Plains All American Pipeline (PAA) 10-Q 7 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 31, 2015
Document and Entity Information
Entity Registrant Name	PLAINS ALL AMERICAN PIPELINE LP
Entity Central Index Key	1,070,423
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		397,680,214
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash and cash equivalents	$ 28	$ 403
Trade accounts receivable and other receivables, net	2,688	2,615
Inventory	941	891
Other current assets	287	270
Total current assets	3,944	4,179
PROPERTY AND EQUIPMENT	15,077	14,178
Accumulated depreciation	(2,049)	(1,906)
Property and equipment, net	13,028	12,272
OTHER ASSETS
Goodwill	2,442	2,465
Investments in unconsolidated entities	1,841	1,735
Linefill and base gas	976	930
Long-term inventory	159	186
Other long-term assets, net	494	489
Total assets	22,884	22,256
CURRENT LIABILITIES
Accounts payable and accrued liabilities	3,117	2,986
Short-term debt	915	1,287
Other current liabilities	442	482
Total current liabilities	4,474	4,755
LONG-TERM LIABILITIES
Senior notes, net of unamortized discount of $16 and $18, respectively	8,759	8,757
Other long-term debt	378	5
Other long-term liabilities and deferred credits	568	548
Total long-term liabilities	$ 9,705	$ 9,310
COMMITMENTS AND CONTINGENCIES (NOTE 10)
PARTNERS' CAPITAL
Common unitholders (397,680,214 and 375,107,793 units outstanding, respectively)	$ 8,280	$ 7,793
General partner	367	340
Total partners' capital excluding noncontrolling interests	8,647	8,133
Noncontrolling interests	58	58
Total partners' capital	8,705	8,191
Total liabilities and partners' capital	$ 22,884	$ 22,256

CONDENSED CONSOLIDATED BALANCE3

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
CONDENSED CONSOLIDATED BALANCE SHEETS
Senior notes, unamortized discount	$ 16	$ 18
Common unitholders, units outstanding (in units)	397,680,214	375,107,793

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
REVENUES
Supply and Logistics segment revenues	$ 6,346	$ 10,856	$ 11,978	$ 22,201
Transportation segment revenues	180	195	366	376
Facilities segment revenues	137	144	261	301
Total revenues	6,663	11,195	12,605	22,878
COSTS AND EXPENSES
Purchases and related costs	5,848	10,280	10,890	20,950
Field operating costs	417	360	763	696
General and administrative expenses	79	90	157	179
Depreciation and amortization	110	100	217	196
Total costs and expenses	6,454	10,830	12,027	22,021
OPERATING INCOME	209	365	578	857
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	52	23	89	44
Interest expense (net of capitalized interest of $13, $10, $27 and $22, respectively)	(105)	(82)	(207)	(161)
Other income/(expense), net	1	4	(3)	2
INCOME BEFORE TAX	157	310	457	742
Current income tax expense	(19)	(16)	(61)	(52)
Deferred income tax benefit/(expense)	(14)	(6)	12	(18)
NET INCOME	124	288	408	672
Net income attributable to noncontrolling interests		(1)	(1)	(1)
NET INCOME ATTRIBUTABLE TO PAA	124	287	407	671
NET INCOME ATTRIBUTABLE TO PAA:
LIMITED PARTNERS	(22)	166	116	435
GENERAL PARTNER	$ 146	$ 121	$ 291	$ 236
BASIC NET INCOME/(LOSS) PER LIMITED PARTNER UNIT	$ (0.06)	$ 0.45	$ 0.29	$ 1.19
DILUTED NET INCOME/(LOSS) PER LIMITED PARTNER UNIT	$ (0.06)	$ 0.45	$ 0.29	$ 1.18
BASIC WEIGHTED AVERAGE LIMITED PARTNER UNITS OUTSTANDING	397	365	390	363
DILUTED WEIGHTED AVERAGE LIMITED PARTNER UNITS OUTSTANDING	400	367	393	365

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Interest expense, Capitalized interest	$ 13	$ 10	$ 27	$ 22

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)
Net income	$ 124	$ 288	$ 408	$ 672
Other comprehensive income/(loss)	170	91	(206)	(45)
Comprehensive income	294	379	202	627
Comprehensive income attributable to noncontrolling interests		(1)	(1)	(1)
Comprehensive income attributable to PAA	$ 294	$ 378	$ 201	$ 626

CONDENSED CONSOLIDATED STATEME7

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Balance at beginning of period			$ (467)	$ (97)
Reclassification adjustments			19	10
Deferred gain/(loss) on cash flow hedges, net of tax			20	(51)
Currency translation adjustments			(245)	(4)
Total period activity	$ 170	$ 91	(206)	(45)
Balance at end of period	(673)	(142)	(673)	(142)
Derivative Instruments
Balance at beginning of period			(159)	(77)
Reclassification adjustments			19	10
Deferred gain/(loss) on cash flow hedges, net of tax			20	(51)
Total period activity			39	(41)
Balance at end of period	(120)	(118)	(120)	(118)
Translation Adjustments
Balance at beginning of period			(308)	(20)
Currency translation adjustments			(245)	(4)
Total period activity			(245)	(4)
Balance at end of period	$ (553)	$ (24)	$ (553)	$ (24)

CONDENSED CONSOLIDATED STATEME8

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 408	$ 672
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	217	196
Equity-indexed compensation expense	36	68
Inventory valuation adjustments	24	37
Deferred income tax (benefit)/expense	(12)	18
Gain on sales of linefill and base gas		(8)
Gain on foreign currency revaluation	(26)	(5)
Settlement of terminated interest rate hedging instruments	(29)	(7)
Equity earnings in unconsolidated entities	(89)	(44)
Distributions from unconsolidated entities	102	51
Other	(11)	5
Changes in assets and liabilities, net of acquisitions	40	(20)
Net cash provided by operating activities	660	963
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	(64)	(2)
Additions to property, equipment and other	(1,031)	(918)
Investment in unconsolidated entities	(119)	(67)
Cash received for sales of linefill and base gas		23
Cash paid for purchases of linefill and base gas	(125)	(140)
Proceeds from sales of assets	2	3
Other investing activities	(6)
Net cash used in investing activities	(1,343)	(1,101)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings/(repayments) under commercial paper program (Note 6)	151	(344)
Proceeds from the issuance of senior notes (Note 6)		698
Repayments of senior notes (Note 6)	(149)
Net proceeds from the issuance of common units (Note 7)	1,099	444
Contributions from general partner	23	9
Distributions paid to common unitholders (Note 7)	(526)	(450)
Distributions paid to general partner (Note 7)	(284)	(222)
Distributions paid to noncontrolling interests	(1)	(1)
Other financing activities	(4)	(10)
Net cash provided by financing activities	309	124
Effect of translation adjustment on cash	(1)
Net decrease in cash and cash equivalents	(375)	(14)
Cash and cash equivalents, beginning of period	403	41
Cash and cash equivalents, end of period	28	27
Cash paid for:
Interest, net of amounts capitalized	190	161
Income taxes, net of amounts refunded	$ 30	$ 104

CONDENSED CONSOLIDATED STATEME9

CONDENSED 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, 2013	$ 7,349	$ 295	$ 7,644	$ 59	$ 7,703
Balance, beginning of period (in units) at Dec. 31, 2013	359,100,000
Increase (Decrease) in Partners' Capital
Net income	$ 435	236	671	1	672
Distributions	(450)	(222)	(672)	(1)	(673)
Issuance of common units	$ 444	9	453		453
Issuance of common units (in units)	8,100,000
Issuance of common units under LTIP	$ 1	1	2		2
Issuance of common units under LTIP (in units)	600,000
Settlement of employee income tax withholding obligation under LTIP	$ (19)		(19)		(19)
Equity-indexed compensation expense	19	4	23		23
Distribution equivalent right payments	(3)		(3)		(3)
Other comprehensive loss	(44)	(1)	(45)		(45)
Other	(1)		(1)		(1)
Balance, end of period at Jun. 30, 2014	$ 7,731	322	8,053	59	8,112
Balance, end of period (in units) at Jun. 30, 2014	367,800,000
Balance, beginning of period at Dec. 31, 2014	$ 7,793	340	8,133	58	$ 8,191
Balance, beginning of period (in units) at Dec. 31, 2014	375,100,000				375,107,793
Increase (Decrease) in Partners' Capital
Net income	$ 116	291	407	1	$ 408
Distributions	(526)	(284)	(810)	(1)	(811)
Issuance of common units	$ 1,099	22	1,121		1,121
Issuance of common units (in units)	22,100,000
Issuance of common units under LTIP		1	1		1
Issuance of common units under LTIP (in units)	500,000
Settlement of employee income tax withholding obligation under LTIP	$ (13)		(13)		(13)
Equity-indexed compensation expense	16	1	17		17
Distribution equivalent right payments	(3)		(3)		(3)
Other comprehensive loss	(202)	(4)	(206)		(206)
Balance, end of period at Jun. 30, 2015	$ 8,280	$ 367	$ 8,647	$ 58	$ 8,705
Balance, end of period (in units) at Jun. 30, 2015	397,700,000				397,680,214

Organization and Basis of Conso

Organization and Basis of Consolidation and Presentation	6 Months Ended
	Jun. 30, 2015
Organization and Basis of Consolidation and Presentation
Organization and Basis of Consolidation and Presentation	Note 1—Organization and Basis of Consolidation and Presentation Organization Plains All American Pipeline, L.P. (“PAA”) is a Delaware limited partnership formed in 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in this Form 10-Q and unless the context indicates otherwise, the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAA and its subsidiaries. We own and operate midstream energy infrastructure and provide logistics services for crude oil, natural gas liquids (“NGL”), natural gas and refined products. We own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. Our business activities are conducted through three operating segments: Transportation, Facilities and Supply and Logistics. See Note 11 for further discussion of our operating segments. Our 2% general partner interest is held by PAA GP LLC, a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP LLC, AAP also owns all of our incentive distribution rights (“IDRs”). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole member of GP LLC, and at June 30, 2015, owned an approximate 37% limited partner interest in AAP. GP LLC manages our operations and activities and employs our domestic officers and personnel. Our Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC (“PMC”). References to our “general partner,” as the context requires, include any or all of PAA GP LLC, AAP and GP LLC. Definitions Additional defined terms are used in this Form 10-Q and shall have the meanings indicated below: AOCI = Accumulated other comprehensive income/(loss) Bcf = Billion cubic feet Btu = British thermal unit CAD = Canadian dollar DERs = Distribution equivalent rights EPA = United States Environmental Protection Agency FASB = Financial Accounting Standards Board GAAP = Generally accepted accounting principles in the United States ICE = Intercontinental Exchange LIBOR = London Interbank Offered Rate LTIP = Long-term incentive plan Mcf = Thousand cubic feet MLP = Master limited partnership NGL = Natural gas liquids, including ethane, propane and butane NYMEX = New York Mercantile Exchange Oxy = Occidental Petroleum Corporation or its subsidiaries PLA = Pipeline loss allowance SEC = United States Securities and Exchange Commission USD = United States dollar WTI = West Texas Intermediate Basis of Consolidation and Presentation The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our 2014 Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of PAA and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications do not affect net income attributable to PAA. The condensed consolidated balance sheet data as of December 31, 2014 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three and six months ended June 30, 2015 should not be taken as indicative of results to be expected for the entire year. Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable.

