UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~September 30, 2014~~March 31, 2015

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 1-14569

PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)

Delaware		76-0582150
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

333 Clay Street, Suite 1600, Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 646-4100

(Registrant’s telephone number, including area code)

Indicate by check mark whether the ~~registrant:~~registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x		Accelerated filer o

Non-accelerated filer o		Smaller reporting company o
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x No

As of ~~October 31, 2014,~~May 1, 2015, there were ~~372,033,831~~397,241,697 Common Units outstanding.

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)

	September 30,			December 31,			March 31,			December 31,
	2014			2013			2015			2014
	(unaudited)						(unaudited)
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	34		$	41		$	458		$	403
Trade accounts receivable and other receivables, net	3,522			3,638			1,817			2,615
Inventory	1,314			1,065			929			891
Other current assets	290			220			249			270
Total current assets	5,160			4,964			3,453			4,179

PROPERTY AND EQUIPMENT	13,816			12,473			14,436			14,178
Accumulated depreciation	(1,851		)	(1,654		)	(1,952		)	(1,906		)
Property and equipment, net	11,965			10,819			12,484			12,272

OTHER ASSETS
Goodwill	2,481			2,503			2,435			2,465
Investments in unconsolidated entities							1,784			1,735
Linefill and base gas	903			798			960			930
Long-term inventory	270			251			149			186
Investments in unconsolidated entities	582			485
Other, net	476			540
Other long-term assets, net							459			489
Total assets	$	21,837		$	20,360		$	21,724		$	22,256

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES						��
Accounts payable and accrued liabilities	$	4,169		$	3,983		$	2,491		$	2,986
Short-term debt	976			1,113			553			1,287
Other current liabilities	423			315			487			482
Total current liabilities	5,568			5,411			3,531			4,755

LONG-TERM LIABILITIES
Senior notes, net of unamortized discount of $16 and $15, respectively	7,609			6,710
Long-term debt under credit facilities and other	4			5
Senior notes, net of unamortized discount of $17 and $18, respectively							8,758			8,757
Other long-term debt							5			5
Other long-term liabilities and deferred credits	526			531			594			548
Total long-term liabilities	8,139			7,246			9,357			9,310

COMMITMENTS AND CONTINGENCIES (NOTE 11)
COMMITMENTS AND CONTINGENCIES (NOTE 10)

PARTNERS’ CAPITAL
Common unitholders (371,468,177 and 359,133,200 units outstanding, respectively)	7,740			7,349
Common unitholders (397,241,697 and 375,107,793 units outstanding, respectively)							8,413			7,793
General partner	331			295			365			340
Total partners’ capital excluding noncontrolling interests	8,071			7,644			8,778			8,133
Noncontrolling interests	59			59			58			58
Total partners’ capital	8,130			7,703			8,836			8,191
Total liabilities and partners’ capital	$	21,837		$	20,360		$	21,724		$	22,256

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
	2014			2013			2014			2013			2015			2014
	(unaudited)						(unaudited)						(unaudited)
REVENUES
Supply and Logistics segment revenues	$	10,788		$	10,386		$	32,988		$	30,542		$	5,632		$	11,346
Transportation segment revenues	198			179			574			517			185			181
Facilities segment revenues	141			138			443			558			125			157
Total revenues	11,127			10,703			34,005			31,617			5,942			11,684

COSTS AND EXPENSES
Purchases and related costs	10,166			9,909			31,116			28,733			5,042			10,670
Field operating costs	382			326			1,078			1,010			346			336
General and administrative expenses	78			79			257			276			78			89
Depreciation and amortization	97			93			293			265			107			96
Total costs and expenses	10,723			10,407			32,744			30,284			5,573			11,191

OPERATING INCOME	404			296			1,261			1,333			369			493

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	29			19			73			42			37			20
Interest expense (net of capitalized interest of $12, $11, $33 and $30, respectively)	(85		)	(72		)	(246		)	(224		)
Other income/(expense), net	(4		)	3			(2		)	2
Interest expense (net of capitalized interest of $14 and $11, respectively)													(102		)	(78		)
Other expense, net													(4		)	(2		)

INCOME BEFORE TAX	344			246			1,086			1,153			300			433
Current income tax expense	(10		)	(17		)	(62		)	(69		)	(42		)	(36		)
Deferred income tax benefit/(expense)	(10		)	8			(28		)	(10		)	26			(12		)

NET INCOME	324			237			996			1,074			284			385
Net income attributable to noncontrolling interests	(1		)	(6		)	(2		)	(22		)	(1		)	(1		)
NET INCOME ATTRIBUTABLE TO PAA	$	323		$	231		$	994		$	1,052		$	283		$	384

NET INCOME ATTRIBUTABLE TO PAA:
LIMITED PARTNERS	$	195		$	133		$	630		$	764		$	138		$	268
GENERAL PARTNER	$	128		$	98		$	364		$	288		$	145		$	116

BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.52		$	0.38		$	1.71		$	2.23		$	0.36		$	0.74

DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.52		$	0.38		$	1.70		$	2.22		$	0.35		$	0.73

BASIC WEIGHTED AVERAGE LIMITED PARTNER UNITS OUTSTANDING	370			343			365			340			383			360

DILUTED WEIGHTED AVERAGE LIMITED PARTNER UNITS OUTSTANDING	371			345			367			342			385			363

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)

(in millions)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2014

2013

2014

2013

(unaudited)

(unaudited)

Net income

$
324

$
237

$
996

$
1,074

Other comprehensive income/(loss)

(167
)
39

(211
)
(99
)
Comprehensive income

157

276

785

975

Comprehensive income attributable to noncontrolling interests

(1
)
(7
)
(2
)
(27
)
Comprehensive income attributable to PAA

$
156

$
269

$
783

$
948

	Three Months Ended
	March 31,
	2015			2014
	(unaudited)
Net income	$	284		$	385
Other comprehensive loss	(376		)	(136		)
Comprehensive income/(loss)	(92		)	249
Comprehensive income attributable to noncontrolling interests	(1		)	(1		)
Comprehensive income/(loss) attributable to PAA	$	(93	)	$	248

The accompanying notes are an integral part of these condensed consolidated financial statements.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF
CHANGES IN

ACCUMULATED OTHER COMPREHENSIVE INCOME / (LOSS)

(in millions)

	Derivative			Translation						Derivative			Translation
	Instruments			Adjustments			Total			Instruments			Adjustments			Total
	(unaudited)									(unaudited)
Balance at December 31, 2013	$	(77	)	$	(20	)	$	(97	)
Balance at December 31, 2014										$	(159	)	$	(308	)	$	(467	)

Reclassification adjustments	16			—			16			(6		)	—			(6		)
Deferred loss on cash flow hedges, net of tax	(57		)	—			(57		)	(72		)	—			(72		)
Currency translation adjustments	—			(170		)	(170		)	—			(298		)	(298		)
Total period activity	(41		)	(170		)	(211		)	(78		)	(298		)	(376		)
Balance at September 30, 2014	$	(118	)	$	(190	)	$	(308	)
Balance at March 31, 2015										$	(237	)	$	(606	)	$	(843	)

	Derivative			Translation						Derivative			Translation
	Instruments			Adjustments			Total			Instruments			Adjustments			Total
	(unaudited)									(unaudited)
Balance at December 31, 2012	$	(120	)	$	200		$	80
Balance at December 31, 2013										$	(77	)	$	(20	)	$	(97	)

Reclassification adjustments	(124		)	—			(124		)	20			—			20
Deferred gain on cash flow hedges, net of tax	140			—			140
Deferred loss on cash flow hedges, net of tax										(32		)	—			(32		)
Currency translation adjustments	—			(115		)	(115		)	—			(124		)	(124		)
Total period activity	16			(115		)	(99		)	(12		)	(124		)	(136		)
Balance at September 30, 2013	$	(104	)	$	85		$	(19	)
Balance at March 31, 2014										$	(89	)	$	(144	)	$	(233	)

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

							Three Months Ended
	Nine Months Ended September 30,						March 31,
	2014			2013			2015			2014
	(unaudited)						(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	996		$	1,074		$	284		$	385
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	293			265			107			96
Equity-indexed compensation expense	90			96			19			34
Inventory valuation adjustments	37			7			24			37
Deferred income tax expense	28			10
Gain on sales of linefill and base gas	(8		)	(5		)
Deferred income tax (benefit)/expense							(26		)	12
(Gain)/loss on foreign currency revaluation	10			(6		)	(27		)	5
Settlement of terminated interest rate hedging instruments	(7		)	8
Equity earnings in unconsolidated entities, net of distributions	1			(7		)
Equity earnings in unconsolidated entities							(37		)	(20		)
Distributions from unconsolidated entities							54			25
Other	10			—			(9		)	(6		)
Changes in assets and liabilities, net of acquisitions	(172		)	152			343			254
Net cash provided by operating activities	1,278			1,594			732			822

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	(10		)	(28		)	(64		)	—
Additions to property, equipment and other	(1,424		)	(1,217		)	(441		)	(468		)
Investment in unconsolidated entities							(65		)	(26		)
Cash received for sales of linefill and base gas	24			25			—			11
Cash paid for purchases of linefill and base gas	(159		)	(61		)	(96		)	(44		)
Investment in unconsolidated entities	(98		)	(124		)
Proceeds from sales of assets	2			62			1			2
Other investing activities	1			3			(1		)	1
Net cash used in investing activities	(1,664		)	(1,340		)	(666		)	(524		)

CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments under PAA senior secured hedged inventory facility (Note 6)	—			(659		)
Net repayments under PAA senior unsecured revolving credit facility (Note 6)	—			(92		)
Net repayments under PNG credit agreement	—			(32		)
Net borrowings/(repayments) under PAA commercial paper program (Note 6)	(683		)	319
Proceeds from the issuance of senior notes (Note 6)	1,447			699
Net proceeds from the issuance of common units (Note 8)	655			392
Net repayments under commercial paper program (Note 6)							(734		)	(128		)
Net proceeds from the issuance of common units (Note 7)							1,099			148
Contributions from general partner	14			8			22			3
Net proceeds from the issuance of PNG common units	—			40
Distributions paid to common unitholders (Note 8)	(688		)	(585		)
Distributions paid to general partner (Note 8)	(344		)	(270		)
Distributions paid to common unitholders (Note 7)							(254		)	(221		)
Distributions paid to general partner (Note 7)							(136		)	(107		)
Distributions paid to noncontrolling interests	(2		)	(37		)	(1		)	(1		)
Other financing activities	(19		)	(25		)	(2		)	(1		)
Net cash provided by/(used in) financing activities	380			(242		)
Net cash used in financing activities							(6		)	(307		)

Effect of translation adjustment on cash	(1		)	(3		)	(5		)	(2		)

Net increase/(decrease) in cash and cash equivalents	(7		)	9			55			(11		)
Cash and cash equivalents, beginning of period	41			24			403			41
Cash and cash equivalents, end of period	$	34		$	33		$	458		$	30

Cash paid for:
Interest, net of amounts capitalized	$	237		$	230		$	74		$	78
Income taxes, net of amounts refunded	$	135		$	19		$	11		$	66

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(in millions)

								Partners’ Capital																Partners’ Capital
								Excluding						Total										Excluding						Total
	Common Units				General			Noncontrolling			Noncontrolling			Partners’			Common Units				General			Noncontrolling			Noncontrolling			Partners’
	Units	Amount			Partner			Interests			Interests			Capital			Units	Amount			Partner			Interests			Interests			Capital
	(unaudited)																(unaudited)
Balance at December 31, 2013	359.1	$	7,349		$	295		$	7,644		$	59		$	7,703
Balance at December 31, 2014																	375.1	$	7,793		$	340		$	8,133		$	58		$	8,191
Net income	—	630			364			994			2			996			—	138			145			283			1			284
Distributions	—	(688		)	(344		)	(1,032		)	(2		)	(1,034		)	—	(254		)	(136		)	(390		)	(1		)	(391		)
Issuance of common units	11.8	655			14			669			—			669			22.1	1,099			22			1,121			—			1,121
Issuance of common units under LTIP, net of units tendered by employees to satisfy tax withholding obligations	0.6	(18		)	1			(17		)	—			(17		)
Equity-indexed compensation expense	—	25			5			30			—			30			—	8			1			9			—			9
Distribution equivalent right payments	—	(5		)	—			(5		)	—			(5		)	—	(2		)	—			(2		)	—			(2		)
Other comprehensive loss	—	(207		)	(4		)	(211		)	—			(211		)	—	(369		)	(7		)	(376		)	—			(376		)
Other	—	(1		)	—			(1		)	—			(1		)
Balance at September 30, 2014	371.5	$	7,740		$	331		$	8,071		$	59		$	8,130
Balance at March 31, 2015																	397.2	$	8,413		$	365		$	8,778		$	58		$	8,836

								Partners’ Capital																Partners’ Capital
								Excluding						Total										Excluding						Total
	Common Units				General			Noncontrolling			Noncontrolling			Partners’			Common Units				General			Noncontrolling			Noncontrolling			Partners’
	Units	Amount			Partner			Interests			Interests			Capital			Units	Amount			Partner			Interests			Interests			Capital
	(unaudited)																(unaudited)
Balance at December 31, 2012	335.3	$	6,388		$	249		$	6,637		$	509		$	7,146
Balance at December 31, 2013																	359.1	$	7,349		$	295		$	7,644		$	59		$	7,703
Net income	—	764			288			1,052			22			1,074			—	268			116			384			1			385
Distributions	—	(585		)	(270		)	(855		)	(37		)	(892		)	—	(221		)	(107		)	(328		)	(1		)	(329		)
Issuance of common units	7.2	392			8			400			—			400			2.8	148			3			151			—			151
Issuance of common units under LTIP, net of units tendered by employees to satisfy tax withholding obligations	0.5	(11		)	—			(11		)	—			(11		)	0.1	(2		)	—			(2		)	—			(2		)
Equity-indexed compensation expense	—	24			4			28			3			31			—	11			1			12			—			12
Distribution equivalent right payments	—	(4		)	—			(4		)	—			(4		)	—	(1		)	—			(1		)	—			(1		)
Other comprehensive income/(loss)	—	(102		)	(2		)	(104		)	5			(99		)
Issuance of PNG common units	—	8			—			8			32			40
Other	—	(1		)	—			(1		)	—			(1		)
Balance at September 30, 2013	343.0	$	6,873		$	277		$	7,150		$	534		$	7,684
Other comprehensive loss																	—	(133		)	(3		)	(136		)	—			(136		)
Balance at March 31, 2014																	362.0	$	7,419		$	305		$	7,724		$	59		$	7,783

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization and Basis of Consolidation and Presentation

Organization

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

We own and operate midstream energy infrastructure and provide logistics services for crude oil, natural gas liquids (“NGL”), natural gas and refined products. The term NGL includes ethane and natural gasoline products as well as products commonly referred to as liquefied petroleum gas (“LPG”), such as propane and butane. When used in this Form 10-Q, NGL refers to all NGL products including LPG. We own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. Our business activities are conducted through three operating segments: ~~(i)~~ Transportation, ~~(ii)~~ Facilities and ~~(iii)~~ Supply and Logistics. See Note 1211 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. ~~(NYSE: PAGP)~~(“PAGP”) is the sole member of GP LLC, and at ~~September 30, 2014,~~March 31, 2015, owned ~~a 22.4%~~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
~~EBITDA~~EPA		=		~~Earnings before interest, taxes, depreciation and amortization~~United States Environmental Protection Agency
FASB		=		Financial Accounting Standards Board
GAAP		=		Generally accepted accounting principles in the United States
ICE		=		~~IntercontinentalExchange~~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
~~PNG~~	=USD		~~PAA Natural Gas Storage, L.P.~~
~~SEC~~	=		~~Securities and Exchange Commission~~
~~USD~~	=		United States dollar
~~White Cliffs~~	=WTI		~~White Cliffs Pipeline, LLC~~
~~WTI~~	=		West Texas Intermediate

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Basis of Consolidation and Presentation

The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our ~~2013~~2014 Annual Report on Form 10-K. The accompanying consolidated financial statements include the accounts of PAA and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated in ~~consolidation. Certain~~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, ~~2013~~2014 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three ~~and nine~~ months ended ~~September 30, 2014~~March 31, 2015 should not be taken as indicative of results to be expected for the entire year.

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

Note 2—Recent Accounting Pronouncements

~~Other~~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 ~~discussed below and in our 2013 Annual Report on Form 10-K, no new accounting pronouncements have~~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 ~~have been issued during~~voting interest entities, (ii) eliminates the ~~nine months ended~~ ~~September 30, 2014~~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 ~~significance~~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 ~~potential significance to us.~~cash flows.

In May 2014, the FASB issued guidance regarding the recognition of revenue from contracts with customers with the underlying principle that an entity will recognize revenue to reflect amounts expected to be received in exchange for the provision of goods and services to customers upon the transfer of those goods or services. The guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. This guidance becomes effective for interim and annual periods beginning after December 15, 2016 and can be adopted either with a full retrospective approach or a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. We currently expect to adopt this guidance on January 1, 2017, and we are ~~currently~~ evaluating which transition approach to apply and the effect that adopting this guidance will have on our financial position, results of operations and cash flows. In April 2015, the FASB proposed a one year deferral of the effective date of this standard.

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

In March 2013, the FASB issued guidance regarding the release of cumulative translation adjustments into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a business within a foreign entity. This guidance became effective for interim and annual periods beginning after December 15, 2013. We adopted this guidance on January 1, ~~2014.~~2015. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

Table of Contents

Note 3—Net Income Per Limited Partner Unit

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

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

Diluted net income per limited partner unit is computed based on the weighted average number of limited partner units plus the effect of dilutive potential limited partner units outstanding during the period using the two-class method. Our LTIP awards that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical limited partner unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 16 to our Consolidated Financial Statements included in Part IV of our 2014 Annual Report on Form 10-K for a complete discussion of our LTIP awards including specific discussion regarding DERs.

The following table sets forth the computation of basic and diluted net income per limited partner unit for the three months ended March 31, 2015 and 2014 (in millions, except per unit data):

	Three Months Ended March 31,
	2015			2014
Basic Net Income per Limited Partner Unit
Net income attributable to PAA	$	283		$	384
Less: General partner’s incentive distribution (1)	(142		)	(110		)
Less: General partner 2% ownership (1)	(3		)	(6		)
Net income available to limited partners	138			268
Less: Undistributed earnings allocated and distributions to participating securities (1)	(2		)	(2		)
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	136		$	266

Basic weighted average limited partner units outstanding	383			360

Basic net income per limited partner unit	$	0.36		$	0.74

Diluted Net Income per Limited Partner Unit
Net income attributable to PAA	$	283		$	384
Less: General partner’s incentive distribution (1)	(142		)	(110		)
Less: General partner 2% ownership (1)	(3		)	(6		)
Net income available to limited partners	138			268
Less: Undistributed earnings allocated and distributions to participating securities (1)	(2		)	(2		)
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	136		$	266

Basic weighted average limited partner units outstanding	383			360
Effect of dilutive securities: Weighted average LTIP units	2			3
Diluted weighted average limited partner units outstanding	385			363

Diluted net income per limited partner unit	$	0.35		$	0.73

Table of Contents

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

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

	Three Months Ended
	March 31,
	2015		2014
Basic net income per limited partner unit impact	$	—	$	(0.05	)

Diluted net income per limited partner unit impact	$	—	$	(0.05	)

Note 4—Accounts Receivable

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

To mitigate credit risk related to our accounts receivable, we ~~have in place~~utilize a rigorous credit review process. We closely monitor market conditions ~~in order~~ 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 ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, we had received ~~$181~~$130 million and ~~$117~~$180 million, respectively, of advance cash payments from third parties to mitigate credit risk. Furthermore, as of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, we had received ~~$278~~$12 million and ~~$426~~$198 million, respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. ~~In addition,~~The decrease in standby letters of credit and advance cash payments from third parties as of March 31, 2015 compared to December 31, 2014 is largely due to a decrease in exposure to various customers requiring letters of credit. Furthermore, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis.

~~Table of Contents~~

Further, we enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet) for a majority of such arrangements.

