625	$ 0.5425	$ 0.5325	$ 0.5225	$ 0.5125	$ 2.5500	$ 2.3250	$ 2.11

- Definition

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

+ References + Details

Operating Segments (Details) $ in Millions	3 Months Ended								12 Months Ended
Operating Segments (Details) $ in Millions	Dec. 31, 2014 USD ($)	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Sep. 30, 2013 USD ($)	Jun. 30, 2013 USD ($)	Mar. 31, 2013 USD ($)	Dec. 31, 2014 USD ($) segment	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)
Operating Segments
Operating segments number \| segment									3
Revenues:
Revenues	$ 9,459	$ 11,127	$ 11,195	$ 11,684	$ 10,631	$ 10,703	$ 10,295	$ 10,620	$ 43,464	$ 42,249	$ 37,797
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities									108	64	38
Segment profit									2,291	2,167	1,945
Capital expenditures									3,125	1,641	3,471
Maintenance capital									224	176	170
Total assets	22,256				20,360				22,256	20,360	19,235
Investments in unconsolidated entities	1,735				485				1,735	485	343
Transportation
Revenues:
Revenues									774	701	623
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities									108	64	38
Segment profit									925	729	710
Capital expenditures									2,483	1,046	1,244
Maintenance capital									165	123	108
Total assets	9,637				7,221				9,637	7,221	6,423
Investments in unconsolidated entities	1,735				485				1,735	485	343
Facilities
Revenues:
Revenues									576	856	736
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment profit									584	616	482
Capital expenditures									582	549	1,724
Maintenance capital									52	38	49
Total assets	6,843				6,555				6,843	6,555	6,134
Supply and Logistics
Revenues:
Revenues									42,114	40,692	36,438
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment profit									782	822	753
Capital expenditures									60	46	503
Maintenance capital									7	15	13
Total assets	$ 5,776				$ 6,584				5,776	6,584	6,678
Interest expense related to hedged inventory purchases									12	30	12
Operating Segments
Revenues:
Revenues									44,932	43,571	38,954
Operating Segments \| Transportation
Revenues:
Revenues									1,655	1,498	1,416
Operating Segments \| Facilities
Revenues:
Revenues									1,127	1,377	1,098
Operating Segments \| Supply and Logistics
Revenues:
Revenues									42,150	40,696	36,440
Intersegment
Revenues:
Revenues									(1,468)	(1,322)	(1,157)
Intersegment \| Transportation
Revenues:
Revenues									(881)	(797)	(793)
Intersegment \| Facilities
Revenues:
Revenues									(551)	(521)	(362)
Intersegment \| Supply and Logistics
Revenues:
Revenues									$ (36)	$ (4)	$ (2)

Operating Segments (Details 2) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
Operating Segments (Details 2) - USD ($) $ in Millions	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of segment profit to net income attributable to PAA
Segment profit									$ 2,291	$ 2,167	$ 1,945
Depreciation and amortization									(392)	(375)	(482)
Interest expense, net									(340)	(303)	(288)
Other income/(expense), net									(2)	1	6
INCOME BEFORE TAX									1,557	1,490	1,181
Income tax expense									(171)	(99)	(54)
NET INCOME	$ 390	$ 324	$ 288	$ 385	$ 318	$ 237	$ 300	$ 536	1,386	1,391	1,127
Net income attributable to noncontrolling interests									(2)	(30)	(33)
NET INCOME ATTRIBUTABLE TO PAA	$ 389	$ 323	$ 287	$ 384	$ 309	$ 231	$ 292	$ 528	$ 1,384	$ 1,361	$ 1,094

Operating Segments (Details 3) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
Operating Segments (Details 3) - USD ($) $ in Millions	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues and long lived assets attributable to geographic areas
Revenues	$ 9,459	$ 11,127	$ 11,195	$ 11,684	$ 10,631	$ 10,703	$ 10,295	$ 10,620	$ 43,464	$ 42,249	$ 37,797
Long-Lived Assets	18,050				15,366				18,050	15,366
United States
Revenues and long lived assets attributable to geographic areas
Revenues									34,860	32,924	29,978
Long-Lived Assets	14,400				11,743				14,400	11,743
Canada
Revenues and long lived assets attributable to geographic areas
Revenues									8,604	9,325	$ 7,819
Long-Lived Assets	$ 3,650				$ 3,623				$ 3,650	$ 3,623