Recent Accounting Pronouncement

Recent Accounting Pronouncements	6 Months Ended
	Jun. 30, 2015
Recent Accounting Pronouncements
Recent Accounting Pronouncements	Note 2—Recent Accounting Pronouncements In April 2015, the FASB issued guidance to simplify the presentation of debt issuance costs in entities’ financial statements. Under this revised guidance, an entity will present such costs as a direct reduction from the related debt liability (rather than as an asset under current guidance). Additionally, amortization of the debt issuance costs will be reported as interest expense. This guidance will become effective for interim and annual periods beginning after December 15, 2015 and will be adopted retrospectively to all prior periods. Early adoption is permitted for financial statements that have not been previously issued. We expect to adopt this guidance on January 1, 2016, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows. In February 2015, the FASB issued guidance that revises the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. All legal entities are subject to reevaluation under the revised consolidation model. Among other things, this guidance (i) modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (ii) eliminates the presumption that a general partner should consolidate a limited partnership and (iii) affects the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships. This guidance will become effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. We expect to adopt this guidance on January 1, 2016, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows. In January 2015, as part of its initiative to reduce complexity in accounting standards, the FASB issued guidance to eliminate the concept of extraordinary items from GAAP. This guidance will become effective for interim and annual periods beginning after December 15, 2015. We expect to adopt this guidance on January 1, 2016. We do not believe our adoption will have a material impact on our financial position, results of operations or cash flows. In May 2014, the FASB issued guidance regarding the recognition of revenue from contracts with customers with the underlying principle that an entity will recognize revenue to reflect amounts expected to be received in exchange for the provision of goods and services to customers upon the transfer of those goods or services. The guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. This guidance 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. In July 2015, the FASB voted to approve a one-year deferral of the effective date of this standard, with final guidance expected to be issued by the end of the third quarter of 2015. This deferral would make the guidance effective for interim and annual periods beginning after December 15, 2017. Therefore, we currently expect to adopt this guidance on January 1, 2018, and we are evaluating which transition approach to apply and the effect that adopting this guidance will have on our financial position, results of operations and cash flows. In April 2014, the FASB issued guidance that modifies the criteria under which assets to be disposed of are evaluated to determine if such assets qualify as a discontinued operation and requires new disclosures for both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. This guidance is effective prospectively for annual and interim reporting periods beginning after December 15, 2014. We adopted this guidance on January 1, 2015. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

Net Income Per Limited Partner

Net Income Per Limited Partner Unit	6 Months Ended
	Jun. 30, 2015
Net Income Per Limited Partner Unit
Net Income Per Limited Partner Unit	Note 3—Net Income Per Limited Partner Unit Basic and diluted net income per limited partner unit is determined pursuant to the two-class method for MLPs as prescribed in FASB guidance. The two-class method is an earnings allocation formula that is used to determine earnings to our general partner, common unitholders and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings. Under this method, all earnings are allocated to our general partner, common unitholders and participating securities based on their respective rights to receive distributions, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. We calculate basic and diluted net income per limited partner unit by dividing net income attributable to PAA (after deducting the amount allocated to the general partner’s interest, IDRs and participating securities) by the basic and diluted weighted-average number of limited partner units outstanding during the period. Participating securities include LTIP awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units. Diluted net income per limited partner unit is computed based on the weighted average number of limited partner units plus the effect of dilutive potential limited partner units outstanding during the period using the two-class method. Our LTIP awards that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical limited partner unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 16 to our Consolidated Financial Statements included in Part IV of our 2014 Annual Report on Form 10-K for a complete discussion of our LTIP awards including specific discussion regarding DERs. The following table sets forth the computation of basic and diluted net income/(loss) per limited partner unit for the periods indicated (in millions, except per unit data): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Basic Net Income per Limited Partner Unit Net income attributable to PAA $ $ $ $ Less: General partner’s incentive distribution (1) Less: General partner 2% ownership (1) — Net income/(loss) attributable to limited partners Less: Undistributed earnings allocated and distributions to participating securities (1) Net income/(loss) attributable to limited partners in accordance with application of the two-class method for MLPs $ $ $ $ Basic weighted average limited partner units outstanding Basic net income/(loss) per limited partner unit $ $ $ $ Diluted Net Income per Limited Partner Unit Net income attributable to PAA $ $ $ $ Less: General partner’s incentive distribution (1) Less: General partner 2% ownership (1) — Net income/(loss) attributable to limited partners Less: Undistributed earnings allocated and distributions to participating securities (1) Net income/(loss) attributable to limited partners in accordance with application of the two-class method for MLPs $ $ $ $ Basic weighted average limited partner units outstanding Effect of dilutive securities: Weighted average LTIP units Diluted weighted average limited partner units outstanding Diluted net income/(loss) per limited partner unit $ $ $ $ (1) We calculate net income attributable 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 our partnership agreement, basic and diluted net income/(loss) per limited partner unit as reflected in the table above would not have been impacted, as we did not have undistributed earnings for any of the periods presented.

Accounts Receivable

Accounts Receivable	6 Months Ended
	Jun. 30, 2015
Accounts Receivable
Accounts Receivable	Note 4—Accounts Receivable Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas. These purchasers include, but are not limited to, refiners, producers, marketing and trading companies and financial institutions that are active in the physical and financial commodity markets. The majority of our accounts receivable relate to our crude oil supply and logistics activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit or parental guarantees. As of June 30, 2015 and December 31, 2014, we had received $ 115 million and $180 million, respectively, of advance cash payments from third parties to mitigate credit risk. We also received $77 million and $198 million, as of June 30, 2015 and December 31, 2014, respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. The decrease in standby letters of credit and advance cash payments from third parties as of June 30, 2015 compared to December 31, 2014 is largely due to a decrease in exposure to various customers requiring letters of credit. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Furthermore, we also enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet) for a majority of such arrangements. We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At June 30, 2015 and December 31, 2014, substantially all of our trade accounts receivable (net of allowance for doubtful accounts) were less than 30 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled $4 million as of both June 30, 2015 and December 31, 2014. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

Inventory, Linefill and Base Ga

Inventory, Linefill and Base Gas and Long-term Inventory	6 Months Ended
	Jun. 30, 2015
Inventory, Linefill and Base Gas and Long-term Inventory
Inventory, Linefill and Base Gas and Long-term Inventory	Note 5—Inventory, Linefill and Base Gas and Long-term Inventory Inventory, linefill and base gas and long-term inventory consisted of the following as of the dates indicated (barrels and natural gas volumes in thousands and carrying value in millions): June 30, 2015 December 31, 2014 Unit of Carrying Price/ Unit of Carrying Price/ Volumes Measure Value Unit (1) Volumes Measure Value Unit (1) Inventory Crude oil barrels $ $ barrels $ $ NGL barrels $ barrels $ Natural gas Mcf $ Mcf $ Other N/A N/A N/A N/A Inventory subtotal Linefill and base gas Crude oil barrels $ barrels $ NGL barrels $ barrels $ Natural gas Mcf $ Mcf $ Linefill and base gas subtotal Long-term inventory Crude oil barrels $ barrels $ NGL barrels $ barrels $ Long-term inventory subtotal Total $ $ (1) Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products. At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Condensed Consolidated Statements of Oper ations. We recorded a charge of $24 million during the six months ended June 30, 2015, which primarily related to the writedown of our NGL inventory due to declines in prices during the first quarter of 2015. The loss was substantially offset by a portion of the derivative mark-to-market gain that was recognized in the fourth quarter of 2014. See Note 8 for discussion of our derivative and risk management activities. During the six months ended June 30, 2014, we recorded a charge of $37 million related to the writedown of our natural gas inventory that was purchased in conjunction with managing natural gas storage deliverability requirements during the extended period of severe cold weather in the first quarter of 2014 .

Debt

Debt	6 Months Ended
	Jun. 30, 2015
Debt
Debt	Note 6—Debt Debt consisted of the following as of the dates indicated (in millions): June 30, December 31, 2015 2014 SHORT-TERM DEBT Commercial paper notes, bearing a weighted-average interest rate of 0.49% and 0.46% , respectively (1) $ $ Senior notes: 5.25% senior notes due June 2015 — 3.95% senior notes due September 2015 Other Total short-term debt LONG-TERM DEBT Senior notes, net of unamortized discount of $16 and $18 , respectively Commercial paper notes, bearing a weighted-average interest rate of 0.49% (2) — Other Total long-term debt Total debt (3) $ $ (1) We classified these commercial paper notes as short-term at June 30, 2015 and December 31, 2014 as these notes were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits. (2) We have the ability and intent to refinance these commercial paper notes on a long-term basis; therefore, we have classified such notes as long-term at June 30, 2015. (3) Our fixed-rate senior notes (including current maturities) had a face value of approximately $9.2 billion and $9.3 billion as of June 30, 2015 and December 31, 2014, respectively. We estimated the aggregate fair value of these notes as of June 30, 2015 and December 31, 2014 to be approximately $9.4 billion and $9.9 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under our credit facilities and commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, credit facilities and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy. Credit Facilities Senior unsecured 364-day revolving credit facility . In January 2015, we entered into a 364 -day senior unsecured credit agreement with a borrowing capacity of $1.0 billion. Borrowings will accrue interest based, at our election, on either the Eurocurrency Rate or the Base Rate , as defined in the agreement, in each case plus a margin based on our credit rating at the applicable time. Borrowings and Repayments Total borrowings under our credit agreements and commercial paper program for the six months ended June 30, 2015 and 2014 were approximately $17.9 billion and $34.6 billion, respectively. Total repayments under our credit agreements and commercial paper program were approximately $17.7 billion and $34.9 billion for the six months ended June 30, 2015 and 2014, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities. Letters of Credit In connection with our supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs, derivative transactions and construction activities. At June 30, 2015 and December 31, 2014, we had outstanding letters of credit of $63 million and $87 million, respectively. Senior Notes Repayments In June 2015, we repaid our $150 million, 5.25% senior notes. We utilized cash on hand and available capacity under our commercial paper program to repay these notes.

Partners' Capital and Distribut

Partners' Capital and Distributions	6 Months Ended
	Jun. 30, 2015
Partners' Capital and Distributions
Partners' Capital and Distributions	Note 7—Partners’ Capital and Distributions Distributions The following table details the distributions paid during or pertaining to the first six months of 2015, net of reductions to the general partner’s incentive distributions (in millions, except per unit data): Distributions Paid Distributions Limited General Partner per limited Date Declared Distribution Date Partners 2% Incentive Total partner unit July 7, 2015 August 14, 2015 (1) $ $ $ $ $ April 7, 2015 May 15, 2015 $ $ $ $ $ January 8, 2015 February 13, 2015 $ $ $ $ $ (1) Payable to unitholders of rec ord at the close of business on July 31, 2015 for the period April 1, 2015 through June 30, 2015. PAA Equity Offerings Continuous Offering Program . During the six months ended June 30, 2015, we issued an aggregate of approximately 1.1 million common units under our continuous offering program, generating proceeds of $59 million, including our general partner’s proportionate capital contribution of $1 million, net of $1 million of commissions to our sales agents. Underwritten Offering . In March 2015, we completed an underwritten public offering of 21.0 million common units, generating proceeds of approximately $1.1 billion, including our general partner’s proportionate capital contribution of $21 million, net of costs associated with the offering. Noncontrolling Interests in Subsidiaries As of June 30, 2015, noncontrolling interests in our subsidiaries consisted of a 25% interest in SLC Pipeline LLC.