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, substantially all of our accounts receivable (net of allowance for doubtful accounts) were less than 30 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled $4 million ~~and $5 million at September 30, 2014~~as of both March 31, 2015 and December 31, ~~2013, respectively.~~2014. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

Note 4—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):

	September 30, 2014						December 31, 2013
		Unit of	Carrying		Price/			Unit of	Carrying		Price/		March 31, 2015						December 31, 2014
	Volumes	Measure	Value		Unit (1)		Volumes	Measure	Value		Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	5,665	barrels	$	476	$	84.02	6,951	barrels	$	540	$	77.69	15,351	barrels	$	686	$	44.69	6,465	barrels	$	304	$	47.02
NGL	17,392	barrels	699		$	40.19	8,061	barrels	352		$	43.67	7,277	barrels	154		$	21.16	13,553	barrels	454		$	33.50
Natural gas	29,245	Mcf	119		$	4.07	40,505	Mcf	150		$	3.70	10,965	Mcf	31		$	2.83	32,317	Mcf	102		$	3.16
Other	N/A		20		N/A		N/A		23		N/A		N/A		58		N/A		N/A		31		N/A
Inventory subtotal			1,314						1,065						929						891

Linefill and base gas
Crude oil	11,390	barrels	715		$	62.77	10,966	barrels	679		$	61.92	12,970	barrels	777		$	59.91	11,810	barrels	744		$	63.00
NGL	1,214	barrels	54		$	44.48	1,341	barrels	62		$	46.23	1,215	barrels	48		$	39.51	1,212	barrels	52		$	42.90
Natural gas	28,612	Mcf	134		$	4.68	16,615	Mcf	57		$	3.43	28,612	Mcf	135		$	4.72	28,612	Mcf	134		$	4.68
Linefill and base gas subtotal			903						798						960						930

Long-term inventory
Crude oil	2,557	barrels	207		$	80.95	2,498	barrels	202		$	80.86	2,646	barrels	117		$	44.22	2,582	barrels	136		$	52.67
NGL	1,681	barrels	63		$	37.48	1,161	barrels	49		$	42.20	1,681	barrels	32		$	19.04	1,681	barrels	50		$	29.74
Long-term inventory subtotal			270						251						149						186

Total			$	2,487					$	2,114					$	2,038					$	2,007

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

At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Condensed Consolidated Statements of Operations. We ~~did not record any such charges~~recorded a charge of $24 million during the three months ended ~~September 30, 2014. We~~March 31, 2015 primarily related to the writedown of our NGL inventory due to declines in prices. The loss was substantially offset by a portion of the derivative mark-to-market gain that was recognized in the fourth quarter of 2014 for which the related derivatives were still open as of March 31, 2015. See Note 8 for discussion of our derivative and risk management activities. During the three months ended March 31, 2014, we recorded a charge of $37 million ~~during the nine months ended September 30, 2014~~ 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. During the three and nine months ended September 30, 2013, we recorded a charge of $7 million, primarily related to the writedown of our crude oil inventory due to declines in prices during the period. These adjustments are a component of “Purchases and related costs” on our accompanying condensed consolidated statements of operations. The recognition of the adjustment in 2013 was substantially offset by the recognition of gains on derivative instruments being utilized to hedge the future sales of our crude oil inventory. Substantially all of such gains were recorded to “Supply and Logistics segment revenues” on our accompanying condensed consolidated statements of operations. See Note 10 for discussion of our derivatives and risk management activities.

1012

~~Table of Contents~~

~~Note 5—Goodwill~~

~~The table below reflects our goodwill by segment and changes during the period indicated (in millions):~~

Transportation

Facilities

Supply and Logistics

Total

Balance at December 31, 2013

$
878

$
1,162

$
463

$
2,503

Foreign currency translation adjustments

(14
)
(6
)
(3
)
(23
)
Other

—

1

—

1

Balance at September 30, 2014

$
864

$
1,157

$
460

$
2,481

~~We completed our annual goodwill impairment test as of June 30, 2014 and determined that there was no impairment of goodwill.~~

Note 6—Debt

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

September 30,

December 31,

2014

2013

SHORT-TERM DEBT

PAA commercial paper notes, bearing a weighted-average interest rate of 0.30% and 0.33%, respectively (1)

$
423

$
1,109

PAA senior notes:

5.25% senior notes due June 2015

150

—

3.95% senior notes due September 2015

400

—

Other

3

4

Total short-term debt

976

1,113

LONG-TERM DEBT

PAA senior notes:

5.25% senior notes due June 2015

—

150

3.95% senior notes due September 2015

—

400

5.88% senior notes due August 2016

175

175

6.13% senior notes due January 2017

400

400

6.50% senior notes due May 2018

600

600

8.75% senior notes due May 2019

350

350

5.75% senior notes due January 2020

500

500

5.00% senior notes due February 2021

600

600

3.65% senior notes due June 2022

750

750

2.85% senior notes due January 2023

400

400

3.85% senior notes due October 2023

700

700

3.60% senior notes due November 2024

750

—

6.70% senior notes due May 2036

250

250

6.65% senior notes due January 2037

600

600

5.15% senior notes due June 2042

500

500

4.30% senior notes due January 2043

350

350

4.70% senior notes due June 2044

700

—

Unamortized discounts

(16
)
(15
)
PAA senior notes, net of unamortized discounts

7,609

6,710

Other

4

5

Total long-term debt

7,613

6,715

Total debt (2)

$
8,589

$
7,828

	March 31,		December 31,
	2015		2014
SHORT-TERM DEBT
Commercial paper notes, bearing a weighted-average interest rate of 0.46% at December 31, 2014 (1)	$	—	$	734
Senior notes:
5.25% senior notes due June 2015	150		150
3.95% senior notes due September 2015	400		400
Other	3		3
Total short-term debt	553		1,287

LONG-TERM DEBT
Senior notes, net of unamortized discount of $17 and $18, respectively	8,758		8,757
Other	5		5
Total long-term debt	8,763		8,762
Total debt (2)	$	9,316	$	10,049

~~Table of Contents~~

(2) Our fixed-rate senior notes (including current maturities) had a face value of approximately ~~$8.2~~$9.3 billion ~~and $6.7 billion at September 30, 2014~~as of both March 31, 2015 and December 31, ~~2013, respectively.~~2014. We estimated the aggregate fair value of these notes as of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014 to be approximately ~~$8.8~~$10.0 billion and ~~$7.2~~$9.9 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near quarter end. We estimate that the carrying value of outstanding borrowings under our credit facilities and commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, credit facilities and commercial paper program are based upon observable market data and are classified ~~within~~in Level 2 ~~of the fair value hierarchy. See Note 10 for additional discussion~~ of the fair value hierarchy.

Credit Facilities

~~In August 2014, we extended the maturity dates of our senior secured hedged inventory facility and our~~PAA senior unsecured 364-day revolving credit ~~facility by one year through~~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 ~~exercise of~~Eurocurrency Rate or the ~~option included~~Base Rate, as defined in the ~~current~~agreement, in each case plus a margin based on our credit ~~agreements. Our senior secured hedged inventory facility and our senior unsecured revolving credit facility now mature in August 2017 and August 2019, respectively.~~rating at the applicable time.

Borrowings and Repayments

Total borrowings under our credit agreements and ~~the~~ commercial paper program for the ~~nine~~three months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~ were approximately ~~$55.6~~$7.0 billion and ~~$12.7~~$19.2 billion, respectively. Total repayments under our credit agreements and ~~the~~ commercial paper program were approximately $7.7 billion and $19.3 billion for the ~~nine~~three months ended ~~September 30,~~March 31, 2015 and 2014, ~~and 2013 were approximately $56.3 billion and $13.2 billion,~~ respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.

Letters of Credit

In connection with our supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs and construction activities. At ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, we had outstanding letters of credit of ~~$66~~$83 million and ~~$41~~$87 million, respectively.

~~Senior Notes Issuances~~

On April 23, 2014, we completed the issuance of $700 million, 4.70% senior notes due 2044 at a public offering price of 99.734%. Interest payments are due on June 15 and December 15 of each year, commencing on December 15, 2014. In anticipation of the issuance of these senior notes, we entered into $250 million notional principal amount of U.S. treasury locks in March and April 2014 to hedge the treasury rate portion of the interest rate on a portion of the notes. We terminated these treasury locks in April 2014. See Note 10 for additional disclosure.

On September 9, 2014, we completed the issuance of $750 million, 3.60% senior notes due 2024 at a public offering price of 99.842%. Interest payments are due on May 1 and November 1 of each year, commencing on May 1, 2015.

~~Commercial Paper Program~~

~~Effective October 20, 2014, the maximum aggregate borrowing capacity under our commercial paper program was increased from $1.5 billion to $3.0 billion.~~

~~Note 7—Net Income Per Limited Partner Unit~~

~~Basic and diluted net income per limited partner unit is determined~~ pursuant to the two-class method for Master Limited Partnerships 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.

~~Table of Contents~~

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

Diluted net income per limited partner unit is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period using the two-class method. Our LTIP awards that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by FASB. See Note 15 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K for a complete discussion of our LTIP awards including specific discussion regarding DERs.

The following table sets forth the computation of basic and diluted net income per limited partner unit for the three and nine months ended September 30, 2014 and 2013 (in millions, except per unit data):

Three Months Ended
September 30,

Nine Months Ended
September 30,

2014

2013

2014

2013

Basic Net Income per Limited Partner Unit

Net income attributable to PAA

$
323

$
231

$
994

$
1,052

Less: General partner’s incentive distribution (1)

(124
)
(95
)
(351
)
(272
)
Less: General partner 2% ownership (1)

(4
)
(3
)
(13
)
(16
)
Net income available to limited partners

195

133

630

764

Less: Undistributed earnings allocated and distributions to participating securities (1)

(1
)
(1
)
(5
)
(5
)
Net income available to limited partners in accordance with application of the two-class method for MLPs

$
194

$
132

$
625

$
759

Basic weighted average limited partner units outstanding

370

343

365

340

Basic net income per limited partner unit

$
0.52

$
0.38

$
1.71

$
2.23

Diluted Net Income per Limited Partner Unit

Net income attributable to PAA

$
323

$
231

$
994

$
1,052

Less: General partner’s incentive distribution (1)

(124
)
(95
)
(351
)
(272
)
Less: General partner 2% ownership (1)

(4
)
(3
)
(13
)
(16
)
Net income available to limited partners

195

133

630

764

Less: Undistributed earnings allocated and distributions to participating securities (1)

(1
)
(1
)
(5
)
(4
)
Net income available to limited partners in accordance with application of the two-class method for MLPs

$
194

$
132

$
625

$
760

Basic weighted average limited partner units outstanding

370

343

365

340

Effect of dilutive securities: Weighted average LTIP units

1

2

2

2

Diluted weighted average limited partner units outstanding

371

345

367

342

Diluted net income per limited partner unit

$
0.52

$
0.38

$
1.70

$
2.22

~~(1)~~We calculate net income available to limited partners based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, limited partners and participating securities in accordance with the contractual terms of the partnership agreement and as further prescribed under the two-class method.

~~Table of Contents~~

Three Months Ended
September 30 ,

Nine Months Ended
September 30,

2014

2013

2014

2013

Basic net income per limited partner unit impact

$
—

$
—

$
—

$
(0.23
)

Diluted net income per limited partner unit impact

$
—

$
—

$
—

$
(0.23
)

Note 8—7—Partners’ Capital and Distributions

Distributions

The following table details the distributions paid during or pertaining to the first ~~nine~~three months of ~~2014,~~2015, net of reductions to the general partner’s incentive distributions (in millions, except per unit data):

Distributions Paid

Distributions

Common

General Partner

per limited

Date Declared

Distribution Date

Units

Incentive

2%

Total

partner unit

October 8, 2014

November 14, 2014 (1)

$
245

$
124

$
5

$
374

$
0.6600

July 8, 2014

August 14, 2014

$
238

$
117

$
5

$
360

$
0.6450

April 7, 2014

May 15, 2014

$
229

$
110

$
5

$
344

$
0.6300

January 9, 2014

February 14, 2014

$
221

$
102

$
5

$
328

$
0.6150

		Distributions Paid								Distributions
		Limited		General Partner						per limited
Date Declared	Distribution Date	Partners		2%		Incentive		Total		partner unit
April 7, 2015	May 15, 2015(1)	$	272	$	6	$	142	$	420	$	0.6850
January 8, 2015	February 13, 2015	$	254	$	5	$	131	$	390	$	0.6750

(1) Payable to unitholders of record at the close of business on ~~October 31, 2014~~May 1, 2015 for the period ~~July~~January 1, ~~2014~~2015 through ~~September 30, 2014.~~March 31, 2015.

~~Continuous Offering Program~~PAA Equity Offerings

In August 2014, we entered into an equity distribution agreement with several financial institutions pursuant to which we may offer and sell, through sales agents, common units representing limited partner interests having an aggregate offering price of up to $900 million.Continuous Offering Program. During the ~~nine~~three months ended ~~September 30, 2014,~~March 31, 2015, we issued an aggregate of approximately ~~11.8~~1.1 million common units under our continuous offering program, generating proceeds of ~~$669~~$59 million, including our general partner’s proportionate capital contribution of ~~$14~~$1 million, net of $7$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 ~~September 30, 2014,~~March 31, 2015, noncontrolling interests in our subsidiaries consisted of a 25% interest in SLC Pipeline LLC. ~~On December 31, 2013, we purchased the noncontrolling interests in PNG, and PNG became our wholly-owned subsidiary.~~

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 15 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K.

~~Table of Contents~~

~~PAA LTIP Awards~~

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

Units (1)

Weighted Average Grant
Date
Fair Value per Unit

Outstanding at December 31, 2013

8.4

$
36.97

Granted

1.1

$
47.27

Vested (2)

(1.9
)
$
25.54

Cancelled or forfeited

(0.3
)
$
39.63

Outstanding at September 30, 2014

7.3

$
41.28

~~(1)Amounts do not include AAP Management Units.~~

~~(2)~~During the nine months ended September 30, 2014, approximately 0.6 million PAA common units were issued, net of approximately 0.3 million units withheld for taxes, in connection with the settlement of vested awards. The remaining PAA awards (approximately 1.0 million units) that vested during the nine months ended September 30, 2014 were settled in cash.

~~AAP Management Units~~

~~Activity for AAP Management Units is summarized in the following table (in millions):~~

Reserved for Future
Grants

Outstanding

Outstanding Units
Earned

Grant Date
Fair Value Of Outstanding AAP
Management Units (1)

Balance at December 31, 2013

3.5

48.6

47.0

$
51

Granted

(0.4
)
0.4

—

11

Earned

N/A

N/A

0.8

N/A

Balance at September 30, 2014

3.1

49.0

47.8

$
62

~~(1)~~Of the $62 million grant date fair value, approximately $54 million had been recognized through September 30, 2014. Approximately $5 million of such amount was recognized as expense during the nine months ended September 30, 2014.

~~Other Consolidated Equity-Indexed Compensation Plan Information~~

The table below summarizes the expense recognized and the value of vested LTIPs (settled both in common units and cash) under our equity-indexed compensation plans and includes both liability-classified and equity-classified awards (in millions):

Three Months Ended

Nine Months Ended

September 30,

September 30,

2014

2013

2014

2013

Equity-indexed compensation expense

$
22

$
17

$
90

$
96

LTIP unit-settled vestings

$
1

$
1

$
52

$
47

LTIP cash-settled vestings

$
—

$
—

$
52

$
61

DER cash payments

$
2

$
2

$
6

$
5

~~Table of Contents~~

~~Note 10—~~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 ~~September 30, 2014,~~March 31, 2015, net derivative positions related to these activities included:

· An average of ~~248,700~~233,600 barrels per day net long position (total of ~~7.7~~7.0 million barrels) associated with our crude oil purchases, which was unwound ratably during ~~October 2014~~April 2015 to match monthly average pricing.

· A net short time spread position averaging ~~approximately 19,900~~18,200 barrels per day (total of ~~11.5~~7.2 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through June 2016. ~~Our use of these derivatives does not expose us to outright price risk.~~

· An average of ~~15,200~~37,500 barrels per day (total of ~~6.5~~9.1 million barrels) of crude oil grade spread positions through December 2015. These derivatives allow us to lock in grade basis differentials. ~~Our use of these derivatives does not expose us to outright price risk.~~

· A net short position of ~~approximately 25.1~~6.8 Bcf through April 2016 related to anticipated sales of natural gas inventory and base gas requirements.

· A net short position of ~~approximately 12.1~~16.8 million barrels through ~~December 2015~~March 2017 related to ~~the~~ anticipated purchases and sales of our crude oil, NGL and refined products inventory.

~~Pipeline Loss Allowance Oil~~ — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to offset losses due to evaporation, measurement and other losses in transit. We utilize derivative instruments to hedge a portion of the anticipated sales of the allowance oil that is to be collected under our tariffs. As of September 30, 2014, our PLA hedges included a net short position for an average of approximately 1,400 barrels per day (total of 1.1 million barrels) through December 2016 and a long call position of approximately 0.6 million barrels through December 2016.

Natural Gas Processing/NGL Fractionation — ~~As part of our supply and logistics activities, we~~We purchase natural gas for processing and operational needs. Additionally, we purchase NGL mix for fractionation and we 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 ~~September 30, 2014,~~March 31, 2015, we had a long natural gas position of ~~approximately 33.3~~18.1 Bcf through December 2016, a short propane position of ~~approximately 5.4~~3.5 million barrels through December 2016, a short butane position of 1.0 million barrels through December 2016 and a short ~~butane~~WTI position of ~~approximately 1.6~~0.4 million barrels through December 2016.

~~Table~~ In addition, we had a long power position of ~~Contents~~0.4 million megawatt hours, which hedges a portion of our power supply requirements at our natural gas processing and fractionation plants through December 2016.

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

Interest Rate Risk Hedging

We use interest rate derivatives to hedge interest rate risk associated with anticipated debt issuances and outstanding debt instruments. The derivative instruments we use to manage this risk consist primarily of interest rate swaps and treasury locks. As of ~~September 30, 2014,~~March 31, 2015, AOCI includes deferred losses of ~~$108~~$234 million that relate to open and terminated interest rate derivatives that were designated ~~for hedge accounting.~~as cash flow hedges. The terminated interest rate derivatives were cash-settled in connection with the issuance or refinancing of debt agreements. The deferred loss related to these instruments is being amortized to interest expense over the terms of the hedged debt instruments.

We have entered into forward starting interest rate swaps to hedge the underlying benchmark interest rate related to forecasted debt issuances through ~~2015.~~2019. The following table summarizes the terms of our forward starting interest rate swaps as of ~~September 30, 2014~~March 31, 2015 (notional amounts in millions):

Hedged Transaction

Number and Types of
Derivatives Employed

Notional
Amount

Expected
Termination Date

Average Rate
Locked

Accounting
Treatment

Number and Types of
Derivatives Employed

Notional
Amount

Expected
Termination Date

Average Rate
Locked

Accounting
Treatment

Anticipated debt offering

10 forward starting swaps (30-year)

250

6/15/2015

3.60%

Cash flow hedge

10 forward starting swaps (30-year)

250

6/15/2015

3.60%

Cash flow hedge

Anticipated debt offering

8 forward starting swaps (30-year)

200

6/15/2016

3.06%

Cash flow hedge

Anticipated debt offering

8 forward starting swaps (30-year)

200

6/15/2017

3.14%

Cash flow hedge

Anticipated debt offering

8 forward starting swaps (30-year)

200

6/15/2018

3.20%

Cash flow hedge

Anticipated debt offering

8 forward starting swaps (30-year)

200

6/14/2019

2.83%

Cash flow hedge

In anticipation of our April 2014 issuance of senior notes, we entered into an aggregate of five treasury lock agreements in March and April 2014 for a combined notional amount of $250 million at a locked in rate of 3.62%. The treasury locks were designated as cash flow hedges, thus, changes in fair value are deferred in AOCI. In connection with our April 2014 senior notes issuance, these treasury locks were terminated prior to maturity for an aggregate cash payment of $7 million. The effective portion of the treasury locks was deferred in AOCI and will be amortized to interest expense over the life of the senior notes.15

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 ~~September 30, 2014,~~March 31, 2015, our outstanding foreign currency derivatives include derivatives we use to (i) hedge currency exchange risk associated with USD-denominated commodity purchases and sales in Canada and (ii) hedge currency exchange risk created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales.

The following table summarizes our open forward exchange contracts as of ~~September 30, 2014~~March 31, 2015 (in millions):

USD

CAD

Average Exchange Rate USD
to CAD

Forward exchange contracts that exchange CAD for USD:

2014

$
284

$
319

$1.00 - $1.12

2015

178

200

$1.00 - $1.12

$
462

$
519

$1.00 - $1.12

Forward exchange contracts that exchange USD for CAD:

2014

$
284

$
313

$1.00 - $1.10

2015

178

195

$1.00 - $1.09

$
462

$
508

$1.00 - $1.10

~~Table of Contents~~

		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2015	$	147	$	187	$1.00 - $1.27
	2016	5		7		$1.00 - $1.27
		$	152	$	194

Forward exchange contracts that exchange USD for CAD:
	2015	$	181	$	225	$1.00 - $1.24
	2016	5		7		$1.00 - $1.27
		$	186	$	232

Summary of Financial Impact

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

Table of Contents

A summary of the impact of our derivative activities recognized in earnings for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~ is as follows (in millions):

	Three Months Ended September 30, 2014											Three Months Ended September 30, 2013
	Derivatives in Hedging Relationships											Derivatives in Hedging Relationships											Three Months Ended March 31, 2015									Three Months Ended March 31, 2014
Location of gain/(loss)	Gain/(loss) reclassified from AOCI into income (1)			Other gain/(loss) recognized in income		Derivatives Not Designated as a Hedge			Total			Gain/(loss) reclassified from AOCI into income (1)			Other gain/(loss) recognized in income		Derivatives Not Designated as a Hedge			Total			Derivatives in Hedging Relationships (1)			Derivatives Not Designated as a Hedge			Total			Derivatives in Hedging Relationships (1)			Derivatives Not Designated as a Hedge			Total
Commodity Derivatives

Supply and Logistics segment revenues	$	(4	)	$	—	$	(17	)	$	(21	)	$	109		$	—	$	(91	)	$	18		$	7		$	(34	)	$	(27	)	$	(19	)	$	—		$	(19	)

Facilities segment revenues	—			—		—			—			(2		)	—		—			(2		)
Transportation segment revenues																							—			2			2			—			—			—

Field operating costs	—			—		(2		)	(2		)	—			—		2			2			—			(4		)	(4		)	—			(1		)	(1		)

Interest Rate Derivatives

Interest expense	(1		)	—		—			(1		)	(2		)	3		—			1			(1		)	—			(1		)	(1		)	—			(1		)

Foreign Currency Derivatives

Supply and Logistics segment revenues	—			—		(17		)	(17		)	—			—		—			—			—			(17		)	(17		)	—			(9		)	(9		)

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

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(5	)	$	—	$	(36	)	$	(41	)	$	106		$	3	$	(89	)	$	20		$	6		$	(53	)	$	(47	)	$	(20	)	$	(10	)	$	(30	)

(1)Represents gains/(losses) on cash flow hedges reclassified from AOCI to income during the period.