Derivatives and Risk Management

Derivatives and Risk Management Activities	6 Months Ended
	Jun. 30, 2015
Derivatives and Risk Management Activities
Derivatives and Risk Management Activities	Note 8—Derivatives and Risk Management Activities We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on hydrocarbon commodity (referred to herein as “commodity”) price changes. We use various derivative instruments to (i) manage our exposure to commodity price risk, as well as to optimize our profits, (ii) manage our exposure to interest rate risk and (iii) manage our exposure to currency exchange rate risk. Our commodity risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in a transaction are highly effective in offsetting changes in cash flows or the fair value of hedged items. Commodity Price Risk Hedging Our core business activities involve certain commodity price-related risks that we manage in various ways, including through the use of derivative instruments. Our policy is to (i) only purchase inventory for which we have a market, (ii) structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold physical inventory or derivatives for the purpose of speculating on commodity price changes. The material commodity-related risks inherent in our business activities can be divided into the following general categories: Commodity Purchases and Sales — In the normal course of our operations, we purchase and sell commodities. We use derivatives to manage the associated risks and to optimize profits. As of June 30, 2015, net derivative positions related to these activities included: · An average of 151,600 barrels per day net long position (total of 4.7 million barrels) associated with our crude oil purchases, which was unwound ratably during July 2015 to match monthly average pricing. · A net short time spread position averaging 17,800 barrels per day (total of 7.6 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through October 2016. · An average of 35,800 barrels per day (total of 5.5 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 13.9 Bcf through April 2016 related to anticipated sales of natural gas inventory and base gas requirements. · A net short position of 15.3 million barrels through June 2017 related to anticipated purchases and sales of our crude oil, NGL and refined products inventory. Storage Capacity Utilization — We own a significant amount of crude oil, NGL and refined products storage capacity other than that used in our transportation operations. This storage may be leased to third parties or utilized in our own supply and logistics activities, including for the storage of inventory in a contango market. For capacity allocated to our supply and logistics operations, we have utilization risk in a backwardated market structure. As of June 30, 2015, we used derivatives to manage the risk of not utilizing approximately 0.8 million barrels of storage capacity through January 2016. These positions involve no outright price exposure, but instead enable us to profitably use the capacity to store hedged crude oil. 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 June 30, 2015, we had a long natural gas position of 15.2 Bcf through December 2016, a short propane position of 2.9 million barrels through December 2016, a short butane position of 0.9 million barrels through December 2016 and a short WTI position of 0.3 million barrels through December 2016. In addition, we had a long power position of 0.5 million megawatt hours, which hedges a portion of our power supply requirements at our natural gas processing and fractionation plants through December 2018. 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 and outstanding interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist primarily of interest rate swaps and treasury locks. As of June 30, 2015, AOCI includes deferred losses of $109 million that relate to open and terminated interest rate derivatives that were designated as cash flow hedges. The terminated interest rate derivatives were cash-settled in connection with the issuance or refinancing of debt agreements. The deferred loss related to these instruments is being amortized to interest expense over the terms of the hedged debt instruments. We have entered into forward starting interest rate swaps to hedge the underlying benchmark interest rate related to forecasted interest payments through 2049. The following table summarizes the terms of our forward starting interest rate swaps as of June 30, 2015 (notional amounts in millions): Number and Types of Notional Expected Average Rate Accounting Hedged Transaction Derivatives Employed Amount Termination Date Locked Treatment Anticipated interest payments 7 forward starting swaps (30-year) $ 9/15/2015 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 6/15/2016 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 6/15/2017 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 6/15/2018 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 6/14/2019 % Cash flow hedge During June 2015, we terminated ten forward starting swaps. These swaps had an aggregate notional amount of $250 million and an average fixed rate of 3.60% . We made a cash payment of approximately $31 million in connection with the termination of these swaps. 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 June 30, 2015, our outstanding foreign currency derivatives include derivatives we use to (i) hedge currency exchange risk associated with USD-denominated commodity purchases and sales in Canada and (ii) hedge currency exchange risk created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales. The following table summarizes our open forward exchange contracts as of June 30, 2015 (in millions): Average Exchange Rate USD CAD USD to CAD Forward exchange contracts that exchange CAD for USD: $ $ $ 1.00 - $ $ 1.00 - $ $ $ Forward exchange contracts that exchange USD for CAD: $ $ $ 1.00 - $ $ 1.00 - $ $ $ Summary of Financial Impact We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify as cash flow hedges, changes in fair value of the effective portion of the hedges are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions are recognized in earnings. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of the hedged items are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Condensed Consolidated Statements of Cash Flows. A summary of the impact of our derivative activities recognized in earnings for the periods indicated is as follows (in millions): Three Months Ended June 30, 2015 Derivatives in Hedging Relationships Gain/(Loss) Other Reclassified Gain/(Loss) Derivatives Not from AOCI Recognized Designated Location of Gain/(Loss) into Income (1) (2) in Income (3) as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ $ — $ $ Transportation segment revenues — — Field operating costs — — Interest Rate Derivatives Interest expense — Total Gain/(Loss) on Derivatives Recognized in Net Income $ $ $ $ Three Months Ended June 30, 2014 Derivatives in Hedging Relationships Gain/(Loss) Other Reclassified Gain/(Loss) Derivatives Not from AOCI Recognized Designated Location of Gain/(Loss) into Income (1) (2) in Income (3) as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ $ — $ — $ Interest Rate Derivatives Interest expense — — Foreign Currency Derivatives Supply and Logistics segment revenues — — Total Gain/(Loss) on Derivatives Recognized in Net Income $ $ — $ $ Six Months Ended June 30, 2015 Derivatives in Hedging Relationships Gain/(Loss) Other Reclassified Gain/(Loss) Derivatives Not from AOCI Recognized Designated Location of Gain/(Loss) into Income (1) (2) in Income (3) as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ $ — $ $ Transportation segment revenues — — Field operating costs — — Interest Rate Derivatives Interest expense — Foreign Currency Derivatives Supply and Logistics segment revenues — — Total Gain/(Loss) on Derivatives Recognized in Net Income $ $ $ $ Six Months Ended June 30, 2014 Derivatives in Hedging Relationships Gain/(Loss) Other Reclassified Gain/(Loss) Derivatives Not from AOCI Recognized Designated Location of Gain/(Loss) into Income (1) (2) in Income (3) as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ $ — $ — $ Field operating costs — — Interest Rate Derivatives Interest expense — — Total Gain/(Loss) on Derivatives Recognized in Net Income $ $ — $ $ (1) Represents gains/(losses) on cash flow hedges reclassified from AOCI to income during the period. (2) During the three and six months ended June 30, 2015 we reclassified a loss of approximately $4 million from AOCI to Interest expense as a result of anticipated hedged transactions that are probable of not occurring. All of our anticipated hedged transactions were deemed probable of occurring during the three and six months ended June 30, 2014. (3) Amounts represent ineffective portion of cash flow hedges. The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheets on a gross basis as of June 30, 2015 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Balance Sheet Location Fair Value Location Fair Value Derivatives designated as hedging instruments: Commodity derivatives Other current assets $ Other current liabilities $ Other long-term liabilities and deferred credits Interest rate derivatives Other current assets Other current liabilities Other long-term assets, net Other long-term liabilities and deferred credits Total derivatives designated as hedging instruments $ $ Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ Other current assets $ Other long-term assets, net Other long-term assets, net Other current liabilities Other current liabilities Other long-term liabilities and deferred credits Foreign currency derivatives Other current liabilities Total derivatives not designated as hedging instruments $ $ Total derivatives $ $ The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheets on a gross basis as of December 31, 2014 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Balance Sheet Location Fair Value Location Fair Value Derivatives designated as hedging instruments: Commodity derivatives Other current assets $ Other current assets $ Other long-term assets, net Other long-term assets, net Interest rate derivatives Other current liabilities Other long-term liabilities and deferred credits Total derivatives designated as hedging instruments $ $ Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ Other current assets $ Other long-term assets, net Other long-term assets, net Other current liabilities Other long-term liabilities and deferred credits Foreign currency derivatives Other current liabilities Total derivatives not designated as hedging instruments $ $ Total derivatives $ $ 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 June 30, 2015, we had a net broker payable of $46 million (consisting of initial margin of $49 million reduced by $95 million of variation margin that had been returned to us). As of December 31, 2014, we had a net broker payable of $133 million (consisting of initial margin of $126 million reduced by $259 million of variation margin that had been returned to us). The following table presents 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): June 30, 2015 December 31, 2014 Derivative Derivative Derivative Derivative Asset Positions Liability Positions Asset Positions Liability Positions Netting Adjustments: Gross position - asset/(liability) $ $ $ $ Netting adjustment Cash collateral paid/(received) — — Net position - asset/(liability) $ $ $ $ Balance Sheet Location After Netting Adjustments: Other current assets $ $ — $ $ — Other long-term assets, net — — Other current liabilities — — Other long-term liabilities and deferred credits — — $ $ $ $ As of June 30, 2015, there was a net loss of $120 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 June 30, 2015, we expect to reclassify a net gain of $4 million to earnings in the next twelve months. The remaining deferred loss of $124 million is expected to be reclassified to earnings through 2049. A portion of these amounts are based on market prices as of June 30, 2015; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions. The net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives for the periods indicated was as follows (in millions): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Commodity derivatives, net $ $ — $ $ Interest rate derivatives, net Total $ $ $ $ At June 30, 2015 and December 31, 2014, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings . Although we may be required to post margin on our cleared derivatives as described above, we do not require our non-cleared derivative counterparties to post collateral with us. Recurring Fair Value Measurements Derivative Financial Assets and Liabilities The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the dates indicated (in millions): Fair Value as of June 30, 2015 Fair Value as of December 31, 2014 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ $ $ $ $ $ $ $ Interest rate derivatives — — — — Foreign currency derivatives — — — — Total net derivative asset/(liability) $ $ $ $ $ $ $ $ (1) Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits. Level 1 Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives such as futures and options. The fair value of exchange-traded commodity derivatives is based on unadjusted quoted prices in active markets. Level 2 Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives and over-the-counter commodity, interest rate and foreign currency derivatives that are traded in active markets. In addition, it includes certain physical commodity contracts. The fair value of these derivatives is based on broker price quotations which are corroborated with market observable inputs. Level 3 Level 3 of the fair value hierarchy includes certain physical commodity contracts. The fair value of our Level 3 physical commodity contracts is based on a valuation model utilizing broker-quoted forward commodity prices, and timing estimates, which involve management judgment. The significant unobservable inputs used in the fair value measurement of our Level 3 derivatives are forward prices obtained from brokers. A significant increase or decrease in these forward prices could result in a material change in fair value to our Level 3 derivatives. We report unrealized gains and losses associated with Level 3 commodity derivatives in our Condensed Consolidated Statements of Operations as Supply and Logistics segment revenues. Rollforward of Level 3 Net Asset/(Liability) The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 for the periods indicated (in millions): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Beginning Balance $ $ $ $ Gains/(losses) for the period included in earnings — — Settlements — Derivatives entered into during the period — Ending Balance $ $ $ $ Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ $ $ $

Equity-Indexed Compensation Pla

Equity-Indexed Compensation Plans	6 Months Ended
	Jun. 30, 2015
Equity-Indexed Compensation Plans
Equity-Indexed Compensation Plans	Note 9—Equity-Indexed Compensation Plans We refer to the PAA LTIPs and AAP Management Units collectively as our “equity-indexed compensation plans.” For additional discussion of our equity-indexed compensation plans and awards, see Note 16 to our Consolidated Financial Statements included in Part IV of our 2014 Annual Report on Form 10-K. PAA LTIP Awards Activity for LTIP awards under our equity-indexed compensation plans denominated in PAA units is summarized in the following table (units in millions): Weighted Average Grant Date Units (1) Fair Value per Unit Outstanding at December 31, 2014 $ Granted $ Vested (2) $ Cancelled or forfeited $ Outstanding at June 30, 2015 $ (1) Amounts do not include AAP Management Units. (2) Approximately 0.5 million PAA common units were issued, net of tax withholding of 0.2 million units, during the six months ended June 30, 2015 in connection with the settlement of vested awards. The remaining PAA awards that vested during the six months ended June 30, 2015 of approximately 1.1 million units were settled in cash. AAP Management Units Activity for AAP Management Units is summarized in the following table (in millions): Grant Date Reserved for Future Outstanding Units Fair Value Of Outstanding Grants Outstanding Earned AAP Management Units (1) Balance at December 31, 2014 $ Earned N/A N/A N/A Balance at June 30, 2015 $ (1) Of the $64 million grant date fair value, $57 million had been recognized through June 30, 2015 on a cumulative basis. Of this amount, $1 million was recognized as expense during the six months ended June 30, 2015. Other Consolidated Equity-Indexed Compensation Plan Information The table below summarizes the expense recognized and the value of vested LTIP awards (settled both in common units and cash) under our equity-indexed compensation plans and includes both liability-classified and equity-classified awards for the periods indicated (in millions): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Equity-indexed compensation expense $ $ $ $ LTIP unit-settled vestings $ $ $ $ LTIP cash-settled vestings $ $ $ $ DER cash payments $ $ $ $