Table of Contents

The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of March 31, 2015 (in millions):

	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	18	Other long-term liabilities and deferred credits	$	(2	)
	Other long-term liabilities and deferred credits	3

Interest rate derivatives				Other current liabilities	(64		)
				Other long-term liabilities and deferred credits	(80		)
Total derivatives designated as hedging instruments		$	21		$	(146	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	205	Other current assets	$	(47	)
	Other long-term assets, net	18		Other current liabilities	(40		)
	Other long-term liabilities and deferred credits	2		Other long-term liabilities and deferred credits	(13		)

Foreign currency derivatives				Other current liabilities	(4		)
Total derivatives not designated as hedging instruments		$	225		$	(104	)

Total derivatives		$	246		$	(250	)

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

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	23	Other current assets	$	(12	)
	Other long-term assets, net	8		Other long-term assets, net	(1		)

Interest rate derivatives				Other current liabilities	(44		)
				Other long-term liabilities and deferred credits	(26		)
Total derivatives designated as hedging instruments		$	31		$	(83	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	439	Other current assets	$	(246	)
	Other long-term assets, net	23		Other long-term assets, net	(3		)
				Other current liabilities	(35		)
				Other long-term liabilities and deferred credits	(5		)

Foreign currency derivatives				Other current liabilities	(12		)
Total derivatives not designated as hedging instruments		$	462		$	(301	)

Total derivatives		$	493		$	(384	)

Table of Contents

Nine Months Ended September 30, 2014

Nine Months Ended September 30, 2013

Derivatives in Hedging
Relationships

Derivatives in Hedging
Relationships

Location of gain/(loss)

Gain/(loss)
reclassified
from
AOCI into
income (1)

Other
gain/(loss)
recognized
in income

Derivatives
Not
Designated
as a
Hedge

Total

Gain/(loss)
reclassified
from
AOCI into
income (1)

Other
gain/(loss)
recognized
in income

Derivatives
Not
Designated
as a
Hedge

Total

Commodity Derivatives

Supply and Logistics segment revenues

$
(12
)
$
—

$
(17
)
$
(29
)

$
139

$
—

$
(34
)
$
105

Facilities segment revenues

—

—

—

—

(14
)
—

—

(14
)

Field operating costs

—

—

(3
)
(3
)

—

—

7

7

Interest Rate Derivatives

Interest expense

(4
)
—

—

(4
)

(5
)
3

—

(2
)

Foreign Currency Derivatives

Supply and Logistics segment revenues

—

—

(17
)
(17
)

—

—

—

—

Other income/(expense), net

—

—

—

—

4

—

—

4

Total Gain/(Loss) on Derivatives Recognized in Net Income

$
(16
)
$
—

$
(37
)
$
(53
)

$
124

$
3

$
(27
)
$
100

~~(1)~~During the three and nine months ended September 30, 2014, all of our hedged transactions were probable of occurring. During the three months ended September 30, 2013 we reclassified losses of $2 million from AOCI to Facilities segment revenues as a result of anticipated hedged transactions that were probable of not occurring. During the nine months ended September 30, 2013, we reclassified gains of $3 million and losses of $1 million from AOCI to Supply and Logistics segment revenues and Facilities segment revenues, respectively, as a result of anticipated hedged transactions that were probable of not occurring.

~~Table of Contents~~

~~The following table summarizes the derivative assets and liabilities on our condensed consolidated balance sheet on a gross basis as of September 30, 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

$
7

Other long-term assets

4

Interest rate derivatives

Other current liabilities

$
(15
)
Total derivatives designated as hedging instruments

$
11

$
(15
)

Derivatives not designated as hedging instruments:

Commodity derivatives

Other current assets

$
65

Other current assets

$
(43
)

Other long-term assets

5

Other current liabilities

(7
)

Other current liabilities

2

Other long-term liabilities

(2
)
Foreign currency derivatives

Other current liabilities

(10
)
Total derivatives not designated as hedging instruments

$
72

$
(62
)

Total derivatives

$
83

$
(77
)

~~The following table summarizes the derivative assets and liabilities on our condensed consolidated balance sheet on a gross basis as of December 31, 2013 (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

$
36

Other current assets

$
(24
)

Other long-term assets

5

Interest rate derivatives

Other long-term assets

26

Total derivatives designated as hedging instruments

$
67

$
(24
)

Derivatives not designated as hedging instruments:

Commodity derivatives

Other current assets

$
60

Other current assets

$
(117
)

Other long-term assets

5

Other long-term assets

(6
)

Other current liabilities

1

Other current liabilities

(5
)

Other long-term liabilities

(1
)
Foreign currency derivatives

Other current liabilities

(4
)
Total derivatives not designated as hedging instruments

$
66

$
(133
)

Total derivatives

$
133

$
(157
)

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

~~Table of Contents~~

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 ~~September 30, 2014,~~March 31, 2015, we had a net broker ~~receivable~~payable of ~~$35~~$112 million (consisting of initial margin of ~~$74~~$61 million reduced by ~~$39~~$173 million of variation margin that had been returned to us). As of December 31, ~~2013,~~2014, we had a net broker ~~receivable~~payable of ~~$161~~$133 million (consisting of initial margin of ~~$85~~$126 million ~~increased~~reduced by ~~$76~~$259 million of variation margin that had been ~~posted by~~returned to us).

The following tables present information about derivatives and financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements ~~at September 30, 2014 and December 31, 2013~~as of the dates indicated (in millions):

	September 30, 2014						December 31, 2013
	Derivative			Derivative			Derivative			Derivative			March 31, 2015						December 31, 2014
	Asset Positions			Liability Positions			Asset Positions			Liability Positions			Derivative			Derivative			Derivative			Derivative
													Asset Positions			Liability Positions			Asset Positions			Liability Positions
Netting Adjustments:
Gross position - asset/(liability)	$	83		$	(77	)	$	133		$	(157	)	$	246		$	(250	)	$	493		$	(384	)
Netting adjustment	(45		)	45			(148		)	148			(52		)	52			(262		)	262
Cash collateral paid/(received)	35			—			161			—			(112		)	—			(133		)	—
Net position - asset/(liability)	$	73		$	(32	)	$	146		$	(9	)	$	82		$	(198	)	$	98		$	(122	)

Balance Sheet Location After Netting Adjustments:
Other current assets	$	64		$	—		$	116		$	—		$	64		$	—		$	71		$	—
Other long-term assets	9			—			30			—
Other long-term assets, net													18			—			27			—
Other current liabilities	—			(30		)	—			(8		)	—			(108		)	—			(91		)
Other long-term liabilities	—			(2		)	—			(1		)
Other long-term liabilities and deferred credits													—			(90		)	—			(31		)
	$	73		$	(32	)	$	146		$	(9	)	$	82		$	(198	)	$	98		$	(122	)

As of ~~September 30, 2014,~~March 31, 2015, there was a net loss of ~~$118~~$237 million deferred in AOCI including tax effects. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the earnings recognition of the underlying hedged commodity transaction or (ii) interest expense accruals associated with underlying debt instruments. Of the total net loss deferred in AOCI at ~~September 30, 2014,~~March 31, 2015, we expect to reclassify a net gain of $1$9 million to earnings in the next twelve months. The remaining deferred loss of ~~$119~~$246 million is expected to be reclassified to earnings through ~~2045.~~2049. A portion of these amounts are based on market prices as of ~~September 30, 2014;~~March 31, 2015; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

The net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013 are~~was as follows (in millions):

	Three Months Ended					Nine Months Ended					Three Months Ended
	September 30,					September 30,					March 31,
	2014			2013		2014			2013		2015			2014
Commodity derivatives, net	$	2		$	66	$	(10	)	$	77	$	3		$	(12	)
Interest rate derivatives, net	(8		)	12		(47		)	63		(75		)	(20		)
Total	$	(6	)	$	78	$	(57	)	$	140	$	(72	)	$	(32	)

At ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~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.

2119

Table of Contents

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 ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014 (in millions):

	Fair Value as of September 30, 2014										Fair Value as of December 31, 2013											Fair Value as of March 31, 2015										Fair Value as of December 31, 2014
Recurring Fair Value Measures (1)	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total
Commodity derivatives	$	6	$	22		$	3	$	31		$	16	$	(59	)	$	(3	)	$	(46	)	$	16	$	123		$	5	$	144		$	(85	)	$	261		$	15	$	191
Interest rate derivatives	—		(15		)	—		(15		)	—		26			—			26			—		(144		)	—		(144		)	—			(70		)	—		(70		)
Foreign currency derivatives	—		(10		)	—		(10		)	—		(4		)	—			(4		)	—		(4		)	—		(4		)	—			(12		)	—		(12		)
Total net derivative asset/(liability)	$	6	$	(3	)	$	3	$	6		$	16	$	(37	)	$	(3	)	$	(24	)	$	16	$	(25	)	$	5	$	(4	)	$	(85	)	$	179		$	15	$	109

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Note ~~11—~~9—Equity-Indexed Compensation Plans

We refer to the PAA LTIPs and AAP Management Units collectively as our “equity-indexed compensation plans.” For additional discussion of our equity-indexed compensation plans and awards, see Note 16 to our Consolidated Financial Statements included in Part IV of our 2014 Annual Report on Form 10-K.

PAA LTIP Awards

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

			Weighted Average
			Grant Date
	Units (1)		Fair Value per Unit
Outstanding at December 31, 2014	7.3		$	41.45
Granted	1.1		$	39.99
Vested (2)	—		$	40.23
Cancelled or forfeited	(0.1	)	$	39.69
Outstanding at March 31, 2015	8.3		$	41.26

(1)Amounts do not include AAP Management Units.

(2)During the three months ended March 31, 2015, less than 0.1 million PAA LTIP awards were settled in cash.

AAP Management Units

Activity for AAP Management Units is summarized in the following table (in millions):

	Reserved for Future Grants	Outstanding	Outstanding Units Earned	Grant Date Fair Value of Outstanding AAP Management Units (1)
Balance at December 31, 2014	3.0	49.1	47.8	$	64
Earned	N/A	N/A	0.3	N/A
Balance at March 31, 2015	3.0	49.1	48.1	$	64

(1)Of the $64 million grant date fair value, $56 million had been recognized through March 31, 2015 on a cumulative basis. Of this amount, $1 million was recognized as expense during the three months ended March 31, 2015.

Other Consolidated Equity-Indexed Compensation Plan Information

The table below summarizes the expense recognized and the value of vested LTIP awards (settled both in common units and cash) under our equity-indexed compensation plans and includes both liability-classified and equity-classified awards (in millions):

	Three Months Ended
	March 31,
	2015		2014
Equity-indexed compensation expense	$	19	$	34
LTIP unit-settled vestings	$	—	$	5
LTIP cash-settled vestings (1)	$	—	$	1
DER cash payments	$	2	$	2

(1)For the three months ended March 31, 2015, the value of PAA LTIP awards that were settled in cash was less than $1 million.

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Note 10—Commitments and Contingencies

Litigation

~~General.~~ In the ordinary course of business, we are involved in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows. Although we believe that our operations are presently in material compliance with applicable requirements, as we acquire and incorporate additional assets it is possible that the EPA or other governmental entities may seek to impose fines, penalties or performance obligations on us (or on a portion of our operations) as a result of any past noncompliance whether such noncompliance initially developed before or after our acquisition.

Environmental

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

At ~~September 30,~~March 31, 2015, our estimated undiscounted reserve for environmental liabilities totaled $75 million, of which $11 million was classified as short-term and $64 million was classified as long-term. At December 31, 2014, our estimated undiscounted reserve for environmental liabilities totaled ~~$87~~$82 million, of which $13 million was classified as short-term and $74 million was classified as long-term. At December 31, 2013, our estimated undiscounted reserve for environmental liabilities totaled $93 million, of which $11 million was classified as short-term and $82$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.~~Condensed Consolidated Balance Sheets. At ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, we had recorded receivables totaling $9$7 million and ~~$10~~$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.~~Condensed Consolidated Balance Sheets.

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

~~Table of Contents~~

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

Kemp River Pipeline ~~Release~~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. ~~AER’s final~~Final investigation by the Alberta Energy Regulator is not complete. To date, no charges, fines or penalties have been assessed against PMC with respect to these releases; however, it is possible that fines or penalties may be assessed against PMC in the future. We estimate that the aggregate clean-up and remediation costs associated with these releases will be ~~approximately~~ $15 million. Through ~~September 30, 2014,~~March 31, 2015, we spent ~~approximately $8~~$9 million in connection with clean-up and remediation activities.

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

In the Matter of Bakersfield Crude Terminal LLC et al. On April 30, 2015, the EPA issued a Finding and Notice of Violation (“NOV”) to PAA’s Bakersfield Crude Terminal LLC for alleged violations of the Clean Air Act, as amended. The NOV, which cites 10 separate rule violations, questions the validity of construction and operating permits issued to our Bakersfield rail unloading facility in 2012 and 2014 by the San Joaquin Valley Air Pollution Control District (the “SJV District”). We believe we fully complied with all applicable regulatory requirements and that the permits issued to us by the SJV District are valid. To date, no fines or penalties have been assessed in this matter; however, it is possible that fines and penalties could be assessed in the future.

Note ~~12—~~11—Operating Segments

We manage our operations through three operating segments: ~~(i)~~ Transportation, ~~(ii)~~ Facilities and ~~(iii)~~ 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 ~~(i)~~(a) purchases and related costs, ~~(ii)~~(b) field operating costs and ~~(iii)~~(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.

~~Table of Contents~~

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

	Transportation		Facilities		Supply and Logistics		Total		Transportation		Facilities		Supply and Logistics		Total
Three Months Ended September 30, 2014
Revenues (1):
Three Months Ended March 31, 2015
Revenues:
External Customers	$	198	$	141	$	10,788	$	11,127	$	185	$	125	$	5,632	$	5,942
Intersegment ~~(2)~~(1)	226		140		5		371		215		132		2		349
Total revenues of reportable segments	$	424	$	281	$	10,793	$	11,498	$	400	$	257	$	5,634	$	6,291
Equity earnings in unconsolidated entities	$	29	$	—	$	—	$	29	$	37	$	—	$	—	$	37
Segment profit (3) (4)	$	231	$	147	$	152	$	530
Segment profit (2) (3)									$	241	$	142	$	130	$	513
Maintenance capital	$	35	$	19	$	2	$	56	$	33	$	15	$	2	$	50

Three Months Ended September 30, 2013
Revenues:
External Customers	$	179	$	138	$	10,386	$	10,703
Intersegment (2)	199		142		—		341
Total revenues of reportable segments	$	378	$	280	$	10,386	$	11,044
Equity earnings in unconsolidated entities	$	19	$	—	$	—	$	19
Segment profit (3) (4)	$	198	$	146	$	64	$	408
Maintenance capital	$	29	$	6	$	7	$	42

	Transportation		Facilities		Supply and Logistics		Total		Transportation		Facilities		Supply and Logistics		Total
Nine Months Ended September 30, 2014
Revenues (1):
Three Months Ended March 31, 2014
Revenues:
External Customers	$	574	$	443	$	32,988	$	34,005	$	181	$	157	$	11,346	$	11,684
Intersegment ~~(2)~~(1)	648		415		33		1,096		206		142		22		370
Total revenues of reportable segments	$	1,222	$	858	$	33,021	$	35,101	$	387	$	299	$	11,368	$	12,054
Equity earnings in unconsolidated entities	$	73	$	—	$	—	$	73	$	20	$	—	$	—	$	20
Segment profit (3) (4)	$	658	$	435	$	534	$	1,627
Segment profit (2) (3)									$	206	$	154	$	249	$	609
Maintenance capital	$	111	$	34	$	6	$	151	$	34	$	10	$	2	$	46

Nine Months Ended September 30, 2013
Revenues:
External Customers	$	517	$	558	$	30,542	$	31,617
Intersegment (2)	594		425		2		1,021
Total revenues of reportable segments	$	1,111	$	983	$	30,544	$	32,638
Equity earnings in unconsolidated entities	$	42	$	—	$	—	$	42
Segment profit (3) (4)	$	522	$	445	$	673	$	1,640
Maintenance capital	$	84	$	23	$	17	$	124

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~~(4)~~(3) The following table reconciles segment profit to net income attributable to PAA (in millions):

	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
	2014			2013			2014			2013			2015			2014
Segment profit	$	530		$	408		$	1,627		$	1,640		$	513		$	609
Depreciation and amortization	(97		)	(93		)	(293		)	(265		)	(107		)	(96		)
Interest expense, net	(85		)	(72		)	(246		)	(224		)	(102		)	(78		)
Other income/(expense), net	(4		)	3			(2		)	2
Other expense, net													(4		)	(2		)
Income before tax	344			246			1,086			1,153			300			433
Income tax expense	(20		)	(9		)	(90		)	(79		)	(16		)	(48		)
Net income	324			237			996			1,074			284			385
Net income attributable to noncontrolling interests	(1		)	(6		)	(2		)	(22		)	(1		)	(1		)
Net income attributable to PAA	$	323		$	231		$	994		$	1,052		$	283		$	384

Note ~~13—~~12—Related Party Transactions

See Note 1415 to our Consolidated Financial Statements included in Part IV of our ~~2013~~2014 Annual Report on Form 10-K for a complete discussion of our related party transactions.

~~Occidental Petroleum Corporation~~Transactions with Oxy

As of ~~September 30, 2014, a subsidiary of Occidental Petroleum Corporation (“Oxy”)~~March 31, 2015, Oxy owned approximately ~~25%~~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 nine~~ months ended ~~September 30,~~March 31, 2015 and 2014, ~~and 2013,~~ we recognized sales and transportation revenues and purchased petroleum products from ~~companies affiliated with~~ Oxy. These transactions were conducted at posted tariff rates or prices that we believe approximate market. See detail below (in millions):

	Three Months Ended				Nine Months Ended				Three Months Ended
	September 30,				September 30,				March 31,
	2014		2013		2014		2013		2015		2014
Revenues	$	369	$	441	$	812	$	1,135	$	176	$	92

Purchases and related costs	$	233	$	229	$	701	$	604	$	104	$	259

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

	September 30,		December 31,		March 31,		December 31,
	2014		2013		2015		2014
Trade accounts receivable and other receivables	$	274	$	133	$	465	$	489

Accounts payable	$	233	$	181	$	410	$	441

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~~Note 14—Subsequent Events~~

As of November 5, 2014, we entered into a definitive purchase and sale agreement with Oxy that provides for our purchase of Oxy’s 50% interest in BridgeTex Pipeline Company LLC (“BridgeTex”) for $1.075 billion. BridgeTex owns a 300,000 barrel-per-day crude oil pipeline (“BridgeTex Pipeline”) that extends from Colorado City in West Texas to Texas City. The remaining 50% interest in BridgeTex is owned by Magellan Midstream Partners, L.P. (“MMP”), which is also the operator of the BridgeTex Pipeline. Contemporaneous with the purchase by us of Oxy’s 50% interest in BridgeTex, BridgeTex has agreed to sell the southern leg of the pipeline system which runs from Houston to Texas City (the “Texas City Leg”) to MMP, and MMP has agreed to enter into a long term capacity lease with BridgeTex pursuant to which BridgeTex shippers will have access to capacity on the Texas City Leg.

In addition to customary closing conditions and the contemporaneous consummation of the sale of the Texas City Leg and execution of the capacity lease, our acquisition of Oxy’s 50% interest in BridgeTex is subject to the completion by PAGP, prior to December 31, 2014, of an underwritten secondary offering pursuant to which Oxy would sell a portion of its equity interest in PAGP. In order to facilitate such offering and the overall transaction, (i) the board of directors of PAGP’s general partner has agreed to an early release of the 15-month lock-up arrangement that was originally imposed on certain PAGP equity owners, including Oxy, in connection with PAGP’s initial public offering in October 2013, (ii) certain affiliates of Kayne Anderson Investment Management, Inc., The Energy & Minerals Group and PAA Management, L.P. have agreed to waive their participation rights in such offering and (iii) Oxy, certain affiliates of Kayne Anderson Investment Management, Inc., The Energy & Minerals Group and PAA Management, L.P. have agreed to refrain from selling any of their respective interests in PAGP for a period of up to 90 days following such offering. If an offering is not completed prior to December 31, 2014, both PAA and Oxy have the right to terminate the purchase and sale agreement.

~~Table of Contents~~

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical Consolidated Financial Statements and accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations as presented in our ~~2013~~2014 Annual Report on Form 10-K. For more detailed information regarding the basis of presentation for the following financial information, see the ~~condensed consolidated financial statements~~Condensed Consolidated Financial Statements and related notes that are contained in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Our discussion and analysis includes the following:

· Executive Summary

· Acquisitions and ~~Internal Growth~~Capital Projects

· Results of Operations

· Liquidity and Capital Resources

· Off-Balance Sheet Arrangements

· Recent Accounting Pronouncements

· Critical Accounting Policies and Estimates

· Forward-Looking Statements

Executive Summary

Company Overview

We own and operate midstream energy infrastructure and provide logistics services for crude oil, 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. We were formed in 1998, and our operations are conducted directly and indirectly through our operating subsidiaries and are managed through three operating segments: ~~(i)~~ Transportation, ~~(ii)~~ Facilities and ~~(iii)~~ Supply and Logistics. See “—Results of Operations—Analysis of Operating Segments” for further discussion.

Overview of Operating Results, Capital Investments and Other Significant Activities

During the first ~~nine~~three months of ~~2014,~~2015, we recognized net income attributable to PAA of ~~$994~~$283 million as compared to net income attributable to PAA of ~~$1.052 billion~~$384 million recognized during the first ~~nine~~three months of ~~2013. These~~2014. The decrease in operating results ~~include total segment profit that~~ was ~~relatively flat between periods, but higher costs as discussed further below.~~

Our segment profit includes favorable results from our Transportation segment, primarily driven by the continued increase in North American crude oil production and our related, recently completed internal growth projects. These favorable results were offset bydue to less favorable results from our ~~NGL marketing activities in our~~ Supply and Logistics ~~segment,~~and Facilities segments partially offset by ~~a favorable period-over-period impact from the mark-to-market~~growth in our Transportation segment (see further discussion of ~~derivative instruments. Our results were also impacted by decreased margins from~~ our ~~crude oil marketing activities; however, these unfavorable results were primarily attributable to the comparative first-quarter periods, as we experienced more favorable~~segment operating results in the ~~second and third quarters of 2014. In addition, our Facilities and Supply and Logistics segments were negatively impacted by costs incurred in our natural gas storage activities~~following sections). Net income attributable to ~~manage deliverability requirements in conjunction with the severe cold weather experienced during~~PAA for the first ~~quarter~~three months of ~~2014.~~

~~Other significant items during the period were:~~2015 was also impacted by:

· ~~Increased~~Higher depreciation and amortization expense ~~resulting from internal growth projects completed since September 30, 2013~~ and ~~accelerated depreciation on certain pipeline assets;~~

·~~Increased~~ interest expense ~~resulting from higher average debt outstanding during the 2014 period;~~

·~~Increased income tax expense resulting from higher year over year earnings from~~associated with our ~~taxable Canadian operations;~~growing asset base and related financing activities; and

· ~~A reduction~~Decreased income tax expense resulting from derivative mark-to-market losses in ~~net income attributable to noncontrolling interests.~~our Canadian operations.

We invested $586 million in midstream infrastructure projects during the three months ended March 31, 2015, with a targeted expansion capital plan for the full year of 2015 of $2.15 billion. To fund such capital activities, we issued approximately 22.1 million common units for net proceeds of approximately $1.1 billion during the first quarter. In addition, we paid $390 million of cash distributions to our limited partners and general partner during the three months ended March 31, 2015, and we declared a quarterly distribution of $0.6850 per limited partner unit to be paid on May 15, 2015.

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Acquisitions and ~~Internal Growth~~Capital Projects

The following table summarizes our ~~capital~~ expenditures for ~~acquisitions, internal growth projects~~acquisition capital, expansion capital and maintenance capital for the periods indicated (in millions):

	Nine Months Ended				Three Months Ended
	September 30,				March 31,
	2014		2013		2015		2014
Acquisition capital	$	10	$	19	$	64	$	—
Internal growth projects	1,552		1,253
Expansion capital (1)					586		563
Maintenance capital(1)	151		124		50		46
Total	$	1,713	$	1,396
					$	700	$	609

(1)Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as expansion capital. Capital expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets are classified as maintenance capital.

~~Internal Growth~~2015 Capital Projects

Our capital program is highlighted by a large number of small-to-medium sized projects spread across multiple geographic regions/resource plays. We believe the diversity of our program mitigates the impact of delays, cost overruns or adverse market developments with respect to a particular project or geographic region/resource play. The majority of our 2015 expansion capital program will be invested in our fee-based Transportation and Facilities segments. We expect that our investments will have minimal contributions to our 2015 results, but will provide growth for 2016 and beyond. The following table summarizes our ~~more~~ notable projects in progress during ~~2014~~2015 and the forecasted expenditures for the year ending December 31, ~~2014~~2015 (in millions):

Projects		~~2014~~2015
Permian Basin Area Projects		$~~425~~390
~~Cactus Pipeline~~Fort Saskatchewan Facility Projects / NGL Line		~~350~~300
Rail Terminal Projects (1)		~~235~~265
~~Ft. Sask Facility Projects / NGL Line~~Cactus Pipeline (2)		135
Diamond Pipeline		130
Red River Pipeline (Cushing to Longview)		130
Saddlehorn Pipeline		100
Eagle Ford JV Project		~~110~~90
~~Western Oklahoma Extension~~Cowboy Pipeline (Cheyenne to Carr)		8050
~~Mississippian Lime Pipeline~~Eagle Ford Area Projects		5545
~~White Cliffs Expansion~~Cushing Terminal Expansions		40
Line 63 Reactivation		35
~~Natural Gas Storage Expansions~~		35
~~Diamond Pipeline~~		25
~~St. James Facility Expansions~~		25
Other Projects		~~505~~450
		$~~2,050~~2,150
Potential Adjustments for Timing / Scope Refinement ~~(2)~~(3)		-$~~100~~50 + $100
Total Projected Expansion Capital Expenditures		$~~1,950~~2,100 - ~~$2,150~~$2,250

Maintenance Capital Expenditures		$205 - $225

(1) Includes railcar purchases and projects located in or near ~~Bakersfield, CA; Carr, CO; Van Hook, ND;~~St. James, LA and Kerrobert, Canada.

(2)Includes linefill costs associated with the project.

(3) Potential variation to current capital costs estimates may result from (i) changes to project design, (ii) final cost of materials and labor and (iii) timing of incurrence of costs due to uncontrollable factors such as permits, regulatory approvals and weather.

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Results of Operations

~~Table of Contents~~

The following table sets forth an overview of our consolidated financial results calculated in accordance with GAAP (in millions, except per unit data):

							Favorable/											Favorable/
	Three Months Ended						(Unfavorable)					Nine Months Ended						(Unfavorable)					Three Months Ended						Favorable/(Unfavorable)
	September 30,						Variance					September 30,						Variance					March 31,						Variance
	2014			2013			$			%		2014			2013			$			%		2015			2014			$			%
Transportation segment profit	$	231		$	198		$	33		17	%	$	658		$	522		$	136		26	%	$	241		$	206		$	35		17	%
Facilities segment profit	147			146			1			1	%	435			445			(10		)	(2	)%	142			154			(12		)	(8	)%
Supply and Logistics segment profit	152			64			88			138	%	534			673			(139		)	(21	)%	130			249			(119		)	(48	)%
Total segment profit	530			408			122			30	%	1,627			1,640			(13		)	(1	)%	513			609			(96		)	(16	)%
Depreciation and amortization	(97		)	(93		)	(4		)	(4	)%	(293		)	(265		)	(28		)	(11	)%	(107		)	(96		)	(11		)	(11	)%
Interest expense, net	(85		)	(72		)	(13		)	(18	)%	(246		)	(224		)	(22		)	(10	)%	(102		)	(78		)	(24		)	(31	)%
Other income/(expense), net	(4		)	3			(7		)	(233	)%	(2		)	2			(4		)	(200	)%
Other expense, net																							(4		)	(2		)	(2		)	(100	)%
Income tax expense	(20		)	(9		)	(11		)	(122	)%	(90		)	(79		)	(11		)	(14	)%	(16		)	(48		)	32			67	%
Net income	324			237			87			37	%	996			1,074			(78		)	(7	)%	284			385			(101		)	(26	)%
Net income attributable to noncontrolling interests	(1		)	(6		)	5			83	%	(2		)	(22		)	20			91	%	(1		)	(1		)	—			—	%
Net income attributable to PAA	$	323		$	231		$	92		40	%	$	994		$	1,052		$	(58	)	(6	)%	$	283		$	384		$	(101	)	(26	)%

Net income attributable to PAA:
Basic net income per limited partner unit	$	0.52		$	0.38		$	0.14		37	%	$	1.71		$	2.23		$	(0.52	)	(23	)%	$	0.36		$	0.74		$	(0.38	)	(51	)%
Diluted net income per limited partner unit	$	0.52		$	0.38		$	0.14		37	%	$	1.70		$	2.22		$	(0.52	)	(23	)%	$	0.35		$	0.73		$	(0.38	)	(52	)%
Basic weighted average limited partner units outstanding	370			343			27			8	%	365			340			25			7	%	383			360			23			6	%
Diluted weighted average limited partner units outstanding	371			345			26			8	%	367			342			25			7	%	385			363			22			6	%

Non-GAAP Financial Measures

To supplement our financial information presented in accordance with GAAP, management uses additional measures that are known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future. The primary additional measures used by management are adjusted earnings before interest, taxes, depreciation and amortization (“adjusted EBITDA”) and implied distributable cash flow (“DCF”).

Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance and results of operations because these measures, when used in conjunction with related GAAP financial measures, (i) provide additional information about our core operating performance and ability to generate and distribute cash flow, (ii) provide investors with the financial analytical framework upon which management bases financial, operational, compensation and planning decisions and (iii) present measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) the mark-to-market ~~adjustment~~ of derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (iii) long-term inventory costing adjustments, (iv) items that are not indicative of our core operating results and business outlook and/or ~~(iv)~~(v) other items that we believe should be excluded in understanding our core operating performance. We have defined all such items hereinafter as “Selected Items Impacting Comparability.” These additional financial measures are reconciled to the most directly comparable measures as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our ~~condensed consolidated financial statements~~Condensed Consolidated Financial Statements and footnotes.

3027

~~Table of Contents~~

The following table sets forth non-GAAP financial measures that are reconciled to the most directly comparable GAAP measures (in millions):

							Favorable/											Favorable/
	Three Months Ended						(Unfavorable)					Nine Months Ended						(Unfavorable)					Three Months Ended						Favorable/(Unfavorable)
	September 30,						Variance					September 30,						Variance					March 31,						Variance
	2014			2013			$			%		2014			2013			$			%		2015			2014			$			%
Net income	$	324		$	237		$	87		37	%	$	996		$	1,074		$	(78	)	(7	)%	$	284		$	385		$	(101	)	(26	)%
Add:
Interest expense, net	85			72			13			18	%	246			224			22			10	%	102			78			24			31	%
Income tax expense	20			9			11			122	%	90			79			11			14	%	16			48			(32		)	(67	)%
Depreciation and amortization	97			93			4			4	%	293			265			28			11	%	107			96			11			11	%
EBITDA	$	526		$	411		$	115		28	%	$	1,625		$	1,642		$	(17	)	(1	)%	$	509		$	607		$	(98	)	(16	)%

Selected Items Impacting Comparability of EBITDA
Gains/(losses) from derivative activities net of inventory valuation adjustments (1)	$	27		$	(59	)	$	86		146	%	$	77		$	(9	)	$	86		956	%	$	(91	)	$	65		$	(156	)	(240	)%
Long-term inventory costing adjustments (2)																							(38		)	—			(38		)	N/A
Equity-indexed compensation expense ~~(2)~~(3)	(12		)	(12		)	—			—	%	(48		)	(51		)	3			6	%	(11		)	(19		)	8			42	%
Net gain/(loss) on foreign currency revaluation ~~(3)~~(4)	(16		)	2			(18		)	(900	)%	(10		)	5			(15		)	(300	)%	27			(5		)	32			640	%
Other (5)																							—			(1		)	1			100	%
Selected Items Impacting Comparability of EBITDA	$	(1	)	$	(69	)	$	68		99	%	$	19		$	(55	)	$	74		135	%	$	(113	)	$	40		$	(153	)	(383	)%

EBITDA	$	526		$	411		$	115		28	%	$	1,625		$	1,642		$	(17	)	(1	)%	$	509		$	607		$	(98	)	(16	)%
Selected Items Impacting Comparability of EBITDA	1			69			(68		)	(99	)%	(19		)	55			(74		)	(135	)%	113			(40		)	153			383	%
Adjusted EBITDA	$	527		$	480		$	47		10	%	$	1,606		$	1,697		$	(91	)	(5	)%	$	622		$	567		$	55		10	%

Adjusted EBITDA	$	527		$	480		$	47		10	%	$	1,606		$	1,697		$	(91	)	(5	)%	$	622		$	567		$	55		10	%
Interest expense, net	(85		)	(72		)	(13		)	(18	)%	(246		)	(224		)	(22		)	(10	)%	(102		)	(78		)	(24		)	(31	)%
Maintenance capital (4)	(56		)	(42		)	(14		)	(33	)%	(151		)	(124		)	(27		)	(22	)%
Maintenance capital (6)																							(50		)	(46		)	(4		)	(9	)%
Current income tax expense	(10		)	(17		)	7			41	%	(62		)	(69		)	7			10	%	(42		)	(36		)	(6		)	(17	)%
Equity earnings in unconsolidated entities, net of distributions	(6		)	(6		)	—			—	%	1			(7		)	8			114	%	17			5			12			240	%
Distributions to noncontrolling interests (5)	(1		)	(13		)	12			92	%	(3		)	(38		)	35			92	%
Distributions to noncontrolling interests (7)																							(1		)	(1		)	—			—	%
Implied DCF	$	369		$	330		$	39		12	%	$	1,145		$	1,235		$	(90	)	(7	)%	$	444		$	411		$	33		8	%
Less: Distributions paid (5)	(374		)	(305		)						(1,078		)	(886		)
DCF Excess/(Shortage) (6)	$	(5	)	$	25							$	67		$	349
Less: Distributions paid (7)																							(420		)	(344		)
DCF Excess/(Shortage) (8)																							$	24		$	67

(1) We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results of operations, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining Adjusted EBITDA. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. See Note 108 to our ~~condensed consolidated financial statements~~Condensed Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities.

31(2)We carry approximately 4 million barrels of crude oil and NGL inventory that consists of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to Linefill in our own assets). We treat the impact of changes in the average cost of the long-term inventory that result from fluctuations in market prices and writedowns of such inventory that result from price declines as a selected item impacting comparability. See Note 5 to our Consolidated Financial Statements included in Part IV of our 2014 Annual Report on Form 10-K for a complete discussion of our long-term inventory.

~~Table of Contents~~

~~(2)~~(3) Our total equity-indexed compensation expense includes expense associated with awards that will or may be settled in units and awards that will or may be settled in cash. The awards that will or may be settled in units are included in our diluted earnings per unit calculation when the applicable performance criteria have been met. We consider the compensation expense associated with these awards as a selected item impacting comparability as the dilutive impact of the outstanding awards is included in our diluted earnings per unit calculation and the majority of the awards are expected to be settled in units. The portion of compensation expense associated with awards that are certain to be settled in cash is not considered a selected item impacting comparability. See Note 1516 to our Consolidated Financial Statements included in Part IV of our ~~2013~~2014 Annual Report on Form 10-K for a comprehensive discussion regarding our equity-indexed compensation plans.

~~(3)~~(4) During the three ~~and nine~~ months ended ~~September 30,~~March 31, 2015 and 2014, ~~and 2013,~~ there were fluctuations in the value of the Canadian dollar (“CAD”) to the U.S. dollar (“USD”), resulting in gains and losses that were not related to our core operating results for the period and were thus classified as selected items impacting comparability. ~~See Note 10 to our condensed consolidated financial statements for further discussion regarding our currency exchange rate risk hedging activities.~~

~~(4)~~(5)Includes other immaterial selected items impacting comparability.

(6) Maintenance capital expenditures are defined as 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.

~~(5)~~(7) Includes distributions that pertain to the current period’s net income and are paid in the subsequent period.

~~(6)~~(8) Excess DCF is retained to establish reserves for future distributions, capital expenditures and other partnership purposes.

Analysis of Operating Segments

Transportation Segment

Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems, trucks and barges. The Transportation segment generates revenue through a combination of tariffs, third-party ~~leases of~~ pipeline capacity agreements and other transportation fees.

The following ~~table sets~~tables set forth our operating results from our Transportation segment for the periods indicated:

	Three Months Ended						Favorable/ (Unfavorable)					Nine Months Ended						Favorable/ (Unfavorable)					Three Months Ended						Favorable/(Unfavorable)
Operating Results (1)	September 30,						Variance					September 30,						Variance					March 31,						Variance
(in millions, except per barrel data)	2014			2013			$			%		2014			2013			$			%		2015			2014			$			%
Revenues
Tariff activities	$	372		$	329		$	43		13	%	$	1,063		$	959		$	104		11	%	$	358		$	336		$	22		7	%
Trucking	52			49			3			6	%	159			152			7			5	%	42			51			(9		)	(18	)%
Total transportation revenues	424			378			46			12	%	1,222			1,111			111			10	%	400			387			13			3	%

Costs and Expenses
Trucking costs	(38		)	(35		)	(3		)	(9	)%	(116		)	(109		)	(7		)	(6	)%	(30		)	(37		)	7			19	%
Field operating costs(2)	(153		)	(131		)	(22		)	(17	)%	(419		)	(402		)	(17		)	(4	)%	(136		)	(129		)	(7		)	(5	)%
Equity-indexed compensation expense - operations	(4		)	(3		)	(1		)	(33	)%	(14		)	(15		)	1			7	%	(3		)	(4		)	1			25	%
Segment general and administrative expenses (2) (3)	(20		)	(25		)	5			20	%	(62		)	(74		)	12			16	%	(22		)	(22		)	—			—	%
Equity-indexed compensation expense - general and administrative	(7		)	(5		)	(2		)	(40	)%	(26		)	(31		)	5			16	%	(5		)	(9		)	4			44	%
Equity earnings in unconsolidated entities	29			19			10			53	%	73			42			31			74	%	37			20			17			85	%
Segment profit	$	231		$	198		$	33		17	%	$	658		$	522		$	136		26	%	$	241		$	206		$	35		17	%
Maintenance capital	$	35		$	29		$	(6	)	(21	)%	$	111		$	84		$	(27	)	(32	)%	$	33		$	34		$	1		3	%
Segment profit per barrel	$	0.59		$	0.58		$	0.01		2	%	$	0.60		$	0.52		$	0.08		15	%	$	0.63		$	0.60		$	0.03		5	%

3229

	Three Months Ended		Favorable/(Unfavorable)
Average Daily Volumes	March 31,		Variance
(in thousands of barrels per day) (4)	2015	2014	Volumes		%
Tariff activities
Crude Oil Pipelines
All American	36	33	3		9	%
Bakken Area Systems (5)	152	131	21		16	%
Basin / Mesa / Sunrise	821	745	76		10	%
BridgeTex	83	—	83		N/A
Capline	153	126	27		21	%
Eagle Ford Area Systems (5)	263	189	74		39	%
Line 63 / Line 2000	136	125	11		9	%
Manito	53	45	8		18	%
Mid-Continent Area Systems	371	326	45		14	%
Permian Basin Area Systems	754	760	(6	)	(1	)%
Rainbow	118	120	(2	)	(2	)%
Rangeland	62	69	(7	)	(10	)%
Salt Lake City Area Systems (5)	130	131	(1	)	(1	)%
South Saskatchewan	66	64	2		3	%
White Cliffs	47	23	24		104	%
Other	687	650	37		6	%
NGL Pipelines
Co-Ed	61	57	4		7	%
Other	130	116	14		12	%
Tariff activities total	4,123	3,710	413		11	%
Trucking	121	130	(9	)	(7	)%
Transportation segment total	4,244	3,840	404		11	%

~~Table of Contents~~(1) Revenues and costs and expenses include intersegment amounts.

Favorable/

Favorable/

Three Months Ended

(Unfavorable)

Nine Months Ended

(Unfavorable)

Average Daily Volumes

September 30,

Variance

September 30,

Variance

(in thousands of barrels per day) (4)

2014

2013

Volumes

%

2014

2013

Volumes

%

Tariff activities

Crude Oil Pipelines

All American

40

40

—

—
%

37

39

(2
)
(5
)%
Bakken Area Systems

164

136

28

21
%

147

130

17

13
%
Basin / Mesa

743

731

12

2
%

734

712

22

3
%
Capline

178

147

31

21
%

142

153

(11
)
(7
)%
Eagle Ford Area Systems

247

119

128

108
%

215

81

134

165
%
Line 63 / Line 2000

126

113

13

12
%

119

113

6

5
%
Manito

44

47

(3
)
(6
)%

44

46

(2
)
(4
)%
Mid-Continent Area Systems

346

256

90

35
%

340

277

63

23
%
Permian Basin Area Systems

776

593

183

31
%

765

540

225

42
%
Rainbow

104

128

(24
)
(19
)%

111

125

(14
)
(11
)%
Rangeland

61

54

7

13
%

65

59

6

10
%
Salt Lake City Area Systems

140

131

9

7
%

134

132

2

2
%
South Saskatchewan

62

56

6

11
%

61

50

11

22
%
White Cliffs

33

22

11

50
%

27

22

5

23
%
Other

831

738

93

13
%

747

737

10

1
%
NGL Pipelines

Co-Ed

57

56

1

2
%

56

55

1

2
%
Other

143

200

(57
)
(29
)%

127

190

(63
)
(33
)%
Refined Products Pipelines

—

54

(54
)
(100
)%

—

88

(88
)
(100
)%
Tariff activities total

4,095

3,621

474

13
%

3,871

3,549

322

9
%
Trucking

131

120

11

9
%

129

113

16

14
%
Transportation segment total

4,226

3,741

485

13
%

4,000

3,662

338

9
%

(2)Field operating costs and Segment general and administrative expenses exclude equity-indexed compensation expense, which is presented separately in the table above.

(3)Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.

(4)Volumes associated with assets employed through acquisitions and capital expansion projects represent total volumes (attributable to our interest) for the number of days we employed the assets divided by the number of days in the period.

(5) Area systems include volumes (attributable to our interest) from our investments in unconsolidated entities.

Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The segment profit generated by our tariff and other fee-related activities depends on the volumes transported on the pipeline and the level of the tariff and other fees charged as well as the fixed and variable field costs of operating the pipeline. Revenue from our pipeline capacity agreements generally reflects a negotiated amount. Revenues and expenses from our Canadian based subsidiaries, which use the Canadian dollar as their functional currency, are translated at the prevailing average exchange rates for each month.

The following is a discussion of items impacting Transportation segment profit and segment profit per barrel for the periods indicated.