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments and Contingencies.
Commitments and Contingencies	Note 10—Commitments and Contingencies Loss Contingencies — General To the extent we are able to assess the likelihood of a negative outcome for a contingency, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Legal Proceedings — General In the ordinary course of business, we are involved in various legal proceedings , including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully protect us from losses arising from current or future legal proceedings. Taking into account what we believe to be all relevant known facts and circumstances, and based on what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing laws and regulations, we do not believe that the outcome of the legal proceedings in which we are currently involved (including those described below) will, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Environmental — General Although over the course of the last several years we have made significant investments in our maintenance and integrity programs, and have hired additional personnel in those areas, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail and storage operations. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows. At June 30, 2015, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled $297 million, of which $197 million was classified as short-term and $100 million was classified as long-term. At December 31, 2014, our estimated undiscounted reserve for environmental liabilities totaled $82 million, of which $13 million was classified as short-term and $69 million was classified as long-term. The short- and long-term environmental liabilities referenced above are reflected in “Accounts payable and accrued liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Condensed Consolidated Balance Sheets. At June 30, 2015 and December 31, 2014, we had recorded receivables totaling $200 million and $8 million, respectively, for amounts probable of recovery under insurance and from third parties under indemnification agreements, which are predominantly reflected in “Trade accounts receivable and other receivables, net” on our Condensed Consolidated Balance Sheets. In some cases, the actual cash expenditures associated with these liabilities may not occur for three years or longer. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing 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 consolidated financial condition, results of operations or cash flows. Specific Legal, Environmental or Regulatory Matters Line 901 Incident . During May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. A portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert. Following the release, we shut down the pipeline and initiated our emergency response plan. A Unified Command, which includes the United States Coast Guard, the EPA, the California Office of Spill Prevention and Response and the Santa Barbara Office of Emergency Management was established for the response effort. Clean-up and remediation operations and contamination monitoring continue, and the cause of the release is currently under investigation. Although the precise volume of crude oil released in connection with this incident has not been determined, following the release, we developed and have periodically updated a “worst case” estimate of the amount of oil spilled, which represents what we believe to be the maximum volume of oil that could have been spilled based on relevant facts, data and information available at the time of such calculation. Our worst-case estimate has been developed primarily using information regarding (i) an estimate of the amount of oil that flowed into Line 901 during the period between the estimated time of release and the point when the pumps were shut down and (ii) an estimate of the volume of oil that drained out of the line due to the natural force of gravity based on the characteristics of the pipeline (i.e., length, elevation profile, diameter and location of the release point). Using this “drain-down” methodology, our worst case estimate of the volume of oil released totaled approximately 2,400 barrels. We believe that the “drain-down” methodology represents the most straight forward and accurate calculation of the potential worst case discharge. In the second half of June we completed the process of emptying and purging Line 901, which resulted in the removal of approximately 26,500 barrels of crude oil from the line. This activity provided additional data to assess the reasonableness of our worst case estimate of 2,400 barrels based on the “drain-down” methodology. Based on a preliminary analysis, an alternative calculation using the purge data could be as much as 1,000 barrels higher than the worst-case estimate calculated using the drain-down methodology. However, the alternative calculation does not take into account certain factors that could account for a meaningful portion of the difference between the two calculations and this reconciliation process is ongoing. As part of our effort to reconcile these differences, we have retained an outside, third party consulting firm to review the materials and submit a report, but such study has not been completed. Accordingly, to date we have not finalized our calculation of the “worst case” estimate of the amount of oil released from Line 901, and such volume estimate may change as additional facts, data and information are analyzed during the course of the investigation of this incident. Any variance between the current and final estimate of the worst case discharge is not expected to impact our estimate of response, clean-up or remediation costs, but could impact our estimate of fines and penalties. As a result of the Line 901 incident, several governmental agencies and regulators have initiated investigations into the Line 901 incident, various claims have been made against us and a number of lawsuits have been filed against us. Set forth below is a brief summary of such actions and matters: On May 21, 2015, we received a corrective action order from the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”), the governmental agency that has jurisdiction over the operation of Line 901 as well as over a second stretch of pipeline extending from Gaviota Pump Station in Santa Barbara County to Emidio Pump Station in Kern County, California (Line 903), requiring us to shut down, purge, review, remediate and test Line 901. On June 3, 2015, the corrective action order was amended to require us to take additional corrective actions with respect to both Lines 901 and 903 (as amended, the “CAO”). Among other requirements, the CAO also obligates us to conduct a root cause failure analysis with respect to Line 901 and present remedial work plans and restart plans to PHMSA prior to returning Line 901 to service; the CAO also imposes a pressure restriction on Line 903 and requires us to take other specified actions with respect to both Lines 901 and 903. We fully intend to comply with the CAO and to cooperate with any other governmental investigations relating to or arising out of the release. Excavation and removal of the affected section of the pipeline was completed on May 28, 2015. No timeline has been established for the restart of Line 901. By virtue of its statutory authority, PHMSA has the power and authority to impose fines and penalties on us and cause civil or criminal charges to be brought against us. While to date PHMSA has not imposed any such fines or penalties or pursued any such civil or criminal charges, there can be no assurance that such fines or penalties will not be imposed upon us, or that such civil or criminal charges will not be brought against us, in the future. In late May, on behalf of the EPA, the United States Attorney for the Department of Justice, Central District of California, Environmental Crimes Section (“DOJ”) began an investigation into whether there were any violations of federal criminal statutes in connection with the Line 901 incident, including potential violations of the federal Clean Water Act. We are cooperating with the DOJ’s investigation by responding to their requests for documents and access to our employees. The DOJ has expressed an interest in talking to several of our employees and consistent with the terms of our governing organizational documents, we are funding their defense costs, including the costs of separate counsel engaged to represent such individuals. In addition to the DOJ, the California Attorney General’s Office and the District Attorney’s Office for the County of Santa Barbara have also announced that they are investigating the Line 901 incident to determine whether any applicable state or local laws have been violated. While to date no civil or criminal charges have been brought against PAA or any of its affiliates, officers or employees by the DOJ, California Attorney General or Santa Barbara County District Attorney, and no fines or penalties have been imposed by such governmental agents, there can be no assurance that such fines or penalties will not be imposed upon us, or that such civil or criminal charges will not be brought against us, in the future. Shortly following the Line 901 incident, we established a claims line and encouraged any parties that were damaged by the release to contact us to discuss their damage claims. We have received a number of claims through the claims line and we are processing those claims as we receive them. In addition, we have also had six class action lawsuits filed against us, all of which have been filed in the United States District Court for the Central District of California. In general, these lawsuits have been brought by various plaintiffs seeking to establish different classes of claimants that have allegedly been damaged by the release, including potential classes such as persons that derive a significant portion of their income through commercial fishing and harvesting activities in the waters adjacent to Santa Barbara County or from businesses that are dependent on marine resources from Santa Barbara County, retail businesses located in historic downtown Santa Barbara, certain owners of oceanfront and/or beachfront property on the Pacific Coast of California, and other classes of businesses that were allegedly impacted by the release. In addition to the foregoing, as the “responsible party” for the Line 901 incident we are liable for various costs and for certain natural resource damages under the Oil Pollution Act, and we also have exposure to the payment of additional fines, penalties and costs under other applicable federal, state and local laws, statutes and regulations. To the extent any such costs are reasonably estimable, we have included an estimate of such costs in the loss accrual described below. Taking the foregoing into account, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $257 million, which estimate includes actual and projected emergency response and clean-up costs, natural resource damage assessments and certain third party claims settlements as well as estimates for fines, penalties and certain legal fees. This estimate does not include any lost revenue associated with the shutdown of Line 901 or 903. In addition, this estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the expected number of days that clean up, remediation and monitoring services will be required, the number of personnel and equipment required at the site and the rates charged by the associated service and equipment providers, (ii) the duration of the natural resource damage assessment and the ultimate amount of damages determined, (iii) the resolution of certain third party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and excluding future claims and lawsuits, (iv) the determination and calculation of fines and penalties and (v) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. Our assumptions and estimates may turn out to be inaccurate and our total costs could turn out to be higher; accordingly, we can provide no assurance that we will not have to accrue additional costs in the future with respect to the Line 901 incident. We have accrued such estimate of aggregate total costs to “Field operating costs” on our Condensed Consolidated Statement of Operations. As of June 30, 2015, we had a remaining undiscounted gross liability of $221 million related to this event, the majority of which is presented as a current liability in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheets. We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such environmental liabilities. Subject to such exclusions and deductibles, we believe that our coverage is adequate to cover the current estimated total emergency response and clean-up costs, claims settlement costs and remediation costs and we believe that this coverage is also adequate to cover any potential increase in the estimates for these costs that exceed the amounts currently identified. We therefore have recognized a receivable of $192 million as of June 30, 2015 for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles. A majority of this receivable has been recognized as a current asset in “Trade accounts receivable and other receivables, net” on our Condensed Consolidated Balance Sheets with the offset reducing “Field operating costs” on our Condensed Consolidated Statement of Operations. We currently expect that the clean-up and remediation efforts, excluding long-term site monitoring activities, will be substantially completed during 2015; however, we expect to make payments for additional costs associated with restoration and monitoring of the area, as well as natural resource damage assessment, legal, professional and regulatory costs, in addition to fines and penalties, during future periods. MP29 Release. On July 10, 2015 , we experienced a crude oil release of approximately 100 barrels at our Pocahontas Pump Station near the border of Bond and Madison Counties in Illinois, approximately 40 miles from St. Louis Missouri. The Pocahontas Station is part of the Capwood pipeline that runs from our Patoka Station to Wood River, Illinois. A portion of the released crude oil was contained within our Pocahontas facility, but some of the released crude oil entered a nearby waterway where it was contained with booms. On July 14, 2015, PHMSA issued a corrective action order requiring us to take various actions in response to the release, including remediation, reporting and other actions. We are in the process of satisfying the requirements of the corrective action order. To date, no fines or penalties have been assessed in this matter; however, it is possible that fines and penalties could be assessed in the future. In connection with this incident, we have also had one class action lawsuit filed against us in the United States District Court for the Southern District of Illinois. In this lawsuit, the plaintiff seeks unspecified money damages and other remedies on behalf of itself and other unspecified similarly situated claimants. We estimate that the aggregate total costs associated with this release will be less than $10 million. Cushing Tank Cathodic Protection . On May 22, 2015, PHMSA issued a Final Order relating to an April 2013 Notice of Probable Violation and Proposed Compliance Order alleging that we did not maintain adequate cathodic protection for certain tanks at our Cushing Terminal. In its 2013 Notice of Probable Violation, PHMSA maintained that the proprietary cathodic protection system utilized by us for certain of our storage tanks at our Cushing, Oklahoma facility was not contemplated by applicable regulations. In response to the notice, we provided extensive documentation and supporting information regarding the effectiveness of the technology we were utilizing, including past communications with PHMSA regarding the topic. At a hearing in August 2013 we gave a formal presentation on the technology, provided empirical data confirming its effectiveness and also had a third party corrosion expert witness speak to the effectiveness of the technology. Almost two years later, PHMSA issued the Final Order and Compliance Order dated May 22, 2015 ruling against our position, assessing a penalty of $102,900 and specifying certain corrective actions to be completed by us. We chose not to further contest this matter and paid the penalty on June 5, 2015. On July 14, 2015, we submitted to PHMSA a Remediation Plan and schedule to satisfy the conditions of the Compliance Order. In the Matter of Bakersfield Crude Terminal LLC et al. On April 30, 2015, the EPA issued a Finding and Notice of Violation (“NOV”) to Bakersfield Crude Terminal LLC, our subsidiary, for alleged violations of the Clean Air Act, as amended. The NOV, which cites 10 separate rule violations, questions the validity of construction and operating permits issued to our Bakersfield rail unloading facility in 2012 and 2014 by the San Joaquin Valley Air Pollution Control District (the “SJV District”). We believe we fully complied with all applicable regulatory requirements and that the permits issued to us by the SJV District are valid. To date, no fines or penalties have been assessed in this matter; however, it is possible that fines and penalties could be assessed in the future. 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. Kemp River Pipeline Releases . During May and June 2013, two separate releases were discovered on our Kemp River pipeline in Northern Alberta, Canada that, in the aggregate, resulted in the release of approximately 700 barrels of condensate and light crude oil. Clean-up and remediation activities are being conducted in cooperation with the applicable regulatory agencies. Final investigation by the Alberta Energy Regulator is not complete. To date, no charges, fines or penalties have been assessed against PMC with respect to these releases; however, it is possible that fines or penalties may be assessed against PMC in the future. We estimate that the aggregate clean-up and remediation costs associated with these releases will be $15 million. Through June 30, 2015, we spent $9 million in connection with clean-up and remediation activities. Bay Springs Pipeline Release. During February 2013, we experienced a crude oil release of approximately 120 barrels on a portion of one of our pipelines near Bay Springs, Mississippi. Most of the released crude oil was contained within our pipeline right of way, but some of the released crude oil entered a nearby waterway where it was contained with booms. The EPA has issued an administrative order requiring us to take various actions in response to the release, including remediation, reporting and other actions. We have satisfied the requirements of the administrative order; however, we may be subjected to a civil penalty. The aggregate cost to clean up and remediate the site was $6 million.