Net Operating Revenues and Volumes. As noted in the table above, our total Transportation segment revenues, net of trucking costs, and volumes increased for the three months ended March 31, 2015 compared to the three months ended March 31, 2014. Our Transportation segment results for the comparative periods were impacted by the following:

·North American Crude Oil Production and Related Expansion Projects— Production growth from the development of certain North American crude oil resource plays increased volumes and revenues on our existing pipeline systems over the comparative periods presented. We estimate that the impact of increased throughput and related infrastructure projects, most notably on our Eagle Ford and Mid-Continent Area Systems and certain pipelines in our Permian Basin Area Systems, and our recently constructed Sunrise, Pascagoula and Bakken North pipelines, increased our revenues by $20 million.

·Tariff Rates— Revenues on our pipelines are impacted by various tariff rate changes that may occur during the period, which include (i) rate increases or decreases on our intrastate and Canadian pipelines and fees on related system assets, (ii) the indexing of rates on our FERC regulated pipelines or (iii) other negotiated rate changes. We estimate that the net impact of such rate changes on our pipelines increased revenues by $18 million primarily due to tariff rate increases on certain of our Canadian crude oil pipelines and incremental fees on related system assets, and, to a much lesser extent, the FERC indexing effective July 1, 2014 and rate increases on our intrastate pipelines.

·Loss Allowance Revenue— As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to offset losses due to evaporation, measurement and other losses in transit. We value the variance of allowance volumes to actual losses at the estimated net realizable value (including the impact of gains and losses from derivative-related activities) at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues. The loss allowance revenue decreased by $9 million primarily due to a lower average realized price per barrel, partially offset by higher volumes.

·Foreign Exchange Impact —We estimate that revenues from our Canadian pipeline systems and trucking operations were unfavorably impacted by $11 million for the three months ended March 31, 2015 compared to the three months ended March 31, 2014 due to the depreciation of CAD relative to USD.

Field Operating Costs. Field operating costs (excluding equity-indexed compensation expense) increased during the three months ended March 31, 2015 compared to the three months ended March 31, 2014 primarily due to increased salary and related expenses and higher property tax expense associated with the growth and capital expansion in the segment. The increase in operating costs for the comparative quarter ended periods was partially offset by lower maintenance and repairs cost and a $4 million favorable impact of foreign exchange.

Equity-Indexed Compensation Expense. On a consolidated basis across all segments, equity-indexed compensation expense decreased for the three months ended March 31, 2015 compared to the same period in 2014 primarily due to the impact of the decrease in unit price during the period compared to the impact of the increase in unit price for the same period in 2014.

Allocations of equity-indexed compensation expense vary over time (i) between field operating costs and general and administrative expenses and (ii) between segments and could result in variances in those expense categories or segments that differ from the consolidated variance explanations above. See Note 16 to our Consolidated Financial Statements included in Part IV of our 2014 Annual Report on Form 10-K for additional information regarding our equity-indexed compensation plans.

Equity Earnings in Unconsolidated Entities. The favorable variance in equity earnings in unconsolidated entities for the three months ended March 31, 2015 compared to the three months ended March 31, 2014 was primarily driven by (i) earnings from our 50% interest in BridgeTex, which we acquired in November 2014, (ii) increased throughput on the White Cliffs pipeline due to an expansion of the pipeline that was placed into service in July 2014 and (iii) increased throughput on the Eagle Ford pipeline as a result of increased crude oil production, as discussed in “Net Operating Revenues and Volumes” above.

Facilities Segment

Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. The Facilities segment generates revenue through a combination of month-to-month and multi-year agreements and processing arrangements. Revenues and expenses from our Canadian based subsidiaries, which use the Canadian dollar as their functional currency, are translated at the prevailing average exchange rates for each month.

The following tables set forth our operating results from our Facilities segment for the periods indicated:

	Three Months Ended						Favorable/(Unfavorable)
Operating Results (1)	March 31,						Variance
(in millions, except per barrel data)	2015			2014			$			%
Revenues	$	257		$	299		$	(42	)	(14	)%
Storage related costs (natural gas related)	(4		)	(26		)	22			85	%
Field operating costs (2)	(91		)	(97		)	6			6	%
Equity-indexed compensation expense - operations	(1		)	(1		)	—			—	%
Segment general and administrative expenses (2) (3)	(15		)	(13		)	(2		)	(15	)%
Equity-indexed compensation expense - general and administrative	(4		)	(8		)	4			50	%
Segment profit	$	142		$	154		$	(12	)	(8	)%
Maintenance capital	$	15		$	10		$	(5	)	(50	)%
Segment profit per barrel	$	0.38		$	0.42		$	(0.04	)	(10	)%

	Three Months Ended		Favorable/(Unfavorable)
	March 31,		Variance
Volumes (4)	2015	2014	Volumes		%
Crude oil, refined products and NGL terminalling and storage (average monthly capacity in millions of barrels)	99	95	4		4	%
Rail load / unload volumes (average volumes in thousands of barrels per day)	206	229	(23	)	(10	)%
Natural gas storage (average monthly working capacity in billions of cubic feet)	97	97	—		—	%
NGL fractionation (average volumes in thousands of barrels per day)	102	92	10		11	%
Facilities segment total (average monthly volumes in millions of barrels) (5)	124	121	3		2	%

(1) Revenues and costs and expenses include intersegment amounts.

(2) Field operating costs and Segment general and administrative expenses exclude equity-indexed compensation expense, which is presented separately in the table above.

(3) Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.

(4) Volumes associated with assets employed through acquisitions and ~~internal growth~~capital expansion projects represent total volumes ~~(attributable to our interest)~~ for the number of ~~days~~months we employed the assets divided by the number of ~~days~~months in the period.

~~Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The~~(5)Facilities segment ~~profit generated by our tariff and other fee-related activities depends on the volumes transported on the pipeline and the level of the tariff and other fees charged as well~~total is calculated as the ~~fixed~~sum of: (i) crude oil, refined products and ~~variable field costs~~NGL terminalling and storage capacity; (ii) rail load and unload volumes multiplied by the number of ~~operating~~days in the ~~pipeline. Revenue from our pipeline~~period and divided by the number of months in the period; (iii) natural gas storage working capacity ~~leases generally reflects a negotiated amount.~~divided by 6 to account for the 6:1 mcf of natural gas to crude Btu equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and (iv) NGL fractionation volumes multiplied by the number of days in the period and divided by the number of months in the period.

Table of Contents

The following is a discussion of items impacting ~~Transportation~~Facilities segment profit and segment profit per barrel for the periods indicated.

Net Operating Revenues and Volumes.As noted in the table above, our ~~total Transportation~~Facilities segment revenues, ~~net of trucking~~less storage related costs, ~~and volumes increased for both~~decreased during the three ~~and nine~~ months ended ~~September 30, 2014~~March 31, 2015 as compared to the ~~three and nine months ended September 30, 2013.~~same period in 2014, while total volumes increased slightly. Our ~~Transportation~~Facilities segment results for the comparative periods were impacted by:

·Rail Terminals —Revenues from our rail activities decreased by $9 million due to lower rail fees related to the ~~following:~~movement of certain volumes of Bakken crude oil, primarily to our St. James rail terminal, partially offset by volumes and revenues from our Bakersfield rail terminal that came online in the fourth quarter of 2014.

·NGL Storage, NGL Fractionation and Natural Gas Processing Activities — Revenues from our Canadian NGL storage, NGL fractionation and natural gas processing activities decreased by $7 million primarily due to unfavorable foreign currency effects of $9 million from the depreciation of CAD relative to USD. Excluding foreign currency effects, revenue increases from higher facility fees at certain of our fractionation and gas processing facilities were largely offset by lower physical processing gains related to component mix at our fractionation facilities and significantly lower NGL prices during the first quarter of 2015.

Field Operating Costs. Field operating costs (excluding equity-indexed compensation expense) decreased during the three months ended March 31, 2015 compared to the three months ended March 31, 2014 primarily due to lower gas and power costs. Other decreases in maintenance and repairs costs and certain joint venture expenses were offset by increases in property taxes and salary and related expenses primarily associated with new rail facilities. The decrease in field operating costs was also impacted by a $4 million favorable foreign exchange effect.

Maintenance Capital. The increase in maintenance capital for the three months ended March 31, 2015 compared to the three months ended March 31, 2014 was primarily due to various tank projects and equipment replacements.

Supply and Logistics Segment

Our revenues from supply and logistics activities reflect the sale of gathered and bulk-purchased crude oil, as well as sales of NGL volumes purchased from suppliers and natural gas sales attributable to the activities performed by our natural gas storage commercial optimization group. Generally, we expect our segment profit to increase or decrease directionally with (i) increases or decreases in our Supply and Logistics segment volumes (which consist of lease gathering crude oil purchase volumes and NGL sales volumes), (ii) demand for lease gathering services we provide producers and (iii) the overall volatility and strength or weakness of market conditions and the allocation of our assets among our various risk management strategies. In addition, the execution of our risk management strategies in conjunction with our assets can provide upside in certain markets. We do not anticipate that future changes in revenues resulting from variances in commodity prices will be a primary driver of segment profit.

The following tables set forth our operating results from our Supply and Logistics segment for the periods indicated:

	Three Months Ended						Favorable/(Unfavorable)
Operating Results (1)	March 31,						Variance
(in millions, except per barrel data)	2015			2014			$			%
Revenues	$	5,634		$	11,368		$	(5,734	)	(50	)%
Purchases and related costs (2)	(5,353		)	(10,975		)	5,622			51	%
Field operating costs (3)	(118		)	(106		)	(12		)	(11	)%
Equity-indexed compensation expense - operations	(1		)	(1		)	—			—	%
Segment general and administrative expenses (3) (4)	(27		)	(26		)	(1		)	(4	)%
Equity-indexed compensation expense - general and administrative	(5		)	(11		)	6			55	%
Segment profit	$	130		$	249		$	(119	)	(48	)%
Maintenance capital	$	2		$	2		$	—		—	%
Segment profit per barrel	$	1.14		$	2.37		$	(1.23	)	(52	)%

Table of Contents

·North American Crude Oil Production and Related Expansion Projects — The increase in North American crude oil production has had a favorable impact on volumes and revenues on our existing pipeline systems and has also provided opportunities for midstream infrastructure development in production growth areas. The resulting increases in volumes for the three and nine months ended September 30, 2014 over the comparable 2013 periods were most notably on our Permian Basin, Eagle Ford and Mid-Continent Area Systems. We estimate that increased production combined with our recently completed internal growth projects increased revenues by $20 million and $70 million for the three and nine months ended September 30, 2014, respectively, compared to the three and nine months ended September 30, 2013.

·Loss Allowance Revenue — As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor that is intended to offset losses due to evaporation, measurement and other losses in transit. We value the variance of allowance volumes to actual losses at the estimated net realizable value (including the impact of gains and losses from derivative-related activities) at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues. The loss allowance revenue increased by $7 million and $37 million, respectively, for the three and nine months ended September 30, 2014 compared to the three and nine months ended September 30, 2013 driven primarily by higher volumes.

·Rate Changes — Revenues on our pipelines are impacted by various rate changes that may occur during the period. These primarily include the indexing of rates on our FERC regulated pipelines, rate increases or decreases on our intrastate and Canadian pipelines or other negotiated rate changes. We estimate that the net impact of rate changes on our pipelines increased revenues by $17 million and $30 million for the three and nine months ended September 30, 2014, respectively, compared to the three and nine months ended September 30, 2013.

·Sale of Refined Products Pipelines — We sold certain refined products pipeline systems and related assets in July 2013 and November 2013. As we did not own these assets during the three and nine months ended September 30, 2014, our revenues were lower by $7 million and $27 million, respectively, and volumes were lower by 54,000 and 88,000 barrels per day, respectively, as compared to the three and nine months ended September 30, 2013.

·Foreign Exchange Impact — Revenues and expenses from our Canadian based subsidiaries, which use the Canadian dollar as their functional currency, are translated at the prevailing average exchange rates for each month. The average CAD to USD exchange rates for the three months ended September 30, 2014 and 2013 were $1.09 CAD: $1.00 USD and $1.04 CAD: $1.00 USD, respectively. The average CAD to USD exchange rates for the nine months ended September 30, 2014 and 2013 were $1.09 CAD: $1.00 USD and $1.02 CAD: $1.00 USD, respectively. Therefore, we estimate that revenues from our Canadian pipeline systems and trucking operations were unfavorably impacted by $5 million and $20 million for the three and nine months ended September 30, 2014, respectively, compared to the three and nine months ended September 30, 2013 due to the depreciation of the Canadian dollar relative to the U.S. dollar.

Additional noteworthy volume and revenue variances on our pipelines for the three and nine months ended September 30, 2014 compared to the three and nine months ended September 30, 2013 were (i) increased volumes and revenues on our Rangeland, South Saskatchewan and Co-Ed pipelines, as these pipelines were shut down during a portion of the second and third quarters of 2013 due to high river flow rates and flooding in the surrounding area, (ii) incremental volumes and revenues from our Pascagoula, Wascana and Bakken North pipelines, which were placed into service during the second quarter of 2014, (iii) incremental revenues from increased pumpover volumes at our Basin pipeline terminal, (iv) decreased volumes and revenues on our Rainbow pipeline due to (a) lower producer volumes and (b) operational issues during September 2014, (v) higher revenues resulting from a reclassification of certain of our Canadian storage facilities to our Transportation segment during the second quarter of 2014, (vi) increased volumes and revenues on our Line 2000 pipeline for the three-month comparable period due to increased refiner demand for heavy volumes, (vii) increased volumes and revenues on our Capline pipeline for the three-month comparative period due to the timing of a refinery turnaround, which occurred in the third quarter of 2013 and (viii) decreased volumes and revenues on certain of our NGL pipelines due to (a) the discontinuation in the fourth quarter of 2013 of an agreement to transport volumes on a pipeline and (b) the impact of netting joint venture related volumes to our share on a pipeline during 2014, which did not affect revenues.

~~Field Operating Costs.~~ Field operating costs (excluding equity-indexed compensation expenses) increased during the three and nine months ended September 30, 2014 compared to the three and nine months ended September 30, 2013 due to (i) a change in classification of certain costs from General and Administrative expenses, (ii) increased asset integrity spending, (iii) higher utility costs associated with increased throughput volumes and (iv) operational issues related to crude oil contamination. The increase in field operating costs was not as pronounced for the comparative nine-month periods due to higher environmental remediation costs in 2013.

~~Table of Contents~~

~~General and Administrative Expenses.~~ General and administrative expenses (excluding equity-indexed compensation expenses) decreased during the three and nine months ended September 30, 2014 compared to the three and nine months ended September 30, 2013 primarily due to a change in classification of certain costs to Field Operating Costs.

~~Maintenance Capital.~~ 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 increase in maintenance capital for the three and nine months ended September 30, 2014 compared to the three and nine months ended September 30, 2013 is primarily due to increased investments on integrity-related projects.

~~Equity-Indexed Compensation Expense~~. On a consolidated basis across all segments, equity-indexed compensation expense increased for the three months ended September 30, 2014 compared to the same period in 2013, primarily due to a smaller impact of the decrease in unit price during the period compared to the impact of the decrease in unit price for the same period in 2013. Consolidated equity-indexed compensation expense decreased for the nine months ended September 30, 2014 compared to the same period in 2013, primarily due to a less significant impact of the increase in unit price during the nine months ended September 30, 2014 compared to the same period in 2013.

Allocations of equity-indexed compensation expense vary over time (i) between field operating costs and general and administrative expenses and (ii) between segments and could result in variances in those expense categories or segments that differ from the consolidated variance explanations above. See Note 15 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K for additional information regarding our equity-indexed compensation plans.

~~Equity Earnings in Unconsolidated Entities~~. The favorable variance in equity earnings in unconsolidated entities for the three and nine months ended September 30, 2014 compared to the three and nine months ended September 30, 2013 was largely due to increased throughput on the Eagle Ford joint venture pipeline as a result of increased production, as discussed above, and increased throughput on the White Cliffs pipeline due to an expansion of the pipeline that was placed into service in July 2014.

~~Facilities Segment~~

~~The following table sets forth operating results from our Facilities segment for the periods indicated:~~

Favorable/

Favorable/

Three Months Ended

(Unfavorable)

Nine Months Ended

(Unfavorable)

Operating Results (1)

September 30,

Variance

September 30,

Variance

(in millions, except per barrel data)

2014

2013

$

%

2014

2013

$

%

Revenues

$
281

$
257

$
24

9
%

$
858

$
787

$
71

9
%
Natural gas sales (2)

—

23

(23
)
(100
)%

—

196

(196
)
(100
)%
Storage related costs (natural gas related)

(9
)
(4
)
(5
)
(125
)%

(47
)
(12
)
(35
)
(292
)%
Natural gas sales costs (2)

—

(19
)
19

100
%

—

(184
)
184

100
%
Field operating costs (3)

(104
)
(92
)
(12
)
(13
)%

(307
)
(272
)
(35
)
(13
)%
Equity-indexed compensation expense - operations

(1
)
—

(1
)
N/A

(4
)
(2
)
(2
)
(100
)%
Segment general and administrative expenses (3) (4)

(16
)
(15
)
(1
)
(7
)%

(46
)
(48
)
2

4
%
Equity-indexed compensation expense - general and administrative

(4
)
(4
)
—

—
%

(19
)
(20
)
1

5
%
Segment profit

$
147

$
146

$
1

1
%

$
435

$
445

$
(10
)
(2
)%
Maintenance capital

$
19

$
6

$
(13
)
(217
)%

$
34

$
23

$
(11
)
(48
)%
Segment profit per barrel

$
0.40

$
0.41

$
(0.01
)
(2
)%

$
0.40

$
0.41

$
(0.01
)
(2
)%

~~Table of Contents~~

Favorable/

Favorable/

Three Months Ended

(Unfavorable)

Nine Months Ended

(Unfavorable)

September 30,

Variance

September 30,

Variance

Volumes (5)

2014

2013

Volumes

%

2014

2013

Volumes

%

Crude oil, refined products and NGL terminalling and storage (average monthly capacity in millions of barrels)

95

94

1

1
%

95

94

1

1
%
Rail load / unload volumes (average volumes in thousands of barrels per day)

241

218

23

11
%

232

221

11

5
%
Natural gas storage (average monthly working capacity in billions of cubic feet)

97

97

—

—
%

97

96

1

1
%
NGL fractionation (average volumes in thousands of barrels per day)

104

106

(2
)
(2
)%

94

99

(5
)
(5
)%
Facilities segment total (average monthly volumes in millions of barrels) (6)

121

120

1

1
%

121

120

1

1
%

	Three Months Ended		Favorable/(Unfavorable)
Average Daily Volumes	March 31,		Variance
(in thousands of barrels per day)	2015	2014	Volumes	%
Crude oil lease gathering purchases	981	893	88	10	%
NGL sales	286	273	13	5	%
Supply and Logistics segment total	1,267	1,166	101	9	%

(1) Revenues and costs ~~and expenses~~ include intersegment amounts.

(2) ~~Effective January 1,~~Purchases and related costs include interest expense (related to hedged inventory purchases) of $1 million and $2 million for the three months ended March 31, 2015 and 2014, ~~our natural gas sales and costs, primarily attributable to the activities performed by our natural gas storage commercial optimization group, are reported in the Supply and Logistics segment.~~respectively.

(3) Field operating costs and Segment general and administrative expenses exclude equity-indexed compensation expense, which is presented separately in the table above.

(4) Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.

~~(5)~~Volumes associated with assets employed through acquisitions and internal growth projects represent total volumes for the number of months we employed the assets divided by the number of months in the period.

~~(6)~~Facilities segment total is calculated as the sum of: (i) crude oil, refined products and NGL terminalling and storage capacity; (ii) rail load and unload volumes multiplied by the number of days in the period and divided by the number of months in the period; (iii) natural gas storage working capacity divided by 6 to account for the 6:1 mcf of gas to crude Btu equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and (iv) NGL fractionation volumes multiplied by the number of days in the period and divided by the number of months in the period.

~~The following is a discussion of items impacting Facilities segment profit and segment profit per barrel for the periods indicated.~~

~~Net Operating Revenues and Volumes.~~ As noted in the table above, our Facilities segment revenues, less storage related costs, increased during the three and nine months ended September 30, 2014 as compared to the same periods of 2013. Total Facilities segment volumes were relatively consistent over the periods presented. Variances between the comparative periods were driven by:

·NGL Fractionation, NGL Storage and Natural Gas Processing Activities — Increased net revenues from our NGL fractionation and storage and natural gas processing activities of $11 million and $33 million, respectively, for the three and nine months ended September 30, 2014 compared to the three and nine months ended September 30, 2013, were largely driven by higher facility fee revenues due to rate increases at certain of our storage and fractionation facilities, which more than offset the impact of lower fractionation volumes during the 2014 periods.

These increases in NGL revenues include estimated unfavorable foreign currency impacts of $3 million and $13 million for the three and nine months ended September 30, 2014, respectively, as compared to the three and nine months ended September 30, 2013 due to the depreciation of the Canadian dollar relative to the U.S. dollar. The average CAD to USD exchange rates for the three months ended September 30, 2014 and 2013 were $1.09 CAD: $1.00 USD and $1.04 CAD: $1.00 USD, respectively. The average CAD to USD exchange rates for the nine months ended September 30, 2014 and 2013 were $1.09 CAD: $1.00 USD and $1.02 CAD: $1.00 USD, respectively.

~~Table of Contents~~

·Rail Terminals — Revenues from rail load and unload activities increased by $3 million and $5 million for the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013. These increases were due to new rail terminals that came on line in the fourth quarter of 2013, partially offset by the unfavorable impact of rail delays and lower volumes at certain of our existing rail terminals during the comparative 2014 periods. The nine-month 2014 period was further unfavorably impacted by weather-related issues at certain of our terminals during the first quarter of 2014.