Operating Segments

Operating Segments	6 Months Ended
	Jun. 30, 2015
Operating Segments
Operating Segments	Note 11—Operating Segments We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates segment performance based on measures including segment profit and maintenance capital investment. We define segment profit as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses. Each of the items above excludes depreciation and amortization. Maintenance capital consists of capital expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. The following table reflects certain financial data for each segment for the periods indicated (in millions): Transportation Facilities Supply and Logistics Total Three Months Ended June 30, 2015 Revenues: External customers $ $ $ $ Intersegment (1) Total revenues of reportable segments $ $ $ $ Equity earnings in unconsolidated entities $ $ — $ — $ Segment profit (2) (3) $ $ $ $ Maintenance capital $ $ $ $ Three Months Ended June 30, 2014 Revenues: External customers $ $ $ $ Intersegment (1) Total revenues of reportable segments $ $ $ $ Equity earnings in unconsolidated entities $ $ — $ — $ Segment profit (2) (3) $ $ $ $ Maintenance capital $ $ $ $ Transportation Facilities Supply and Logistics Total Six Months Ended June 30, 2015 Revenues: External customers $ $ $ $ Intersegment (1) Total revenues of reportable segments $ $ $ $ Equity earnings in unconsolidated entities $ $ — $ — $ Segment profit (2) (3) $ $ $ $ Maintenance capital $ $ $ $ Six Months Ended June 30, 2014 Revenues: External customers $ $ $ $ Intersegment (1) Total revenues of reportable segments $ $ $ $ Equity earnings in unconsolidated entities $ $ — $ — $ Segment profit (2) (3) $ $ $ $ Maintenance capital $ $ $ $ (1) Segment revenues and purchases and related costs include intersegment amounts. Intersegment sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market. For further discussion, see “Analysis of Operating Segments” under Item 7 of our 2014 Annual Report on Form 10-K. (2) Supply and Logistics segment profit includes interest expense (related to hedged inventory purchases) of $2 million and $5 million for the three months ended June 30, 2015 and 2014, respectively, and $3 million and $7 million for the six months ended June 30, 2015 and 2014, respectively. (3) The following table reconciles segment profit to net income attributable to PAA (in millions): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Segment profit $ $ $ $ Depreciation and amortization Interest expense, net Other income/(expense), net Income before tax Income tax expense Net income Net income attributable to noncontrolling interests — Net income attributable to PAA $ $ $ $

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2015
Related Party Transactions
Related Party Transactions	Note 12—Related Party Transactions See Note 15 to our Consolidated Financial Statements included in Part IV of our 2014 Annual Report on Form 10-K for a complete discussion of our related party transactions. Transactions with Oxy As of June 30, 2015, Oxy owned approximately 13% of the limited partner interests in our general partner and had a representative on the board of directors of GP LLC. During the three and six months ended June 30, 2015 and 2014, we recognized sales and transportation revenues and purchased petroleum products from Oxy. These transactions were conducted at posted tariff rates or prices that we believe approximate market. See detail below (in millions): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Revenues $ $ $ $ Purchases and related costs $ $ $ $ We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with Oxy were as follows as of the dates indicated (in millions): June 30, December 31, 2015 2014 Trade accounts receivable and other receivables $ $ Accounts payable $ $

Net Income Per Limited Partne22

Net Income Per Limited Partner Unit (Tables)	6 Months Ended
	Jun. 30, 2015
Net Income Per Limited Partner Unit
Computation of basic and diluted net income/(loss) per limited partner unit	The following table sets forth the computation of basic and diluted net income/(loss) per limited partner unit for the periods indicated (in millions, except per unit data): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Basic Net Income per Limited Partner Unit Net income attributable to PAA $ $ $ $ Less: General partner’s incentive distribution (1) Less: General partner 2% ownership (1) — Net income/(loss) attributable to limited partners Less: Undistributed earnings allocated and distributions to participating securities (1) Net income/(loss) attributable to limited partners in accordance with application of the two-class method for MLPs $ $ $ $ Basic weighted average limited partner units outstanding Basic net income/(loss) per limited partner unit $ $ $ $ Diluted Net Income per Limited Partner Unit Net income attributable to PAA $ $ $ $ Less: General partner’s incentive distribution (1) Less: General partner 2% ownership (1) — Net income/(loss) attributable to limited partners Less: Undistributed earnings allocated and distributions to participating securities (1) Net income/(loss) attributable to limited partners in accordance with application of the two-class method for MLPs $ $ $ $ Basic weighted average limited partner units outstanding Effect of dilutive securities: Weighted average LTIP units Diluted weighted average limited partner units outstanding Diluted net income/(loss) per limited partner unit $ $ $ $ (1) We calculate net income attributable 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.

Inventory, Linefill and Base 23

Inventory, Linefill and Base Gas and Long-term Inventory (Tables)	6 Months Ended
	Jun. 30, 2015
Inventory, Linefill and Base Gas and Long-term Inventory
Schedule of inventory, linefill and base gas and long-term inventory	Inventory, linefill and base gas and long-term inventory consisted of the following as of the dates indicated (barrels and natural gas volumes in thousands and carrying value in millions): June 30, 2015 December 31, 2014 Unit of Carrying Price/ Unit of Carrying Price/ Volumes Measure Value Unit (1) Volumes Measure Value Unit (1) Inventory Crude oil barrels $ $ barrels $ $ NGL barrels $ barrels $ Natural gas Mcf $ Mcf $ Other N/A N/A N/A N/A Inventory subtotal Linefill and base gas Crude oil barrels $ barrels $ NGL barrels $ barrels $ Natural gas Mcf $ Mcf $ Linefill and base gas subtotal Long-term inventory Crude oil barrels $ barrels $ NGL barrels $ barrels $ Long-term inventory subtotal Total $ $ (1) Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products.

Debt (Tables)

Debt (Tables)	6 Months Ended
	Jun. 30, 2015
Debt
Schedule of debt	Debt consisted of the following as of the dates indicated (in millions): June 30, December 31, 2015 2014 SHORT-TERM DEBT Commercial paper notes, bearing a weighted-average interest rate of 0.49% and 0.46% , respectively (1) $ $ Senior notes: 5.25% senior notes due June 2015 — 3.95% senior notes due September 2015 Other Total short-term debt LONG-TERM DEBT Senior notes, net of unamortized discount of $16 and $18 , respectively Commercial paper notes, bearing a weighted-average interest rate of 0.49% (2) — Other Total long-term debt Total debt (3) $ $ (1) We classified these commercial paper notes as short-term at June 30, 2015 and December 31, 2014 as these notes were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits. (2) We have the ability and intent to refinance these commercial paper notes on a long-term basis; therefore, we have classified such notes as long-term at June 30, 2015. (3) Our fixed-rate senior notes (including current maturities) had a face value of approximately $9.2 billion and $9.3 billion as of June 30, 2015 and December 31, 2014, respectively. We estimated the aggregate fair value of these notes as of June 30, 2015 and December 31, 2014 to be approximately $9.4 billion and $9.9 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under our credit facilities and commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, credit facilities and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy.

Partners' Capital and Distrib25

Partners' Capital and Distributions (Tables)	6 Months Ended
	Jun. 30, 2015
Partners' Capital and Distributions
Schedule of distributions paid, net of reductions in the general partner's incentive distributions	The following table details the distributions paid during or pertaining to the first six months of 2015, net of reductions to the general partner’s incentive distributions (in millions, except per unit data): Distributions Paid Distributions Limited General Partner per limited Date Declared Distribution Date Partners 2% Incentive Total partner unit July 7, 2015 August 14, 2015 (1) $ $ $ $ $ April 7, 2015 May 15, 2015 $ $ $ $ $ January 8, 2015 February 13, 2015 $ $ $ $ $ (1) Payable to unitholders of rec ord at the close of business on July 31, 2015 for the period April 1, 2015 through June 30, 2015.

Derivatives and Risk Manageme26

Derivatives and Risk Management Activities (Tables)	6 Months Ended
	Jun. 30, 2015
Derivative disclosures
Impact of derivative activities recognized in earnings	A summary of the impact of our derivative activities recognized in earnings for the periods indicated is as follows (in millions): Three Months Ended June 30, 2015 Derivatives in Hedging Relationships Gain/(Loss) Other Reclassified Gain/(Loss) Derivatives Not from AOCI Recognized Designated Location of Gain/(Loss) into Income (1) (2) in Income (3) as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ $ — $ $ Transportation segment revenues — — Field operating costs — — Interest Rate Derivatives Interest expense — Total Gain/(Loss) on Derivatives Recognized in Net Income $ $ $ $ Three Months Ended June 30, 2014 Derivatives in Hedging Relationships Gain/(Loss) Other Reclassified Gain/(Loss) Derivatives Not from AOCI Recognized Designated Location of Gain/(Loss) into Income (1) (2) in Income (3) as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ $ — $ — $ Interest Rate Derivatives Interest expense — — Foreign Currency Derivatives Supply and Logistics segment revenues — — Total Gain/(Loss) on Derivatives Recognized in Net Income $ $ — $ $ Six Months Ended June 30, 2015 Derivatives in Hedging Relationships Gain/(Loss) Other Reclassified Gain/(Loss) Derivatives Not from AOCI Recognized Designated Location of Gain/(Loss) into Income (1) (2) in Income (3) as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ $ — $ $ Transportation segment revenues — — Field operating costs — — Interest Rate Derivatives Interest expense — Foreign Currency Derivatives Supply and Logistics segment revenues — — Total Gain/(Loss) on Derivatives Recognized in Net Income $ $ $ $ Six Months Ended June 30, 2014 Derivatives in Hedging Relationships Gain/(Loss) Other Reclassified Gain/(Loss) Derivatives Not from AOCI Recognized Designated Location of Gain/(Loss) into Income (1) (2) in Income (3) as a Hedge Total Commodity Derivatives Supply and Logistics segment revenues $ $ — $ — $ Field operating costs — — Interest Rate Derivatives Interest expense — — Total Gain/(Loss) on Derivatives Recognized in Net Income $ $ — $ $ (1) Represents gains/(losses) on cash flow hedges reclassified from AOCI to income during the period. (2) During the three and six months ended June 30, 2015 we reclassified a loss of approximately $4 million from AOCI to Interest expense as a result of anticipated hedged transactions that are probable of not occurring. All of our anticipated hedged transactions were deemed probable of occurring during the three and six months ended June 30, 2014. (3) Amounts represent ineffective portion of cash flow hedges.
Summary of derivative assets and liabilities on condensed consolidated balance sheet on a gross basis	The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheets on a gross basis as of June 30, 2015 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Balance Sheet Location Fair Value Location Fair Value Derivatives designated as hedging instruments: Commodity derivatives Other current assets $ Other current liabilities $ Other long-term liabilities and deferred credits Interest rate derivatives Other current assets Other current liabilities Other long-term assets, net Other long-term liabilities and deferred credits Total derivatives designated as hedging instruments $ $ Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ Other current assets $ Other long-term assets, net Other long-term assets, net Other current liabilities Other current liabilities Other long-term liabilities and deferred credits Foreign currency derivatives Other current liabilities Total derivatives not designated as hedging instruments $ $ Total derivatives $ $ The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheets on a gross basis as of December 31, 2014 (in millions): Asset Derivatives Liability Derivatives Balance Sheet Balance Sheet Location Fair Value Location Fair Value Derivatives designated as hedging instruments: Commodity derivatives Other current assets $ Other current assets $ Other long-term assets, net Other long-term assets, net Interest rate derivatives Other current liabilities Other long-term liabilities and deferred credits Total derivatives designated as hedging instruments $ $ Derivatives not designated as hedging instruments: Commodity derivatives Other current assets $ Other current assets $ Other long-term assets, net Other long-term assets, net Other current liabilities Other long-term liabilities and deferred credits Foreign currency derivatives Other current liabilities Total derivatives not designated as hedging instruments $ $ Total derivatives $ $
Schedule of derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements	The following table presents 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): June 30, 2015 December 31, 2014 Derivative Derivative Derivative Derivative Asset Positions Liability Positions Asset Positions Liability Positions Netting Adjustments: Gross position - asset/(liability) $ $ $ $ Netting adjustment Cash collateral paid/(received) — — Net position - asset/(liability) $ $ $ $ Balance Sheet Location After Netting Adjustments: Other current assets $ $ — $ $ — Other long-term assets, net — — Other current liabilities — — Other long-term liabilities and deferred credits — — $ $ $ $
Net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives	The net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives for the periods indicated was as follows (in millions): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Commodity derivatives, net $ $ — $ $ Interest rate derivatives, net Total $ $ $ $
Schedule of derivative financial assets and liabilities by level within the fair value hierarchy accounted for at fair value on a recurring basis	The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the dates indicated (in millions): Fair Value as of June 30, 2015 Fair Value as of December 31, 2014 Recurring Fair Value Measures (1) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Commodity derivatives $ $ $ $ $ $ $ $ Interest rate derivatives — — — — Foreign currency derivatives — — — — Total net derivative asset/(liability) $ $ $ $ $ $ $ $ (1) Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.
Reconciliation of changes in fair value of derivatives classified as Level 3	The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 for the periods indicated (in millions): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Beginning Balance $ $ $ $ Gains/(losses) for the period included in earnings — — Settlements — Derivatives entered into during the period — Ending Balance $ $ $ $ Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period $ $ $ $
Interest Rate Swaps
Derivative disclosures
Schedule of terms of forward starting interest rate swaps	We have entered into forward starting interest rate swaps to hedge the underlying benchmark interest rate related to forecasted interest payments through 2049. The following table summarizes the terms of our forward starting interest rate swaps as of June 30, 2015 (notional amounts in millions): Number and Types of Notional Expected Average Rate Accounting Hedged Transaction Derivatives Employed Amount Termination Date Locked Treatment Anticipated interest payments 7 forward starting swaps (30-year) $ 9/15/2015 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 6/15/2016 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 6/15/2017 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 6/15/2018 % Cash flow hedge Anticipated interest payments 8 forward starting swaps (30-year) $ 6/14/2019 % Cash flow hedge
Foreign Currency Derivatives
Derivative disclosures
Open forward exchange contracts	The following table summarizes our open forward exchange contracts as of June 30, 2015 (in millions): Average Exchange Rate USD CAD USD to CAD Forward exchange contracts that exchange CAD for USD: $ $ $ 1.00 - $ $ 1.00 - $ $ $ Forward exchange contracts that exchange USD for CAD: $ $ $ 1.00 - $ $ 1.00 - $ $ $