·Condensate Processing Activities — Increased revenues from our condensate processing activities of $2 million and $7 million for the three and nine months ended September 30, 2014, respectively, compared to the three and nine months ended September 30, 2013 were largely driven by the start-up and subsequent expansion of our Eagle Ford processing facility.

·Crude Oil Storage — Revenues from our crude oil storage activities increased by $3 million and $4 million, respectively, for the three and nine months ended September 30, 2014 over the three and nine months ended September 30, 2013, primarily due to an expansion at our St. James terminal and increased throughput at our Cushing and Yorktown terminals. However, such results were partially offset by lower net revenues from certain storage facilities in California and the East Coast due to decreased demand, as well as the reclassification of certain of our Canadian storage facilities to our Transportation segment during the second quarter of 2014.

·Natural Gas Storage Operations — Net revenues from our natural gas storage operations decreased by approximately $5 million and $26 million during the three and nine month 2014 periods, respectively, primarily due to less favorable storage rates on contracts that renewed or replaced expiring contracts. The nine-month 2014 period was further unfavorably impacted by costs incurred in our natural gas storage activities to manage deliverability requirements in conjunction with the extended period of severe cold weather experienced during the first quarter of 2014.

~~Field Operating Costs.~~ Field operating costs (excluding equity-indexed compensation expenses) increased during the three and nine months ended September 30, 2014 compared to the three and nine months ended September 30, 2013 due to (i) increased costs for rail facilities which came on line in the fourth quarter of 2013, (ii) a change in classification of certain costs from General and Administrative expenses and (iii) an increase in costs associated with our NGL storage caverns. Higher gas and electricity utility prices in the first and second quarters of 2014 also contributed to an increase in costs for the comparative nine-month periods.

~~General and Administrative Expenses.~~ General and administrative expenses (excluding equity-indexed compensation expenses) remained relatively consistent for the three months ended September 30, 2014 compared to the three months ended September 30, 2013 and decreased slightly during the comparative nine-month periods. These results reflect the net impact of a decrease in General and Administrative expenses due to a change in classification of certain costs to Field Operating Costs during the 2014 periods partially offset by increased expenses resulting from overall growth in the segment.

~~Maintenance Capital.~~ The increase in maintenance capital for the three and nine months ended September 30, 2014 compared to the three and nine months ended September 30, 2013 is primarily due to timing of maintenance projects for tanks and other facility assets.

~~Supply and Logistics~~ ~~Segment~~

Our revenues from supply and logistics activities reflect the sale of gathered and bulk-purchased crude oil, as well as sales of NGL volumes purchased from suppliers and natural gas sales attributable to the activities performed by our natural gas storage commercial optimization group. We do not anticipate that future changes in revenues resulting from variances in commodity prices will be a primary driver of segment profit. Generally, we expect our segment profit to increase or decrease directionally with (i) increases or decreases in our Supply and Logistics segment volumes (which consist of lease gathering crude oil purchase volumes, NGL sales volumes and waterborne cargos), (ii) demand for lease gathering services we provide producers and (iii) the overall volatility and strength or weakness of market conditions and the allocation of our assets among our various risk management strategies. In addition, the execution of our risk management strategies in conjunction with our assets can provide upside in certain markets.

~~Table of Contents~~

~~The following table sets forth operating results from our Supply and Logistics segment for the periods indicated:~~

Favorable/

Favorable/

Three Months Ended

(Unfavorable)

Nine Months Ended

(Unfavorable)

Operating Results (1) (2)

September 30,

Variance

September 30,

Variance

(in millions, except per barrel data)

2014

2013

$

%

2014

2013

$

%

Revenues

$
10,793

$
10,386

$
407

4
%

$
33,021

$
30,544

$
2,477

8
%
Purchases and related costs (3)

(10,488
)
(10,189
)
(299
)
(3
)%

(32,041
)
(29,439
)
(2,602
)
(9
)%
Field operating costs (4)

(122
)
(103
)
(19
)
(18
)%

(340
)
(327
)
(13
)
(4
)%
Equity-indexed compensation expense - operations

—

—

—

—
%

(2
)
(2
)
—

—
%
Segment general and administrative expenses (4) (5)

(25
)
(25
)
—

—
%

(79
)
(77
)
(2
)
(3
)%
Equity-indexed compensation expense - general and administrative

(6
)
(5
)
(1
)
(20
)%

(25
)
(26
)
1

4
%
Segment profit

$
152

$
64

$
88

138
%

$
534

$
673

$
(139
)
(21
)%
Maintenance capital

$
2

$
7

$
5

71
%

$
6

$
17

$
11

65
%
Segment profit per barrel

$
1.47

$
0.69

$
0.78

113
%

$
1.75

$
2.33

$
(0.58
)
(25
)%

Favorable/

Favorable/

Three Months Ended

(Unfavorable)

Nine Months Ended

(Unfavorable)

Average Daily Volumes

September 30,

Variance

September 30,

Variance

(in thousands of barrels per day)

2014

2013

Volumes

%

2014

2013

Volumes

%

Crude oil lease gathering purchases

971

856

115

13
%

932

855

77

9
%
NGL sales

153

145

8

6
%

188

196

(8
)
(4
)%
Waterborne cargos

—

4

(4
)
(100
)%

—

5

(5
)
(100
)%
Supply and Logistics segment total

1,124

1,005

119

12
%

1,120

1,056

64

6
%

~~(1)Revenues and costs include intersegment amounts.~~

~~(2)~~Prior to January 1, 2014, natural gas sales revenues and costs attributable to the activities performed by our natural gas storage commercial optimization group were reported in the Facilities segment.

~~(3)~~Purchases and related costs include interest expense (related to hedged inventory purchases) of $4 million and $11 million for the three and nine months ended September 30, 2014 and $8 million and $21 million for the three and nine months ended September 30, 2013, respectively.

~~(4)Field operating costs and Segment general and administrative expenses exclude equity-indexed compensation expense, which is presented separately in the table above.~~

~~(5)~~Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.

~~Table of Contents~~

The following table presents the range of the NYMEX ~~West Texas Intermediate~~WTI benchmark price of crude oil during the ~~three and nine months ended September 30, 2014 and 2013.~~periods indicated (in dollars per barrel):

NYMEX WTI

Crude Oil Price

Low

High

Three months ended September 30, 2014

$
90

$
106

Three months ended September 30, 2013

$
96

$
112

Nine months ended September 30, 2014

$
90

$
108

Nine months ended September 30, 2013

$
86

$
112

	NYMEX WTI
	Crude Oil Price
	Low		High
Three months ended March 31, 2015	$	43	$	54
Three months ended March 31, 2014	$	92	$	105

Because the commodities that we buy and sell are generally indexed to the same pricing indices for both the sales and purchases, revenues and costs related to purchases will fluctuate with market prices. However, the margins related to those sales and purchases will not necessarily have a corresponding increase or decrease. The absolute amount of our revenues and purchases ~~increased~~decreased for the three ~~and nine~~ months ended ~~September 30, 2014 relative~~March 31, 2015 due to ~~the comparative periods, primarily resulting from increases in~~lower crude oil ~~volumes in 2014, partially offset by decreases in crude oil~~and NGL prices relative to the comparative ~~three-month~~2014 period.

Generally, we expect a base level of earnings from our Supply and Logistics segment from the assets employed by this segment. This base level may be optimized and enhanced when there is a high level of market volatility, favorable basis differentials and/or a steep contango or backwardated market structure. Also, our NGL ~~marketing~~ operations are sensitive to weather-related demand, particularly during the approximate five-month peak heating season of November through March, and temperature differences from period-to-period may have a significant effect on NGL demand and thus our financial performance.

The following is a discussion of items impacting Supply and Logistics segment profit and segment profit per barrel for the periods indicated.

Net Operating Revenues and Volumes. Our Supply and Logistics segment revenues, net of purchases and related costs, ~~excluding gains and losses from certain derivative activities (see the “Impact from Certain Derivative Activities” section below), increased slightly~~decreased for the three months ended ~~September 30, 2014~~March 31, 2015 compared to the three months ended ~~September 30, 2013, while such results decreased year-over-year for the nine month comparative periods presented.~~March 31, 2014. The following ~~factors impacted revenues and volumes~~summarizes the more significant items in the comparative periods:

·~~NGL Marketing~~ Crude Oil Operations — Net revenues from our NGL marketing operations decreased during the three and nine months ended September 30, 2014 as compared to the three and nine months ended September 30, 2013. This decrease was driven by higher purchases and related costs in the 2014 periods, primarily due to (i) a higher weighted average inventory cost and (ii) increased facility fees. Additionally, NGL margins during the nine-month 2014 period were further impacted by less favorable market conditions, most notably during the second quarter of 2014, as market pricing was stronger in 2013 due to heating requirements during a winter season that extended into the second quarter and greater petrochemical demand for propane.

·North American Crude Oil Production and Related Market Economics — The significant increase in oil and liquids-rich gas production growth in North America has generally created regional supply and demand imbalances due to the lack of sufficient infrastructure to support the movement of such production, which increased certain crude oil location differentials. The lack of existing pipeline takeaway capacity and associated logistical challenges created market conditions that provided opportunities to capture above-baseline margins in our supply and logistics crude oil activities over the last few years.

~~For the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013, net~~ revenues from our crude oil supply and logistics activities decreased ~~as there were fewer opportunities to capture above-baseline margins, particularly in~~for the ~~first quarter of 2014~~three months ended March 31, 2015 as compared to the ~~first quarter of 2013. However,~~same period in 2014, primarily driven by the ~~widening~~compression of certain differentials during the 2015 period, which resulted in ~~the third quarter of 2014 allowed for more~~fewer opportunities to capture above-baseline margins as compared to the ~~third~~first quarter of ~~2013, which led to an increase in net~~2014. Such unfavorable results were partially offset by incremental lease gathering revenues from ~~our crude oil supply and logistics activities for the three months ended September 30, 2014 compared to the three months ended September 30, 2013.~~

We believe the fundamentals of our business remain strong as lease-gathered volumes for the three and nine month periods ended September 30, 2014 increased by 13% and 9%, respectively, as compared to volumes in the same three and nine month periods in 2013. However, as the midstream infrastructure continues to be developed, we believe a normalization of margins will continue to occur as the logistics challenges are addressed. (See Items 1 and 2 “Business and Properties—Description of Segments and Associated Assets—Supply and Logistics Segment—Impact of Commodity Price Volatility and Dynamic Market Conditions on Our Business Model” included in Part I of our 2013 Annual Report on Form 10-K for further discussion regarding our business model, including diversification and utilization of our asset base among varying demand- and supply-driven markets.)

~~Table of Contents~~higher volumes.

·Natural Gas Storage Commercial Optimization — ~~Our~~During the first quarter of 2014, our natural gas storage commercial optimization activities ~~for the nine months ended September 30, 2014~~ were unfavorably impacted by costs incurred to manage deliverability requirements in conjunction with the extended period of severe cold ~~weather~~weather. We did not incur similar costs during the first quarter of 2015 and, therefore, we experienced ~~during~~more favorable results from our natural gas storage activities in the 2015 period as compared to the first quarter of 2014.

· NGL Operations — Net revenues from our NGL operations increased for the three months ended March 31, 2015 as compared to the three months ended March 31, 2014. The favorable variance was driven by higher sales volumes during the end of our winter heating season, partially offset by increased facility fees.

Table of Contents

·Impact from Certain Derivative Activities,. Net of Inventory Valuation Adjustments — The mark-to-market ~~valuation~~ of certain of our derivative activities impacted our net revenues as shown in the table below (in millions):

Three Months Ended

Nine Months Ended

September 30,

September 30,

2014

2013

Variance

2014

2013

Variance

Gains/(losses) from certain derivative activities (1)

$
29

$
(57
)
$
86

$
81

$
(6
)
$
87

	Three Months Ended
	March 31,					Variance
	2015			2014		$			%
Gains/(losses) from certain derivative activities net of inventory valuation adjustments (1)	$	(93	)	$	66	$	(159	)	(241	)%

(1) Includes mark-to-market and other gains and losses resulting from certain derivative instruments that are related to underlying activities in ~~future periods or~~another period (or the reversal of mark-to-market gains and losses from a prior period), gains and losses on certain derivatives that are related to investing activities (such as the ~~prior period. These amounts are reduced by the net impact~~purchase of linefill) and inventory valuation adjustments, ~~attributable to inventory hedged by the related derivative and gains recognized in later periods on physical sales of inventory that was previously written down.~~as applicable. See Note 108 to our ~~condensed consolidated financial statements~~Condensed Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities.

· Long-Term Inventory Costing Adjustment — Our operating results for the first quarter of 2015 were unfavorably impacted by a $38 million reduction in the value of our long-term crude oil and NGL inventory pools resulting from the decrease in the price of crude oil and NGL during the period. This costing adjustment is related to inventory necessary to meet our minimum inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future.

·Foreign Exchange — During the three months ended March 31, 2015 and 2014, there were fluctuations in the value of CAD to USD, resulting in net foreign exchange gains on U.S. denominated net assets within our Canadian operations of $32 million.

Field Operating Costs. The increase in field operating costs (excluding equity-indexed compensation ~~expenses)~~expense) for the three ~~and nine~~ months ended ~~September 30, 2014~~March 31, 2015 compared to the three ~~and nine~~ months ended ~~September 30, 2013~~March 31, 2014 was primarily due to ~~an increase~~increases in driver salaries and related expenses and trucking costs associated with higher crude oil lease ~~gathered~~gathering purchases volumes. ~~However, the~~The increase in field operating costs for the comparative ~~nine-month~~ periods was partially offset by a ~~decrease~~reduction in ~~third-party transportation~~fuel costs ~~in the first quarter of 2014 as compared to the first quarter of 2013.~~

~~Maintenance Capital.~~ ~~The decrease in maintenance capital for the three and nine months ended September 30, 2014 compared to the three and nine months ended September 30, 2013 is primarily~~ due to ~~reduced spending on trucking assets.~~lower average diesel fuel cost per gallon.

Other Income and Expenses

Depreciation and Amortization

~~The increase in depreciation~~Depreciation and amortization expense increased for the three ~~and nine~~ months ended ~~September 30, 2014 over~~March 31, 2015 compared to the three ~~and nine~~ months ended ~~September 30, 2013 was~~March 31, 2014, primarily due to various internal growth projects completed ~~throughout 2013 and 2014, as well as an acceleration of depreciation on certain pipeline assets to reflect a change in their estimated useful lives.~~since March 31, 2014.

Interest Expense

The increase in interest expense for the three ~~and nine~~ months ended ~~September 30, 2014~~March 31, 2015 over the three ~~and nine~~ months ended ~~September 30, 2013 resulted from higher average debt outstanding during the~~March 31, 2014 ~~periods,~~was primarily due to ~~(i) our August 2013 issuance~~a higher weighted average debt balance driven by an aggregate of ~~$700 million, 3.85%~~$2.6 billion of senior notes ~~(ii)~~issued in 2014.

Income Tax Expense

Income tax expense decreased for the three months ended March 31, 2015 compared to the three months ended March 31, 2014 primarily as a result of a deferred income tax benefit associated with derivative mark-to-market losses in our ~~April 2014 issuance of $700 million, 4.70% senior notes and (iii) our September 2014 issuance of $750 million, 3.60% senior notes,~~Canadian operations. This benefit was partially offset by ~~the maturity~~higher current income tax expense as a result of increased year-over-year taxable earnings from our ~~$250 million, 5.63% senior notes in December 2013.~~

~~Other Income/(Expense), Net~~

Other income/(expense), net in each of the periods presented was primarily comprised of foreign currency gains or losses related to revaluations of CAD-denominated interest receivables associated with our intercompany notes and the impact of related foreign currency hedges.Canadian operations.

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~~Income Tax Expense~~

~~The increase in income tax expense for the three and nine months ended September 30, 2014 compared to the three and nine months ended September 30, 2013 was primarily a result of~~ ~~higher year over year earnings from our taxable Canadian operations.~~

~~Net Income Attributable to Noncontrolling Interests~~

Net income attributable to noncontrolling interests decreased for the three and nine months ended September 30, 2014 compared to the three and nine months ended September 30, 2013 as a result of our completion of the PNG Merger on December 31, 2013, pursuant to which we acquired all of the noncontrolling interests in PNG.

Liquidity and Capital Resources

General

Our primary sources of liquidity are (i) cash flow from operating activities, (ii) borrowings under our credit facilities or commercial paper program ~~or credit facilities~~ and (iii) funds received from sales of equity and debt securities. Our primary cash requirements include, but are not limited to (i) ordinary course of business uses, such as the payment of amounts related to the purchase of crude oil, NGL and other products and other expenses and interest payments on outstanding debt, (ii) expansion and maintenance activities, (iii) acquisitions of assets or businesses, (iv) repayment of principal on our long-term debt and (v) distributions to our unitholders and general partner. We generally expect to fund our short-term cash requirements through cash flow generated from operating activities and/or borrowings under our commercial paper program or credit facilities. In addition, we generally expect to fund our long-term needs, such as those resulting from expansion activities or acquisitions and refinancing our long-term debt, through a variety of sources (either separately or in combination), which may include the sources mentioned above as funding for short-term needs and/or the issuance of additional equity or debt securities. As of ~~September 30, 2014,~~March 31, 2015, we had a working capital deficit of ~~$408~~$78 million and approximately ~~$2.5~~$4.4 billion of liquidity available to meet our ongoing operating, investing and financing needs as noted below (in millions):

	As of September 30, 2014			March 31, 2015
Availability under PAA senior unsecured revolving credit facility (1)	$	1,591
Availability under PAA senior secured hedged inventory facility (1)	1,343
Less: Amounts outstanding under PAA commercial paper program	(423		)
Availability under senior unsecured revolving credit facility (1)				$	1,584
Availability under senior secured hedged inventory facility (1)				1,333
Availability under senior unsecured 364-day revolving credit facility				1,000
Subtotal	2,511			3,917
Cash and cash equivalents	34			458
Total	$	2,545		$	4,375

(1) ~~Represents availability prior to giving effect to amounts outstanding under the PAA commercial paper program.~~ Borrowings under ~~the PAA~~our commercial paper program reduce available capacity under the facility. There were no commercial paper borrowings outstanding as of March 31, 2015.

We believe that we have, and will continue to have, the ability to access ~~the~~our commercial paper program and credit facilities, which we use to meet our short-term cash needs. We believe that our financial position remains strong and we have sufficient liquidity; however, extended disruptions in the financial markets and/or energy price volatility that adversely affect our business may have a materially adverse effect on our financial condition, results of operations or cash flows. Also, see Item 1A. “Risk Factors” ~~in Item 1A~~ of our ~~2013~~2014 Annual Report on Form 10-K for further discussion regarding such risks that may impact our liquidity and capital resources. Usage of ~~the~~our credit facilities, certain of which provide the backstop for ~~the~~our commercial paper program, is subject to ongoing compliance with covenants. As of ~~September 30, 2014,~~March 31, 2015, we were in compliance with all such covenants.

Cash Flow from Operating Activities

For a comprehensive discussion of the primary drivers of cash flow from operating activities, including the impact of varying market conditions and the timing of settlement of our ~~derivative activities,~~derivatives, see “Liquidity and Capital ~~Resources-Cash~~Resources—Cash Flow from Operating Activities” under Item 7 of our ~~2013~~2014 Annual Report on Form 10-K.

Net cash provided by operating activities for the first three months of 2015 and 2014 was $732 million and $822 million, respectively, and primarily resulted from earnings from our operations. Additionally, as discussed further below, changes in our inventory levels during these periods impacted our cash flow from operating activities.

During the three months ended March 31, 2015, we decreased the volume of inventory that we held, primarily due to the seasonal sale of NGL and natural gas inventory. The net proceeds received from liquidation of such inventory during the quarter were used to repay borrowings under our commercial paper program and favorably impacted cash flow from operating activities. Additionally, lower inventory levels were further impacted by lower prices for such inventory stored at the end of the quarter compared to the prior year end. However, the favorable effects from liquidation of our NGL and natural gas inventory were partially offset by increased levels of crude oil inventory purchased and stored due to contango market conditions.

During the first three months of 2014, we decreased the volume of our inventory, primarily due to the sale of NGL and natural gas inventory related to high demand for product used for heating during the extended 2014 winter season. The net proceeds received from liquidation of such inventory were used to repay borrowings under our commercial paper program and favorably impacted cash flow from operating activities.

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Net cash provided by operating activities for the first nine months of 2014 was approximately $1.3 billion, primarily resulting from earnings from our operations. Net cash provided by operating activities for the first nine months of 2013 of approximately $1.6 billion also resulted primarily from earnings from our operations. In addition, we decreased the amount of our inventory during the first nine months of 2013, primarily due to the sale of crude oil inventory that had been stored during the contango market. This decrease in crude oil inventory was partially offset by an increase in NGL inventory as we began to increase inventory levels in preparation for end users’ increased demand for product used for heating during the peak heating season of November through March. The net proceeds received from liquidation of our crude oil inventory during this period was used to repay borrowings under our credit facilities or commercial paper program and favorably impacted our cash flow from operating activities.

A~~cquisitions~~Acquisitions and Capital Expenditures

In addition to operating needs discussed above, we also use cash for our acquisition activities and ~~internal growth~~capital projects. We have made and will continue to make capital expenditures for acquisitions, expansion capital and maintenance capital.