Equity-Indexed Compensation P27

Equity-Indexed Compensation Plans (Tables)	6 Months Ended
	Jun. 30, 2015
Summary of expense recognized and the value of vested LTIP awards under equity-indexed compensation plans	The table below summarizes the expense recognized and the value of vested LTIP awards (settled both in common units and cash) under our equity-indexed compensation plans and includes both liability-classified and equity-classified awards for the periods indicated (in millions): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Equity-indexed compensation expense $ $ $ $ LTIP unit-settled vestings $ $ $ $ LTIP cash-settled vestings $ $ $ $ DER cash payments $ $ $ $
Long-Term Incentive Plan Awards
Summary of activity for equity-indexed compensation plans	Activity for LTIP awards under our equity-indexed compensation plans denominated in PAA units is summarized in the following table (units in millions): Weighted Average Grant Date Units (1) Fair Value per Unit Outstanding at December 31, 2014 $ Granted $ Vested (2) $ Cancelled or forfeited $ Outstanding at June 30, 2015 $ (1) Amounts do not include AAP Management Units. (2) Approximately 0.5 million PAA common units were issued, net of tax withholding of 0.2 million units, during the six months ended June 30, 2015 in connection with the settlement of vested awards. The remaining PAA awards that vested during the six months ended June 30, 2015 of approximately 1.1 million units were settled in cash.
AAP Management Units
Summary of activity for equity-indexed compensation plans	Activity for AAP Management Units is summarized in the following table (in millions): Grant Date Reserved for Future Outstanding Units Fair Value Of Outstanding Grants Outstanding Earned AAP Management Units (1) Balance at December 31, 2014 $ Earned N/A N/A N/A Balance at June 30, 2015 $ (1) Of the $64 million grant date fair value, $57 million had been recognized through June 30, 2015 on a cumulative basis. Of this amount, $1 million was recognized as expense during the six months ended June 30, 2015.

Operating Segments (Tables)

Operating Segments (Tables)	6 Months Ended
	Jun. 30, 2015
Operating Segments
Segment financial data	The following table reflects certain financial data for each segment for the periods indicated (in millions): Transportation Facilities Supply and Logistics Total Three Months Ended June 30, 2015 Revenues: External customers $ $ $ $ Intersegment (1) Total revenues of reportable segments $ $ $ $ Equity earnings in unconsolidated entities $ $ — $ — $ Segment profit (2) (3) $ $ $ $ Maintenance capital $ $ $ $ Three Months Ended June 30, 2014 Revenues: External customers $ $ $ $ Intersegment (1) Total revenues of reportable segments $ $ $ $ Equity earnings in unconsolidated entities $ $ — $ — $ Segment profit (2) (3) $ $ $ $ Maintenance capital $ $ $ $ Transportation Facilities Supply and Logistics Total Six Months Ended June 30, 2015 Revenues: External customers $ $ $ $ Intersegment (1) Total revenues of reportable segments $ $ $ $ Equity earnings in unconsolidated entities $ $ — $ — $ Segment profit (2) (3) $ $ $ $ Maintenance capital $ $ $ $ Six Months Ended June 30, 2014 Revenues: External customers $ $ $ $ Intersegment (1) Total revenues of reportable segments $ $ $ $ Equity earnings in unconsolidated entities $ $ — $ — $ Segment profit (2) (3) $ $ $ $ Maintenance capital $ $ $ $ (1) Segment revenues and purchases and related costs include intersegment amounts. Intersegment sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market. For further discussion, see “Analysis of Operating Segments” under Item 7 of our 2014 Annual Report on Form 10-K. (2) Supply and Logistics segment profit includes interest expense (related to hedged inventory purchases) of $2 million and $5 million for the three months ended June 30, 2015 and 2014, respectively, and $3 million and $7 million for the six months ended June 30, 2015 and 2014, respectively. (3) The following table reconciles segment profit to net income attributable to PAA (in millions): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Segment profit $ $ $ $ Depreciation and amortization Interest expense, net Other income/(expense), net Income before tax Income tax expense Net income Net income attributable to noncontrolling interests — Net income attributable to PAA $ $ $ $
Reconciliation of segment profit to net income attributable to PAA	Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Segment profit $ $ $ $ Depreciation and amortization Interest expense, net Other income/(expense), net Income before tax Income tax expense Net income Net income attributable to noncontrolling interests — Net income attributable to PAA $ $ $ $

Related Party Transactions (Tab

Related Party Transactions (Tables)	6 Months Ended
	Jun. 30, 2015
Oxy
Related party transaction
Schedule of related party transactions	These transactions were conducted at posted tariff rates or prices that we believe approximate market. See detail below (in millions): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Revenues $ $ $ $ Purchases and related costs $ $ $ $ We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with Oxy were as follows as of the dates indicated (in millions): June 30, December 31, 2015 2014 Trade accounts receivable and other receivables $ $ Accounts payable $ $

Organization and Basis of Prese

Organization and Basis of Presentation (Details) - 6 months ended Jun. 30, 2015 - segment	Total
Organization
Operating segments number	3
General partner ownership interest (as a percent)	2.00%
PAGP | AAP
Organization
PAGP limited partner interest in AAP (as a percent)	37.00%

Net Income Per Limited Partne31

Net Income Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Net Income Per Limited Partner Unit
General partner ownership interest (as a percent)			2.00%
Basic Net Income per Limited Partner Unit
Net income attributable to PAA	$ 124	$ 287	$ 407	$ 671
Less: General partner's incentive distribution	(146)	(117)	(289)	(227)
Less: General partner 2% ownership		(4)	(2)	(9)
Net income/(loss) attributable to limited partners	(22)	166	116	435
Less: Undistributed earnings allocated and distributions to participating securities	(1)	(1)	(3)	(3)
Net income/(loss) attributable to limited partners in accordance with application of the two-class method for MLPs	$ (23)	$ 165	$ 113	$ 432
Basic weighted average limited partner units outstanding	397	365	390	363
Basic net income/(loss) per limited partner unit	$ (0.06)	$ 0.45	$ 0.29	$ 1.19
Diluted Net Income per Limited Partner Unit
Net income attributable to PAA	$ 124	$ 287	$ 407	$ 671
Less: General partner's incentive distribution	(146)	(117)	(289)	(227)
Less: General partner 2% ownership		(4)	(2)	(9)
Net income/(loss) attributable to limited partners	(22)	166	116	435
Less: Undistributed earnings allocated and distributions to participating securities	(1)	(1)	(3)	(3)
Net income/(loss) attributable to limited partners in accordance with application of the two-class method for MLPs	$ (23)	$ 165	$ 113	$ 432
Basic weighted average limited partner units outstanding	397	365	390	363
Effect of dilutive securities:
Weighted average LTIP units	3	2	3	2
Diluted weighted average limited partner units outstanding	400	367	393	365
Diluted net income/(loss) per limited partner unit	$ (0.06)	$ 0.45	$ 0.29	$ 1.18

Accounts Receivable (Details)

Accounts Receivable (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Accounts Receivable
Advance cash payments received from third parties to mitigate credit risk	$ 115	$ 180
Standby letters of credit	$ 77	$ 198
Substantially all trade accounts receivable, net, maximum age of balances past their scheduled invoice date	30 days	30 days
Allowance for doubtful accounts receivable	$ 4	$ 4

Inventory, Linefill and Base 33

Inventory, Linefill and Base Gas and Long-term Inventory (Details) bbl in Thousands, Mcf in Thousands, $ in Millions	6 Months Ended
	Jun. 30, 2015USD ($)$ / bbl$ / McfMcfbbl	Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)$ / bbl$ / McfMcfbbl
Inventory by category
Inventory	$ 941		$ 891
Linefill and base gas	976		930
Long-term inventory	159		186
Total	2,076		2,007
Inventory-related disclosures
Charge related to the write-down of inventory	24	$ 37
Crude oil
Inventory by category
Inventory	649		304
Linefill and base gas	790		744
Long-term inventory	$ 134		$ 136
Inventory, Volumes (in barrels or in Mcf) | bbl	12,916		6,465
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl	13,195		11,810
Long-term inventory, Volumes (in barrels or in Mcf) | bbl	2,420		2,582
Inventory, Price/Unit of measure (in dollars per unit) | $ / bbl	50.25		47.02
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / bbl	59.87		63
Long-term inventory, Price/Unit of measure (in dollars per unit) | $ / bbl	55.37		52.67
NGL
Inventory by category
Inventory	$ 213		$ 454
Linefill and base gas	48		52
Long-term inventory	$ 25		$ 50
Inventory, Volumes (in barrels or in Mcf) | bbl	12,931		13,553
Linefill and base gas, Volumes (in barrels or in Mcf) | bbl	1,348		1,212
Long-term inventory, Volumes (in barrels or in Mcf) | bbl	1,652		1,681
Inventory, Price/Unit of measure (in dollars per unit) | $ / bbl	16.47		33.50
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / bbl	35.61		42.90
Long-term inventory, Price/Unit of measure (in dollars per unit) | $ / bbl	15.13		29.74
Natural gas
Inventory by category
Inventory	$ 45		$ 102
Linefill and base gas	$ 138		$ 134
Inventory, Volumes (in barrels or in Mcf) | Mcf	16,342		32,317
Linefill and base gas, Volumes (in barrels or in Mcf) | Mcf	29,812		28,612
Inventory, Price/Unit of measure (in dollars per unit) | $ / Mcf	2.75		3.16
Linefill and base gas, Price/Unit of measure (in dollars per unit) | $ / Mcf	4.63		4.68
Other
Inventory by category
Inventory	$ 34		$ 31

Debt (Details)