~~2014~~2015 Capital ~~Expansion~~ Projects. ~~See “—Acquisitions~~“See —Acquisitions and ~~Internal Growth~~Capital Projects” for detail of our projected capital expenditures for the year ending December 31, ~~2014.~~2015. We expect the majority of funding for our remaining ~~2014~~2015 capital program will ~~continue to~~ be provided by borrowings under our commercial paper program ~~our credit facilities and cash flow in excess of partnership distributions,~~ as well as through proceeds received from our ~~access to the capital markets for~~March 2015 underwritten equity ~~and debt as we deem necessary.~~offering.

~~Acquisitions.~~ The price of acquisitions includes cash paid, assumed liabilities and net working capital items. Because of the non-cash items included in the total price of the acquisition and the timing of certain cash payments, the net cash paid may differ significantly from the total price of the acquisitions completed during the period. Historically, we have financed acquisitions primarily with cash generated from operating activities and the financing activities discussed below.

As of November 5, 2014, we entered into a definitive purchase and sale agreement with Oxy that provides for our purchase of Oxy’s 50% interest in BridgeTex for $1.075 billion. See Note 14 to our condensed consolidated financial statements for details of this potential acquisition, including discussion of conditions precedent to closing. We intend to initially use borrowings under our commercial paper program to fund this acquisition. On a long-term basis, we intend to follow our financial strategy by funding at least 55% of the acquisition with equity and cash flow in excess of distributions and the remaining amount with long-term debt.

Equity and Debt Financing Activities

Our financing activities primarily relate to funding acquisitions, ~~internal~~expansion capital ~~expansion~~ projects and refinancing of our debt maturities, as well as short-term working capital and hedged inventory borrowings related to our NGL business and contango market activities. Our financing activities have primarily consisted of equity offerings, senior notes offerings and borrowings and repayments under our credit facilities or commercial paper program, ~~or credit facilities,~~ as well as payment of distributions to our unitholders and general partner.

Registration ~~Statements.~~Statements. We periodically access the capital markets for both equity and debt financing. We have filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to an aggregate of $2.0 billion of debt or equity securities (“Traditional Shelf”). All issuances of equity securities associated with our continuous offering program, as discussed further below, have been issued pursuant to the Traditional Shelf. At ~~September 30, 2014,~~March 31, 2015, we had approximately ~~$809~~$555 million of unsold securities available under the Traditional Shelf. We also have access to a universal shelf registration statement (“WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, ~~via an underwritten offering,~~ subject to market conditions and our capital needs. The March 2015 underwritten equity offering, as discussed further below, was conducted under our WKSI Shelf.

Continuous Offering Program. In August 2014, we entered into an equity distribution agreement with several financial institutions pursuant to which we may offer and sell, through sales agents, common units representing limited partner interests having an aggregate offering price of up to $900 million. During the ~~nine~~three months ended ~~September 30, 2014,~~March 31, 2015, we issued an aggregate of approximately ~~11.8~~1.1 million common units under our continuous offering program, generating proceeds of ~~$669~~$59 million, including our general partner’s proportionate capital contribution of ~~$14~~$1 million, net of $7$1 million of commissions to our sales agents. The net proceeds from sales were used for general partnership purposes.

Underwritten Offering. In March 2015, we completed an underwritten public offering of 21.0 million common units generating net proceeds of approximately $1.1 billion, including our general partner’s proportionate capital contribution of $21 million and net of costs associated with the offering. We used a portion of the net proceeds from this offering to repay outstanding borrowings under our commercial paper program and for general partnership purposes, and we intend to use the remaining net proceeds for general partnership purposes, including expenditures for our 2015 capital program.

Credit Agreements, Commercial Paper Program and Indentures.Our credit agreements (which impact our ability to access our commercial paper program because they provide the backstop that supports our short-term credit ratings) and the indentures governing our senior notes contain cross-default provisions. A default under our credit agreements would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with the provisions in our credit agreements, our ability to make distributions of available cash is not restricted. We were in compliance with the covenants contained in our credit agreements and indentures as of ~~September 30, 2014.~~

~~Table of Contents~~March 31, 2015.

During the ~~nine~~three months ended ~~September 30,~~March 31, 2015 and 2014, ~~and 2013,~~ we had net repayments on our credit agreements and commercial paper program of ~~$683~~$734 million and ~~$464~~$128 million, respectively. The net repayments during both periods resulted primarily from cash flow from operating activities, including sales of NGL and natural gas inventory that was liquidated during the periods, as well as cash received from our ~~debt and~~ equity activities.

In ~~August 2014,~~January 2015, we ~~extended the maturity dates of our senior secured hedged inventory facility and our~~entered into a new $1.0 billion, 364-day senior unsecured ~~revolving~~ credit ~~facility by one year through~~agreement. Borrowings, if any, accrue interest based, at our election, on either the ~~exercise of~~Eurocurrency Rate or the ~~option included~~Base Rate, as defined in the ~~current~~agreement, in each case plus a margin based on our credit ~~agreements. Our senior secured hedged inventory facility and our senior unsecured revolving credit facility now mature in August 2017 and August 2019, respectively.~~

~~Effective October 20, 2014,~~rating at the ~~maximum aggregate borrowing capacity under our commercial paper program was increased from $1.5 billion to $3.0 billion.~~

In April 2014, we completed the issuance of $700 million, 4.70% senior notes due 2044 at a public offering price of 99.734%. Interest payments are due on June 15 and December 15 of each year, commencing on December 15, 2014. We used the net proceeds from this offering of $691 million, after deducting the underwriting discount and offering expenses, to repay outstanding borrowings under our commercial paper program and for general partnership purposes.

In September 2014, we completed the issuance of $750 million, 3.60% senior notes due 2024 at a public offering price of 99.842%. Interest payments are due on May 1 and November 1 of each year, commencing on May 1, 2015. We used the net proceeds from this offering of $743 million, after deducting the underwriting discount and offering expenses, to repay outstanding borrowings under our commercial paper program and for general partnership purposes.applicable time.

Our $150 million, 5.25% senior notes will mature in June 2015, and our $400 million, 3.95% senior notes will mature in September 2015. We intend to use borrowings under our commercial paper program to repay these senior notes when they mature.

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Distributions Paid to Our Unitholders, General Partner and Noncontrolling Interests

Distributions to our unitholders and general partner. We distribute 100% of our available cash within 45 days ~~after~~following the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. On ~~November 14, 2014~~May 15, 2015, we will pay a quarterly distribution of ~~$0.6600~~$0.6850 per limited partner ~~unit, which~~unit. This distribution represents a ~~10.0%~~year-over-year distribution increase ~~over the distribution we paid in November 2013.~~of approximately 8.7%. See Note 87 to our ~~condensed consolidated financial statements~~Condensed Consolidated Financial Statements for details of distributions paid. Also, see Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy” included in our ~~2013~~2014 Annual Report on Form 10-K for additional discussion onregarding distributions.

Distributions to noncontrolling interests. We paid ~~$2 million and $37~~$1 million for distributions to noncontrolling interests during each of the ~~nine~~three months ended ~~September 30,~~March 31, 2015 and 2014, ~~and 2013,~~ respectively. ~~The decrease in amounts paid is due to our completion of the purchase of all of the noncontrolling interests in PNG on December 31, 2013.~~

We believe that we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow. A prolonged material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity.

Contingencies

For a discussion of contingencies that may impact us, see Note 1110 to our ~~condensed consolidated financial statements.~~Condensed Consolidated Financial Statements.

Commitments

Contractual Obligations. In the ordinary course of doing business, we purchase crude oil and NGL from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years with a limited number of contracts extending up to ~~approximately ten~~nine years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. In addition, we enter into similar contractual obligations in conjunction with our natural gas operations. The table below includes purchase obligations related to these activities. Where applicable, the amounts presented represent the net obligations associated with our counterparties (including giving effect to netting buy/sell contracts and those subject to a net settlement arrangement). We do not expect to use a significant amount of internal capital to meet these

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obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy or who have provided credit support we consider adequate.

The following table includes our best estimate of the amount and timing of these payments as well as others due under the specified contractual obligations as of ~~September 30, 2014~~March 31, 2015 (in millions):

															Remainder of										2020 and
	Remainder of 2014		2015		2016		2017		2018		2019 and Thereafter		Total		2015		2016		2017		2018		2019		Thereafter		Total
Long-term debt, including current maturities and related interest payments (1)	$	103	$	954	$	560	$	755	$	928	$	9,798	$	13,098	$	884	$	604	$	799	$	972	$	1,188	$	10,605	$	15,052
Leases (2)	41		148		140		116		93		419		957		127		185		165		143		118		533		1,271
Other obligations (3)	79		127		93		64		45		213		621		472		394		71		43		29		175		1,184
Subtotal	223		1,229		793		935		1,066		10,430		14,676		1,483		1,183		1,035		1,158		1,335		11,313		17,507
Crude oil, natural gas, NGL and other purchases (4)	4,360		7,584		6,497		4,987		2,909		8,215		34,552		5,034		4,137		3,125		1,811		1,325		3,608		19,040
Total	$	4,583	$	8,813	$	7,290	$	5,922	$	3,975	$	18,645	$	49,228	$	6,517	$	5,320	$	4,160	$	2,969	$	2,660	$	14,921	$	36,547

(1) Includes debt service payments, interest payments due on senior notes and the commitment fee on assumed available capacity under the PAA revolving credit facilities. Although there may be short-term borrowings under the PAA revolving credit facilities and commercial paper program, we historically repay and borrow at varying amounts. As such, we have included only the maximum commitment fee (as if no short-term borrowings were outstanding on the facilities or commercial paper program) in the amounts above.

(2) Leases are primarily for (i) surface rentals, (ii) office rent, (iii) pipeline assets and (iv) trucks, trailers and railcars. Includes both capital and operating leases as defined by FASB guidance.

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(3) Includes (i) other long-term liabilities, (ii) storage, processing and transportation agreements and (iii) non-cancelable commitments related to our capital expansion projects, including projected contributions for our share of the capital spending of our equity-method investments. Excludes a non-current liability of $2approximately $90 million related to derivative activity included in Crude oil, natural gas, NGL and other purchases.

(4) Amounts are primarily based on estimated volumes and market prices based on average activity during ~~September 2014.~~March 2015. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.

Letters of Credit. In connection with supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs and construction activities. At ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, we had outstanding letters of credit of ~~$66~~approximately $83 million and ~~$41~~$87 million, respectively.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements as defined by Item 303 of Regulation S-K.

Recent Accounting Pronouncements

See Note 2 to our ~~condensed consolidated financial statements.~~Condensed Consolidated Financial Statements.

Critical Accounting Policies and Estimates

For ~~additional~~a discussion regarding our critical accounting policies and estimates, see “Critical Accounting Policies and Estimates” under Item 7 of our ~~2013~~2014 Annual Report on Form 10-K.

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FORWARD-LOOKING STATEMENTS

All statements included in this report, other than statements of historical fact, are forward-looking statements, including but not limited to statements incorporating the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast,” as well as similar expressions and statements regarding our business strategy, plans and objectives for future operations. The absence of such words, expressions or statements, however, does not mean that the statements are not forward-looking. Any such forward-looking statements reflect our current views with respect to future events, based on what we believe to be reasonable assumptions. Certain factors could cause actual results or outcomes to differ materially from the results or outcomes anticipated in the forward-looking statements. The most important of these factors include, but are not limited to:

· failure to implement or capitalize, or delays in implementing or capitalizing, on planned ~~internal~~ growth projects;

·~~unanticipated changes in crude oil market structure, grade differentials and volatility (or lack thereof);~~

·~~environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;~~

· declines in the volume of crude oil, refined product and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our facilities, whether due to declines in production from existing oil and gas reserves, failure to develop or slowdown in the development of additional oil and gas reserves, whether from reduced cash flow to fund drilling or the inability to access capital, or other factors;

·unanticipated changes in crude oil market structure, grade differentials and volatility (or lack thereof);

·environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;

· fluctuations in refinery capacity in areas supplied by our mainlines and other factors affecting demand for various grades of crude oil, refined products and natural gas and resulting changes in pricing conditions or transportation throughput requirements;

· the effects of competition;

·the occurrence of a natural disaster, catastrophe, terrorist attack or other event, including attacks on our electronic and computer systems;

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·tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness;

· weather interference with business operations or project construction, including the impact of extreme weather events or conditions;

· ~~tightened capital markets or other factors that increase~~continued creditworthiness of, and performance by, our ~~cost of capital or limit our access to capital;~~counterparties, including financial institutions and trading companies with which we do business;

· maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties;

·~~continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business;~~

· the currency exchange rate of the Canadian dollar;

· the availability of, and our ability to consummate, acquisition or combination opportunities;

· the successful integration and future performance of acquired assets or businesses and the risks associated with operating in lines of business that are distinct and separate from our historical operations;

·~~shortages or cost increases of supplies, materials or labor;~~

· the effectiveness of our risk management activities;

· ~~our ability to obtain debt~~shortages or ~~equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment~~cost increases of supplies, materials or ~~refinancing of indebtedness;~~labor;

· the impact of current and future laws, rulings, governmental regulations, accounting standards and statements, and related interpretations;

· non-utilization of our assets and facilities;

· ~~the effects of competition;~~

·increased costs, or lack of availability, of insurance;

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· fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans;

· risks related to the development and operation of our facilities, including our ability to satisfy our contractual obligations to our customers at our facilities;

· factors affecting demand for natural gas and natural gas storage services and rates;

· general economic, market or business conditions and the amplification of other risks caused by volatile financial markets, capital constraints and pervasive liquidity concerns; and

· other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil and refined products, as well as in the storage of natural gas and the processing, transportation, fractionation, storage and marketing of natural gas liquids.

Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read “Risk Factors” discussed in Item 1A of our ~~2013~~2014 Annual Report on Form 10-K. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various market risks, including (i) commodity price risk, (ii) interest rate risk and (iii) currency exchange rate risk. We use various derivative instruments to manage such risks and, in certain circumstances, to realize incremental margin during volatile market conditions. Our risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our exchange-cleared and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. We have a risk management function that has direct responsibility and authority for our risk policies, related controls around commercial activities and certain aspects of corporate risk management. Our risk management function also approves all new risk management strategies through a formal process. The following discussion addresses each category of risk.

C~~ommodity~~Commodity Price Risk

We use derivative instruments to hedge commodity price risk associated with the following commodities:

· Crude oil ~~and refined products~~

We utilize crude oil ~~and refined products~~ derivatives to hedge commodity price risk inherent in our Supply and Logistics and Transportation segments. Our objectives for these derivatives include hedging anticipated purchases and sales, stored inventory, and storage capacity utilization. We manage these exposures with various instruments including exchange-traded and over-the-counter futures, forwards, swaps and options.

· Natural gas

We utilize natural gas derivatives to hedge commodity price risk inherent in our Supply and Logistics and Facilities segments. Our objectives for these derivatives include hedging anticipated purchases and sales and managing our anticipated base gas requirements. We manage these exposures with various instruments including exchange-traded futures, swaps and options.

· NGL and other

We utilize NGL derivatives, primarily butane and propane derivatives, to hedge commodity price risk inherent in our Supply and Logistics segment. Our objectives for these derivatives include hedging anticipated purchases and ~~sales.~~sales and stored inventory. We manage these exposures with various instruments including exchange-traded and over-the-counter futures, forwards, swaps and options.

See Note 108 to our ~~condensed consolidated financial statements~~Condensed Consolidated Financial Statements for further discussion regarding our hedging strategies and objectives.

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Our policy is to (i) purchase only product for which we have a market, (ii) hedge our purchase and sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold physical inventory or other derivative instruments for the purpose of speculating on outright commodity price changes, as these activities could expose us to significant losses.

The fair value of our commodity derivatives and the change in fair value as of ~~September 30, 2014~~March 31, 2015 that would be expected from a 10% price increase or decrease is shown in the table below (in millions):

Effect of 10%

Effect of 10%

Effect of 10%

Effect of 10%

Fair Value

Price Increase

Price Decrease

Fair Value

Price Increase

Price Decrease

Crude oil and related products

$
7

$
32

$
(27
)
Crude oil

$
48

$
(31
)
$
31

Natural gas

(2
)
$
1

$
(1
)

(24
)
$
2

$
(2
)
NGL and other

26

$
(69
)
$
69

120

$
(17
)
$
17

Total fair value

$
31

$
144

41

Table of Contents

The fair values presented in the table above reflect the sensitivity of the derivative instruments only and do not include the effect of the underlying hedged commodity. Price-risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in near-term commodity prices, the fair value of our derivative portfolio would typically change less than that shown in the table as changes in near-term prices are not typically mirrored in delivery months further out.

Interest Rate Risk

Our use of variable rate debt and any forecasted issuances of fixed rate debt expose us to interest rate risk. Therefore, from time to time we use interest rate derivatives to hedge interest rate risk associated with anticipated debt issuances and, in certain cases, outstanding debt instruments. All of our senior notes are fixed rate notes and thus are not subject to interest rate risk. ~~The majority of our~~We did not have any variable rate debt ~~at September 30, 2014, $423 million, is subject to interest rate re-sets, which range from one day to two weeks.~~outstanding as of March 31, 2015. The average interest rate ~~of approximately 0.3% is~~on variable rate debt that was outstanding during the three months ended March 31, 2015 was 0.4%, based upon rates in effect during ~~the nine months ended September 30, 2014.~~such period. The fair value of our interest rate derivatives is a liability of ~~$15~~$144 million as of ~~September 30, 2014.~~March 31, 2015. A 10% increase in the forward LIBOR curve as of ~~September 30, 2014~~March 31, 2015 would result in an increase of ~~$17~~$57 million to the fair value of our interest rate derivatives. A 10% decrease in the forward LIBOR curve as of ~~September 30, 2014~~March 31, 2015 would result in a decrease of ~~$17~~$57 million to the fair value of our interest rate derivatives. See Note 108 to our ~~condensed consolidated financial statements~~Condensed Consolidated Financial Statements for a discussion of our interest rate risk hedging activities.

Currency Exchange Rate Risk

We use foreign currency derivatives to hedge foreign currency exchange rate risk associated with our exposure to fluctuations in the USD-to-CAD exchange rate. 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 certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts, forwards and options. The fair value of our foreign currency derivatives is a liability of ~~$10~~$4 million as of ~~September 30, 2014.~~March 31, 2015. A 10% increase in the exchange rate (USD-to-CAD) would result in a decrease of ~~$41~~$15 million to the fair value of our foreign currency derivatives. A 10% decrease in the exchange rate (USD-to-CAD) would result in an increase of ~~$42~~$15 million to the fair value of our foreign currency derivatives. See Note 108 to our ~~condensed consolidated financial statements~~Condensed Consolidated Financial Statements for a discussion of our currency exchange rate risk hedging.

Item 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We maintain written disclosure controls and procedures, which we refer to as our “DCP.” Our DCP is designed to ensure that information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 (the “Exchange Act”) is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.

47

~~Table of Contents~~
Applicable SEC rules require an evaluation of the effectiveness ~~of the design and operation~~ of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of ~~the design and operation of~~ our DCP as of March 31, 2015, the end of the period covered by this report, and, ~~has found~~based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our DCP to be effective in providing reasonable assurance of the timely recording, processing, summarization and reporting of information, and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosure.is effective.

Changes in Internal Control over Financial Reporting

In addition to the information concerning our DCP, we are required to disclose certain changes in internal control over financial reporting. ~~Although we have made various enhancements to our controls, there~~There have been no changes in our internal control over financial reporting during the ~~period covered by this report~~first quarter of 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Certifications

The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a) are filed with this report as Exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350 are furnished with this report as Exhibits 32.1 and 32.2.

4842

Table of Contents

PART II. OTHER INFORMATION

Item 1.LEGAL PROCEEDINGS

The information required by this item is included under the caption “Litigation” in Note 1110 to our ~~condensed consolidated financial statements,~~Condensed Consolidated Financial Statements, and is incorporated herein by reference thereto.

Item 1A.RISK FACTORS

For a discussion regarding our risk factors, see Item 1A of our ~~2013~~2014 Annual Report on Form 10-K. Those risks and uncertainties are not the only ones facing us and there may be additional matters of which we are unaware or that we currently consider immaterial. All of those risks and uncertainties could adversely affect our business, financial condition and/or results of operations.

I~~tem~~Item 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

Item 3.DEFAULTS UPON SENIOR SECURITIES

None.

Item 4.MINE SAFETY DISCLOSURES

None.

Item 5.OTHER INFORMATION

None.

Item 6.EXHIBITS

The exhibits listed on the accompanying Exhibit Index are filed or incorporated by reference as part of this report, and such Exhibit Index is incorporated herein by reference.

4943

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PLAINS ALL AMERICAN PIPELINE, L.P.
By:
PAA GP LLC,
its general partner

By:
~~PAA GP LLC,~~ Plains AAP, L.P.,
its ~~general partner~~sole member

~~By:~~
~~PLAINS AAP, L.P., its sole member~~

By:
PLAINS ALL AMERICAN GP LLC,
its general partner

~~Date: November 7, 2014~~

By:
/s/ Greg L. Armstrong
Greg L. Armstrong,
Chairman of the Board,
Chief Executive Officer and Director of Plains All American GP LLC
(Principal Executive Officer)

~~Date: November 7, 2014~~May 8, 2015

By:
/s/ Al Swanson
Al Swanson,
Executive Vice President and Chief Financial Officer of Plains All American GP LLC
~~Chief Financial Officer~~
(Principal Financial Officer)

~~Date: November 7, 2014~~May 8, 2015

By:
/s/ Chris Herbold
Chris Herbold,
Vice ~~President-~~President —Accounting and Chief Accounting ~~and~~Officer of Plains All American GP LLC
(Principal Accounting Officer)

~~Chief Accounting Officer~~
May 8, 2015
~~(Principal Accounting Officer)~~

5044

Table of Contents

EXHIBIT INDEX

3.1

—

Fourth Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. dated as of May 17, 2012 (incorporated by reference to Exhibit 3.1 to ~~the~~our Current Report on Form 8-K filed May 23, 2012).