Debt (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Short-term debt:
Commercial paper notes, bearing a weighted-average interest rate of 0.49% and 0.46%, respectively	$ 512	$ 734
Other short-term debt	3	3
Total short-term debt	915	1,287
Long-term debt:
Senior notes, net of unamortized discount of $16 and $18, respectively	8,759	8,757
Unamortized discount	16	18
Commercial paper notes, bearing a weighted-average interest rate of 0.49%	373
Long-term debt, other	5	5
Total long-term debt	9,137	8,762
Total debt	$ 10,052	$ 10,049
Commercial paper program
Short-term debt:
Weighted average interest rate, short-term (as a percent)	0.49%	0.46%
Long-term debt:
Weighted average interest rate, long-term (as a percent)	0.49%
5.25% senior notes due June 2015
Short-term debt:
Senior Notes, Current		$ 150
Long-term debt:
Debt instrument, interest rate (as a percent)		5.25%
3.95% senior notes due September 2015
Short-term debt:
Senior Notes, Current	$ 400	$ 400
Long-term debt:
Debt instrument, interest rate (as a percent)	3.95%	3.95%

Debt (Details 2)

Debt (Details 2) - USD ($) $ in Millions	1 Months Ended		6 Months Ended
	Jun. 30, 2015	Jan. 31, 2015	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Debt
Repayments of senior notes			$ 149
Outstanding letters of credit	$ 63		63		$ 87
Senior unsecured 364-day revolving credit facility
Debt
Expiration period for credit facility		364 days
Borrowing capacity	1,000	$ 1,000	$ 1,000
Basis Variable interest rate used			Eurocurrency Rate or the Base Rate
Credit agreements and commercial paper program
Debt
Total borrowings			$ 17,900	$ 34,600
Total repayments			17,700	$ 34,900
Senior notes
Debt
Debt instrument face value	9,200		9,200		9,300
Senior notes | Level 2
Debt
Debt instrument fair value	9,400		$ 9,400		$ 9,900
5.25% senior notes due June 2015
Debt
Repayments of senior notes	$ 150

Partners' Capital and Distrib36

Partners' Capital and Distributions (Details) - USD ($) $ / shares in Units, $ in Millions	Aug. 14, 2015	May. 15, 2015	Feb. 13, 2015	Jun. 30, 2015	Jun. 30, 2014
Partners Capital and Distribution
Percentage of distribution amount to the general partner before incentive distributions				2.00%
Total distributions paid during the period				$ 811	$ 673
First Quarter Distribution
Partners Capital and Distribution
Distributions paid to Limited Partners		$ 272
Distributions paid to General Partner - 2%		6
Distributions paid to General Partner - Incentive		142
Total distributions paid during the period		$ 420
Distributions per limited partner unit		$ 0.6850
Distribution declared, date				Apr. 7, 2015
Distribution Date				May 15, 2015
Fourth Quarter Distribution
Partners Capital and Distribution
Distributions paid to Limited Partners			$ 254
Distributions paid to General Partner - 2%			5
Distributions paid to General Partner - Incentive			131
Total distributions paid during the period			$ 390
Distributions per limited partner unit			$ 0.6750
Distribution declared, date				Jan. 8, 2015
Distribution Date				Feb. 13, 2015
Subsequent Event | Second Quarter Distribution
Partners Capital and Distribution
Distributions paid to Limited Partners	$ 276
Distributions paid to General Partner - 2%	6
Distributions paid to General Partner - Incentive	146
Total distributions paid during the period	$ 428
Distributions per limited partner unit	$ 0.6950
Distribution declared, date				Jul. 7, 2015
Distribution Date				Aug. 14, 2015
Unitholders of record, date				Jul. 31, 2015

Partners' Capital and Distrib37

Partners' Capital and Distributions (Details 2) - USD ($) shares in Millions, $ in Millions	1 Months Ended	6 Months Ended
	Mar. 31, 2015	Jun. 30, 2015	Jun. 30, 2014
Partners Capital and Distribution
Issuance of common units, net proceeds		$ 1,121	$ 453
SLC Pipeline LLC
Partners Capital and Distribution
Noncontrolling interests in subsidiaries (as a percent)		25.00%
Continuous Offering Program
Partners Capital and Distribution
Issuance of common units (in units)		1.1
Issuance of common units, net proceeds		$ 59
Contribution from general partner		1
Commissions paid		$ 1
Underwritten Offering
Partners Capital and Distribution
Issuance of common units (in units)	21
Issuance of common units, net proceeds	$ 1,100
Contribution from general partner	$ 21

Derivatives and Risk Manageme38

Derivatives and Risk Management Activities (Details) - Jun. 30, 2015 bbl in Millions, Mcf in Millions, MWh in Millions	bbl / dMWhMcfbbl
Net long position associated with crude oil purchases
Commodity Price Risk Hedging:
Average derivative positions notional amount per day (in barrels) | bbl / d	151,600
Derivative position notional amount (in barrels or Mcf)	4.7
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	17,800
Derivative position notional amount (in barrels or Mcf)	7.6
Crude oil grade spread positions
Commodity Price Risk Hedging:
Average derivative positions notional amount per day (in barrels) | bbl / d	35,800
Derivative position notional amount (in barrels or Mcf)	5.5
Net short position related to anticipated sales of natural gas inventory and base gas requirements
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf) | Mcf	13.9
Net short position related to anticipated purchases and sales of crude oil, NGL and refined products inventory
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	15.3
Positions hedging risk of not utilizing storage capacity
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	15.2
Short propane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	2.9
Short butane position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	0.9
Short WTI position related to subsequent sale of products
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Mcf)	0.3
Long power position for power supply requirements
Commodity Price Risk Hedging:
Derivative position notional amount (in megawatt hours) | MWh	0.5

Derivatives and Risk Manageme39

Derivatives and Risk Management Activities (Details 2) - Income Statement Location [Domain] $ in Millions	1 Months Ended	6 Months Ended
	Jun. 30, 2015USD ($)contract	Jun. 30, 2015USD ($)contract	Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Interest Rate Risk Hedging
Net deferred gains (losses) from interest rate risk hedging included in AOCI	$ (673)	$ (673)	$ (142)	$ (467)	$ (97)
Cash paid in connection with termination of interest rate derivatives		29	$ 7
Interest Rate Derivatives
Interest Rate Risk Hedging
Net deferred gains (losses) from interest rate risk hedging included in AOCI	$ (109)	$ (109)
7 forward starting interest rate swaps (30-year) | Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives (in contracts) | contract	7	7
Notional amount of derivatives	$ 250	$ 250
Rate of fixed interest to be received on interest rate swap (as a percent)	3.02%	3.02%
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	8
Notional amount of derivatives	$ 200	$ 200
Rate of fixed interest to be received on interest rate swap (as a percent)	3.06%	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	8
Notional amount of derivatives	$ 200	$ 200
Rate of fixed interest to be received on interest rate swap (as a percent)	3.14%	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	8
Notional amount of derivatives	$ 200	$ 200
Rate of fixed interest to be received on interest rate swap (as a percent)	3.20%	3.20%
8 forward starting interest rate swaps (30-year), four | Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives (in contracts) | contract	8	8
Notional amount of derivatives	$ 200	$ 200
Rate of fixed interest to be received on interest rate swap (as a percent)	2.83%	2.83%
10 forward starting interest rate swaps | Cash flow hedge
Interest Rate Risk Hedging
Number of interest rate derivatives terminated (in contracts) | contract	10
Notional amount of derivatives	$ 250	$ 250
Rate of fixed interest to be received on interest rate swap (as a percent)	3.60%	3.60%
Cash paid in connection with termination of interest rate derivatives	$ 31

Derivatives and Risk Manageme40

Derivatives and Risk Management Activities (Details 3) - Jun. 30, 2015 CAD in Millions, $ in Millions	USD ($)CAD / $	CADCAD / $
Forward exchange contracts that exchange CAD for USD at the rate USD 1.00 to CAD 1.25 maturing in 2015
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 208	CAD 260
Average exchange rate	1.25	1.25
Forward exchange contracts that exchange CAD for USD at the rate USD 1.00 to CAD 1.25 maturing in 2016
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 30	CAD 38
Average exchange rate	1.25	1.25
Forward exchange contracts that exchange CAD for USD
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 238	CAD 298
Forward exchange contracts that exchange USD for CAD at the rate USD 1.00 to CAD 1.24 maturing in 2015
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 253	CAD 315
Average exchange rate	1.24	1.24
Forward exchange contracts that exchange USD for CAD at the rate USD 1.00 to CAD 1.22 maturing in 2016
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 30	CAD 37
Average exchange rate	1.22	1.22
Forward exchange contracts that exchange USD for CAD
Currency Exchange Rate Risk Hedging:
Notional amount of derivatives	$ 283	CAD 352

Derivatives and Risk Manageme41

Derivatives and Risk Management Activities (Details 4) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Impact of derivative activities recognized in earnings
Total	$ 25	$ 20	$ (22)	$ (11)
Commodity Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	25	12	(2)	(8)
Commodity Derivatives | Transportation segment revenues
Impact of derivative activities recognized in earnings
Total	2		4
Commodity Derivatives | Field operating costs
Impact of derivative activities recognized in earnings
Total	2		(2)	(1)
Interest Rate Derivatives | Interest expense
Impact of derivative activities recognized in earnings
Total	(4)	(1)	(5)	(2)
Foreign Currency Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total		9	(17)
Derivatives in Hedging Relationships | Hedged Transactions probable of not occurring | Interest expense
Impact of derivative activities recognized in earnings
Gain/(loss) reclassified from AOCI into income	(4)		(4)
Derivatives in Hedging Relationships | Cash flow hedge
Impact of derivative activities recognized in earnings
Gain/(loss) reclassified from AOCI into income	(25)	11	(19)	(10)
Other gain/(loss) recognized in income	2		2
Derivatives in Hedging Relationships | Cash flow hedge | Commodity Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Gain/(loss) reclassified from AOCI into income	(19)	12	(12)	(8)
Derivatives in Hedging Relationships | Cash flow hedge | Interest Rate Derivatives | Interest expense
Impact of derivative activities recognized in earnings
Gain/(loss) reclassified from AOCI into income	(6)	(1)	(7)	(2)
Other gain/(loss) recognized in income	2		2
Derivatives Not Designated as a Hedge
Impact of derivative activities recognized in earnings
Total	48	9	(5)	(1)
Derivatives Not Designated as a Hedge | Commodity Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total	44		10
Derivatives Not Designated as a Hedge | Commodity Derivatives | Transportation segment revenues
Impact of derivative activities recognized in earnings
Total	2		4
Derivatives Not Designated as a Hedge | Commodity Derivatives | Field operating costs
Impact of derivative activities recognized in earnings
Total	$ 2		(2)	$ (1)
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Supply and Logistics segment revenues
Impact of derivative activities recognized in earnings
Total		$ 9	$ (17)

Derivatives and Risk Manageme42

Derivatives and Risk Management Activities (Details 5) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015USD ($)contract	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)contract	Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)contract
Derivatives disclosures
Asset Derivatives Fair Value	$ 184		$ 184		$ 493
Liability Derivatives Fair Value	(92)		(92)		(384)
Broker payable	46		46		133
Initial margin	49		49		126
Variation margin posted/(returned)	(95)		(95)		$ (259)
Net gain/(loss) deferred in AOCI	(120)		(120)
Net gain/(loss) expected to be reclassified to earnings in next 12 months			4
Gain/(loss) expected to be reclassified to earnings through 2049			(124)
Net deferred gain/(loss) recognized in AOCI on derivatives	$ 92	$ (19)	$ 20	$ (51)
Number of outstanding derivatives containing credit-risk related contingent features | contract	0		0		0
Derivative credit-risk related contingent features			none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings
Commodity Derivatives
Derivatives disclosures
Net deferred gain/(loss) recognized in AOCI on derivatives	$ (28)		$ (25)	(12)
Interest Rate Derivatives
Derivatives disclosures
Net deferred gain/(loss) recognized in AOCI on derivatives	120	$ (19)	45	$ (39)
Derivatives in Hedging Relationships
Derivatives disclosures
Asset Derivatives Fair Value	30		30		$ 31
Liability Derivatives Fair Value	(9)		(9)		(83)
Derivatives in Hedging Relationships | Commodity Derivatives | Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	11		11		23
Liability Derivatives Fair Value					(12)
Derivatives in Hedging Relationships | Commodity Derivatives | Other long-term assets, net
Derivatives disclosures
Asset Derivatives Fair Value					8
Liability Derivatives Fair Value					(1)
Derivatives in Hedging Relationships | Commodity Derivatives | Other current liabilities
Derivatives disclosures
Liability Derivatives Fair Value	(1)		(1)
Derivatives in Hedging Relationships | Commodity Derivatives | Other long-term liabilities and deferred credits
Derivatives disclosures
Asset Derivatives Fair Value	2		2
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	1		1
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other long-term assets, net
Derivatives disclosures
Asset Derivatives Fair Value	16		16
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other current liabilities
Derivatives disclosures
Liability Derivatives Fair Value	(6)		(6)		(44)
Derivatives in Hedging Relationships | Interest Rate Derivatives | Other long-term liabilities and deferred credits
Derivatives disclosures
Liability Derivatives Fair Value	(2)		(2)		(26)
Derivatives Not Designated as a Hedge
Derivatives disclosures
Asset Derivatives Fair Value	154		154		462
Liability Derivatives Fair Value	(83)		(83)		(301)
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other current assets
Derivatives disclosures
Asset Derivatives Fair Value	139		139		439
Liability Derivatives Fair Value	(59)		(59)		(246)
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other long-term assets, net
Derivatives disclosures
Asset Derivatives Fair Value	14		14		23
Liability Derivatives Fair Value	(1)		(1)		(3)
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other current liabilities
Derivatives disclosures
Asset Derivatives Fair Value	1		1
Liability Derivatives Fair Value	(17)		(17)		(35)
Derivatives Not Designated as a Hedge | Commodity Derivatives | Other long-term liabilities and deferred credits
Derivatives disclosures
Liability Derivatives Fair Value	(4)		(4)		(5)
Derivatives Not Designated as a Hedge | Foreign Currency Derivatives | Other current liabilities
Derivatives disclosures
Liability Derivatives Fair Value	$ (2)		$ (2)		$ (12)

Derivatives and Risk Manageme43

Derivatives and Risk Management Activities (Details 6) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Derivative Asset Positions
Gross Position - Asset	$ 184	$ 493
Netting Adjustment	(63)	(262)
Cash collateral received	(46)	(133)
Net Position - Asset	75	98
Derivative Liability Positions
Gross Position - Liability	(92)	(384)
Netting Adjustment	63	262
Net Position - Liability	(29)	(122)
Other current assets
Derivative Asset Positions
Net Position - Asset	46	71
Other long-term assets, net
Derivative Asset Positions
Net Position - Asset	29	27
Other current liabilities
Derivative Liability Positions
Net Position - Liability	(25)	(91)
Other long-term liabilities and deferred credits
Derivative Liability Positions
Net Position - Liability	$ (4)	$ (31)

Derivatives and Risk Manageme44

Derivatives and Risk Management Activities (Details 7) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Level 3
Rollforward of Level 3 Net Asset/(Liability)
Beginning Balance	$ 5	$ 1	$ 15	$ (3)
Gains/(losses) for the period included in earnings	1		1
Settlements	(1)		(13)	3
Derivatives entered into during the period	4		6	1
Ending Balance	9	1	9	1
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period	5	$ 1	6	$ 1
Recurring Fair Value Measures
Recurring Fair Value Measures
Net derivative asset/(liability)	92		92		$ 109
Recurring Fair Value Measures | Commodity Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	85		85		191
Recurring Fair Value Measures | Interest Rate Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	9		9		(70)
Recurring Fair Value Measures | Foreign Currency Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	(2)		(2)		(12)
Recurring Fair Value Measures | Level 1
Recurring Fair Value Measures
Net derivative asset/(liability)	(18)		(18)		(85)
Recurring Fair Value Measures | Level 1 | Commodity Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	(18)		(18)		(85)
Recurring Fair Value Measures | Level 2
Recurring Fair Value Measures
Net derivative asset/(liability)	101		101		179
Recurring Fair Value Measures | Level 2 | Commodity Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	94		94		261
Recurring Fair Value Measures | Level 2 | Interest Rate Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	9		9		(70)
Recurring Fair Value Measures | Level 2 | Foreign Currency Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	(2)		(2)		(12)
Recurring Fair Value Measures | Level 3
Recurring Fair Value Measures
Net derivative asset/(liability)	9		9		15
Recurring Fair Value Measures | Level 3 | Commodity Derivatives
Recurring Fair Value Measures
Net derivative asset/(liability)	$ 9		$ 9		$ 15

Equity-Indexed Compensation P45

Equity-Indexed Compensation Plans (Details) - 6 months ended Jun. 30, 2015 - Long-Term Incentive Plan Awards - $ / shares shares in Millions	Total
Outstanding (in units)
Outstanding at beginning of period (in units)	7.3
Granted (in units)	1.1
Vested (in units)	(1.8)
Cancelled or forfeited (in units)	(0.1)
Outstanding at end of period (in units)	6.5
Weighted Average Grant Date Fair Value per Unit
Outstanding at beginning of period (in dollars per unit)	$ 41.45
Granted (in dollars per unit)	39.98
Vested (in dollars per unit)	25.96
Cancelled or forfeited (in dollars per unit)	43.26
Outstanding at end of period (in dollars per unit)	$ 45.47
Units issued in connection with the settlement of vested awards, net of tax withholding (in units)	0.5
Units withheld for taxes (in units)	0.2
Vested awards settled in cash (in units)	1.1

Equity-Indexed Compensation P46

Equity-Indexed Compensation Plans (Details 2) - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended		95 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015
Grant Date Fair Value of Outstanding AAP Management Units
Equity-indexed compensation expense	$ 17	$ 34	$ 36	$ 68
AAP Management Units
Reserved for Future Grants
Reserved for future grants, beginning balance (in units)			3
Reserved for future grants, ending balance (in units)	3		3		3
Outstanding
Outstanding, beginning balance (in units)			49.1
Outstanding, ending balance (in units)	49.1		49.1		49.1
Outstanding Units Earned
Outstanding Units Earned, beginning balance (in units)			47.8
Earned (in units)			0.4
Outstanding Units Earned, ending balance (in units)	48.2		48.2		48.2
Grant Date Fair Value of Outstanding AAP Management Units
Grant Date Fair Value of Outstanding AAP Management Units, beginning balance			$ 64
Grant Date Fair Value of Outstanding AAP Management Units, ending balance	$ 64		64		$ 64
Equity-indexed compensation expense			$ 1		$ 57

Equity-Indexed Compensation P47

Equity-Indexed Compensation Plans (Details 3) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Other Consolidated Equity-Indexed Compensation Plan Information
Equity-indexed compensation expense	$ 17	$ 34	$ 36	$ 68
LTIP unit-settled vestings	35	44	35	51
LTIP cash-settled vestings	55	51	55	52
DER cash payments	$ 2	$ 2	$ 4	$ 4

Commitments and Contingencies (

Commitments and Contingencies (Details)	Jul. 10, 2015bbl	Jan. 15, 2015item	Jul. 31, 2015item	May. 31, 2015bbl	Feb. 28, 2013bbl	Jun. 30, 2015USD ($)itembbl	Jun. 30, 2013itembbl	Jun. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Jul. 14, 2015USD ($)	May. 22, 2015USD ($)	Apr. 30, 2015item	Feb. 28, 2015CAD	Dec. 31, 2014USD ($)
Environmental
Estimated undiscounted reserve for environmental liabilities						$ 297,000,000		$ 297,000,000	$ 297,000,000					$ 82,000,000
Estimated undiscounted reserve for environmental liabilities, short-term						197,000,000		197,000,000	197,000,000					13,000,000
Estimated undiscounted reserve for environmental liabilities, long-term						100,000,000		100,000,000	100,000,000					69,000,000
Amounts probable of recovery under insurance and from third parties under indemnification agreements						200,000,000		200,000,000	200,000,000					$ 8,000,000
Line 901 Incident
Environmental
Aggregate total estimated costs						257,000,000		257,000,000	257,000,000
Estimated undiscounted reserve for environmental liabilities						221,000,000		221,000,000	221,000,000
Amounts probable of recovery under insurance and from third parties under indemnification agreements						$ 192,000,000		192,000,000	192,000,000
Amount of crude oil removed from pipeline (in barrels) | bbl						26,500
Charges, fines or penalties assessed						$ 0		0	0
Line 901 Incident | Civil or Criminal Charges
Environmental
Number of cases filed during the period | item						0
Line 901 Incident | Class Action Lawsuits
Environmental
Number of cases filed during the period | item						6
Line 901 Incident | Drain Down Methodology
Environmental
Estimated size of release, excluding potential incremental amount (in barrels) | bbl				2,400		2,400
Line 901 Incident | Alternative Purge Data
Environmental
Estimated size of release, potential incremental amount (in barrels) | bbl						1,000
MP 29 Release | Subsequent Event
Environmental
Estimated size of release (in barrels) | bbl	100
Charges, fines or penalties assessed										$ 0
MP 29 Release | Maximum | Subsequent Event
Environmental
Aggregate total estimated costs										$ 10,000,000
MP 29 Release | Class Action Lawsuits | Subsequent Event
Environmental
Number of cases filed during the period | item			1
Cushing Tank Cathodic Protection | PHMSA
Environmental
Charges, fines or penalties assessed											$ 102,900
In the Matter of Bakersfield Crude Terminal LLC et al
Environmental
Number of alleged rule violations | item												10
Charges, fines or penalties assessed						$ 0		0	0
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						15,000,000		15,000,000	15,000,000
Cost incurred, to date, to clean up and remediate the site								9,000,000
Bay Springs Pipeline Release
Environmental
Estimated size of release (in barrels) | bbl					120
Total cost to clean up and remediate the site									6,000,000
PMC | National Energy Board Audit
Environmental
Number of conditions imposed related to regulatory compliance | item		6
Charges, fines or penalties assessed | CAD													CAD 76,000
PMC | Kemp River Pipeline Release
Environmental
Charges, fines or penalties assessed						$ 0		$ 0	$ 0

Operating Segments (Details)

Operating Segments (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)segment	Jun. 30, 2014USD ($)
Operating Segments
Operating segments number | segment			3
Revenues:
Revenues	$ 6,663	$ 11,195	$ 12,605	$ 22,878
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	52	23	89	44
Segment profit	371	488	884	1,097
Maintenance capital	52	48	102	95
Transportation
Revenues:
Revenues	180	195	366	376
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	52	23	89	44
Segment profit	186	221	428	427
Maintenance capital	33	42	66	76
Facilities
Revenues:
Revenues	137	144	261	301
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment profit	144	134	285	288
Maintenance capital	17	5	32	15
Supply and Logistics
Revenues:
Revenues	6,346	10,856	11,978	22,201
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment profit	41	133	171	382
Maintenance capital	2	1	4	4
Interest expense related to hedged inventory purchases	2	5	3	7
Operating Segments
Revenues:
Revenues	7,022	11,549	13,312	23,602
Operating Segments | Transportation
Revenues:
Revenues	402	412	803	798
Operating Segments | Facilities
Revenues:
Revenues	269	277	525	576
Operating Segments | Supply and Logistics
Revenues:
Revenues	6,351	10,860	11,984	22,228
Intersegment
Revenues:
Revenues	(359)	(354)	(707)	(724)
Intersegment | Transportation
Revenues:
Revenues	(222)	(217)	(437)	(422)
Intersegment | Facilities
Revenues:
Revenues	(132)	(133)	(264)	(275)
Intersegment | Supply and Logistics
Revenues:
Revenues	$ (5)	$ (4)	$ (6)	$ (27)

Operating Segments (Details 2)

Operating Segments (Details 2) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Reconciliation of segment profit to net income attributable to PAA
Segment profit	$ 371	$ 488	$ 884	$ 1,097
Depreciation and amortization	(110)	(100)	(217)	(196)
Interest expense, net	(105)	(82)	(207)	(161)
Other income/(expense), net	1	4	(3)	2
INCOME BEFORE TAX	157	310	457	742
Income tax expense	(33)	(22)	(49)	(70)
NET INCOME	124	288	408	672
Net income attributable to noncontrolling interests		(1)	(1)	(1)
NET INCOME ATTRIBUTABLE TO PAA	$ 124	$ 287	$ 407	$ 671

Related Party Transactions (Det

Related Party Transactions (Details) - Oxy - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Related party transaction
Related party ownership of general partner interest (as a percent)	13.00%		13.00%
Revenues	$ 382	$ 351	$ 558	$ 443
Purchases and related costs	41	$ 209	146	$ 468
Trade accounts receivable and other receivables, gross	736		736		$ 489
Accounts payable, gross	$ 588		$ 588		$ 441