3.2

—

Amendment No. 1 dated October 1, 2012 to the Fourth Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to ~~the~~our Current Report on Form 8-K filed October 2, 2012).

3.3

—

Amendment No. 2 dated December 31, 2013 to the Fourth Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to ~~the~~our Current Report on Form 8-K filed December 31, 2013).

3.4

—

Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.2 to ~~the~~our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.5

—

Amendment No. 1 dated December 31, 2010 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.9 to ~~the~~our Annual Report on Form 10-K for the year ended December 31, 2010).

3.6

—

Amendment No. 2 dated January 1, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.10 to ~~the~~our Annual Report on Form 10-K for the year ended December 31, 2010).

3.7

—

Amendment No. 3 dated June 30, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.7 to ~~the~~our Annual Report on Form 10-K for the year ended December 31, 2013).

3.8

—

Amendment No. 4 dated January 1, 2013 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, ~~L.P.~~L.P (incorporated by reference to Exhibit 3.8 to ~~the~~our Annual Report on Form 10-K for the year ended December 31, 2013).

3.9

—

Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.3 to ~~the~~our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.10

—

Amendment No. 1 dated January 1, 2013 to the Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. (incorporated by reference to Exhibit 3.10 to ~~the~~our Annual Report on Form 10-K for the year ended December 31, 2013).

3.11

—

Sixth Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated October 21, 2013 (incorporated by reference to Exhibit 3.2 to ~~the~~our Current Report on Form 8-K filed October 25, 2013).

3.12

—

Seventh Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. dated October 21, 2013 (incorporated by reference to Exhibit 3.1 to ~~the~~our Current Report on Form 8-K filed October 25, 2013).

3.13

—

Amendment No. 1 dated December 31, 2013 to the Seventh Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.2 to ~~the~~our Current Report on Form 8-K filed December 31, 2013).

3.14

—

Certificate of Incorporation of PAA Finance Corp (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.10 to ~~the~~our Annual Report on Form 10-K for the year ended December 31, 2006).
45

Table of Contents

3.15

—

Bylaws of PAA Finance Corp (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.11 to ~~the~~our Annual Report on Form 10-K for the year ended December 31, 2006).
51

~~Table of Contents~~

3.16

—

Limited Liability Company Agreement of PAA GP LLC dated December 28, 2007 (incorporated by reference to Exhibit 3.3 to ~~the~~our Current Report on Form 8-K filed January 4, 2008).

4.1

—

Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).

4.2

—

Fourth Supplemental Indenture (Series A and Series B 5.875% Senior Notes due 2016) dated August 12, 2004
among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.5 to ~~the~~our Registration Statement on Form S-4, File No. 333-121168).

4.3

—

Fifth Supplemental Indenture (Series A and Series B 5.25% Senior Notes due 2015) dated May 27, 2005 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed May 31, 2005).

4.4

—

Sixth Supplemental Indenture (Series A and Series B 6.70% Senior Notes due 2036) dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed May 12, 2006).

4.5

—

Ninth Supplemental Indenture (Series A and Series B 6.125% Senior Notes due 2017) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed October 30, 2006).

4.6

—

Tenth Supplemental Indenture (Series A and Series B 6.650% Senior Notes due 2037) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to ~~the~~our Current Report on Form 8-K filed October 30, 2006).

4.7

—

Thirteenth Supplemental Indenture (Series A and Series B ~~6.5%~~6.50% Senior Notes due 2018) dated April 23, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed April 23, 2008).

4.8

—

Fifteenth Supplemental Indenture (8.75% Senior Notes due 2019) dated April 20, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed April 20, 2009).

4.9

—

Seventeenth Supplemental Indenture (5.75% Senior Notes due 2020) dated September 4, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed September 4, 2009).

4.10

—

Eighteenth Supplemental Indenture (3.95% Senior Notes due 2015) dated July 14, 2010 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed July 13, 2010).
46

Table of Contents

4.11

—

Nineteenth Supplemental Indenture (5.00% Senior Notes due 2021) dated January 14, 2011 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed January 11, 2011).

4.12

—

Twentieth Supplemental Indenture (3.65% Senior Notes due 2022) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance ~~Corp~~Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed March 26, 2012).
52

~~Table of Contents~~

4.13

—

Twenty-First Supplemental Indenture (5.15% Senior Notes due 2042) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance ~~Corp~~Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to ~~the~~our Current Report on Form 8-K filed March 26, 2012).

4.14

—

Twenty-Second Supplemental Indenture (2.85% Senior Notes due 2023) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee
~~(incorporated~~ (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed December 12, 2012).

4.15

—

Twenty-Third Supplemental Indenture (4.30% Senior Notes due 2043) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to ~~the~~our Current Report on Form 8-K filed December 12, 2012).

4.16

—

Twenty-Fourth Supplemental Indenture (3.85% Senior Notes due 2023) dated August 15, 2013, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed August 15, 2013).

4.17

—

Twenty-Fifth Supplemental Indenture (4.70% Senior Notes due 2044) dated April 23, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed April 29, 2014).

4.18

—

Twenty-Sixth Supplemental Indenture (3.60% Senior Notes due 2024) dated September 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed September 11, 2014).

4.19
—
Twenty-Seventh Supplemental Indenture (2.60% Senior Notes due 2019) dated December 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed December 11, 2014).
4.20
—
Twenty-Eighth Supplemental Indenture (4.90% Senior Notes due 2045) dated December 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 11, 2014).
4.21
—
Registration Rights Agreement dated September 3, 2009 by and between Plains All American Pipeline, L.P. and Vulcan Gas Storage LLC (incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-3, File No. 333-162477).
10.1
—
364-Day Credit Agreement dated January 16, 2015 among Plains All American Pipeline, L.P., as Borrower; Bank of America, N.A., as Administrative Agent; Citibank, N.A., JPMorgan Chase Bank N.A. and Wells Fargo Bank, National Association, as Co-Syndication Agents; DNB Bank ASA, New York Branch and Mizuho Bank, Ltd., as Co-Documentation Agents; the other Lenders party thereto; and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., DNB Markets, Inc., J.P. Morgan Securities LLC, Mizuho Bank, Ltd. and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed January 20, 2015).
12.1 †

—

Computation of Ratio of Earnings to Fixed ~~Charges~~Charges.

31.1 †

—

Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

31.2 †

—

Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).
47

Table of Contents
32.1 ††††

—

Certification of Principal Executive Officer pursuant to 18 U.S.C. ~~1350~~1350.

32.2 ††††

—

Certification of Principal Financial Officer pursuant to 18 U.S.C. ~~1350~~1350.

~~101.INS†~~101.INS†

—

XBRL Instance Document

~~101.SCH†~~101.SCH†

—

XBRL Taxonomy Extension Schema Document

~~101.CAL†~~101.CAL†

—

XBRL Taxonomy Extension Calculation Linkbase Document

~~101.DEF†~~101.DEF†

—

XBRL Taxonomy Extension Definition Linkbase Document

~~101.LAB†~~101.LAB†

—

XBRL Taxonomy Extension Label Linkbase Document

~~101.PRE†~~101.PRE†

—

XBRL Taxonomy Extension Presentation Linkbase Document

†Filed herewith.
~~†† Furnished herewith.~~

53††Furnished herewith.
48

		Page
PART I. FINANCIAL INFORMATION
Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
Condensed Consolidated Balance Sheets: As of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014		3
Condensed Consolidated Statements of Operations: For the three ~~and nine~~ months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~		4
Condensed Consolidated Statements of Comprehensive ~~Income:~~Income / (Loss): For the three ~~and nine~~ months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~		5
Condensed Consolidated Statements of Changes in Accumulated Other Comprehensive Income / (Loss): For the ~~nine~~three months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~		5
Condensed Consolidated Statements of Cash Flows: For the ~~nine~~three months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~		6
Condensed Consolidated Statements of Changes in Partners’ Capital: For the ~~nine~~three months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~		7
Notes to the Condensed Consolidated Financial Statements:
1. Organization and Basis of Consolidation and Presentation		8
2. Recent Accounting Pronouncements		9
3. Net Income Per Limited Partner Unit		10
4. Accounts Receivable	9	11
4.5. Inventory, Linefill and Base Gas and Long-term Inventory	10
~~5. Goodwill~~	1112
6. Debt	11	13
7. ~~Net Income Per Limited Partner Unit~~	12
8. Partners’ Capital and Distributions		14
8. Derivatives and Risk Management Activities		14
9. Equity-Indexed Compensation Plans	14	21
10. ~~Derivatives and Risk Management Activities~~	16
~~11.~~ Commitments and Contingencies		22
11. Operating Segments		23
12. ~~Operating Segments~~	24
~~13.~~ Related Party Transactions	26	24
~~14. Subsequent Events~~	27

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	28	25
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	46	41
Item 4. CONTROLS AND PROCEDURES	47	42

PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS	49	43
Item 1A. RISK FACTORS	49	43
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	49	43
Item 3. DEFAULTS UPON SENIOR SECURITIES	49	43
Item 4. MINE SAFETY DISCLOSURES	49	43
Item 5. OTHER INFORMATION	49	43
Item 6. EXHIBITS	49	43
SIGNATURES	50	44

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Basic Net Income per Limited Partner Unit
Net income attributable to PAA	$	323		$	231		$	994		$	1,052
Less: General partner’s incentive distribution (1)	(124		)	(95		)	(351		)	(272		)
Less: General partner 2% ownership (1)	(4		)	(3		)	(13		)	(16		)
Net income available to limited partners	195			133			630			764
Less: Undistributed earnings allocated and distributions to participating securities (1)	(1		)	(1		)	(5		)	(5		)
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	194		$	132		$	625		$	759

Basic weighted average limited partner units outstanding	370			343			365			340

Basic net income per limited partner unit	$	0.52		$	0.38		$	1.71		$	2.23

Diluted Net Income per Limited Partner Unit
Net income attributable to PAA	$	323		$	231		$	994		$	1,052
Less: General partner’s incentive distribution (1)	(124		)	(95		)	(351		)	(272		)
Less: General partner 2% ownership (1)	(4		)	(3		)	(13		)	(16		)
Net income available to limited partners	195			133			630			764
Less: Undistributed earnings allocated and distributions to participating securities (1)	(1		)	(1		)	(5		)	(4		)
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	194		$	132		$	625		$	760

Basic weighted average limited partner units outstanding	370			343			365			340
Effect of dilutive securities: Weighted average LTIP units	1			2			2			2
Diluted weighted average limited partner units outstanding	371			345			367			342

Diluted net income per limited partner unit	$	0.52		$	0.38		$	1.70		$	2.22

	Three Months Ended September 30 ,				Nine Months Ended September 30,
	2014		2013		2014		2013
Basic net income per limited partner unit impact	$	—	$	—	$	—	$	(0.23	)

Diluted net income per limited partner unit impact	$	—	$	—	$	—	$	(0.23	)

		Distributions Paid								Distributions
		Common		General Partner						per limited
Date Declared	Distribution Date	Units		Incentive		2%		Total		partner unit
October 8, 2014	November 14, 2014 (1)	$	245	$	124	$	5	$	374	$	0.6600
July 8, 2014	August 14, 2014	$	238	$	117	$	5	$	360	$	0.6450
April 7, 2014	May 15, 2014	$	229	$	110	$	5	$	344	$	0.6300
January 9, 2014	February 14, 2014	$	221	$	102	$	5	$	328	$	0.6150

	Units (1)		Weighted Average Grant Date Fair Value per Unit
Outstanding at December 31, 2013	8.4		$	36.97
Granted	1.1		$	47.27
Vested (2)	(1.9	)	$	25.54
Cancelled or forfeited	(0.3	)	$	39.63
Outstanding at September 30, 2014	7.3		$	41.28

	Reserved for Future Grants		Outstanding	Outstanding Units Earned	Grant Date Fair Value Of Outstanding AAP Management Units (1)
Balance at December 31, 2013	3.5		48.6	47.0	$	51
Granted	(0.4	)	0.4	—	11
Earned	N/A		N/A	0.8	N/A
Balance at September 30, 2014	3.1		49.0	47.8	$	62

		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2014	$	284	$	319	$1.00 - $1.12
	2015	178		200		$1.00 - $1.12
		$	462	$	519	$1.00 - $1.12

Forward exchange contracts that exchange USD for CAD:
	2014	$	284	$	313	$1.00 - $1.10
	2015	178		195		$1.00 - $1.09
		$	462	$	508	$1.00 - $1.10

				Effect of 10%			Effect of 10%						Effect of 10%			Effect of 10%
	Fair Value			Price Increase			Price Decrease			Fair Value			Price Increase			Price Decrease
Crude oil and related products	$	7		$	32		$	(27	)
Crude oil										$	48		$	(31	)	$	31
Natural gas	(2		)	$	1		$	(1	)	(24		)	$	2		$	(2	)
NGL and other	26			$	(69	)	$	69		120			$	(17	)	$	17
Total fair value	$	31								$	144

	PLAINS ALL AMERICAN PIPELINE, L.P.

	By:	PAA GP LLC,
		its general partner

	By:	~~PAA GP LLC,~~ Plains AAP, L.P.,
		its ~~general partner~~sole member
	~~By:~~	~~PLAINS AAP, L.P., its sole member~~
	By:	PLAINS ALL AMERICAN GP LLC,
		its general partner

~~Date: November 7, 2014~~

	By:	/s/ Greg L. Armstrong
		Greg L. Armstrong,
		*Chairman of the Board,*
	Chief Executive Officer and Director of Plains All American GP LLC
		*(Principal Executive Officer)*

~~Date: November 7, 2014~~May 8, 2015

	By:	/s/ Al Swanson
		Al Swanson,
		*Executive Vice President and Chief Financial Officer of Plains All American GP LLC*
	*~~Chief Financial Officer~~*
	*(Principal Financial Officer)*

~~Date: November 7, 2014~~May 8, 2015

	By:	/s/ Chris Herbold
		Chris Herbold,
		*Vice ~~President-~~President —Accounting and Chief Accounting ~~and~~Officer of Plains All American GP LLC*
		*(Principal Accounting Officer)*
	~~Chief Accounting Officer~~
May 8, 2015	~~(Principal Accounting Officer)~~

3.1	—	Fourth Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. dated as of May 17, 2012 (incorporated by reference to Exhibit 3.1 to ~~the~~our Current Report on Form 8-K filed May 23, 2012).

3.2	—	Amendment No. 1 dated October 1, 2012 to the Fourth Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to ~~the~~our Current Report on Form 8-K filed October 2, 2012).

3.3	—	Amendment No. 2 dated December 31, 2013 to the Fourth Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to ~~the~~our Current Report on Form 8-K filed December 31, 2013).

3.4	—	Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.2 to ~~the~~our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.5	—	Amendment No. 1 dated December 31, 2010 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.9 to ~~the~~our Annual Report on Form 10-K for the year ended December 31, 2010).

3.6	—	Amendment No. 2 dated January 1, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.10 to ~~the~~our Annual Report on Form 10-K for the year ended December 31, 2010).

3.7	—	Amendment No. 3 dated June 30, 2011 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. (incorporated by reference to Exhibit 3.7 to ~~the~~our Annual Report on Form 10-K for the year ended December 31, 2013).

3.8	—	Amendment No. 4 dated January 1, 2013 to the Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, ~~L.P.~~L.P (incorporated by reference to Exhibit 3.8 to ~~the~~our Annual Report on Form 10-K for the year ended December 31, 2013).

3.9	—	Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.3 to ~~the~~our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

3.10	—	Amendment No. 1 dated January 1, 2013 to the Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. (incorporated by reference to Exhibit 3.10 to ~~the~~our Annual Report on Form 10-K for the year ended December 31, 2013).

3.11	—	Sixth Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated October 21, 2013 (incorporated by reference to Exhibit 3.2 to ~~the~~our Current Report on Form 8-K filed October 25, 2013).

3.12	—	Seventh Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. dated October 21, 2013 (incorporated by reference to Exhibit 3.1 to ~~the~~our Current Report on Form 8-K filed October 25, 2013).

3.13	—	Amendment No. 1 dated December 31, 2013 to the Seventh Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.2 to ~~the~~our Current Report on Form 8-K filed December 31, 2013).

3.14	—	Certificate of Incorporation of PAA Finance Corp (f/k/a Pacific Energy Finance Corporation, successor-by-merger to PAA Finance Corp.) (incorporated by reference to Exhibit 3.10 to ~~the~~our Annual Report on Form 10-K for the year ended December 31, 2006).


3.16	—	Limited Liability Company Agreement of PAA GP LLC dated December 28, 2007 (incorporated by reference to Exhibit 3.3 to ~~the~~our Current Report on Form 8-K filed January 4, 2008).

4.1	—	Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).

4.2	—	Fourth Supplemental Indenture (Series A and Series B 5.875% Senior Notes due 2016) dated August 12, 2004
		among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.5 to ~~the~~our Registration Statement on Form S-4, File No. 333-121168).

4.3	—	Fifth Supplemental Indenture (Series A and Series B 5.25% Senior Notes due 2015) dated May 27, 2005 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed May 31, 2005).

4.4	—	Sixth Supplemental Indenture (Series A and Series B 6.70% Senior Notes due 2036) dated May 12, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed May 12, 2006).

4.5	—	Ninth Supplemental Indenture (Series A and Series B 6.125% Senior Notes due 2017) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed October 30, 2006).

4.6	—	Tenth Supplemental Indenture (Series A and Series B 6.650% Senior Notes due 2037) dated October 30, 2006 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to ~~the~~our Current Report on Form 8-K filed October 30, 2006).

4.7	—	Thirteenth Supplemental Indenture (Series A and Series B ~~6.5%~~6.50% Senior Notes due 2018) dated April 23, 2008 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed April 23, 2008).

4.8	—	Fifteenth Supplemental Indenture (8.75% Senior Notes due 2019) dated April 20, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed April 20, 2009).

4.9	—	Seventeenth Supplemental Indenture (5.75% Senior Notes due 2020) dated September 4, 2009 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed September 4, 2009).

4.10	—	Eighteenth Supplemental Indenture (3.95% Senior Notes due 2015) dated July 14, 2010 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed July 13, 2010).

4.11	—	Nineteenth Supplemental Indenture (5.00% Senior Notes due 2021) dated January 14, 2011 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed January 11, 2011).

4.12	—	Twentieth Supplemental Indenture (3.65% Senior Notes due 2022) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance ~~Corp~~Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed March 26, 2012).


4.13	—	Twenty-First Supplemental Indenture (5.15% Senior Notes due 2042) dated March 22, 2012 among Plains All American Pipeline, L.P., PAA Finance ~~Corp~~Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to ~~the~~our Current Report on Form 8-K filed March 26, 2012).

4.14	—	Twenty-Second Supplemental Indenture (2.85% Senior Notes due 2023) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee
		~~(incorporated~~ (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed December 12, 2012).

4.15	—	Twenty-Third Supplemental Indenture (4.30% Senior Notes due 2043) dated December 10, 2012, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to ~~the~~our Current Report on Form 8-K filed December 12, 2012).

4.16	—	Twenty-Fourth Supplemental Indenture (3.85% Senior Notes due 2023) dated August 15, 2013, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed August 15, 2013).

4.17	—	Twenty-Fifth Supplemental Indenture (4.70% Senior Notes due 2044) dated April 23, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed April 29, 2014).

4.18	—	Twenty-Sixth Supplemental Indenture (3.60% Senior Notes due 2024) dated September 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ~~the~~our Current Report on Form 8-K filed September 11, 2014).

4.19	—	Twenty-Seventh Supplemental Indenture (2.60% Senior Notes due 2019) dated December 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed December 11, 2014).

4.20	—	Twenty-Eighth Supplemental Indenture (4.90% Senior Notes due 2045) dated December 9, 2014, by and among Plains All American Pipeline, L.P., PAA Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed December 11, 2014).

4.21	—	Registration Rights Agreement dated September 3, 2009 by and between Plains All American Pipeline, L.P. and Vulcan Gas Storage LLC (incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-3, File No. 333-162477).

10.1	—	364-Day Credit Agreement dated January 16, 2015 among Plains All American Pipeline, L.P., as Borrower; Bank of America, N.A., as Administrative Agent; Citibank, N.A., JPMorgan Chase Bank N.A. and Wells Fargo Bank, National Association, as Co-Syndication Agents; DNB Bank ASA, New York Branch and Mizuho Bank, Ltd., as Co-Documentation Agents; the other Lenders party thereto; and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., DNB Markets, Inc., J.P. Morgan Securities LLC, Mizuho Bank, Ltd. and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed January 20, 2015).

12.1 †	—	Computation of Ratio of Earnings to Fixed ~~Charges~~Charges.

31.1 †	—	Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

31.2 †	—	Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).


32.1 ††††	—	Certification of Principal Executive Officer pursuant to 18 U.S.C. ~~1350~~1350.

32.2 ††††	—	Certification of Principal Financial Officer pursuant to 18 U.S.C. ~~1350~~1350.

~~101.INS†~~101.INS†	—	XBRL Instance Document

~~101.SCH†~~101.SCH†	—	XBRL Taxonomy Extension Schema Document

~~101.CAL†~~101.CAL†	—	XBRL Taxonomy Extension Calculation Linkbase Document

~~101.DEF†~~101.DEF†	—	XBRL Taxonomy Extension Definition Linkbase Document

~~101.LAB†~~101.LAB†	—	XBRL Taxonomy Extension Label Linkbase Document

~~101.PRE†~~101.PRE†	—	XBRL Taxonomy Extension Presentation Linkbase Document